INSIGHT
DECEMBER 2022
Corporate week in brief
Corporate week in brief
Introduction
The Corporate Week in Brief report highlights the latest need-to-know events from the corporate global energy sector, combined
with Wood Mackenzie's expert analysis and opinion. You can bookmark this report for regular updates.
Q4 2022
Eni boosts Italian renewables portfolio
Greig Aitken, 5 December 2022
The facts: Eni has agreed to acquire 100% of PLT, an Italian integrated renewable electricity producer/supplier. The deal adds
400 MW (>80% wind power) of assets in Italy (80% operational; 20% under construction with start-up due by 2024). It also adds
1.2 GW of under-development projects (>80% wind) in Italy and Spain, 60% of which are in advanced maturity. The business
also has 90,000 retail customers in Italy. No consideration has been disclosed.
Our take: At end Q3 2022, Eni had 1,827 MW of installed renewables capacity. It was already on track to reach its 2022
installed capacity target of 2 GW prior to this transaction. Eni also had line of sight on its 2025 target of >6 GW of capacity, and
this deal further strengthens confidence in achieving that target. The deal helps to build confidence in Eni achieving its mediumterm installed capacity target of >15 GW by 2030. Its pipeline currently stands at ~13 GW.
In Italy, as in other Southern European markets, Eni is targeting an integrated energy model. Boosting retail customer numbers
is therefore one of Eni core targets. It intends to increase customer numbers from ~10 million currently to 11.5 million by 2025.
In addition to boosting its customer base, Eni is focused on increasing its margin per customer by upselling low-carbon products
and services.
For a deep dive into Eni’s renewables portfolio, see Eni’s corporate new energy profile, which we updated last month.
Eni reportedly eyeing up Neptune Energy
Greig Aitken, 5 December 2022
The facts: according to the FT, Eni is in preliminary discussions to acquire private equity-backed Neptune Energy. The report
claims that Eni is yet to make an offer and that talks remain at a very early stage.
Our take: we would have been very surprised at this mooted transaction 12 months ago. The Majors are leaning heavily into the
energy transition, and Eni has set ambitious long-term goals in renewable power and decarbonisation. We expected that future
large transactions by the Euro Majors would target these themes. At a rumoured price of US$5 to 6 billion, this would constitute
the largest upstream acquisition by a European oil and gas Major since BP bought BHP’s US shale assets in 2018.
However, the Russian invasion of Ukraine has changed attitudes to energy security along with gas supply and prices. Eni has
been working hard to replace Russian gas supply into Italy and earlier this year acquired BP’s gas assets in Algeria. Regarding
Neptune specifically, there are features of its portfolio which are a good fit with Eni’s ambitions:
•
its hydrocarbon production is heavily weighted towards gas (Eni intends to boost its own gas weighting to 60% by 2030, from
~55% now)
•
Neptune's Scope 1 and Scope 2 emissions intensity levels are relatively low (16.3 tCO2e/kboe, and falling)
•
the two companies’ portfolios have strong alignment across multiple geographies including Indonesia, Australia and Norway.
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Neptune’s largest country exposure is to Norway. Eni’s assets in Norway are owned through its majority shareholding in Oslolisted Var Energi. We wonder whether any potential transaction might involve Var Energi’s direct involvement, rather than being
executed solely at Eni group level.
Neptune’s backers have been looking to exit for some time, with an IPO previously being mooted.
For further details on this rumoured transaction, see our Lens video analysis.
Petrobras unveils its 2023-2027 plan
Raphael Portela, 2 December 2022
The facts: Petrobras unveiled its latest five-year strategy plan, covering ambitions for growth in E&P, capital allocation and
sustainability.
Our take: There’s a big asterisk in Petrobras’ latest plan. Lula is returning to Brazil’s presidency, and the company is all but
certain to be impacted by the left-wing administration. The change in directive has just not yet percolated through the business.
Petrobras acknowledged that its planning process began months prior to the election results, and fielded questions about the
potential for mid-year revisions. Bottom line: it is a possibility.
Areas with the highest risk of amendments include its dividend policy and disposal programme. We think downstream
divestments will be halted. Other key announcements included a 12% increase in five-year E&P capex (US$64 billion) and an
acceleration in low-carbon spend, now 6% of the corporate budget or US$4.4 billion over the period. Near-term emissions and
CCUS targets were also pushed higher, while its production outlook suffered a marginal downgrade. Stay tuned for our strategy
update insight in the coming days.
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TotalEnergies sells its Dunga oil field stake in Kazakhstan and advances
large onshore wind deal
Ashley Sherman, 1 December 2022
The facts: TotalEnergies has signed a US$330 million agreement to divest its 60% operated interest in Kazakhstan’s
onshore Dunga PSC. The buyer is Oriental Sunrise Corp, a local firm. Completion of the transaction is subject to Kazakh
regulatory approval and the pre-emption rights of TotalEnergies’ PSC partners: OQ (Oman) and PTTEP (Thailand).
The deal was one of many documents signed during a visit by the Kazakh President to France. TotalEnergies’ current net
production at Dunga is about 7,400 boe/d. In 2022, the field’s oil output has averaged less than 15,000 b/d on a 100% basis.
The Euro Major also reached terms with state-owned partners for Kazakhstan’s largest-ever wind project. The onshore Mirny
development would provide 1 GW of wind capacity, alongside 600 MWh of battery storage. This follows preliminary
agreements by Total Eren in 2021-22.
Our take: Both moves are well aligned with TotalEnergies’ corporate strategy: the sale of a peripheral upstream oil asset and
involvement in a landmark low-carbon initiative in a core country. The Mirny wind project is pre-development, but TotalEnergies
already has 128 MW of operational solar capacity in Kazakhstan.
Speculation has surrounded the Dunga stake since TotalEnergies inherited it from Maersk in 2018. The deal value is close to
our current NPV10 of US$347 million (at January 2023). Risks have escalated in Kazakhstan this year, most notably to oil
exports via Russia. Nevertheless, we view Dunga as an attractive proposition. It offers long-term cash flow thanks to its PSC
extension to 2039 and the benefits of ongoing Phase III investment.
We understand that the purchaser, Oriental Sunrise Corp, is related to Magnetic Oil, which also bought OMV Petrom’s Kazakh
upstream assets in 2021. This is a notable acquisition for a private local firm. Despite the merits of Dunga as a medium-sized
onshore project, and multiple interested parties, few IOC bids may have been forthcoming.
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After the Dunga exit, Kazakhstan will remain a top-six upstream location for TotalEnergies thanks to its 16.81% stake in the
offshore Kashagan megaproject. Growth remains on the agenda there via new investment phases. The company is also starting
to gain materiality in the Kazakh renewables sector with its latest move.
Look out for our upcoming Insight on TotalEnergies’ Dunga exit.
Woodside Energy fails to excite with 2022 investor update
Andrew Harwood, 1 December 2022
The facts: Woodside Energy reiterated its value proposition for shareholders at its Investor Briefing Day 2022 on 1 December.
A high-quality portfolio, a disciplined approach to capital management, and well positioned for the energy transition were the
intended takeaways for investors. The share price was down 1.3% on the day.
The business remains on track to generate US$13 billion of free cash flow over 2022-2024, aligning with our forecast at our
base price assumption. With mid-year gearing of 2.2% well below the target range of 10-20%, the balance sheet is prepped for
increased distributions, growth investments and an acceleration of Woodside’s low-carbon strategy.
Our take: Having earlier announced its 2023 guidance (production to rise 19% to 495-520 kboe/d, capex to increase 51% to
US$6-6.5 billion), there were few surprises in the latest update.
The key Sangomar and Scarborough projects are on track for start-up in late 2023 and 2026 respectively. The deepwater Trion
development is moving towards Final Investment Decision in 2023. And work is underway to progress the development
concepts for Browse, Sunrise and Calypso.
Woodside is also progressing its low carbon portfolio. The company is targeting FID for the H2OK project in the US in 2023,
aiming at the production of green hydrogen for the trucking sector from 2026. Woodside is seeding further solar, green hydrogen
and ammonia projects across Australia and the US as part of its plans to invest US$5 billion in low-carbon opportunities by
2030.
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And that was pretty much that. After 2021 saw a new CEO, the transformational merger with BHP, and the launch of a new lowcarbon strategy, Woodside could perhaps be forgiven for its 2022 investor briefing being less dramatic. The focus now switches
to execution of its declared plans.
CCUS partnership to develop third party verification framework
Rachel Schelble and Mackenzie Monsour, 1 December 2022
The facts: Six companies have partnered to develop a third-party verification framework to ensure that CO2 is safely captured,
transported, and permanently sequestered. Project Canary, Denbury, IMA Financial Group, Enerflex, Wolf Carbon Solutions and
Advanced Resources International have expertise that spans the CCUS value chain from carbon capture to sequestration, with
expertise in technology, operations, subsurface risk, and CCUS storage. Project Canary’s digital platform will be used to
measure, report, and verify stored volumes of CO2.
Our take: Measurement, verification, and reporting will be key to unlocking climate finance and showing progress on climate
goals. In 2023, we expect to see more energy companies pursue carbon capture and storage projects in the US, where they can
leverage incentives from the inflation reduction act’s (IRA) updated guidance for the 45Q tax credit.
The expected rapid growth in CCUS in the US will require the standardized and objective third-party verification offered by this
collective and will be crucial to build investor and public trust. This collective will address existing gaps and CCUS concerns
such as reservoir integrity, storage permanence and accounting of net emissions.
Enhanced oil recovery projects and depleted oil reservoirs will also benefit from this oversight potentially helping to reconcile
concerns over long-term carbon storage in these reservoirs. The oil and gas industry has a competitive advantage in developing
CCUS projects in oil and gas reservoirs where they have significant expertise in operations and geology, and infrastructure to
monitor CO2 sequestration.
Oxy to work with Enbridge to develop CO2 transport and storage facilities
Zoë Sutherland, 1 December 2022
The facts: Occidental's Low Carbon Ventures subsidiary (OLCV) has signed a deal with Enbridge to explore the development
of a CO2 pipeline transport and sequestration hub near Corpus Christi in Texas. Enbridge will develop, construct, and operate
the pipeline facilities while OLCV will develop, construct and operate the sequestration facilities. The CO2 hub will serve
Enbridge’s facilities and those of third-party emitters in the area.
Our take: last month Oxy announced a lease agreement with King Ranch which involved pore space to store up to 3 billion tpa
of CO2 near Corpus Christi. This latest deal could facilitate the transportation of CO2 to this hub.
Oxy’s CCUS plans are gaining momentum. The company hopes to establish at least three carbon sequestration hubs as soon
as 2025, with a combined storage capacity of 18 Mtpa. It has now made concrete steps towards two of these hubs. In addition
to its Corpus Christi hub, OLCV’s subsidiary 1point5 announced in July it had acquired pore space in Western Louisiana for its
planned West Bay hub which would serve 3rd party emitters in the area.
For more on corporate activity in CCUS, see our latest Insights - Emerging CCUS business models utilising existing
infrastructure and Majors' CCUS benchmarking 2022
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PETRONAS sanctions Kasawari CCS
Huong Tra Ho, Andrew Harwood, 30 November 2022
The facts: PETRONAS has taken FID on the second phase of Kasawari development, its first major CCS project. The Kasawari
CCS project in block SK316 will capture and sequester 3.3 million tonnes of CO2 per year, that would otherwise be flared,
making it the largest upstream CCS project under development in Asia.
Kasawari Phase 2 will involve a dedicated CCS platform at Kasawari, a 135km CO2 pipeline to the depleted M1 field, an
injection platform at M1 and three injector wells. The EPCIC (Engineering, Procurement, Construction, Installation and
Commissioning) contract for the project has been awarded to Malaysia Marine and Heavy Engineering (MMHE), who is also
executing Phase 1 EPCIC.
Our take: The Kasawari CCS project will unlock an additional 3.2 tcf of gas supply for PETRONAS’ Bintulu LNG complex, which
currently supplies around 25 mmtpa of LNG. With over 7 tcf in-place, but an average CO2 content of 20%, Kasawari has been a
test of PETRONAS’ decarbonisation ambitions.
While enabling PETRONAS to maintain LNG, Kasawari CCS will support PETRONAS’ plan to reduce Scope 1 and 2 emissions
by 25% by 2030, and to reach net zero emissions by 2050. PETRONAS is also progressing the Sarawak Integrated Sour Gas
Evacuation System (SISGES), putting Malaysia on a path to become one of Asia’s leading CCS/CCUS hubs.
Shell to acquire Nature Energy for US$2 billion
Luke Parker, 29 November 2022
The facts: Shell has reached agreement to acquire Nature Energy – Europe’s largest biomethane producer – for US$2 billion.
Nature Energy operates 14 waste biogas plants in Denmark and Netherlands, which produced around 158 mmcm of
biomethane in 2021. It has a further 30 projects in the pipeline, across Europe and North America, with the potential to more
than double production by 2030.
NB. Biomethane and renewable natural gas (RNG) are one in the same: the former term is more commonly used in Europe, the
latter in North America.
Our take: The acquisition of Nature Energy marks Shell’s entry into European biomethane. It’s also the largest deal in European
biomethane to date by a distance. So big news for company and sector.
But biomethane is familiar territory for Shell, which already has a burgeoning business in the US. It started production from its
first biomethane facility – Junction City, Oregon – in September 2021, and has four more sites under construction (see our North
America RNG project tracker for detail). Shell also holds an indirect interest, through Raízen, in one of the world's largest biogas
plants in São Paulo state, Brazil.
The acquisition of Nature Energy is part of a broader, integrated strategy. Shell is already building new businesses further down
the biogas value chain. It opened Europe’s first bioLNG plant in the Netherlands in 2021 and is currently building a second in
Germany. The bioLNG that these facilities produce feeds Shell’s growing network of LNG stations for heavy-duty road haulage.
Shell has, to date, sourced feedstock biogas for its bioLNG plants from third parties. Indeed, Shell signed a long-term biogas
supply agreement with Nature Energy in 2020, which suggests a degree of familiarity with the business and the economics. The
acquisition of Nature effectively completes the bioLNG value chain for Shell in Europe – from landfill to truck driver. That bioLNG
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is, in turn, a part of a broader integrated energy offering that Shell is building for customers looking to decarbonise their energy
use (think Amazon, or Amsterdam city council).
Shell’s move for Nature Energy follows hot on the heels of BP’s $4 billion acquisition of Archaea Energy. Eni, TotalEnergies and
Engie have also made biomethane acquisitions (albeit much smaller) in recent months. While it’s still early days for biogas, the
growing wave of interest from the industry’s biggest players is a clear signal of where the market is headed.
Enel sharpens strategic and financial focus
Norman Valentine and Akif Chaudhry, 24 November 2022
The facts: leading European utility Enel presented its latest three-year strategy at its 2022 Capital Markets Day. The company
outlined investment of EUR37 billion to the end of 2025, with 50% allocated to generation, 40% to networks and 10% to
customers. Investment will focus on 6 countries across Europe (Italy, Spain), Latin America (Brazil, Colombia and Chile) and the
US.
Enel’s refocused business plan will see it realise EUR21 billion of enterprise value from asset sales over the next three years
and include country exits from Romania, Peru and Argentina as well as a withdrawal from gas activities. Divestment proceeds
will be used to reduce net debt.
Enel aims to increase its renewables generation capacity from 59 GW to 75 GW over the next three years, including 4 GW of
battery storage. By 2025, 75% of the company’s generation will come from renewable sources. Renewables investment will
focus on solar (52% of 3-year spend), onshore wind (27%) and battery storage (18%) with nearly 90% of spend concentrated in
Europe and the US.
Investment in grids will focus on Italy and Spain. Enel also retained its 2040 net zero target.
Our take: integration, risk management and streamlining were the main themes in this strategy update. Investment in
renewables combined with disposals will shift Enel ‘s business mix away from thermal generation sources and towards fixed
priced power sales, reducing market risk exposure. Supply chain risks to renewables capacity build out will be mitigated by the
expansion of Enel’s 3Sun solar panel production facility from 200 MW/yr to 3 GW/yr by 2024. Enel will also continue focus on
onshore renewables and does not see offshore wind as a part of its integrated generation and customer strategy.
Asset sales will focus the portfolio on core geographies and integrated positions where Enel can add value. In contrast to some
peers, Enel ruled out acquisitions in the US, citing challenges in regulatory regimes as a barrier to growth. Enel will also look to
crystallise value from the sale of renewable assets which are not clearly linked to its customer business.
Successful implementation will see Enel become leaner and more strategically focused. Net debt reduction of EUR21 billion via
asset sales will see financial resilience improve and bring Enel’s financial gearing (74% at mid-year 2022 based on our
definition) more in line with peers (average c 55%). But a greater focus on a smaller number of markets will increase portfolio
concentration risk. Exposure to fiscal and regulatory uncertainties in Spain and Italy will remain key swing factors.
TotalEnergies and Air Liquide get creative in low emissions fuels strategy
Tom Ellacott, 22 November 2022
The facts: TotalEnergies has provided more detail on its Grandpuits zero crude platform. Air Liquide is to invest €130 million to
build a new hydrogen unit with a capacity of over 20,000 tpa. The unit will partly use biogas from TotalEnergies’ Grandpuits
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biorefinery. Air Liquide will deploy its Cryocap carbon capture technology to capture over 110,000 tpa of CO2 for reuse in food
and industrial applications.
TotalEnergies has also signed a long-term contract to purchase the low-carbon hydrogen produced. The company will use the
majority to produce sustainable aviation fuel.
Our take: the Grandpuits Zero Crude Platform is part of TotalEnergies’ drive to decarbonise all of the hydrogen consumed in its
European refineries by 2030. The company is using relatively small-scale projects linked to its industrial facilities as a test bed
for a range of hydrogen technologies.
It makes more economic sense to upgrade biogas to biomethane and take the gas price. But this is all about the integration with
the wider refinery complex. TotalEnergies’ application of several low carbon solutions will also help it get up the learning curve in
the embryonic renewable hydrogen sector. This will pave the wave for commercial scale-up of hydrogen, biofuels and e-fuels
from 2030.
Success will play a vital role in ensuring the Supermajor’s long-term sustainability as it starts to wind down its oil and gas
business next decade. TotalEnergies expects low-emissions fuels to account for 25% of its overall energy production by 2050.
Saudi Aramco continues downstream investment push
Kavita Jadhav and Yuqi Hu, 21 November 2022
The facts: Saudi Aramco announced a US$7 billion investment in a refinery-integrated petrochemical steam cracker in South
Korea through its S-OIL affiliate. Located at S-OIL’s existing site in Ulsan, the Shaheen project will have the capacity to produce
3.2 million tons of petrochemicals annually including high-value polymers. The project will begin construction next year and is
expected to be completed by 2026.
Our take: Shaheen demonstrates the company’s continued strategy to grow downstream in order to diversify into geographies,
particularly high-growth Asian markets, and integrate across the crude to chemicals value chain. It follows an earlier US$4 billion
investment into the first phase of the petrochemical expansion at Ulsan completed in 2018.
This second phase is the first commercialization of Aramco’s crude to chemicals technology, which increases chemical yield,
reduces operating costs and also reduces the energy intensity of the production process. Development and deployment of this
technology demonstrates Saudi Aramco’s efforts to reduce the carbon intensity of its operations, towards its 2050 goal of net
zero Scope 1 and 2 emissions.
The US$69 billion acquisition of a 70% share in SABIC from the Public Investment Fund, the sovereign wealth fund of Saudi
Arabia, positioned Aramco as a world-leading petrochemical player and highlighted the scale of its ambitions. Petrochemicals
are expected to be one of the main drivers of oil demand growth to 2040 and the Shaheen project deepens existing market
positions.
SSE profits surge, sticks to strategy, faces UK windfall tax
Norman Valentine and Akif Chaudhry, 18 November 2022
The facts: SSE’s half-year adjusted earnings after tax tripled year-on-year to GBP 489 million (c US$577 million). The interim
dividend increased 13.7%. Adjusted net debt edged up 4% to GBP10 billion due to higher investment and acquisition costs.
Company guidance on full-year profits, annual dividend and 5-year earnings growth remained unchanged.
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On the following day, the UK government introduced an electricity generator levy as part of its Autumn Budget Statement. The
levy will see revenue from nuclear and renewable generation above a GBP75/MWh threshold taxed at a rate of 45% from
January 2023 to March 2028.
Our take: SSE’s business is proving resilient amidst volatile European energy markets. The core networks business has
benefited from indexed-linked returns on a growing asset base (half-year EBIT +14%). In the generation and gas storage
segment, higher prices pushed up operating profit (+200% y-o-y) despite a total GBP130 million hit from delays and
overhedging at the Seagreen offshore wind project combined with thermal generation outages.
There were no major strategy changes on this call. SSE is sticking with its GBP12.5 billion 5-year net capex plan out to March
2026, split 40:40:20 across networks, renewables and other businesses.
Management was repeatedly quizzed about the impact of rising costs and interest rates on investment and plans to divest a
25% minority stake in the networks business. With big investments already underway (Seagreen, Dogger Bank and Viking),
SSE should be shielded from near-term renewables cost inflation. Regulated cost increases in the networks segment remains a
key swing factor in SSE’s “build, build, build” strategy.
The UK government’s windfall tax on low-carbon power producers grabbed headlines but the near-term impact on SSE’s future
profits will be limited by hedging positions and levy allowances (e.g. CFD revenues are exempt). Approximately 90% of SSE’s
renewable generation out to April 2024 is hedged at weighted average price of GBP77/MWh. The market was expecting worse
and SSE shares were up 5% over the course of the week.
Gorgon CO2 injections continue to fall short of nameplate capacity
Rachel Schelble and Alex Beeker, 18 November 2022
The facts: It was reported this week that Chevron and its partners continue to underperform at the world’s largest CCS project
in western Australia. Gorgon CCS was designed to inject up to 4 million tons of CO2 per annum but has fallen far short of that
mark. Last year, the company and its partners had to purchase US$184 million of carbon offsets for failing to meet its quota.
The shortfall for the period 18 July 2017 to 17 July 2022 was approximately 2.4 million tons of CO2 equivalent.
Technical challenges have plagued the Gorgon CCS project from the beginning – water entering the CO2 pipeline causing
corrosion risk, equipment failure, sand clogging the reservoir have all been cited as reasons for coming up short. In its recent
report, Chevron said that the CCS part of the CO2 injection is working fine but it’s the water production and water management
system that is challenging.
Our take: oil and gas companies are growing increasingly dependent on CCS to meet net zero ambitions, leveraging the
synergies between subsurface hydrocarbon exploration and carbon storage. It’s become a core pillar of energy transition
strategies for everyone from the Majors to E&Ps, and we expect this trend to grow.
CO2 has been injected into subsurface oil and gas reservoirs for decades as part of tertiary recovery efforts to extract more oil
and gas from producing reservoirs on decline. Enhanced oil recovery projects that inject CO2 into the reservoir are carefully
designed on a reservoir-by-reservoir basis considering geological variability and subsurface complexity using seismic data sets
and reservoir flow models.
The ambitious Gorgon project is one of the first projects that has attempted to develop CCS on a large scale, and we can only
hope that the technical complexities that Chevron and its partners have faced with Gorgon’s CCS challenges are not a
bellwether for scaling up other CCUS projects that the world will count on to meet 2050 net zero goals.
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Shell starts up flagship Pennsylvania development
Luke Parker, 18 November 2022
The facts: Shell has commenced commercial operations at its Pennsylvania Chemical project, Shell Polymers Monaca (SPM).
Sanctioned in 2016, with a reported budget of US$6 billion, the facility was originally slated to start up in 2020. Two years on,
SPM is expected to ramp up to full production of 1.6 million tonnes per year of polyethylene (roughly equivalent to 93,000 b/d of
ethane) by mid-2023. The addition will boost Shell’s global petrochemical capacity to 16 million tonnes (net).
Our take: Chemicals is an important strategic growth area for Shell, and key to the transition story. The portfolio is evolving to
include sustainable chemicals (recycled feedstocks), more intermediates and higher-margin performance chemicals such as
polycarbonate and polyethylene (as at SMP).
At a reported budget of US$6 billion, SPM would rank as the second single largest investment in Shell’s global portfolio (all
segments) over the past five years. The final cost is undisclosed, but SPM will have accounted for a big chunk of the estimated
US$16 billion of organic cash capex the company put into Chemicals in the five years from 2017 to 2021.
SPM is a chemicals-only site – not one of Shell’s six integrated Energy and Chemicals Parks. However, as an advantaged asset
– low-cost feedstock gas; performance chemicals; close to massive demand – it is core to the portfolio, and should deliver a
measurable improvement in financial performance over the coming years.
Diamondback Energy acquires Lario Permian LLC for US$1.55 billion
Alex Beeker, 17 November 2022
The facts: Diamondback Energy (FANG) rattled west Texas again with another bolt-on acquisition. FANG announced it has
agreed to acquire Lario Permian, LLC, a subsidiary of Lario Oil & Gas, for US$1.55 billion. The deal is being financed with 4.18
million shares and US$850 million cash (pre-adjustments at closing). Part of the cash portion will be funded through its undrawn
credit facility and/or proceeds from a senior notes offering.
The transaction includes 15,000 net acres with estimated 2023 average production of 25 kboe/d (72% oil) and 154 drilling
locations. Lario is currently running two rigs on the acreage but FANG signaled it will drop to one rig or less next year. The move
mimics FANG’s actions after the FireBird deal and are likely done to support free cash flow.
Our take: In recent earnings calls, Diamondback expressed discomfort with Midland Basin bolt-ons due to elevated private
company valuations and limited opportunities remaining in the Basin. They would only consider deals if it would be extremely
competitive with their current inventory.
FANG’s gearing ratio at the end of Q3-22 was 28% which remains slightly above peers. The company issued US$1.1 billion of
senior notes after the FireBird deal and may issue more following Lario (albeit the company expects leverage to be unchanged
after the deal). Taking on new debt at a higher cost could be considered worrisome after shale’s overleveraged history.
But Diamondback’s relentless commitment to shareholder distributions may buy them some leniency with equity holders. The
company has committed to return at least 75% of free cash flow to shareholders through dividends and buybacks. While many
peers are chasing mid single-digit growth, Diamondback remains steadfast on stay flat mode. The capital discipline required to
acquire high-quality acreage and drop rigs to preserve capital efficiency is remarkable and should ease the concerns of skeptics
that are fearful of shale returning to its old overspending habits.
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Chevron and QatarEnergy announce FID on petrochemical facility at US
Gulf Coast
Alex Beeker, 17 November 2022
The facts: Chevron Phillips Chemical Company LLC (CPChem) and QatarEnergy announced they made a final investment
decision on an integrated polymers facility that will be located in Orange, Texas. The cost of the project is approximately US$8.5
billion and is expected to create more than 500 full-time jobs.
The plant is expected to begin operations in 2026 and will include a 2,080 KTA ethane cracker and two 1,000 KTA high-density
polyethylene units. The project is targeting 25% lower GHG emissions than similar facilities in the US and Europe.
The joint-venture company, Golden Triangle Polymers Company LLC, will be owned 51% by CPChem and 49% by
QatarEnergy.
Our take: The announcement highlights the confidence both companies have in petrochemical demand throughout the energy
transition. It also provides an outlet for Chevron’s growing NGL production from the Permian which we forecast to be 210 kboe/d
by 2030. Our Chevron corporate report highlights how the company’s Permian position is less integrated than rival ExxonMobil.
This project will help narrow the gap between the two.
But ExxonMobil still maintains an advantage when it comes to downstream emissions. Chevron’s net zero target only applies to
upstream emissions, whereas ExxonMobil’s net zero target is corporate-wide. The project references a plan to achieve 25%
lower GHG emissions compared with similar projects in the US and Europe. This is certainly a good start – but Chevron may
soon be pressured to take it a step further.
Strategy update: Santos 2022 Investor Briefing
Andrew Harwood, 14 November 2022
Wood Mackenzie attended Santos' latest investor briefing in Adelaide, where the Australian LNG operator unveiled a refreshed
corporate strategy. This included the roll-out of its Santos Energy Solutions division, providing greater corporate focus on
long-term decarbonisation and clean fuel ambitions.
But it was visibility on near-term targets that caught investors off-guard, with the market reacting negatively to a production
downgrade and an increase in capital spend in its 2023 guidance. Santos’ shares closed 5% down on the day.
Read our key takeaways of briefing, including our perspective on investor calls to increase shareholder returns amid rising cash
flow and falling gearing.
Ithaca Energy completes London IPO
Greg Roddick, 14 November 2022
The facts: Ithaca Energy has listed on the London stock exchange, raising £262 million (US$305 million) and implying a market
capitalisation of £2.5 billion (US$3 billion). Shares were offered at the bottom of a reported £2.50–2.70/share target range.
Ithaca’s share price closed down 8% on day one of trading. Brent and an index of European oil and gas equities were down
3.1% and 1.9% respectively.
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Ithaca Energy allocated 10.4% of the new shares to investors while erstwhile owner Delek has retained an 89.4% controlling
share. Delek has made 1.5% of additional shares available for any over-allotment. Delek will receive all net proceeds from the
listing.
Our take: an IPO has been part of Delek’s strategic plans for Ithaca for some time. The decision to go-ahead against a
backdrop of uncertainty in global financial markets and a deteriorating economic outlook suggest conditions were as favourable
as they were likely to get. Oil and gas prices remain high and the sector is generating record profits.
Ithaca Energy is the second North Sea E&P to go public this year (Var Energi listed in Oslo back in February) and the first in
London since 2018. However, lower future hydrocarbon demand, price risk and other ESG and energy transition uncertainties
still make oil and gas IPOs an increasingly difficult sell to long-term investors. Other private companies that are considering their
options (possibly NEO Energy and Neptune Energy for example) be watching closely.
Read our Inform for further details, including a valuation and analysis of Ithaca’s portfolio.
US independents Q3 results round up
Dave Clark, Raphael Portela and Alex Beeker, 11 November 2022
The facts: three weeks of US independents Q3 results wrapped up with Occidental this week. We take a look at the aggregated
data for the 37 companies we track, and identify some key emerging trends in the quarter.
Our take: after a record-breaking Q2, aggregate operating cash flow, while still robust, slipped 11% to US$39.7 billion. Despite
that, return of capital surged another 32% to nearly US$20 billion. That came on the heels of a 60% quarter-to-quarter increase
in Q2. The increase reflected a couple of factors – reduced debt paydown (thus more available FCF) and the jump in variable
dividends declared in the previous quarter (when cash flow peaked), but payable in Q3.
Declared variables in Q3 (mostly payable in Q4) were indeed down a bit on average, but surprisingly four of the nine payers
increased their declared disbursements. The more formulaic variables (Pioneer, Devon, Diamondback) were all down – perhaps
illustrating the weakness of that strategy. The thought was that formulaic variables would appeal to investors due to their
transparency and reduced risk of management-driven thesis drift. But they also take a tool out of the hands of management to
keep total dividends less volatile.
Ten companies increased their declared base dividend on the quarter, including three that either initiated or reinstated a
quarterly dividend – Comstock, Permian Resources and SM Energy.
Most of the group raised capex either on Q1 (12 out of 37), Q2 (21) or both (four). In Q3, a majority again increased full-year
guidance (19), but average impact was smaller at 5%. Only three companies have maintained beginning of year budget –
Occidental, Chesapeake and Range Resources. Overall reinvestment rates drifted up mildly in Q3, rising from 33% to 39%.
Aggregate gearing fell for the seventh consecutive quarter, now 26% versus Q2’s 29%. Debt reduction has gone from 36% of
free cash flow usage in Q1, to 29% in Q2, to just 10% in Q3. The sector is rapidly reaching balance sheet targets, which means
FCF is increasingly being used for return of capital. There are now five companies with net cash positive balance sheets, and
another five with net debt/book capital below 15% – a growing trend towards “fortress balance sheets”.
Chat about 2023 picked up this quarter, though we will still have to wait for firm guidance. The general expectation appears to
be for 10-20% inflation impact. The group is roughly evenly split in terms of planned activity increases next year.
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For more thoughts and detail on US independents’ Q3, see our results summary Inform.
Use of free cash flow*
Source: Wood Mackenzie. *Free cash flow is defined as operating cash flow minus capital expenditures. Chart focuses on cash usage and
therefore excludes proceeds from disposals. However, it does account for liability and equity management (i.e., debt and share issuances).
Equinor delays Wisting
Norman Valentine and Greg Roddick, 11 November 2022
The facts: Equinor has postponed a final investment decision (FID) on the 500 mmbbl Wisting project in Norway’s Barents Sea.
Equinor has suggested FID, previously scheduled for late 2022, could now be taken in 2026. Equinor also announced Wisting
cost estimates had increased to NKr 104 billion (US$13 billion), up almost 50% from the previous range of NKr 65-70 billion
(US$8-8.75 billion).
Project partners include Equinor (35%, operator), Aker BP (35%), Petoro (20%) and INPEX Idemitsu Norge (10%).
Our take: a combination of project specific risk, cost inflation and supply chain challenges has scuppered Wisting. The field’s
remote location, shallow reservoir depth, low reservoir temperature, high well count, water injection limits, horizontal drilling and
power from shore all contributed to elevated and rising costs. Capacity challenges in the supplier market and increasing lead
times from fabrication yards put project execution at risk.
Equinor’s medium-term upstream trajectory is now in question. The company had aimed to sustain oil and gas output to at least
2030 but push-back on one of its largest greenfield projects threatens that ambition.
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While much of this decision was related to Norway-specific bottlenecks, delays to FIDs on other important greenfield projects
such as BM-C-33 (Brazil), Rosebank (UK) and Bay Du Nord (East Coast Canada) could now be more likely, putting post-2025
output at risk.
In total, yet-to-be-sanctioned conventional developments, including Wisting, contributed 350,000 b/d to our base case estimate
of Equinor’s 2030 production, one of the biggest exposures to new projects among the Majors. Equinor’s management will now
be under pressure to provide revised upstream investment and growth goals at its capital markets day in February next year.
For further analysis of Wisting project economics and the impact of the postponement to Aker BP and Norway, please see our
Inform.
Iberdrola’s CMD 2022 shifts emphasis towards regulated assets
Akif Chaudhry and Norman Valentine, 11 November 2022
The facts: Iberdrola presented its latest strategic outlook at its Capital Markets Day (CMD) 2022. This included an updated
investment plan with details on capital allocation.
Iberdrola plans to make organic investments of around EUR36 billion over 2023-2025 and EUR65-75 billion in 2026-2030.
Over the next 3 years, organic capital spend of around EUR17 billion is earmarked for renewables and EUR16 billion for
networks.
Our take: Iberdrola’s CMD 2022 was a lean towards the steadier, more traditional utility-type business model.
Global energy markets continue to be defined by the war in Ukraine, regulatory risk, inflationary pressures, supply chain issues
and the need to decarbonise power markets whilst returns from renewables generation are under significant pressure.
Against this backdrop, management was at pains to point out that protecting the solidity of the balance sheet was key. They
stated that being prudent was the right tact in a market awash with ongoing uncertainty.
This view clearly underpinned a notable shift in emphasis between Iberdrola’s two main businesses over the near-term.
The outlook for the networks' asset base was increased from the CMD 2020 view. Conversely, expectations for renewables
capacity were pared back as EUR3 billion of capital spend across 2023-2025 was shaved off the previous CMD outlook.
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Renewables installed capacity outlook CMD 2022 vs Networks asset base outlook CMD 2022 vs CMD
CMD 2020
2020
Renewables will continue to be a key part in Iberdrola’s growth story. Under its latest plan, the company's renewable generation
capacity is still expected to double by 2030 from current levels.
But the approach towards renewables in this period will be more conservative, with growth coming through “selective
investment”. Offshore wind will receive the lion’s share of spend, focused on four core markets: US, UK, France and Germany.
We think developers will need to take increased risk across the portfolio to boost returns from renewable generation assets from
current subdued levels. The playbook includes actions such as more merchant price exposure, power trading, and building
power-to-x projects.
The regulated networks business is still a way to play the energy transition given the huge upgrades required to transmission
and distribution grids. Crucially, it also provides greater visibility on revenues and returns to which Iberdrola is more
accustomed.
Brookfield and EIG propose US$12 billion Origin Energy takeover
Andrew Harwood, 10 November 2022
The facts: a consortium of Brookfield Asset Management and MidOcean Energy has moved to buy Australian utility and LNG
exporter Origin Energy. The consortium has offered AUD9.00 per share, implying an enterprise value of AUD18.4 billion (US$12
billion). The offer price is a 55% premium over the 9 November closing price of AUD5.81 per share. The Origin Board has
recommended the deal to shareholders, but it will require ACCC & FIRB approvals.
Post completion, Brookfield would acquire Origin’s Energy Markets business, with MidOcean, backed by private equity player
EIG, taking on the Integrated Gas business, where most of the value sits in a 27.5% share in the APLNG project.
Read our insight for our take on what this endgame means for Origin's shareholders and why private equity players Brookfield
and EIG are committing billions to Australia's east coast gas market.
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Chevron to explore hydrogen opportunities in US and Asia Pacific
Alex Beeker, 10 November 2022
The facts: Chevron New Energies and JERA (a 50-50 joint venture between Tokyo Electric Power Company and Chubu
Electric Power) are collaborating on multiple low carbon opportunities – including production, CCUS, and new technology
commercialization – focused on the US and Asia Pacific regions.
Chevron and JERA will study liquid organic hydrogen carriers (LOHC) in the US, which has the potential to enable efficient
hydrogen transport and long duration energy storage applications. Both companies have both invested in Hydrogenious LOHC
Technologies and the partnership will conduct a feasibility study expected to be completed in 2023.
Our take: Chevron brings a wealth of knowledge and experience around LNG and CCS to this partnership. Hydrogen is a core
part of Chevron’s strategy to help decarbonize hard-to-abate sectors of the economy. But CCUS and renewable fuels have
received much more attention and investment since the company unveiled its energy transition strategy in September 2021.
Chevron has repeatedly emphasized the importance of partnerships and technology to reaching its lower carbon goals. This
announcement hits on both points. LOHC can essentially use hydrogen as a battery to deliver lower carbon energy on demand.
Wood Mackenzie forecasts hydrogen demand to double, from 110 Mt in 2020 to 212 Mt in 2050 in our base case. In a 1.5
degree world, hydrogen production could grow almost five times to 529 Mt.
CNOOC-ConocoPhillips dip toes in water with floating wind pilot
Kavita Jadhav, Yuqi Hu and Dave Clark, 10 November 2022
The facts: CNOOC Ltd. (CNL) and ConocoPhillips have signed an agreement to jointly invest in a floating wind project. The
Penglai floating wind pilot project will have capacity of 34 MW and meet 30% of the power demand of the Penglai oil field in
China. The companies did not provide details on project timelines and emissions reductions.
Our take: CNL marked a first step in floating wind and upstream electrification last year, when it announced the 6.25 MW
Wenchang floating wind project, to supply power to the Wenchang oil complex.
This second announcement is a step-up from the previous wind project on capacity and demonstrates CNL’s commitment to the
model of using renewable power for upstream electrification, to decarbonise its oil and gas operations. It is also in line with
CNL’s strategy to leverage marine expertise gained from its upstream business to grow an offshore wind position. This strategy
of multiple smaller-scale pilot projects is well suited to floating wind, which is an emerging technology with limited scale and
deployment, compared to conventional fixed-bottom technology.
And, notably, this is CNL’s first energy transition investment with an IOC which could evolve further. Both companies have said
they are evaluating opportunities for power from shore and CCS at the Penglai field.
For ConocoPhillips this marks a second toe in the water this year with offshore wind. In June, Equinor, along with its partners at
the Troll and Oseberg fields (ConocoPhillips, TotalEnergies, Shell, Petoro), announced the Trollvind project, a 1 GW floating
wind farm that will power those mature fields as well as deliver electricity for Norwegian domestic use. The partners expect FID
for Trollvind in 2023, with start up in 2027. ConocoPhillips is still trying to find its energy transition strategy, and these types of
partner-driven projects are a low-risk way to build experience in the nascent offshore wind sector.
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ExxonMobil reopens Kizomba treasure chest
Liam Yates, 8 November 2022
The facts: ExxonMobil has made a near-field oil discovery with its Bavuca South-1 exploration well, drilled by the Valaris DS-9
rig in August and September. It encountered 30 metres of “high-quality” hydrocarbon-bearing sandstones. No volumes were
announced.
Our take: Bavuca South is the first discovery on Block 15 since 2003 and the eighteenth in total. We estimate recoverable
volumes of nearly 50 million barrels.
The area is not shy of more recent exploration success. Eni has discovered several billion barrels of oil on the relinquished
areas of Block 15: its prolific Block 15/06. For ExxonMobil, returning to near-field targets on Block 15 is a no brainer in such a
prolific basin.
ExxonMobil’s redevelopment programme aims to add 40,000 b/d of incremental production at Kizomba B, through infill drilling
and debottlenecking. We’d expect Bavuca South to be tied-back to the FPSO, located 15 kilometres to the southeast. We can
expect a swift development given the 2032 licence expiry, using subsea wells and a manifold.
US Independent earnings week 2 (out of 3)
Dave Clark, Alex Beeker, Raphael Portela, 6 November 2022
The facts: Another 22 US independent E&Ps reported earnings last week, including many of the large-cap oil-focused names.
Due to the way the calendar fell this year, Q3 earnings season spanned three weeks rather than two, and we will publish our
quarterly summary Inform after the final round of companies (including Oxy, Diamondback, Comstock and Ovintiv) report this
week. Below we highlight some interesting takeaways from week 2.
Our take: After only one company raised 2022 budget in week 1 (out of eight), we were wondering if the sector had built
sufficient cushion into its Q1 and Q2 capex guidance increases to absorb the inflationary pressure we have seen in H2. Week
two disabused us of that notion – another 15 companies boosted 2022 capex by an average of 6%. ConocoPhillips increased its
budget for the second time this year (US$7.8 billion to US$8.1 billion). Three companies also decreased their guidance – EQT,
Chord Energy and Civitas.
Several companies gave an early view on 2023 budgets. APA sees a 15% increase, mostly driven by activity. EOG plans to add
2-3 rigs in 2023. There seems to be a consensus that inflation will impact budgets in the 10-20% range. Chesapeake struck a
pretty bearish tone on 2023 and announced they will drop one rig – they see a better picture for 2024 and will fluctuate between
5-8 rigs in the Haynesville going forward, which yields double-digit growth at the high end.
ConocoPhillips became just the third company to reach the “1 Mboe/d Club” in the Lower 48 in Q3 (1,013 kboe/d), joining
ExxonMobil and EQT (post-Tug Hill close). Two others are over 900 kboe/d and growing – Chevron (~969 kboe/d in Q3) and
EOG (919 kboe/d in Q3).
Sector-wide aggregate net debt/book capital is now about 24%. The group began the year at 35%, and Q2 2022 aggregate was
about 28%. Numerous companies are pivoting to return-of-capital mode as they arrive at leverage targets. Murphy, for example,
expects to reach its debt reduction target by year-end, which will trigger the start-up of a major buyback program (25% of
adjusted free cash flow). Nine companies have net debt/book capital below 15%, and five now have net cash-positive balance
sheets.
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EOG announced a 395k net acres position in the Utica (primarily in the liquids window). The company has completed four wells
across a 140-mile trend. Management did not provide granular cost/production metrics but said one well had an IP of 2,500
boe/d for “multiple weeks” (i.e., not a 30-day rate). High mineral ownership across the southern part of its position will boost
returns.
Civitas now includes a line in its cash flow statement for “purchase of carbon offsets” – they have spent US$7.2 million year-todate through Q3. Could we see other companies using offsets as part of their energy transition strategy follow suit?
Ørsted Q3 earnings buoyed by conventional assets
Akif Chaudhry and Norman Valentine, 4 November 2022
The facts: Ørsted reported underlying EBITDA of DKK3 billion (c.US$ 0.4 billion), in line with the same period last year. Gains
from the 50% farm-down of Hornsea 2 offshore wind farm in the UK elevated headline EBITDA to DKK12 billion (c.US$1.6
billion).
Results were once again buoyed by CHP plants exposed to high European power prices. Onshore renewables earnings also
doubled due to generation from new assets and merchant exposure in the US and Europe. Offshore wind hedging woes again
produced a now familiar drag on earnings.
EBITDA guidance for 2022 was increased by 5% to DKK21-23 billion (US$2.8-3 billion), excluding the impact of farm-downs,
largely to reflect the strong performance of the conventional generation business.
Our take: it was another quarter and another hit for Ørsted’s offshore wind business from overhedging. The culprit this time was
lower than expected wind speeds. With financial hedging for expected offshore wind generation close to 100% through next
year, there is a risk of the same story in coming quarters. The company will now review its hedging framework.
Inflationary and supply chain pressures are intensifying. US offshore wind assets in the northeast, such as Ocean Wind, that
have been awarded a subsidy scheme but not yet taken FID are most vulnerable within Ørsted’s near-term portfolio. New
projects will need to maximise unit revenues to make acceptable returns.
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The onshore business performed well, evidence that Ørsted’s diversification strategy is paying off. Performance was enhanced
by merchant pricing capture through project build phases. PPAs do not kick-in until commissioning. Other companies will take
advantage in the same way.
The rising interest rate environment is a growing challenge for Ørsted. It does not use project finance but raises debt at the
portfolio level. Of note is the heightened near-term liquidity impact, and bearing on net debt, from higher initial collateral and
variation margin requirements of hedged positions. Ørsted had DKK31 billion (c.US$4 billion) tied up at end-Q3, with more than
half posted in Q3. This compares to net debt of DKK46 billion (c.US$6 billion). Although prices are starting to soften, financing
costs will rise.
Marathon buys Ensign Eagle Ford assets
Dave Clark, 3 November 2022
The facts: Marathon Oil announced the acquisition of the Eagle Ford assets of PE-backed Ensign Natural Resources for a total
compensation of US$3.0 billion. The all-cash deal adds 130,000 net acres (with 97% working interest) in a key basin for
Marathon, along with about 67 kboe/d of existing production. The Eagle Ford will now move past the Bakken as the company’s
largest asset. The transaction is expected to close by year-end.
Our take: Among the large-cap oil-focused US independents, MRO stock has risen 80% over the last 12 months, second only
to Occidental (+110%), a clear sign that the market endorses the company’s highly restrained capital program (reinvestment
rate of just 26% YTD) and robust return of capital framework (minimum 40% of adjusted OCF, over 50% in 2022).
There have been market concerns, however, regarding the depth of economic inventory in the portfolio, and so this accretive
deal, which adds about 600 undrilled locations, will likely quiet that unease for now. The company believes that current
production on the acquired acreage can be maintained with a one-rig program.
The EV/EBITDA multiple for the deal (3.4x estimated 2023 at US$81 WTI) is higher than the 2.0-2.5x we have seen for a few
recent “bolt-on” type deals, though it is value-accretive to MRO’s current consensus 4.5x forward multiple. Interestingly,
Marathon doesn’t call this a “bolt-on” acquisition, despite the adjacent acreage in an important basin, unlike other recent similar
deals. Marathon emphasized that the deal valuation did not factor in any synergies or upside potential for redevelopment of the
existing 700 wells, the majority of which were completed pre-2015.
Marathon highlights that the acquisition will boost operating cash flow by about 17%, and free cash flow by 15%, and
announced an 11% increase to the quarterly base dividend (to US$0.10/share, yield of about 1.3%) once the deal closes.
Overall return of capital should rise by about the same percentage as operating cash flow, as the company reiterated its capital
return framework of 40%+ distributions in a US$60/bbl WTI environment.
Read our detailed Inform and stay tuned for an in-depth Deal Insight covering our valuation of the acreage.
Oxy acquires land and pore space for CO2 capture and storage
Zoe Sutherland, 2 November 2022
The facts: Oxy, its subsidiary 1Point5 and partner King Ranch have announced a lease agreement for 106,000 acres in south
Texas, near Corpus Christi, which will support large-scale Direct Air Capture (DAC). The land has potential for enough DAC
facilities to remove 30 Mtpa of CO2 a year and has pore space to store up to 3 billion tpa of CO2 in geological reservoirs.
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The location near Corpus Christi means it will also be able to store CO2 captured from industrial emitters in the Gulf Coast
region.
Our take: Oxy has plans to be net zero from Scope 1,2 & 3 emissions by 2050, with a large DAC business central to reaching
this goal. It sees potential to have as many as 70 DAC facilities in operation by 2035. Its first is currently under construction in
the Permian, with start-up slated for 2024.
However, there are challenges, most notably the cost of this form of carbon capture. Oxy estimates a carbon abatement cost of
US$250/t for DAC today, making it a lower cost solution for only the hardest to decarbonize industries where abatement cost run
as high as US$1,000/t.
Oxy has made tangible progress this year towards establishing its CCS business. In addition to this deal, it has also moved
closer to establishing a network of storage hubs for point source emitters. In July, its Low Carbon Ventures subsidiary
1PointFive acquired pore space in Western Louisiana to develop and operate a carbon sequestration hub. This was followed in
October by an agreement with midstream player Western Midstream Partners (WES} which will see the companies cooperate to
provide CO2 transportation and storage solutions.
Aramco posts record cash flow from higher prices and volumes
Kavita Jadhav and Yuqi Hu, 2 November 2022
The facts: Saudi Aramco’s Q3 net income increased by 39% year-on-year to US$42.4 billion, mainly driven by higher realised
oil prices, higher refining margins and demand. Q3 production was 14.4 million boe/d, up from 13.6 million boe/d in Q2 and 13
million boe/d in Q1.
Aramco reported a record free cash flow of US$45.0 billion versus US$34.6 billion in the last quarter. Capital expenditure
increased by 19% y-o-y to US$9.0 billion in Q3 2022. Gearing fell to minus 4.1%, down from 12% at the end of 2021. Aramco
maintained its quarterly dividend at US$18.8 billion.
Our take: Aramco’s reported net income, while higher year on year, was lower than its record second quarter. Net income was
partially offset by increased production royalties, resulting from stronger crude oil prices and higher sales volume. Tax and
royalties for Q3 were US$38.2 billion, an increase of 46% compared to US$26.2 billion for Q3 2021.
Record quarterly cash flow, due to strong earnings and favourable working capital movements, put Aramco in a net cash
position at the end of Q3. Strong finances supported investment. Upstream capital expenditure increased 25% y-o-y in support
of increased development activity for crude oil increments and gas projects. Downstream capital spend remained relatively flat.
In the quarter, Aramco received the world’s first independent certification recognising the production of blue ammonia and
hydrogen, where a significant amount of the CO2 associated with the manufacture was captured and utilized instead of emitted.
This milestone is an important step towards the company’s target to produce up to 11 million tons of blue ammonia annually by
2030.
Equinor expands in European solar with BeGreen acquisition
Norman Valentine, 2 November 2022
The facts: Equinor has agreed to buy BeGreen, a Denmark-based, European solar developer. BeGreen has approximately 300
MW of operational capacity and a 6 GW project pipeline of early to medium stage solar developments, mainly in Denmark but
also in Sweden and Poland.
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A consideration was not disclosed but Equinor has stated it expects to make a 4-8% real return on the deal, including the
acquisition price.
Our take: this is another step in the expansion of Equinor’s European renewables business following the US$117 million
acquisition of Polish solar developer Wento in 2021. It further diversifies the company’s offshore wind-weighted renewables
portfolio, adding scale to existing solar positions in Europe and Latin America.
The deal is aligned with Equinor’s strategy of acquiring operational control of early-life renewables positions. We estimate the
deal brings Equinor’s net renewables capacity potential to around 16 GW, aligned with the its target of 12-16 GW of net capacity
by 2030.
The acquisition goes some way towards making up ground that Equinor has lost to its European rivals in renewables business
development over the last year. The stage could now be set for another upgrade in Equinor’s new energy growth targets at its
capital markets update in February 2023. Further growth-orientated renewables deals could follow next year.
For more on Equinor’s new energy business, see our Equinor Corporate New Energy profile
BP Q3 reported results
Luke Parker, 1 November 2022
BP rounded out Q3 reporting season for the Majors with another strong set of results. Earnings beat sell-side expectations for
the seventh quarter in a row, underpinned this time by an "exceptional" contribution from gas trading. BP held the dividend flat
and committed to repurchase another US$2.5 billion of shares in Q4. The results call was a terse affair, with no updates to
guidance or strategy.
See our Reported results analysis for more on BP's exceptional trading result and the outlook for shareholder distributions.
Brazil’s president-elect to shake things up in Petrobras
Raphael Portela, 31 October 2022
The facts: Lula is returning to Brazil’s presidency after a tight run-off race this Sunday. The Brazilian politician and trade
unionist is part of the left-wing Workers' Party (PT). Petrobras’ share price was down 7% on the news. The company reports Q3
earnings this Friday.
Our take: With the Brazilian government as its controlling shareholder, Petrobras will be impacted by the change in
administration. It is hard to ascertain how much of the rhetoric – marked by lowering oil prices, reinvesting in refining, and
pivoting into new energies – will be toned down or which points will be pursued with conviction. But we expect a few key themes
to take centre stage in the coming months:
•
Import price parity: the president-elect has vehemently criticized the alignment with international benchmarks. But internal
governance and compliance controls strengthened after the Car Wash scandal proved resilient to government meddling –
even President Bolsonaro could not bypass them when oil prices soared earlier this year. Still, those controls are not set in
stone and, under a longer time horizon, could be modified.
•
M&A: divestments are at a high risk of being scrapped. Though assets currently on sale span all verticals, the remaining bigticket items are refineries, a sector that is already politically charged. We think that it is unlikely these will go through, if not
directly because of a change in company stance, then because of shrinking appetite from risk-averse buyers.
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Corporate week in brief
•
ESG: Petrobras’ recent transformation into an upstream-heavy company has meant a strong focus on decarbonization. But
Lula has indicated that it would like the NOC to have a more active role in new energies. We believe this will likely translate
into tangible corporate action over the next few years, though we do not expect any change in its upcoming business plan (to
be announced in late-November).
Euro Majors Q3 2022 results round-up
Greig Aitken, Luke Parker, Tom Ellacott, Norman Valentine, 31 October 2022
The facts: Eni, Equinor, Shell, TotalEnergies and Repsol reported strong Q3 results last week. BP reports its Q3 results on
Tuesday 1 November.
Our take: the sector delivered as expected: earnings remained stellar, albeit most fell short of the Q2 high; falling refining
margins impacted downstream; and gas generally had a better quarter than oil. There are some headwinds in the form of
additional taxes and production struggles. But balance sheets are rock solid and shareholders are the prime beneficiaries of
surging cash flows.
Eni: Another bumper quarter saw Eni deliver adjusted earnings of €3.7 billion – only fractionally below Q2's multi-year high
point. Global Gas & LNG Portfolio was the standout segment as Eni exploited geographical and timing differences in gas prices.
Eni’s variable distribution system means enhanced shareholder rewards were already mapped out for the year. Gearing
dropped to 10%, though this will rise again through the year end due to buybacks and windfall tax. Full year oil and gas
production expectations were edged down again.
Equinor: beat analyst expectations and delivered another record quarterly result. Adjusted third quarter earnings hit US$6.7
billion, supported by sky-high European gas prices and strong Norway gas output. Equinor again opted to reward shareholders;
distributions for the full year were increased by 5% to US$13.7 billion. But the company stressed caution against a background
of gas price volatility, macro uncertainty and operational challenges. Tax payments drew down on Equinor’s net cash position;
gearing now stands at -19%. Full-year underlying production growth estimate was revised down from 2% to 1%.
Shell: eyewatering underlying profits of US$9.2 billion came in ahead of analyst expectations but were down on the record
posted in Q2. Weaker refining and chemicals margins and “significantly lower” LNG trading results were the culprits. While the
numbers are always shrouded in secrecy, it seems that LNG trading might have made a (rare) loss in Q3. Net debt crept up,
taking gearing to 20% (including leases). Shell committed to repurchase another US$4 billion of shares in Q4 and intends to
boost the dividend by 15%. This year is set to surpass 2019 as a record year for shareholder pay-outs. There was no new
guidance or updates to strategy.
TotalEnergies: another write-down of US$3.1 billion in Russia hit net income but TotalEnergies still notched up its secondhighest quarterly result ever, supported by a stellar quarter for LNG and a strong trading performance. Operating cash flow hit a
new quarterly high of US$18 billion. Gearing fell from 10% to 4% – below the company's 5% guidance for year end. This is
despite its commercial renewables capacity increasing 18% to 45 GW in Q3. But there are headwinds. The EU solidarity tax is
expected to cause a one-off US$1 billion hit. And the full year production target of 2% growth looks at risk after production
slipped 5% year-on-year in Q3.
Repsol: shares jumped 4.9% on a good set of results. Operating cash flow surged 122% year-on-year to €3.2 billion, a level
only surpassed in Q4 2008. Gearing fell ten percentage points to 7%. Repsol sweetened the strong financials by expanding its
buyback programme and increasing its dividend for 2023 by 11%. However, oil and gas production continues to underperform
expectations – full year volumes are now expected to come in 8% below initial guidance of 600 kboe/d.
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CNOOC shines on upstream, PetroChina and Sinopec held back by
downstream
Yuqi Hu and Kavita Jadhav, 31 October 2022
The facts: Q3 net income increased by 89% for CNOOC Ltd. (CNL) and 71% for PetroChina. Sinopec Corp (Sinopec) saw a
decrease of 38% y-o-y.
Our take: Upstream continued to benefit from high commodity prices - year-to-date upstream operating profit increased 138%
y-o-y for PetroChina, 401% for Sinopec and 106% for CNOOC. As state-owned companies, PetroChina and Sinopec are
subject to regulatory price controls during periods of high commodity prices. The natural gas and downstream businesses were
impacted by this.
The operating profit of PetroChina’s natural gas marketing business was down by 57% due to higher importing gas prices and
regulatory price controls that do not allow full passthrough. Downstream performance, particularly the chemicals business, was
impacted by lower domestic demand, lower margins, higher inventories, and higher material costs.
For the nine months, realised operating profits for PetroChina’s chemicals segment were down by 102% y-o-y. Sinopec saw a yo-y decrease across the downstream, with operating profits in refining of US$3.13 billion (-61% y-o-y), marketing of US$3.17
billion (-6% y-o-y) and a loss in chemicals of US$0.61 billion (-125% y-o-y).
•
Production: CNOOC’s Q3 production increased by 9%, PetroChina’s by 4%, and Sinopec Corp’s by 1% y-o-y. The three
Chinese NOCs continued to increase gas production, with 2022 gas production up by 17% for CNOOC, 6% for PetroChina,
and 2% for Sinopec. Due to weaker domestic demand, PetroChina and Sinopec continued to see lower refining throughput in
Q3.
•
Capex: First three quarters’ spending accounted for 65% of the full-year target for PetroChina, 53% for Sinopec and 72% for
CNOOC. Full-year capex guidance was maintained.
•
Opex: The companies have controlled lifting costs quite effectively, with a 2-3% increase y-o-y, though all three face rising
costs in material, power and other operating expenses.
•
Shareholder returns: Sinopec’s board executed its first-ever share buyback program in both the A and H markets by
repurchasing RMB100 million in the A market and RMB47 million in the H market. Sinopec plans to spend RMB1.25-2.5
billion for the A-share buyback.
Chevron and ExxonMobil set quarterly cash flow records
Alex Beeker and Tom Ellacott, 28 October 2022
The facts: ExxonMobil Q3 earnings broke the previous record set last quarter. Chevron earnings declined 5% vs Q2 because of
lower refinery throughput and tighter downstream margins. Share prices of both companies were up modestly on the day with
ExxonMobil outperforming.
Chevron’s downstream earnings were a small blemish on an otherwise stellar quarter. Impressively, upstream outperformed
despite q/q declines in liquids realizations.
The balance sheet and buybacks are benefiting from the improved results. Gearing fell meaningfully during the quarter – now
5% for Chevron and 7% for ExxonMobil. ExxonMobil raised its dividend 4% during the quarter but both companies left buyback
guidance unchanged.
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Corporate week in brief
Our take: improved earnings were impressive considering the q/q decline in oil prices. Shares of both companies traded higher
on a day when Brent prices were down.
In the Permian, production growth has proven harder to come by this year. Chevron is tracking at the low end of its 700-750
kboe/d annual guidance, which would represent 15% y/y growth. ExxonMobil is growing a touch faster at 20% this year, albeit
from a lower base. Both companies acknowledged cost inflation will continue into 2023.
Cash is building on the balance sheet for now – US$15 billion for Chevron and US$30 billion for ExxonMobil at the end of Q3.
But buyback targets can’t absorb all excess cash flow at current prices. Do we see either company increase new energies
capex guidance? CCS and low emissions fuels were hot topics on both calls. ExxonMobil believes the Inflation Reduction Act
(IRA) has doubled the immediately available carbon capture market. Do we see an acceleration of CCS M&A or project
pipelines?
US Independent Earnings - Week 1 recap
Dave Clark, Rapha Portela, Alex Beeker, 28 October 2022
The facts: The first round of Q3 earnings for US Independents included the five gas-focused Appalachian Basin producers, as
well as oil-focused Hess Corporation, Pioneer Natural Resources and Matador Resources.
Our take: Cash flow remained robust for everyone in Q3, though commodity trends favored the gas names. For the gas
producers, aggregate operating cash flow was about flat sequentially, supported by strong realizations and favorable cash
hedge settlement trends. Conversely, cash flow for the three oil-focused E&Ps slipped 17% quarter-to-quarter, following a
US$15/bbl drop in average WTI from Q2 to Q3. Q3 reinvestment rate for the gas-focused E&Ps remained steady at about 42%.
For the oil-focused names it varied widely – we will get a better picture on that front next week.
Only one of the eight independents increased 2022 capex guidance (Antero, due to inflation and a pad-development pulled
forward from 2023), a stark contrast to the first half of the year, when all but Range bumped budgets higher. Range is one of
only four US E&Ps (out of 38 we track) that has maintained beginning-of-year budget, though it did indicate this quarter that
capex would be at the high-end of its 2022 range. EQT actually lowered capex guidance this quarter due to an infrastructureforced activity reduction.
Hess offered a preliminary 2023 budget with a US$1 billion year-over-year jump to US$3.7 billion (+37%), with increases in
Guyana, the Bakken and the Gulf of Mexico. While no one else was ready to offer concrete plans for 2023, numerous
companies highlighted an expectation for 10-20% service cost inflation, corroborated by non-peer operators like Chevron.
Pioneer also plans for an additional 1-2 rigs and another (e-frac) completion crew, suggesting next year’s budget will be about
$600-700m above their US$3.6-3.8 billion 2022 capex (+18%).
Rapid debt reduction has meant that companies that were (badly) over-levered in the downturn are now pivoting towards return
of capital plans – in particular the gas names. EQT, Antero and Range all added US$1 billion to their repurchase authorizations
in Q3. All five Appalachian producers accelerated buybacks, and Range initiated a base dividend in September.
Mended balance sheets also mean a growing potential buyer pool, and increasing interest in bolt-ons or (in the case of Matador
and the gas-focused names) midstream. Matador has gone from nearly-distressed leverage to 0.2x net debt/EBITDAX in less
than two years, and management commentary on the call regarding (small-scale) M&A was explicitly positive.
As expected, the retreat in oil prices resulted in a substantial quarter-to-quarter drop (about 40%) in the announced variable
dividend for Pioneer (out of ten variable dividend payers, the only one to report this week). At US$4.61/share though, its is well
below the US$6.60/share variable declared for Q1, when average WTI was only a dollar higher than Q3.
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Corporate week in brief
Noteworthy on the energy transition front – Pioneer announced it is participating in two wind and solar projects (combined gross
300 MW) to supply renewable power to operations and to the Texas power grid. The 160MW Concho Valley Solar project (via a
PPA executed by Targa) has started up this month. The 140MW wind facility on Pioneer-owned acreage will be developed by
NextEra and starts up in 2024.
Results from another 30+ US Independents over the next two weeks will shed further light on the issues companies are facing
as we head into the homestretch in 2022
Ørsted and CIP form powerhouse offshore wind partnership in Denmark
Akif Chaudhry and Norman Valentine, 28 October 2022
The facts: Ørsted has formed a 50/50 partnership with Copenhagen Infrastructure Partners (CIP) to develop 5.2 GW of offshore
wind capacity in Denmark.
The partnership covers the development, construction and operation of four large-scale projects and transmission assets. The
projects will be developed using Denmark’s “open-door” scheme and so will sit outside of the usual centralised tender process.
The companies expect merger clearance before the year-end.
Our take: this is a major announcement from the two leading offshore wind developers in Denmark. However, the success of
these planned projects will, in large part, depend on achieving suitable offtake arrangements.
Material capacity additions for Ørsted and Denmark
Ørsted currently has around 11 GW of gross offshore wind capacity installed and under construction. It has a further 11 GW
pending FID, most of which is scheduled to be online by 2027. The four projects planned for development with CIP, also
expected online this decade, would be a giant step towards its 30 GW gross target for 2030.
Denmark is aiming for 12.9 GW of offshore wind capacity in 2030, having recently raised its target from 8.9 GW. With just over 2
GW of installed capacity today, the additional capacity from the new partnership would also be a key contributor to bridging this
gap.
Partnering with the competition
It’s notable that the two leading Danish offshore wind project developers have chosen to partner in their home market. But their
local portfolios differ starkly. Ørsted already has almost 1 GW of gross installed capacity in Denmark. However, CIP has
predominately early-stage development projects.
The decision to partner-up perhaps best reflects the scale of the opportunity as well as the challenging market conditions in
offshore wind, particularly from supply-chain and inflationary pressures.
The two key flag bearers have made a big statement in Denmark’s offshore wind plans with a plan to push ahead in tandem.
Success will keep the companies and Denmark at the leading edge of offshore wind development.
Zero-subsidy and power-to-x
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Corporate week in brief
The projects will be established without subsidy support. Denmark’s open-door scheme allows developers to choose the size
and location of proposed wind farms. Developers initiate the process by submitting an unsolicited application.
Route to market will, therefore, be key to generating suitable returns. This includes electricity supply outside of Denmark. The
companies have also stated there is “large potential” for power-to-x associated with these projects, producing hydrogen and
green fuels.
Further clarity on revenue streams will be a key determinant of success for these projects.
TotalEnergies goes big on Brazilian renewables
Tom Ellacott and Brian Gaylord, 26 October
The facts: TotalEnergies has announced the formation of a JV with Brazilian renewables leader Casa dos Ventos (CDV), split
34% TotalEnergies and 66% CDV.
The JV’s portfolio includes:
•
700 MW of operational onshore wind capacity
•
1 GW of onshore wind under construction
•
8 GW of onshore wind and 1.6 GW of solar under well advanced development (potentially online within the next five years)
The JV will also have the right to acquire current and new projects that CDV will develop in the future. This pipeline currently
amounts to at least 6 GW of capacity.
TotalEnergies will pay US$550 million in cash and up to US$30 million in earn-out to complete the acquisition. The Supermajor
will also have the option to acquire a further 15% stake in the JV after five years.
Our take: this is another landmark renewables deal for TotalEnergies that extends its leadership among the Majors. It has the
potential to replicate the successful partnership that TotalEnergies has struck with Adani Green in India. This has opened up a
range of opportunities, including in renewable hydrogen.
We think the unit valuation metrics look reasonable for transactions in Brazil. TotalEnergies is playing US$1.0 million per MW of
operational and under construction capacity and US$0.3 million per MW of pipeline capacity in advanced development.
In any case, US$580 million is small change relative to the US$42 billion of operating cash flow TotalEnergies has generated in
the first three quarters of 2022. That’s especially true given the strategic significance of this move.
TotalEnergies will acquire a leading position in a renewables market with huge potential. The company is aligning itself with the
most important wind developer in Brazil by far: CDV has delivered one-quarter of the wind projects in operation in the country.
We expect CDV to continue to expand its pipeline, fuelling further growth for the JV.
CDV also has extensive experience in arranging PPAs with commercial and industrial clients. Corporate PPAs are now the
major market driver of both wind and PV development in Brazil; and an area of increasing expertise for TotalEnergies.
TotalEnergies also brings its trading capabilities to the Brazilian merchant market and its strong balance sheet will improve the
JV's cost of financing.
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Corporate week in brief
Green hydrogen is the icing on the cake. Sustaining Brazilian annual renewable additions will require support from GW-scale
hybrid onshore wind/PV green hydrogen projects. TotalEnergies will see this as an exciting opportunity given its plans to
dramatically scale-up its hydrogen business next decade.
Wintershall Dea acquires stake in offshore Mexico field
Zoe Sutherland, 26 October
The facts: Wintershall Dea has acquired a 37% non-operating stake in the shallow water Hokchi block offshore Mexico, with the
option to increase its share to 40% at a later stage. The Hokchi field came onstream in 2020 and produces around 26,000
boe/d. Production is expected to reach 37,000 boe/d in 2023. The price paid has not been announced but we value a 37% stake
in the field at US$385 million.
Our take: Wintershall already has a presence in Mexico through the producing field Ogarrioa and a share in the proposed Zama
development. It also holds several exploration blocks and has been actively exploring. It made two discoveries in 2020, Polok
and Chinwol.
The company has been keen to expand its presence outside of Russia, which currently accounts for roughly half of its
production and 44% of its remaining value. Its Q3 earnings suffered as it still cannot repatriate earning from the region.
The Hokchi field is a growth asset and will be a welcome addition to Wintershall Dea’s portfolio, boosting its production from
Mexico to 14,000 boe/d, from the current 4,000 boe/d.
The Majors’ Q3 results preview
Tom Ellacott, Norman Valentine and Greig Aitken, 24 October 2022
The facts: the Majors’ Q3 results season kicks off this week with Shell, TotalEnergies, Equinor, Eni and the US Majors
reporting. BP reports next week.
Our take: earnings and cash flow will fall short of the record highs of Q2. Much weaker margins will hit chemicals hard and
refining margins will be down sharply quarter-on-quarter (although still very high). Gas is set to have a better quarter than oil in
the E&P results.
The Majors may strike a more cautious tone in their earnings calls. But they will still deliver a strong set of financials, including
impressive year-on-year comparisons and potentially a record quarter for shareholder distributions.
Buybacks may surpass previous peaks as programmes ramp up. Variable dividends could also be a theme now that
TotalEnergies has followed Equinor’s lead and recently introduced a special dividend in its2022 Strategy and Update. We think
that the other Supermajors will stick with base dividends and buybacks in allocating cash to shareholders.
Deleveraging will continue in another quarter of ultra-low reinvestment rates. The Majors will also stress the need to beef up
financial resilience as economic headwinds blow stronger. More players will edge closer to joining Equinor with net cash-positive
balance sheets. Both Chevron and Shell ended Q2 with 8% gearing and TotalEnergies is targeting zero net debt by the middle
of next year.
We’ll be looking for some colour on 2023 investment plans. TotalEnergies has set a marker in the sand with its recent
announcement of an 8% to 12% increase in its net investment range. Will other Majors follow its lead as inflationary pressures
build?
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Corporate week in brief
New energies M&A will also be under the spotlight following BP’s announcement of the US$4.1 billion acquisition of biogas
player Archaea Energy. Watch out for signs of a growing appetite for more transformative inorganic growth.
Quarterly prices and margins comparison
US Independents' Q3 2022 earnings preview
Robert Polk, David Clark, Raphael Portela, Alex Beeker, 21 October 2022
The facts: Q3 earnings season begins next week for the US independents, with the focus of week 1 largely on the Appalachian
gas producers (Range Resources kicks it off on Tuesday), though Hess and Pioneer Natural Resources will provide some initial
oil-focused data points as well. For the following week we count at least 21 E&Ps on the calendar.
Our take: US Independents have enjoyed eight straight quarters of rising commodity prices following the depths of H1 2020.
Each quarter since mid-2021 has generated a new record for group free cash flow as a result. Q3 results, however, will reflect
lower price realizations, particularly on the oil side. The tandem of lower prices and persistent cost pressures will likely mean
free cash flow, while still healthy, falls sequentially for the first time in two years.
One impact will be that formulaic variable dividends will trend down. Aggregate variable dividends to date have only gone up
since the framework was adopted by about a quarter of the US Independents, starting in Q3 2021. Companies and investors
know this inflection is coming, but the event will still be a reminder that variable return of capital can cut in both directions.
Share repurchase activity represents another wildcard. Cash flow will be down, but still robust. A slide in commodity prices
coupled with recession fears has pushed what management teams already felt were discounted valuations down further. The
opportunity to more aggressively lean into buybacks exists, but retaining extra liquidity is the more cautious route.
Flat to modest production growth from the US Independents will continue. This has likely been the plan behind the scenes, but
concern about a global recession should solidify continued discipline, even as there are public calls for more production. We
anticipate a bit of discussion on 2023 activity levels (Diamondback, Antero and Laredo provided some early guidance at this
point last year), but do not expect much detail on spending plans yet.
Cost inflation continues to be front of mind. Producers are hard at work procuring equipment and labor for 2023, but the oilfield
service market remains very tight. A couple of companies have pre-announced production misses in Q3 driven by supply chain
issues. The hope that supply chain constraints would be eased by 2023 appears to have been optimistic.
LNG remains a dominant theme, and sector forerunners ConocoPhillips and Devon Energy announced equity investments (nonbinding HoAs) with corresponding supply and offtake agreements in LNG facilities in the last quarter. Gas behemoth EQT
continues to discuss potential equity investments. Capturing greater exposure to the LNG value chain is a theme we expect to
continue to be front of mind during Q3 earnings.
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Material M&A to continue after bumper end to Q3?
Scott Walker, 21 October 2022
The facts: it’s been reported that Equinor is considering buying CNOOC Ltd's UK North Sea assets and that OMV has received
an unsolicited bid for 51% of its upstream business (excluding Romania and Russia), from a consortium of buyers that initially
included Aker, Trafigura and Bluewater (Aker is said to have since pulled out).
Our take: we highlighted in our Q3 M&A summary that September recorded the highest number of larger deals in over five
years. Brent falling from its highs of US$130/bbl has played a part, allowing better alignment between buyers and sellers on
price. Differentiated strategies and views of the future are adding further momentum to the upstream M&A market, feeding the
deal pipeline for a growing pool of cash-rich buyers.
Equinor’s proposed acquisition from CNOOC is a case in point. A reported price tag of between US$2-$3 billion for the CNOOC
package would be the most any Major has paid for upstream assets since 2019.
The UK North Sea is no longer strategic for CNOOC but it remains a core province for Equinor. Sitting on US$11 billion of net
cash, material bolt-on deals make sense. A deal would see it acquire cash generative assets with the added benefit of tax
synergies, which would allow the Major the realise value that is greater than the sum of the parts.
The consortium of buyers interested in OMV’s portfolio will also be backing themselves to be on the right side of the oil price bet.
The unsolicited bid that would reportedly come at a cost of between US$5.5-$7.0 billion has been well targeted. With OMV
guiding to exit upstream by 2050, a material disposal now would signal credible intent at what could be a high point in the
commodity price cycle.
Chevron joins partners to pursue hydrogen project at US Gulf Coast
Alex Beeker, 21 October 2022
The facts: Chevron announced its intent to collaborate on a joint study with Air Liquide, LyondellBasell and Uniper SE that will
evaluate and potentially advance the development of a hydrogen and ammonia production facility along the US Gulf Coast.
The consortium will assess the potential for producing hydrogen using natural gas with CCS and renewable hydrogen via
electrolysis to supply end-use markets including the ammonia, petrochemicals, power and mobility markets.
Our take: this announcement drills home the importance of diversification and high-quality partnerships to Chevron’s energy
transition strategy. It’s a move that should be commended. Chevron realizes it’s entering completely new areas and it can’t do it
alone.
Chevron currently produces ~1.3 bcfd of natural gas in the Permian growing to 2.0 bcfd by 2030. Rival, ExxonMobil has
maintained an edge in the basin since last December when it announced a Permian net zero target (Scope 1 & 2). Chevron has
surprisingly not yet followed with its own Permian net zero target – but could it be setting its sights on something bigger? Blue
hydrogen production at the US Gulf Coast, presumably supplied via Permian natural gas, could allow the company to start
addressing Scope 3 emissions, which would be a first for either US Major.
BP accelerates biogas expansion with US$4.1 billion US acquisition
Tom Ellacott, 21 October 2022
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Corporate week in brief
The facts: BP has announced the acquisition of landfill-focused renewable natural gas (RNG) producer Archaea Energy for
US$4.1 billion. The consideration of US$26/share is a 38% premium to Archaea’s 30-day average share price as of 14 October
2022.
Archaea is one of North America’s leading RNG producers. The company operates more than 50 RNG and landfill-to-electricity
projects. Combined, these produce around 36 mmcfd, equivalent to a 10% market share. BP expects production to increase
fivefold by 2030, supported by a pipeline of over 80 projects.
BP is aiming to complete the acquisition by year-end.
Our take: BP has underlined the importance of biogas to its low carbon pivot with what is the biggest new energy acquisition yet
by a Major. The company is bullish on the opportunity to leverage its project management expertise, trading capability and
customer base in this high-growth sector. This is ‘integration in action’.
Archaea will deliver a proven platform for expansion and management expertise in one stroke. BP expects its biogas supply
volumes to jump by 50% when the deal closes. The deal effectively accelerates growth by three to five years relative to organic
initiatives.
The punchy acquisition multiple of 29 times current EBITDA reflects the strong growth potential. BP expects EBITDA to grow
from US$140 million to US$1 billion in 2027, implying that unit EBITDA could double over the period.
BP believes it can capture additional value through trading to deliver this margin uplift and double-digit returns. Further upside
opportunities include derisking the production plan, expanding the portfolio and capturing additional trading optionality and
efficiencies.
BP will firmly anchor biogas as a growth engine with this acquisition. Alongside growth from its existing portfolio, the Supermajor
believes it could be supplying around 70 kboe/d of biogas by 2030. That’s equivalent to 5% of BP’s projected oil and gas
production and is exactly the type of low-carbon pivot we lay out in our net zero Scope 3 note.
Other integrated players will take note. Flush with cash, the Majors now have the appetite for meaningful new energy
acquisitions. Momentum is building for more transformational M&A that fast-tracks expansion into new energy.
For further details on the acquisition see BP goes big with US$4.1 billion acquisition in US renewable natural gas.
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Corporate week in brief
BP's projected EBITDA growth from the Archaea acquisition
Continental Resources agrees to Hamm family take-private offer
Dave Clark, 17 October 2022
The facts: Continental Resources has agreed to accept an enhanced take-private offer from founder and Chairman Harold
Hamm and his family. The tender offer for the 17% of shares not held by the family was increased to US$74.28/share from the
initial US$70/share announced in June. The tender price represents a 15% premium to the pre-offer price on 13 June, and a 9%
premium to the 14 October close. The transaction has been approved by the board of directors, on the unanimous
recommendation of a special committee established to review the offer. Continental should be a private company by the end of
the year.
Our take: while the ultimate tender offer price was uncertain, we highlighted in June that the chances of realization were high,
and this announcement does not come as a surprise. Private ownership will allow the company to operate free of the constraints
of public shareholder pressure regarding investment, growth, return of capital, emissions targets and energy transition strategy.
Greater discretion over the timing and scale of distributions should enhance flexibility for continued opportunistic M&A. The
largest operator in the mature Bakken will now be a private.
The tender offer price implies an equity value of US$26.6 billion (about US$1.2 billion higher than the offer in June) and an
enterprise value of US$32.3 billion, based on Q2 net debt. Wood Mackenzie values Continental’s upstream asset base at
US$26.0 billion at a long-term real Brent price of US$60/bbl, and US$35.8 billion at our US$80/bbl high case scenario.
For more thoughts on this landmark take-private deal, see our in depth Insight from June.
Diamondback rattles the M&A trend with FireBird purchase
Alex Beeker, 13 October 2022
The facts: on 11 October, Diamondback announced its planned acquisition of PE-backed FireBird Energy. The deal values
Firebird at US$1.6 billion, with consideration split US$775 million in cash (pre-adjustments at closing) and 5.86 million shares of
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Corporate week in brief
FANG equity. Part of the cash payment will be debt-financed, but FANG plans US$500 million of non-core asset sales to help
bridge the gap.
Assets include 68,000 net acres in the western Midland Basin. Three rigs are currently active on the position, supporting 22,000
boe/d of production (78% oil) from the leasehold.
Our take: the deal comes as a slight surprise to us. During its Q2 earnings call Q&A, Diamondback messaged a slight
discomfort with elevated private company valuations. Our upstream team sat with the company two weeks ago too and
understood that Midland bolt-ons would only happen if the acquired inventory would be extremely competitive in the buyers’
own inventory rankings. But that speaks to the buyer’s view of Firebird’s PUD locations.
We’ll publish a full valuation soon in our M&A dataset. But seeing US$1.6 billion assigned to less than 25,000 boe/d highlights
the value put on undrilled locations. Diamondback plans to drop FireBird’s three rigs down to one which will ensure the deal is
accretive to cash flow.
Diamondback is funding the deal with an approximately equal split of cash and equity. This confirms the recent trend of US E&P
deals to include a greater percentage of equity and pay more for undrilled resource. Diamondback’s U-turn on M&A from its Q2
call could also signal that the bid-ask spread between buyers and sellers is narrowing.
ExxonMobil strikes landmark carbon storage partnership
Tom Ellacott and Mhairidh Evans, 13 October 2022
The facts: ExxonMobil, CF Industries and EnLink Midstream have entered into a carbon capture, transport and storage
partnership comprising three elements:
•
CF Industries will invest US$200 million in a CO2 dehydration and compression unit at its manufacturing facility in Louisiana
to capture up to 2 mmtpa of CO2. The company expects to market up to 1.7 mmpta of blue ammonia.
•
ExxonMobil will develop a 125,000-acre CO2 storage site.
•
ExxonMobil has signed an agreement with EnLink Midstream to transport the CO2 through EnLink's pipeline network.
The partners expect the project to start up in 2025.
Our take: this partnership is proper CCS in action. The project has materiality and, due to the new US$85/tonne 45Q tax
incentive, is likely to be in the money across the value chain.
The 45Q tax incentive will apply to CF Industries as the emitter of the CO2. But the CO2 capture will be relatively low cost. This
should allow the payment of a healthy tolling fee for transportation and storage to EnLink and ExxonMobil respectively.
The 45Q tax incentive only lasts for 12 years post-production. CF will look to make its return on investment within this period of
firm revenue support. That should be achievable given the up-front investment of only US$200 million. We also expect some
form of carbon pricing or other support once the 45Q incentive expires.
Project slippage is perhaps the bigger risk given the lengthy federal process to approve well permits for storage. Accelerating
approval will require Louisiana to be granted "primacy", which is expected in 2022 or 2023.
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Corporate week in brief
The move will strengthen ExxonMobil’s positioning in our Majors’ CCUS benchmarking report. It also comes as rumours surface
that the Supermajor has Denbury in its acquisition crosshairs. Of manageable scale (US$4.9 billion enterprise value), Denbury
has good visibility on CCS growth and a leading US CO2 pipeline position. It’s a unique opportunity to fast-track the
development of carbon-as-a-business for any Major with big CCUS ambitions.
Third time's the charm for EIG's Australia LNG ambitions
Andrew Harwood, 13 October 2022
The facts: private equity-backed EIG has paid US$2.15 billion for a portfolio of four Australian LNG projects from Tokyo Gas.
The deal includes Tokyo Gas’ minor interests in Gorgon LNG, Ichthys LNG, Pluto LNG and Queensland Curtis LNG (QCLNG).
EIG will acquire the assets via MidOcean Energy, a new company formed to build a diversified, global integrated ‘pure-play’
integrated LNG business. The deal, subject to approvals, is expected to close in the first half of 2023.
Our take: it's third time lucky for EIG, which appears to have finally landed its coveted Australia LNG position after unsuccessful
plays for Santos in 2018, via Harbour Energy, and a stake in APLNG in 2021. The deal provides MidOcean with a foundation
portfolio of blue-chip assets, primed to generate steady cash flows beyond 2040. It's also a statement of EIG's bullish outlook on
oil and gas, coming soon after the announcement of the acquisition of a 25% stake in Repsol's upstream business.
But the transaction is not without risks. Read our Inform and Deal Insight for more details of the potential downsides and our
take on the wider M&A implications for Australia.
How will companies get to net zero Scope 3 emissions?
Only ten oil and gas companies in our Corporate Service universe have set ambitions to get to Scope 3 net zero emissions. This
limited commitment reflects the massive structural change required, in particular the need to shrink oil and gas production.
Three broad business models have emerged: Big Energy, Carbon as a Service and Sustainable Fuels. The most ambitious
company is targeting net zero Scope 3 in 2030. The majority are aiming for 2050.
Find out how they plan to get there in our latest Corporate Service insight. We analyse how companies are taking different bets
on the levers to get to Scope 3 net zero. The report also includes deep dives into the strategies of the ten companies that have
committed to net zero and the moves other players are making to manage Scope 3 risk.
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Net Zero Scope 3 Business Models
Russia takes first step towards Sakhalin-1 expropriation from ExxonMobil
and partners
13 October 2022
The facts: on 7 October, President Putin signed a decree that instructed the Russian government to create a Russian entity to
take over the rights and obligations of Exxon Neftegaz, operator of the Sakhalin-1 project. This was claimed to be a response to
the actions of ‘unfriendly’ states and organisations that had imposed restrictions on Russia.
Rosneft retains a 20% stake in the new entity through its subsidiaries Sakhalinmorneftegaz-Shelf (11.5%) and RN-Astra (8.5%).
Sakhalinmorneftegaz-Shelf will become temporary operator.
Foreign shareholders – ExxonMobil (30%), Japan’s Sakhalin Oil & Gas Development JV (SODECO, 30%) and India’s ONGC
(20%) – must ask the government for a stake in the new company within one month. If they are not permitted to do so, the
Russian government will sell the interests over a four-month period, keeping any proceeds in a special account. Funds can be
sent to the shareholder or used to repay unspecified PSC damages.
Our take: the groundwork is now laid for the expropriation of foreign-held stakes in Sakhalin-1. This is not unexpected and is
broadly in line with the approach taken by the Russian authorities at the Sakhalin-2 project.
ExxonMobil had already taken a US$3.4 billion charge following its decision to discontinue operations and had previously stated
that it was “engaged in transitioning Sakhalin-1 operating activities to another party." But a presidential decree on 5 August
blocked this. Although it appears unlikely that the Major will seek to remain, its next steps are unclear.
Japanese and Indian investors will also need to decide whether to ask for renewed stakes. While India has avoided joining
countries in imposing sanctions on Russia, Japan’s relations with Russia have become increasingly strained. Unlike with the
Sakhalin-2 LNG project, Japan does not rely on hydrocarbon imports from Sakhalin-1. Moreover, the presence of Japan's
Ministry of Economy, Trade and Industry (METI) as a 50% stakeholder in SODECO complicates the outlook. Other SODECO
participants include Marubeni, INPEX Corporation, JAPEX and Itochu.
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OMV to invest in four solar parks in Romania
Zoe Sutherland, 6 October 2022
The facts: OMV has entered a 50:50 joint venture with CE Oltenia to build four solar parks at former coal mining sites in
Romania. The solar project will require investment of US$392 million and have a capacity of 450 megawatts. Up to 70% of the
development costs will be covered by the European Union’s Modernisation Fund. The solar parks will supply the national grid
starting in 2024.
Our take: OMV has a target of 1 GW of energy produced from renewable sources by 2030 and this is a step towards reaching
its goal. This is not the company’s first foray into solar. It already operates a solar plant in Austria with partner Verbund which
has a capacity of 15.84 GWh. The electricity is used for its own operations.
OMV is one of very few companies outside of the Euro Majors to announce a Scope 3 target. It plans to be Net Zero from Scope
1, 2 & 3 emissions by 2050.
Wintershall Dea wins carbon storage license
Zoe Sutherland, 6 October 2022
The facts: Wintershall Dea has been awarded an exploration and storage license for CO2 in the Norwegian North Sea. The
license covers the Luna acreage and is thought to have a capacity of up to 5 Mtpa of CO2.
Our take: the award is an important step towards Wintershall Dea and Equinors’ plans to build a major CO2 storage site
offshore Norway. The project called NOR-GE will include a 900-km pipeline to connect the storage facility with CO2 collection
sites in Germany and could be commissioned as early as 2032.
Wintershall Dea plans to be net zero from Scope 1&2 emissions by 2030. While it does not yet have a Scope 3 target, it plans to
begin tackling Scope 3 emissions by investing in technology and innovation with a focus on carbon capture & storage (CCS)
and hydrogen. It has a target to abate 20-30 Mtpa of CO2 by 2040.
Oxy investigating CCUS opportunities with Western Midstream
Zoe Sutherland, 6 October 2022
The facts: Oxy and Western Midstream Partners (WES) have signed a letter of intent to explore the delivery of low-carbon
intensity oil and gas products through the deployment of CCUS. Both companies will install CO2 capture facilities at their
operations, and WES will look to provide transportation from these facilities to CO2 offtake delivery locations. Oxy will own and
operate the CO2 offtake facilities for sequestration, EOR or other utilisation activities. The partners intend to offer the CCUS
facilities to other point source emitters.
Our take: establishing a large carbon management business is central to Oxy’s plan to reach net zero from Scope 1,2 & 3
emissions by 2050. Its goal is to establish at least three carbon sequestration hubs by 2025 with a combined storage capacity of
18 Mtpa. During its Low Carbon Ventures day in March, Oxy commented that interest was high from emitters who could tap into
the hubs. It reported it was working with 50 projects with over 40 Mtpa of capture potential.
In July, Occidental's Low Carbon Ventures subsidiary 1PointFive 5 acquired pore space in Western Louisiana to develop and
operate a carbon sequestration hub. Two Class VI injection permits for the site have also been applied for. Oxy’s partnership
with WES is another concrete step for Oxy towards achieving its CCUS ambitions.
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For more on corporate activity in CCUS, see our latest Insights - Emerging CCUS business models utilising existing
infrastructure and Majors' CCUS benchmarking 2022
Ørsted decides not to bid in latest Taiwan auction
Akif Chaudhry and Norman Valentine, 06 October 2022
The facts: Ørsted has stated it will not submit a bid in the first offshore wind auction of Taiwan’s Round 3 process.
Low prices, extreme inflationary pressure on costs and regulation meant it “could not make projects investible at this stage.”
Our take: whilst offshore wind remains core to Ørsted’s plans, successful execution of its diversification strategy beyond the
offshore wind business is becoming more critical to its growth plans.
Intensifying competition, supply chain and input cost inflation are weighing heavy on offshore wind returns. IRRs are hovering
around the cost of capital.
Ørsted’s decision clearly reflects tough market conditions. However, it also indicates the company’s cautious approach in
offshore wind compared to some of its competitors.
Ørsted has been more selective in new project bidding in the last few years. It was conspicuous by its absence from the winners
list in some of the most important recent lease rounds in the UK (LR4) and the US (New York Bight). The announcement in
Taiwan is another example and perhaps not a surprise.
With its strong installed base and new project pipeline, its actions make sense. It is well positioned to meet its 30 GW offshore
wind target for 2030 with firm capacity of over 22 GW.
The onshore business is growing in prominence as part of the company’s plan to diversify. Ørsted announced this week that it
was adopting a new organisational structure through the integration of its offshore and onshore units.
But with firm onshore capacity currently at around 5 GW, Ørsted will need to aggressively grow its generation assets, including
through M&A, to meet its 2030 target of 17.5 GW in onshore renewables.
Further offshore wind analysis can be found in the following insights from our Corporate Power and Renewables team:
Why the Majors need to consider margins in weighing up offshore wind
Europe’s corporate offshore wind leaders
US acquisition a big deal for RWE
Akif Chaudhry and Norman Valentine, 06 October 2022
The facts: RWE has signed a purchase agreement with Con Edison, Inc. to acquire 100% of Con Edison Clean Energy
Businesses, Inc. (Con Edison CEB) for US$6.8 billion including debt.
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Con Edison CEB operates and develops renewable energy generation assets in the US. The deal will add 3 GW of operating
capacity to RWE’s portfolio and boost its US development pipeline by 7 GW. Along with its existing portfolio, the acquisition will
give RWE 24 GW of combined potential development capacity in the world’s second largest renewables market.
The purchase will be funded through debt and equity. This includes EUR2.4 billion raised from Qatar Investment Authority (QIA)
via a mandatory EUR 2.4 billion convertible bond. This represents around 10% of RWE’s pre-deal share capital.
The transaction is expected to close in H1 2023.
Our take: this is a significant announcement and one that’s interesting from several angles.
A positive move from RWE
The investment is a meaningful step towards RWE’s 54 GW net capacity target by 2030 (current 38 GW) of which renewables is
31 GW (current 10 GW).
But the deal is also a clear statement of intent to diversify the portfolio. It brings greater balance across a range of technologies
and geographies through expansion in a key renewables growth market.
Breakdown of RWE’s total installed capacity:
Even more notably, once completed, this deal shifts the balance of installed renewables capacity from Europe to the US. It also
results in greater diversification within the renewables mix with nearly 90% of Con Ed CEB’s assets in solar.
And, with threats of a windfall tax looming large, this sizeable investment in the US, at a time of crisis in the European energy
market, likely also sends a strong message to local regulators.
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Breakdown of RWE’s renewables installed capacity:
The US$6.8 billion consideration equates to an EV/EBITDA of 11x. RWE expects the deal to be earnings accretive from year
one, adding around US$600 million to its EBITDA.
On the face of it, an 11x EV/EBITDA multiple does not appear onerous for this strategic move given the growth potential of the
portfolio acquired. RWE also notes the average weighted remaining price support period is 17 years. That will ensure good cash
flow visibility across the acquired assets (albeit limit upside potential).
Qatar’s sovereign wealth fund diversifying exposure
Qatar Investment Authority (QIA) will own a little over 9% of RWE’s share capital post bond conversion. That gives it a
meaningful stake in a major European utility focused on the energy transition.
RWE has a set out its strategy to invest EUR50 billion gross across offshore and onshore wind, solar, batteries, flexible
generation and hydrogen to reach over 50 GW net capacity by 2030. QIA is buying exposure to this accelerated plan and two
key markets in the renewables space.
Further opportunities to buy US renewables?
ConEdison’s intent to sell was well flagged. Its earnings release in February 2022 noted it was “considering strategic
alternatives” for the Clean Energy Business. Improving balance sheet strength and investment in the regulated business will be
key priorities.
This is in line with broader pressures being felt by regulated US utilities from shareholders to divest their non-regulated assets.
Both American Electric Power and Duke Energy have announced similar plans to sell. Rising interest rates will also put some
smaller-scale developers under pressure to sell.
The Inflation Reduction Act brings investment incentives to new wind and solar amongst other low carbon technologies and will
make a strong project pipeline an attractive proposition to prospective buyers.
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The likes of EDP Renewables, Iberdrola, Ørsted and RWE have built strong positions in the US. Given other businesses are up
for sale, could we yet see more M&A activity from European players, including further moves from the Euro Majors, looking to
strengthen their position in this key market?
For in-depth analysis of Europe’s leading utilities, look out for our upcoming Corporate Power and Renewables Service. For
further information please contact Norman Valentine at norman.valentine@woodmac.com.
Repsol outlines its vision for 2050
Tom Ellacott, 4 October 2022
The facts: Repsol has provided more colour on how its portfolio might evolve to 2050 in its Annual ESG Engagement Report.
The company has developed two demand scenarios for its Upstream and Renewables businesses under the macro conditions
laid out in IEA’s Sustainable Development Scenario (SDS) and Net Zero Emissions by 2050 (NZE) scenario. Repsol has opted
for a single macro environment determined by the European Green Deal for its Industrial and Customer segments.
Highlights in the 2050 vision include:
•
Oil and gas production: falls from the 2022 estimate of 570 kboe/d to 250 to 300 kboe/d (SDS scenario) and 30 to 80
kboe/d (NZE scenario).
•
Crude oil distillation: falls by 80% to 90%, offset by an increase in low-emissions fuels which account for around 70% of
Repsol’s energy product mix by 2050.
•
Renewable hydrogen: increases to 10 to 15 GWe by 2050, up from the 2025 target of 0.55 GWe.
•
Circular economy: Repsol plans to recycle the equivalent of 50% of its total production of polyolefins.
•
Renewable power installed capacity: increases from around 1.7 GW currently to between 40 to 45 GW (SDS) and 50 to 55
GW (NZE).
Repsol also plans to increase the proportion of its total budget allocated to low carbon between 2041 and 2050 to between 65 to
75% (SDS) and 80% to 90% (NZE). Low carbon could account for up to 85% of total capital employed by 2050.
Our take: Repsol has provided more colour than any Euro Major on how its portfolio will evolve to 2050. Projecting a range of
outcomes under the SDS and NZE scenarios is also a useful addition given the uncertain outlook for the development of low
carbon technologies over the period.
The scale of the portfolio transformation is striking. Repsol will have to almost completely pivot its downstream business to low
emissions fuels by 2050. Oil and gas production falls by 95% under the most aggressive scenario (albeit less than 50% in the
upper range to underscore the wide range of possible outcomes). That’s the reality of getting to net zero Scope 3 emissions for
companies with big European downstream footprints.
Repsol has made a strong start in building low-carbon optionality to support the strategic pivot. The company has also set more
ambitious targets in renewables and low emissions fuels than many of its larger peers. These will ensure Repsol stays in the
leading pack of companies positioning for a low carbon future. Execution success will depend on managing first-mover risks,
including backing the right low carbon technologies.
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Corporate week in brief
Q3 2022
Capricorn enters merger agreement with NewMed Energy
Scott Walker, 30 September 2022
Capricorn Energy is terminating its proposed merger with Tullow Oil, having reached a new merger agreement with Israelfocused NewMed Energy. The deal is structured as a reverse takeover, with Capricorn issuing new shares to be exchanged at a
ratio of 2.3 for each NewMed share. Post-completion, NewMed will hold 89.7% in the combined company and Capricorn 10.3%.
The termination of the Tullow agreement has been well signposted after an increasing number of Capricorn investors expressed
their intention to withhold approval. Several voiced concern at the use of Capricorn’s excess cash to lower Tullow’s heavy debt
burden and viewed the merger as value destructive. When it became clear that Capricorn was set to fall short of the 75%
approval needed, the merger was effectively dead under the original terms.
Read our Inform for more details on the drivers for the Capricorn and NewMed deal and look out for our upcoming Deal Insight.
TotalEnergies unveils a new capital allocation framework at its Investor Day
Tom Ellacott, 30 September 2022
The facts: Growing shareholder returns was a focus for TotalEnergies’ 2022 Investor Day. A new capital allocation framework
in which it will allocate a higher payout of 35% to 40% of its cash flow to shareholders was the headline development.
Underpinned by rising energy production, TotalEnergies is targeting US$4 billion of cash flow growth at US$50/bbl over the next
five years to support dividend growth. The company also plans to reduce net debt to zero to sustain base dividends through the
cycle and have the flexibility to undertake opportunistic business development.
In a first, TotalEnergies announced that it will pay a special interim dividend of €1 per share in December 2022. This will bring
the total return to shareholders to within the new range, when combined with the previously announced US$7 billion buyback
programme and 5% base dividend hike.
TotalEnergies will also increase net investment to US$14 to US$18 billion between 2022 to 2025, up 7% to 12% from the
previous guidance of US$13 to US$16 billion. New energy will account for around one-third of total spend.
Our take: less Russia, more US and, in LNG, more Qatar was a key strategic theme running through this strategy update.
TotalEnergies stepped through the outlook for its business excluding Russia, in which its future is increasingly uncertain.
The absence of Russia and the Canadian oil sands business (which TotalEnergies now plans to spin off in 2023) hit absolute
energy production and cash flow projections. Remember, last year we were forecasting 470 kboe/d of production from Russia in
2022, rising to 555 kboe/d by 2030. But TotalEnergies’ underlying energy production growth of 4% between 2021 and 2030 still
impressed.
The strength of the outlook without Russia and the oil sands is testament to a period of outstanding business development
success. TotalEnergies’ portfolio balance has shifted as a result.
The US is now important enough to have its own breakout session. TotalEnergies stressed that the country offers everything to
build its broad energy business – a top-ranking LNG position, advantaged oil assets, a renewables business that has serious
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scale and opportunities to grow. The giant North Field East and North Field South projects will also transform TotalEnergies’
LNG growth trajectory in Qatar and help offset the volumes lost in Russia.
What about the broader implications? It seems likely that other Majors will follow TotalEnergies’ lead in increasing investment
while sticking with disciplined screening criteria. Leverage and net debt targets will also drift down to increase financial
resilience. But will other Supermajors embrace special dividend payments as part of their shareholder distribution strategies?
The jury is still out on that one.
TotalEnergies' capital allocation framework
Chevron signs geothermal collaboration agreement
Alex Beeker, 28 September 2022
The facts: on Monday 26 September, Chevron announced the signing of a joint collaboration agreement with Mitsui (MOECO)
to explore the technical and commercial feasibility of advanced geothermal power generation in Japan.
The new collaboration will study geothermal resource potential across Japan and will evaluate the effectiveness of Advanced
Closed Loop (ACL) technology for a future pilot project in the country. ACL offers an advantage over conventional geothermal
projects – it can potentially access geothermal at a wider range of temperatures and geologies, expanding its potential footprint.
Our take: Success of this partnership will likely be measured in learnings gained rather than NPV generated.
It reemphasizes Chevron’s “wide-net” approach to the energy transition. Core new energies investments remain centered
around CCUS, hydrogen and renewable fuels. But Chevron has demonstrated an interest and commitment to learning about a
host of other low carbon technologies that have some synergies with its legacy operations (e.g., dairy biomethane, geothermal,
and carbonate aggregates).
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The announcement also emphasizes the importance of technology to Chevron. In addition to geothermal, it’s apparent in
Chevron’s CCUS strategy. The company primarily invests in companies or technologies that it believes offer an advantage or
differentiator to the wider industry.
In terms of capital committed to the energy transition, Chevron still lags the Euro Majors. But it’s laying the ground for potentially
catching up in the years ahead.
Santos sells down stake in PNG LNG
Andrew Harwood, Dan Toleman, 27 September 2022
The facts: Kumul Petroleum, Papua New Guinea’s national oil company, has made a binding conditional offer to Santos to
acquire a 5% stake in the PNG LNG project. A consideration of US$1.4 billion, including a US$300 million share of project
finance debt, has been agreed, conditional on the waiver of pre-emption rights by existing project partners, ExxonMobil and
Japan PNG Petroleum.
The deal, with an effective of 31 December 2022, will increase Kumul Petroleum’s stake in the project to 24.6%, with Santos
retaining a 37.5% interest.
Our take: This deal comes as no surprise, having been heavily signposted by Santos during its 2022 H1 financial results
announcement. But the origination of the deal could be seen in the PNG government’s approval of Santos’ transformational
merger with Oil Search.
The announced consideration aligns closely with our modelling of PNG LNG under our US$60/bbl long-term base price
assumption. Strong uncontracted LNG prices in the near term provide upside to our valuation, with around 2 mmtpa (24%) of
gross plant output exposed to spot prices. A 5% stake in the project will generate US$1.3 billion in annual net cash flow by
2030, with the incorporation of the P’nyang project set to extend plateau production out to 2040.
While Santos retains a very material PNG position, the deal reduces exposure to a single project. Selling into a red-hot LNG
market unlocks further value for Santos from the Oil Search merger. We calculate the deal generates a 16% return on the
implied value of a 5% stake in PNG LNG, under the terms of the Oil Search transaction.
Having taken FID on the Pikka project, while deferring the Dorado development, Santos is beginning to leverage the optionality
of a larger portfolio. Future farm-downs of Pikka or Dorado would see Santos comfortably hit its US$2-3bn divestment target.
Proceeds will be used to strengthen the balance sheet (gearing of 22.5% at 30 June 2022) and increase shareholder returns.
See our Deal Insight for more details.
TotalEnergies moves first to expand its LNG portfolio in Qatar
Tom Ellacott, Giles Farrer and Ian Thom, 26 September 2022
The facts: QatarEnergy has selected TotalEnergies as its first international partner in the 16 mmtpa North Field South LNG
project. The Supermajor will secure a 9.375% stake in the project out of the total 25% equity available for international partners.
QatarEnergy will hold the remaining 75%.
Our take: TotalEnergies has moved quickly and decisively to re-build its LNG growth portfolio to offset the growth lost in Russia.
It’s no surprise that Qatar has led the business development effort. The LNG from future projects has the lowest breakevens
globally and carbon mitigation measures will support marketing efforts to sell low carbon LNG.
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TotalEnergies will add 1.5 mmtpa of working interest LNG production from this deal. This is in addition to the 2 mmtpa it
acquired via its 6.25% stake in the North Field East project that was announced in June 2022. We also expect TotalEnergies to
lift and market the equivalent amount of LNG from the project via its global LNG portfolio.
We assume a combined plateau is achieved in 2030, subject to successful execution and cost management. Net oil and gas
production from both projects plateaus at around 100 kboe/d from 2030 in our base-case, equivalent to nearly one-quarter of
TotalEnergies’ current Russian output.
The announcement comes ahead of TotalEnergies’ Investor Day this Wednesday, in which it will exclude Russia from its
strategic plans. But we expect the Supermajor to emphasise how its LNG-led growth trajectory is intact. The numbers impress
based on our analysis. TotalEnergies’ oil and gas production grows out to 2030 following this deal even if it exits Russia.
Talos acquires EnVen energy
Mfon Usoro, 22 September 2022
The facts: on 22 September 2022, Talos announced the acquisition of private-equity-backed EnVen Energy for US$1.1 billion.
Talos will finance the deal by issuing new shares and using cash on hand of US$212.5 million. Upon closing, the new entity will
consist of 66% Talos and 34% EnVen. The deal is expected to close at the end of 2022.
Our take: with the acquisition of EnVen Energy, Talos will become the sole Gulf of Mexico-focused mid-cap independent
company. The company will focus on offshore exploration and development in the US Gulf of Mexico, offshore Mexico, and CCS
onshore and offshore US. Wood Mackenzie values the upstream assets of the combined company at US$5.4 billion (NPV 10).
With 2022 production at nearly 100 kboe/d, Talos will become the sixth largest producer in the US Gulf of Mexico. Talos’
acreage will increase by 57% to roughly 840,000 acres, of which 86% is operated. The independent has also boosted its
infrastructure position in the US GoM by adding five operated production facilities. Although Talos and EnVen do not have direct
overlapping assets (except Bulleit), we still expect operational and cost synergies due to scaling up. Talos has cited US$30
million in cost savings primarily from G&A.
Talos is no stranger to growth via acquisition. The company has grown fourfold since going public in 2017 by acquiring
Riverstone ILX, Castex assets and several bolt-on acquisitions. The capture of incremental acreage, infrastructure, and cash
flow in the US GoM through the addition of EnVen strengthens its balance sheet. In addition, it will set the company up
strategically for its CCS growth ambitions.
For EnVen, the deal is an opportunity for original investors, Bain and EIG, to monetize their investment. EnVen was founded in
2014 and filed an S-1 in 2018 to go public, but those plans never materialized. The private equity-backed company has a
sizeable portfolio in the US GoM, with the shelf contributing about 30% of its 2022 production (24 kboe/d). We estimate cashflow
of close to US$1 billion over the next three years.
See our Deal Insight for more details.
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Talos and EnVen US GoM assets
Eni's Plenitude enters new partnership to develop solar and wind projects
Greig Aitken, 22 September 2022
The facts: Plenitude (Eni’s wholly-owned gas and power retail, renewables and e-mobility company) has entered a new
partnership with Infrastrutture S.p.A. to develop solar and wind power projects in Italy and Spain. Plenitude has acquired a 65%
stake in Hergo Renewables S.P.A., a company that holds a portfolio of projects in the two countries with a total capacity of
~1.5GW. Infrastrutture will retain the remaining 35% stake.
The first project is a 37 MW photovoltaic plant in Montalto di Castro, where work is due to commence imminently. The plant is
expected to come into operation in H2 2023.
Our take: This is in keeping with previous acquisitions Eni has made, inorganically building up the renewables development
pipeline.
Eni is targeting 2 GW of installed renewable capacity by the end of this year, rising to 6 GW in 2025 and 15 GW in 2030. At the
end of H1 Eni had 1.6 GW of installed capacity and ~0.8 GW under construction. It also had line of sight across much of the
2025 target (~3.7 GW of high visibility and medium maturity projects). The acquisition should help fill out what is a steep growth
trajectory between 2025 and 2030.
Eni/Plenitude has formed a number of partnerships to pursue renewables growth. It recently sold its 20% stake in Dogger Bank
into Vårgrønn, its joint venture with HitecVision (65% Eni). In Italy, GreenIT, an alliance with CDP Equity (51% Eni), is targeting
1 GW from PV and onshore wind by 2025.
South32 halts greenfield coal to set Scope 3 net zero goal
James Whiteside, 16 September 2022
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The facts: South32 committed to stopping the development of greenfield steel-making coal projects, building on the company’s
2017 commitment to halt investment in any new thermal coal operations. Concurrently, the company set a goal of net zero
Scope 3 emissions by 2050, aligned to its existing Scope 1 and 2 ambition.
Our take: This announcement signals a turning point in the diversified mining company’s willingness to invest in any type of coal
operation. It closely follows BHP’s suspension of investment in steel-making operations in August.
Despite a positive outlook for the commodity, multiple sustainability pressures are forcing companies to reassess their positions.
For South32, the decision was triggered by committing to eliminating Scope 3 emissions. In contrast, BHP withdrew capex
guidance to reassess the economics of its operations in response to higher royalties and carbon costs. In both announcements,
the companies recognised the commodity’s robust multi-decade demand outlook, as hydrogen steel-making remains unfeasible.
Will more companies stop coal investment? Most diversified mining companies have now either set a pathway to closing coal
operations or exited the market altogether. Production is increasingly dominated by coal-focused miners with less climate
ambition. For these companies, access to capital through financial markets will be a key determinant for the level of investment
going forward.
Petrobras cancels yet another upstream sale
Raphael Portela and Vinicius Moraes, 13 September 2022
The facts: Petrobras announced that it is cancelling the Albacora divestment. Talks were underway with Prio (formerly
PetroRio) for about a year. Prio claims that the parties could not agree on a valuation for the asset. Petrobras now intends to
redevelop the area and replace current production units (P-25 and P-31) with a modern FPSO facility. Both companies did reach
an agreement for Albacora Leste on 28 April (see our deal insight).
Our take: Petrobras’ divestment programme started off with a bang in 2022. Deal considerations surpassed the US$4 billion
mark, driven by the Albacora Leste and Polo Potiguar deals. However, things have cooled off as a series of negotiations failed
to reach mutual agreements. Our base case valuation for the four most recent cancelled negotiations (Albacora, Marlim Cluster,
Sergipe-Alagoas Deepwater, and Urucu Area) stands at US$13 billion (NPV10 discounted to January 2022).
We believe high commodity prices and dry holes in high-profile pre-salt prospects have moved Petrobras’ less core portfolio up
the queue. For instance, the five-year planned capex for the Campos Basin jumped from US$13 billion to US$16 billion in its
latest plan, and the production outlook is now 900 kboe/d by 2026 (previously 700 kboe/d by 2025). Another offshoot of this
broadened strategy is Petrobras’ riskier bet in exploration, targeting the frontier Equatorial Margin. The company knows it will
need more than a few large finds to maintain raised output levels post-2030.
For more information on Petrobras’ divestment programme, visit our dedicated tracker page. And stay tuned for an upcoming
update to the company’s corporate profile.
Gazprom and CNPC agreed payments using Russian roubles and Chinese
renminbi
Yuqi Hu and Andrew Harwood, 13 September 2022
The facts: China’s CNPC has agreed to pay for natural gas supplied by Russia’s Gazprom in a combination of roubles and
renminbi in a 50/50 ratio. The gas deal, agreed initially in February 2022, had been denominated in euros.
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Our take: The currency switch will help Russia navigate Western sanctions implemented in the wake of the Russia/Ukraine
conflict. It will also reduce roubles' volatility and stabilise Russia’s domestic economy. Russia already has a similar currency
agreement for a portion of its gas trade with Turkey.
For China, this second long-term supply deal with Russia will add an additional 10 bcm per year of gas, supporting China’s dual
goals of energy security and energy transition. Partial payment in renminbi will also support China’s efforts to de-dollarise. But
the deal concentrates reliance on Russia, which is China’s second-largest pipeline gas supplier. The strategic cooperation
between Gazprom and CNPC is likely to strengthen in the future, with discussions underway on the Soyuz-Vostok pipeline,
which could add another 50 bcm per year of gas imports.
BLM approves Wyoming CCS storage
Rachel Schelble, 9 September 2022
The facts: in an industry first, the Bureau of Land Management (BLM) approved ExxonMobil’s plan to build subsurface
infrastructure for storage of CO2 on federal lands. ExxonMobil announced FID on expansion of the LaBarge carbon capture and
storage (CCS) project in Wyoming earlier this year where it plans to capture about 60 million tonnes of CO2 per year in the
water leg of the Madison Formation (approximately 18,000 ft depth). Startup is planned for 2025.
Our take: this sort of industry and government collaboration is exactly what is needed to progress CCS forward in the US. While
the Inflation Reduction Act increased economic incentives for the development of CCS projects, the approval by the BLM will go
a long way in convincing operators that regulatory hurdles can be overcome.
The combination of economic incentives and regulatory approval success comes as operators are evaluating their CCS
investment options in light of the enhancements to the 45Q tax credit. Approval for the LaBarge CCS project couldn’t have come
at a better time.
Eni to acquire BP’s Algerian assets
Martijn Murphy, 9 September 2022
The facts: Eni has agreed to acquire BP’s Algerian gas fields: In Amenas and In Salah. BP holds 45.89% and 33.15% interests
in both areas respectively. No consideration has been disclosed. The deal is subject to approval by the Algerian authorities.
Our take: Eni’s acquisition of BP’s Algerian assets had been expected for some time; rumours have been milling since at least
June 2021. BP has long considered Algeria non-core to its portfolio. And with a looming 2030 target to reduce production by
40%, the mature assets were obvious disposal candidates.
Conversely, Eni continues to double down in Algeria. With the acquisition of BP’s assets, it will increase its net production by
30% to 160 kboe/d, cementing its position as Algeria’s top IOC producer. Algeria will overtake Angola and Norway to become
the company’s fifth biggest producing country. And increasing Algeria's gas output will facilitate greater exports as Italy, Algeria's
biggest export customer, seeks to reduce its reliance on Russian gas.
We value BP’s Algerian assets at US$1.15 billion (NPV10 Jan 2022). The fields are in harvest mode and will continue to churn
out free cash flow ahead of impending licence expiries in 2027. Beyond then, the fields present much upside if new licences can
be secured.
See our Deal Insight for more details.
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Tullow and Capricorn merger hangs in the balance
Scott Walker, 8 September 2022
The facts: Capricorn Energy announced that the company is exploring “alternative transactions” in relation to its recently
proposed merger agreement with Tullow Oil. The company said it has received a number of expressions of interest and is
engaging with those parties to assess its options and maximise shareholder value.
Our take: Capricorn’s hand has essentially been forced in the face of increasing investor pressure. The company requires 75%
shareholder approval for the deal with Tullow to proceed but it looks set to fall short of that threshold. At least five institutional
investors – with combined interest above 27% – have come out in opposition to the deal, saying the offer undervalues Capricorn
and is value destructive for shareholders.
We still think there’s sense to the merger for both companies, as we outlined in our analysis at the time of the deal. But it’s now
clear that for this deal to proceed or for another buyer to step in, an increased offer needs to be forthcoming.
Tullow’s 3.8068 for one share offer in June priced Capricorn’s equity at £2.08 per share (a 5% premium to Capricorn’s prevailing
share price). A subsequent drop in Tullow’s stock value means the offer is worth just £1.85 today, yet Capricorn’s shares are
trading at £2.33. The market seems to be anticipating a better offer.
But with agitating investors calling for a price of between £3.00 to £3.30, there’s still a substantial gap to bridge. Tullow might
still find Capricorn’s cash position attractive enough to increase its offer, although at the prices mooted Tullow would find itself a
minority shareholder in the combined company, which could give its own investors pause for thought.
EQT executes US$5.2 billion “bolt-on” acquisition
Robert Polk, 7 September 2022
The facts: EQT Corporation, the largest natural gas producer in the US, agreed to acquire privately owned Appalachian Basin
producer Tug Hill and its integrated midstream business XcL Midstream for US $5.2 billion. Tug Hill currently produces ~800
MMcfe/d, and the complimentary midstream assets include gathering pipelines, compression, processing capacity, and water
handling. The total consideration is financed 50/50 with cash and stock.
Pro forma for the acquisition, EQT’s daily production jumps to 6.3 Bcfe/d. EQT is almost entirely dry gas, but on an equivalent
basis it joins ExxonMobil as the only operators currently producing over 1.0MMBoe/d in the US Lower 48.
Our take: the massive scale of production stands out, but the acquisition provides benefits beyond pure scale. The Tug Hill
upstream assets possess a very low breakeven due to midstream integration and uplift from a higher NGL yield than much of
EQT’s existing acreage. Low gathering rates will enable margin expansion for EQT. The midstream assets also connect to longhaul pipelines out of basin and help reduce firm wide exposure to Appalachian basis.
Offset acreage should create operating efficiencies and contribute more cost synergies and economies of scale. EQT
possesses unparalleled drilling inventory in Appalachia and remains committed to maintenance activity levels, but the acquired
assets will immediately compete for capital. Extremely low methane emissions intensity supports ongoing capital allocation.
Doubling the share repurchase authorization to US$2.0 billion coincided with the deal announcement. Many Lower 48 focused
deals in recent months have also included stepped up returns. A potential interpretation is that investors remain cautious of
Lower 48 capital allocation and require that immediate shareholder benefits must accompany material M&A. Financing 50% of
the transaction with incremental debt is more aggressive than many recent transactions. The ability to hedge acquired
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production at a high strip coupled with the 2023 cash flow potential from existing production facilitate allow EQT to return cash to
shareholders without sacrificing post-deal deleveraging.
See our Deal Insight for more details.
Repsol announces landmark sell-down of its upstream business
Tom Ellacott, 7 September 2022
The facts: Repsol has signed a binding agreement with EIG to sell a 25% equity stake in its global upstream business for
US$4.8 billion. The offer value implies an enterprise value of US$19.0 billion for 100% of Repsol Upstream.
The company will receive US$3.4 billion of net cash proceeds, of which EIG will pay 70% as an upfront payment with the
remainder paid in three equal annual instalments over three years. The upstream vehicle will hold US$5.6 billion of net debt.
Repsol also flagged the potential to IPO the business from 2026 in the United States, subject to favourable market conditions.
Our take: this is a landmark deal for Repsol that strengthens the company’s track record of being a first mover in responding to
the energy transition. It is the first minority equity carve-out to be undertaken by large IOCs as they reposition for a low-carbon
future.
The structure of the deal allows Repsol to retain control of its upstream assets while not losing any group-level synergies or
integration benefits. The company also gains a look-through valuation and cash injection. Additionally, the move positions the
upstream business for further group-level disengagement in the future as Repsol’s energy transition gathers pace.
See our Inform and Deal Insight for further details on the strategic rationale, impact on Repsol and market reaction.
Devon Energy joins US E&P LNG export partnership parade
Dave Clark, 6 September 2022
The facts: Devon Energy announced an agreement with Delfin Midstream to enter an LNG export partnership. The
announcement includes a non-binding Heads-of-Agreement for at least 1.0 mmpta (and potentially up to 2.0 mmtpa) of longterm liquefaction capacity in Delfin’s modular floating LNG project in the Gulf of Mexico, as well as a planned pre-FID strategic
investment in Delfin. The Delfin Deepwater Port is a brownfield facility located 40 miles offshore Louisiana. The project is
expected to be sanctioned by the end of 2022 with a 2026 planned start-up.
Our take: elevated gas prices and increasing access to global gas markets have turned what was once a structural liability for
unconventional producers into a potential long-term strategic value-creator. While tying US gas to international pricing hasn’t
always worked out for US E&Ps (see EOG and the JKM price collapse in 2020), expectations for long-term demand for reliable
LNG continues to rise due to energy security tensions stoked by the Russia-Ukraine war. Major unconventional gas producers
are likely to continue to seek LNG opportunities, and we may see some mid-cap producers join the trend in 2023.
This agreement continues a robust year of US LNG supply-offtake announcements. Like a few other announced deals, Devon’s
contemplates both supply and LNG offtake, and outlines a planned equity investment in the LNG facilities themselves.
Other recent US independent E&P-LNG announcements include ConocoPhillips’ multifaceted LNG deal with Sempra (initial
tolling arrangement for 5 mmpta, or about 665 Mcf/d of supply), EOG’s expanded 15-year 720 Mcf/d supply agreement with
Cheniere and Chesapeake’s 300 Mcf/d supply agreement with Golden Pass LNG (ExxonMobil/QatarEnergy). Devon’s
announcement appears to be more similar to ConocoPhillips', with supply, offtake and equity stake components, though the
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announcement has few details on the contemplated transaction. Both US Majors have also announced recent US LNG offtake
deals, with XOM signing an SPA for 1.0 mmtpa with NextDecade (Rio Grande LNG), and CVX signing two SPAs with Cheniere
for a total of 2.0 mmtpa (Sabine Pass and Corpus Christi).
Delfin has also signed recent binding SPAs with Vitol (July, 0.5 mmtpa) and Centrica (August, 1.0 mmtpa) to line up offtake for
its modular FLNG project. The project requires 2.0-2.5 mmtpa to begin construction, with each FLNG vessel providing 3.5
mmtpa of liquefaction capacity. Further offtake agreement negotiations are ongoing. The Delfin Deepwater Port can support up
to four FLNG vessels (13 mmtpa total capacity). The FLNG port will be supplied by the HIOS pipeline, for which Delfin has a
long-term lease, and the 42” UTOS pipeline, the largest gas pipeline in the Gulf of Mexico, which Delfin purchased from
Enbridge in 2014. More detail on Delfin LNG here.
Devon’s gas production in Q2 2022 was 961 Mcf/d, about two-thirds of which was from the Delaware Basin. Devon's portion of
supply to Delfin LNG (~133-266 Mcf/d) would represent about 14-28% of gas output.
Mitsui and Mitsubishi keep Sakhalin-2 LNG stakes in Russia, while Shell
exits
Luke Parker, 5 September 2022
The facts: On 2 August, the Russian government issued a decree to create a new firm, headquartered in Russia, to take over
the rights and obligations of Bermuda-registered Sakhalin Energy Investment Co. This followed President Putin’s earlier decree
to create such an entity. The company is named Sakhalin Energy, in which Gazprom, through its Gazprom Sakhalin Holding
subsidiary, retains just over 50.0%. The remaining share was up for grabs from the existing Sakhalin-2 shareholders.
Mitsui and Mitsubishi Corporation applied to keep their respective 12.5% and 10.0% stakes. The Russian government approved
Mitsui's application on 26 August and that of Mitsubishi on 31 August. As expected, Shell has opted not to participate in the new
company.
The licences for the Lunskoye and Piltun-Astokhskoye fields were reissued to Sakhalin Energy on 19 August and are valid until
May 2026.
Our take: Shell's decision not to take a stake marks the end of an era, at times tumultuous, for the company in Russia’s LNG
sector. It was Shell that delivered Russia’s first LNG plant in 2009, following a Gazprom farm-in in 2007. Shell’s move is in line
with its stated strategy of exiting Russia’s upstream.
The decision to remain by Mitsui and Mitsubishi largely reflects Japan’s energy security concerns. However, both companies
have taken write-downs of about 60% on their investments in Sakhalin-2, based on a potential long-term reduction in dividends.
The decision to stay is not without risk as both will need to keep one eye on the policy decisions of Japan, a G7 member, with
regards to Russia in response to the invasion of Ukraine. A hardening of the G7 stance towards Russia could impact Russian
government decision-making towards foreign investors.
Shell sanctions Rosmari-Marjoram gas fields, Malaysia
Alexandre Araman and Huong Tra Ho, 5 September 2022
The facts: Shell has taken final investment decision (FID) on the Rosmari and Marjoram gas fields in deepwater Sarawak,
Malaysia. The development features a subsea tieback, an unmanned wellhead platform (WHP), a 207-kilometre offshore
pipeline and an onshore gas plant (OGP) in Bintulu. The project has a capacity of 800 mmcfd of gas and is due to come
onstream in 2026. 240 solar panels will power the remotely operated WHP and the OGP will be connected to the Sarawak
electrical grid. Sarawak's electricity is predominately generated from hydroelectric dams.
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Rosmari and Marjoram are two sour wet gas fields discovered in 2014 on the block SK318, where Shell holds 80% interest
alongside PETRONAS Carigali (20%).
Our take: This will be technically challenging development. Both fields contain CO2 and H2S. While we understand their
combined CO2 content is lower than 6% – and therefore carbon capture and storage (CCS) should not be required – H2S will
need to be removed. The OGP, subsea system and pipelines will require corrosion protection. We estimate a development cost
in the range of US$2 to 2.5 billion. Read our Inform for further detail and analysis.
Shell and ExxonMobil sell US assets
Greig Aitken, 5 September 2022
The facts: Shell and ExxonMobil are selling their joint venture in the Aera oil-production operation to Green Gate Resources, a
subsidiary of German energy asset manager IKAV. Shell holds 51.8% of Aera Energy LLC, with XOM holding the remaining
48.2%. ExxonMobil did not disclose a consideration. Shell reported a US$2 billion headline consideration, plus an undisclosed
contingent amount subject to future oil prices, based on an October 2021 effective date. Aera produced ~95k boe/d in 2021.
Separately, ExxonMobil confirmed the sale of its Fayetteville gas assets to private E&P Flywheel for an undisclosed amount.
The deal is expected to close in Q4.
Our take: Aera operates exclusively in California where it is focused on the San Joaquin basin. Over half of Aera's total
production is heavy oil which is produced with the aid of steam and waterflood programs. Its divestiture fits in with both
ExxonMobil and Shell’s ongoing portfolio management programs.
Shell is focusing its upstream portfolio on eight core positions (dominated by conventional and deepwater), which demonstrate
resilience to both commodity price and carbon. Everything else is a potential divestment candidate. Rumours that Shell would
exit the joint venture had circled since mid-2021.
ExxonMobil hadn’t previously been directly linked with an exit from the Aera joint venture. But the US Major has been actively
divesting mature non-core assets over recent years as it looks to prioritise advantaged low-cost-of-supply assets such as the
Permian and Guyana. Recent divestments include XTO Canada in July and its Barnett position in May.
ExxonMobil first shared plans to scale back its US onshore gas portfolio in late 2020, with the Fayetteville assets first being
marketed a year ago. Other assets which are still up for grabs include its Bakken and Marcellus positions.
See our Deal Insight for more details.
Equinor advances European CCS
Norman Valentine, 31 August 2022
The facts: the Northern Lights joint venture owned by Equinor, Shell and TotalEnergies has signed the world’s first commercial
agreement on cross border CO2 transportation and storage with Yara, the Norway based fertilizer and chemicals company.
Yara and Northern Lights have agreed to transport CO2 captured from Yara Sluiskil, an ammonia and fertiliser plant in the
Netherlands, and permanently store it in Norway. From early 2025, 800,000 tonnes of CO2 will be captured, compressed and
liquefied in the Netherlands, and then transported by ship to the terminal for storage offshore Norway.
Also this week, Equinor and Wintershall Dea agreed to pursue joint development of a CCS value chain connecting Europe and
Norway. The companies plan a 900 km open access pipeline to connect a CO2 collection hub in Germany and storage sites in
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Norway prior to 2032. It is expected to have a capacity of 20 to 40 Mtpa of CO2 per year. The partners will also consider an
early deployment solution in which CO2 will be transported by ship. Wintershall Dea and Equinor also plan to jointly apply for
offshore CO2 storage licences, aiming to store between 15 to 20 Mtpa on the Norwegian Continental Shelf.
Our take: the deal with Yara provides the Northern Lights project with another anchor customer alongside the Norway cement
producer Norcem and the district heating company Hafslund Oslo Celsio. Northern Lights phase 1 has now reached full capacity
of 1.5 Mtpa, allowing the JV partners to work on plans for phase 2 which will the total project capacity to 5-6 Mtpa. The Northern
Lights project is Europe’s most advanced CCS project under construction, ahead of a burgeoning pipeline of proposed CCUS
developments. In our latest CCUS market update, we estimate Europe accounts for over 25% of proposed global CCUS
capacity which has trebled to over 900 Mtpa over the last 12 months.
The deal with Wintershall Dea aims to maintain Equinor’s leading position in CCUS and helps it progress towards its target of
15-30 Mtpa of net CCS capacity by 2035. Equinor will utilise it experience from the Northern Lights project to make the case for
a similar CO2 export project from Germany, Europe’s largest emitter, to Norway. Partnering with Germany’s Wintershall, which
has one of the most aggressive Scope 1 & 2 net zero targets in the industry for its upstream activities, also makes sense. For
further insight into the partners’ new energy and CCUS ambitions, refer to our Equinor Corporate New Energy and Wintershall
Dea reports.
Malaysia taps bank of PETRONAS to support economic recovery
Andrew Harwood, 30 August 2022
The facts: PETRONAS’ Q2 financial results showed a 57% increase in revenues to RM172 billion (US$42 billion), with profits
after tax up 147% to RM46 billion (US$11.3 billion). Higher prices, and a 2% increase in upstream production drove revenues
up, with cash flows from operating activities hitting RM62.4 billion (US$15 billion).
Our take: In keeping with the rest of the industry, higher prices and strong operational performance are enabling PETRONAS to
boost capital investment, strengthen its balance sheet and pass returns to shareholders – the key beneficiary in this case being
the Malaysian government.
PETRONAS will pay RM50 billion (US$11.4 billion) in dividends in 2022. An additional RM25 billion dividend was declared,
on top of the RM25 billion announced in February 2022. With a net cash position of RM141 billion, PETRONAS can easily cover
the payment, but obligations to its key shareholder will remain a consideration in future capital allocation plans.
Low carbon business split out under new Gentari subsidiary. In a reshuffle of its business units, PETRONAS’ clean energy
activities were separated from its Gas & LNG operations. The new subsidiary will accelerate low carbon investments in three
area: - renewable energy, hydrogen, and green mobility.
Exit from Azerbaijan confirmed, with further portfolio optimisation on the cards. PETRONAS is understood to be seeking
buyers for its remaining Africa upstream position, having previously agreed deals to exit Chad and South Sudan. PETRONAS
currently produces around 100 kboe/d from Egypt and South Sudan, but also holds exploration positions in Senegal, Gabon and
Angola. It is also believed to have restarted efforts to divest its 74% stake in South African fuel retailer Engen.
Woodside reports first post-merger financials
Andrew Harwood, 30 August 2022
The facts: Under its new guise as Woodside Energy Group, Australia’s largest listed oil and gas operator reported its first
post-merger financial results, hitting a record US$5.8 billion in operating revenues for the half-year to June 2022. Net profit after
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tax rose five-fold to US$1.6 billion, paving the way for a giant US$2.1 billion interim dividend payout, equivalent to US$1.09 per
share.
Our take: The merger with BHP, completed in June 2022, is doing everything it was supposed to, and then some.
BHP business adds scale. With one month of contribution from BHP Petroleum, Woodside’s production for the six-months
rose 19% to 300 kboe/d. Significantly higher oil and gas prices, supported by an increased exposure to spot gas prices via the
Pluto-KGP Interconnector, flowed into record revenues. High prices also resulted in a US$1.1 billion payment to Woodside on
completion of the merger, taking free cash flow to US$2.6 billion.
Record cash flows feed shareholder returns and balance sheet strengthening. In addition to supporting an interim payout
at the top end of its dividend policy, Woodside has reduced its gearing ratio to 6.8%, from 21.9% at the end of 2021. As a result,
Woodside has amended its gearing target to 10-20%, down from 15-35%. Building balance sheet strength provides Woodside
flexibility ahead of its major upcoming investment programme. The company remains committed to selling down an upstream
stake in the flagship Scarborough LNG project but does not need to rush.
Greater optionality from merged portfolio. Major growth projects Scarborough and Sangomar remain on track, although
commissioning of the Sangomar FPSO will move to Singapore from China to provide schedule certainty. Mad Dog Phase 2
could yet be delayed into 2023.
Longer-term, Trion in Mexico is moving into focus, while Browse, Calypso and Sunrise continue to be assessed for development
potential. The New Energy portfolio is progressing as Woodside seeds investment across hydrogen, solar and CCUS
technologies. Further detail of portfolio optimisation plans will be revealed at Woodside’s investor day in December.
TotalEnergies to sell its stake in Russia’s Termokarstovoye gas condensate
field
Tom Ellacott and Michael Moynihan, 30 August 2022
The facts: On 26 August, TotalEnergies announced it had agreed to sell its 49% stake in Terneftegaz, which operates the
Termokarstovoye gas condensate field in Russia, to NOVATEK. TotalEnergies expects the deal to close in September 2022.
The consideration is ‘on economic terms, enabling TotalEnergies to recover the outstanding amounts invested in the field’. The
company reported US$573 million of capital employed in the asset in its 2021 annual report. Production averaged 38 kboe/d, of
which condensate made up 12 kboe/d.
Our take: the deal is in line with TotalEnergies’ gradual suspension of its activities in Russia that do not contribute to European
security of energy supply. The exit from Termokarstovoye follows the sale of its 20% stake in the Kharyaga oil project to
Zarubezhneft. TotalEnergies has also mothballed its Russian lubricants and batteries businesses.
The announcement capped a difficult week for TotalEnergies. The company released a robust rebuttal to reports in the Le
Monde newspaper that it had supplied feedstock from Terneftgaz for jet fuel used by the Russian military. TotalEnergies
categorically denied all the allegations in the article. The Termokarstovoye sale process also significantly pre-dated the Le
Monde report.
TotalEnergies continues to participate in the Yamal LNG project which supplies LNG to Europe. But the company must be
weighing up its options for the remainder of its business in Russia, which includes a 19.4% stake in NOVATEK. It’s telling that
TotalEnergies will provide an outlook excluding Russia in its Strategy Update on 28 September. Could a complete exit from
Russia be on the cards?
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TotalEnergies will be monitoring other companies seeking to exit. ExxonMobil reported last week that its planned exit has been
blocked by the recent presidential decree that prevents companies from selling stakes in certain projects until the end of 2022.
In response, the company has issued a "notice of difference" to Moscow to start negotiations over its proposed exit from
Sakhalin-1.
We look at what's next for companies in Russia in Q2 Round-up: Corporate impact of Russia-Ukraine.
PetroChina and CNOOC Ltd. post record profits, Sinopec Corp held back by
downstream
Yuqi Hu and Kavita Jadhav, 29 August 2022
The facts: Q2 net income increased by 103% for CNOOC Ltd. (CNOOC) and 71% for PetroChina, whereas Sinopec Corp
(Sinopec) saw a decrease of 2% y-o-y. PetroChina and CNOOC benefitted from high prices in their upstream segments. All
three companies announced generous dividend payouts.
Our take: PetroChina and Sinopec are majority state-owned entities and have the additional responsibility to absorb some of
the price increases. As they can only capture a part of the upside from high prices, we do not see the same magnitude increase
in profitability as other parts of the industry have been reporting. Sinopec, which is a majority downstream company, was
impacted in part due to regulatory price controls which do not allow full passthrough of higher feedstock costs. Similarly,
PetroChina would have seen a much higher increase in net income if not for regulatory controls on gas prices that restricted
margins.
•
Production: CNOOC’s Q2 production increased by 10%, PetroChina by 3%, and Sinopec Corp by 2% y-o-y. All three
Chinese NOCs increased gas production in continuing support of China’s policy to substitute gas for coal – gas production
increased by 13% for CNOOC, 4% for PetroChina, and 3% for Sinopec.
•
Capex: cost inflation is being felt across the board, and rising cost pressure held back capital spend. PetroChina reported a
10% increase in lifting costs due to higher power and operating costs. H1 2022 spending accounted for 38% of the full-year
target for PetroChina, 33% for Sinopec and 44% for CNOOC.
•
Energy transition: PetroChina highlighted that it had obtained approvals for 5,360 MW of wind and solar power generation
with an annual target to raise this to 20,000 MW. CNOOC has started construction of the first deep-sea floating wind farm
demonstration project.
•
Shareholder returns: Sinopec’s board followed CNOOC in approving its first-ever share buyback program. CNOOC
declared a record-high dividend of HK$ 0.70 per share. CNOOC’s interim dividend increased by 133% and PetroChina by
55%, while Sinopec was flat y-o-y.
Eni and TotalEnergies strike gas offshore Cyprus
Greig Aitken, 26 July 2022
The facts: Eni and partner TotalEnergies have announced a significant gas discovery offshore Cyprus. Cronos-1 was drilled in
more than 2,000 metres of water in Block 6 and discovered net gas pay of 260 metres. Eni estimates total volumes of gas in
place at 2.5 tcf. Cronos follows the discovery of Calypso on Block 6 in 2018.
Our take: Based on in-place resources, we think the field could hold 1.75 tcf of gas resources. However, the Tungsten Explorer
drillship has now moved west to drill a second accumulation within the same carbonate structure. A successful well could double
estimated resources.
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Since the Tamar (Israel) discovery in 2009, more than 80 tcf of gas has been found in the Eastern Mediterranean – of which, Eni
has discovered more than 30%.
As with all Cypriot discoveries, commercialisation of Cronos will be far from straight-forward. There is no material domestic
market in Cyprus. The most advantaged export route would be a tie-in to existing Egyptian LNG infrastructure.
Leveraging existing facilities would also provide the lowest cost development solution. We anticipate both ELNG and Damietta –
Eni is a 50% shareholder in the latter – will have ample spare capacity late this decade. Eni’s established position in Egypt’s gas
market at a time when Zohr may come off plateau make this a compelling proposition.
Read the Inform for more details.
FERC allows Berkshire to increase its stake in Occidental
Robert Polk, 21 August 2022
The facts: Berkshire Hathaway received US Federal Energy Regulatory Commission (FERC) approval to buy up to 50% of
Occidental Petroleum’s common stock. Berkshire owns 20.2% of common stock, aggressively building its position in recent
months. Berkshire’s common equity stake is in addition to the US$10.0 billion of preferred equity it holds in Oxy.
Our take: Berkshire’s request and subsequent approval is both procedural and telling. Approval to go beyond a 25% stake was
necessary because Oxy owns FERC-regulated power and chemical plants in Louisiana that supply power to a grid also supplied
by Berkshire Hathaway Energy. Approval was necessary to ensure that Bershire’s increased stake in Oxy would not influence
the local electricity market.
Approval permits Berkshire to continue building its stake, but it does not require Berkshire to do so. Still, applying illustrates an
appetite to increase. Oxy has reached an inflection point with substantial year-to-date debt reduction paving the way for a
stronger pivot towards shareholder returns. With an unhedged production profile and a rapidly improving balance sheet, Oxy’s
stock provides attractive leverage to commodity prices.
Berkshire’s request amplifies the notion that it could ultimately take over the entire company. It wouldn’t necessarily change
anything on Oxy’s outlook though. Warren Buffett seeks value, cash flow, and good management. He has consistently praised
Oxy’s management team and seems to approve of the current strategy and focus. Oxy’s heavy investment in carbon capture is
set to benefit from provisions in the Inflation Reduction Act.
Berkshire’s activity has helped prop Oxy stock up in recent months relative to other oil peers. That dynamic could also support a
slower, more gradual build going forward.
Oxy’s share price traded between US$55-62/share from mid-June and July when Berkshire was most aggressively buying. The
19 Aug 2022 disclosure contributed to an almost 10% jump on the day to US$71.29/share. It is Oxy’s highest closing price since
the Anadarko acquisition in 2019. Berkshire also owns 83.9 million in warrants with a US$59.62 strike. With a share price above
US$70/share, that becomes a stronger consideration despite the dilution impact.
Berkshire’s action is not an indication so much as it is an option, although additional purchases seem given. The question is
when and how much. Like many others, we will be watching closely.
How is inflation impacting upstream budgets globally?
Raphael Portela, 18 August 2022
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A faster-than-expected demand recovery has strained an already tight oil and gas market, driving operators to increase budgets.
Upstream investment at the start of the year had already rebounded 18% versus 2021. That number is now higher at 21%, only
7% below 2019 levels.
The number one culprit is inflation, affecting close to 80% of revisions. Higher prices were seen across the board encompassing
goods, services, and labour. Activity uptick is the second most mentioned category, affecting over half of announcements.
Investment revisions are concentrated within North America, especially in the US and Canada. Larger uplifts are observed
among the smaller-sized E&Ps within our Focused US and Canadian peer groups. Diversified Independents – composed of
larger-than-average US-based operators – come in a farther third place.
Big Oil has been mostly immune for now. Out of the Majors, only TotalEnergies has raised its guidance. But the uplift is modest
and part of the increase is due to renewables business development (in addition to incremental short-cycle opportunities).
Larger players are more shielded from inflation thanks to 1) better negotiating power stemming from scale/volume, and 2)
prevalence of long-term contracts in place.
Caution is palpable. The sector’s response is nowhere near what happened in 2014 – a time when E&Ps were fighting over rig
counts. Quite to the contrary. Many players haven’t kept pace with inflation in 2022. To find out more, read our recently
published insight on the topic.
Santos releases record 2022 half-year results
Andrew Harwood, 17 August 2022
The facts: Santos’ 2022 half-year results reflected the first full six-month contribution from Oil Search, as well as bumper oil and
gas prices. Revenues rose 85% on 2021 H1 to US$4 billion, free cash flow hit US$1.4 billion and profit before tax was up 240%
to US$1.6 billion.
Santos added another US$100 million to its previously announced US$250 million buyback programme and lifted its interim
dividend to 7.6 cents per share, a 38% increase on 2021 H1.
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Santos also updated on several of its growth projects, sanctioning its Pikka oil project in Alaska, delaying the Dorado
development, and flagging the potential sell-down of a 5% stake in PNG LNG.
Our take: The share price fell 2% but Santos continues to build a steady platform from which to capture long-term value.
Record results enable further financial strengthening. Santos’ net debt to equity gearing (excluding leases) fell from 24% at
the end of 2021 to 17%, well below Santos’ upper limit of 25% and providing an important safety net against future volatility.
Disciplined approach makes sense. Questions were asked on the investor call on why not further increase shareholder
returns. Shareholder distributions equated to 35% of 2022 H1 free cash flow before growth capital investments. But Santos is
set to enter a period of major capital investment that could stretch the balance sheet if prices were to fall. That said, Santos is
already working its larger, post-merger portfolio to manage commitments – capital guidance for the year was lowered slightly to
US$2.5-2.6 billion, down from US$2.6-2.7 billion, reflecting a reduction in Pikka development costs and the delay to Dorado.
Pikka FID provides production growth and oil hedge. Pikka (W.I. 51%, operator) generates a return of 20% under our
US$60/bbl long-term assumption, with Santos committed to a net-zero project on a Scope 1 and 2, equity share basis. Santos
had been expected to divest its Alaska business, but now believes there is greater value to be had by holding the project,
particularly as bid-ask spreads in the M&A market widen. Santos remains open to divesting during the development phase.
Dorado deferral and PNG LNG sell down highlight value of portfolio optimisation. Delay of Dorado FID into 2023 reflects
rising supply chain pressures and an opportunity to optimize the development concept to incorporate the nearby Pavo
discovery. Advanced talks around a sell down of a 5% stake in PNG LNG (W.I. 42.5%) provide the opportunity to unlock value
from the Oil Search merger, reduce portfolio value concentration, and take advantage of strong LNG valuations. Meanwhile, the
Barossa and Moomba CCS projects remain on-track, hitting 43% and 20% completion respectively.
Aramco posts biggest quarterly profit of any listed company
Kavita Jadhav and Yuqi Hu, 16 August 2022
The facts: Saudi Aramco’s Q2 net income increased by 90% year-on-year to hit a quarterly record of US$48.4 billion, mainly
driven by higher realised oil prices, increased production and improved downstream margins. Q2 production was 13.6 Mboe/d,
up from 13 Mboe/d in Q1.
Surging quarterly free cash flow (+53% y-o-y to US$34.6 billion) supported higher investment. Capital expenditure increased by
25% y-o-y to US$9.4 billion in Q2 2022. Gearing stayed steady at 8%, the same level at the end of Q1 2022, but down from
14% at the beginning of 2022. Aramco maintained its quarterly dividend at US$18.8 billion and completed a 1 for 10 bonus
share issuance in the quarter, completing the capitalisation of US$4 billion of retained earnings.
Our take: Aramco guided that it would finish the year at the lower end of its full-year investment guidance of US$40-50 billion,
irrespective of inflationary conditions and efforts to increase production.
Analyst questions focused on what Aramco would do with surplus cash if it did not increase dividend or capital spend. The
company referred to international projects for which negotiations are underway. The plan is to gradually increase capital spend
to 2025 and then stabilise. Investment will go towards increasing crude oil “Maximum Sustainable Capacity” from 12 Mb/d to 13
Mb/d by 2027. Aramco has recently floated EPC tenders to scale-up production on Safaniyah, the world's largest offshore oil
field, with plans to add 0.7 Mb/d of incremental oil capacity.
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This quarter saw Aramco agree to buy the lubricants division of the US company Valvoline in an all-cash purchase of US$2.65
billion, subject to regulatory approvals. The acquisition will allow Aramco to own the Valvoline brand for all products globally,
marking another step change in Aramco’s downstream expansion.
Aramco also launched its inaugural sustainability report this quarter. The report details how Aramco will achieve net zero
emissions across wholly owned operated assets by 2050. Interim targets include capturing, utilizing, or storing 11 MtCO2e
annually by 2035; investing in renewables that aim to generate 12 GW of solar and wind power by 2030; producing 11 Mt of
blue ammonia, a carrier of hydrogen, annually by 2030. These targets rival the new energy growth plans of many of the Majors.
PetroChina, Sinopec to voluntarily delist from NYSE
Kavita Jadhav and Yuqi Hu, 15 August 2022
The facts: PetroChina and Sinopec Corp have notified the New York Stock Exchange (NYSE) of their intention to voluntary
delist. The companies which have been listed on the NYSE since 2000 cited low trading volumes, high costs and regulatory
issues for their decision. Sinopec Corp's subsidiary Shanghai Petrochemical Company also announced delisting. Company
filings stated that delisting would complete around 8 September.
Our take: The delisting takes place amid rising tensions between the US and China. The US Securities and Exchange
Commission had added PetroChina and Sinopec Corp to a list of Chinese companies which could be delisted in 2024, if they did
not comply with US audit rules. These rules require foreign inspection of audit documents, which China does not permit due to
national security concerns. The state owns 80% of PetroChina and 69% of Sinopec Corp (as of December 2021). Sinopec Corp
has a 50% interest in Shanghai Petrochemical company.
State-owned peer CNOOC was forced to delist from the NYSE on security grounds in 2021. US investors, including investment
funds, have been barred from buying CNOOC shares and had to divest any holdings. This impacted CNOOC’s fundraising
ability, leading the company to list on the Shanghai Stock Exchange (SSE) in 2022.
Unlike CNOOC, this voluntary delisting should not impact PetroChina and Sinopec Corp’s fundraising ability. The American
Depositary Shares (ADS) represent a small percentage of total share capital. For PetroChina, ADSs account for 3.93% of the
shares traded on the Hong Kong Stock Exchange (HKSE) and approximately 0.45% of the total share capital. PetroChina and
Sinopec Corp are already listed on the HKSE and SSE. The delisting is not expected to impact the ability of US investors to
trade in their shares in Hong Kong and Shanghai.
PetroChina and Sinopec Corp’s share prices were down 3.7% and 2.6% today on the HKSE, reflecting some investor concern
around rising geopolitical risk.
Chevron rumoured to be entering offshore Namibia block
Alex Beeker, 12 August 2022
The facts: Last week media outlets reported Chevron is set to enter an ultra-deepwater block offshore Namibia. The block is
just north of TotalEnergies’ Venus discovery made earlier this year.
The Venus discovery surpassed pre-drill estimates of 1.5 – 2 billion barrels and we conservatively estimate recoverable volumes
of over 3 billion barrels.
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Earlier this year, Shell also made a large oil discovery (Graff-1) in the Orange sub-basin offshore Namibia. The two together
have generated massive interest in the region. Namibia could be on its way to becoming the next Guyana. For context, 26
discoveries have been made at the Stabroek block in Guyana leading to over 11 billion boe of estimated recoverable resources.
Our take: If the deal goes through, Chevron could be getting in on the ground floor of a massive new oil play. A lack of pre-FID
projects relative to peers, especially in deepwater, is a weakness of the company that we highlighted earlier this year in the
Chevron corporate report.
Deepwater accounts for just 12% of Chevron’s upstream NPV compared with an average of 26% for the rest of the Majors. The
company has taken steps to address the shortcoming by bidding on acreage in deepwater Egypt after the addition of Noble
Energy in 2020 – which gave the company a foothold in the region.
With US$12 billion of cash on the balance sheet and plenty more on the way if prices hold, Chevron is in a strong position to
make a bold entrance into Namibia. The company is generating massive cash flow right now without an obvious place to put it.
Buyback guidance of US$5-10 billion per year can’t go much higher without drawing criticism from regulators. Capex guidance
of US$15-17 billion is relatively fixed through 2026. As a result, cash driven M&A and/or exploration farm-ins are a great use of
incremental cash flow for the company.
Ørsted raises FY 2022 guidance but expectations for offshore wind fall
Akif Chaudhry and Norman Valentine, 12 August 2022
The facts: Ørsted reported EBITDA of DKK3.6 billion (c.US$0.5 billion), excluding farm-downs, for Q2 2022, an increase of 27%
on the prior year but below expectations.
CHP plants once again bailed-out the quarter’s earnings, benefiting from persistently high European power prices. Onshore
renewables (predominately US wind assets) also put in a strong performance, driven by greater generation from new assets as
well as higher power prices across Europe and the US.
However, despite wind speeds up on last year – although still below average – and ramp-up of Hornsea 2 production, EBITDA
from offshore wind was down 12% on Q2 2021 levels (excluding farm-downs). In part, this reflected lower generation from
Borssele 1 & 2, following a 50% sell down in May. But significantly, the drop also reflected another hit from overhedging, largely
due to slower than expected commissioning at Hornsea 2. The total charge from the hedging effect in the first six months was
DKK2 billion (c.US$0.3 billion).
Our take: Ørsted reported another quarter that demonstrated it’s not plain sailing in the core offshore wind market. With supply
chain constraints and inflationary pressures ongoing, the risk in the near-term will remain on the downside.
Whilst overall guidance for FY 2022 was increased by 5% – EBITDA range (excluding farm-downs) now at DKK20-22 billion –
this could have been even more bullish were it not weighed down by the offshore wind business.
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FY 2022 guidance change: breakdown
The share price unsurprisingly suffered, down 8% on the day when most major markets finished trading broadly flat.
Ørsted’s results were, however, underpinned by its increasingly diversified approach. Ørsted has set itself a challenging target
to grow its onshore renewables business from around 4 GW of current gross installed capacity to 17.5 GW by 2030. As
competition in offshore wind is rapidly intensifying, especially in more mature markets, geographical and technological
expansion are key to Ørsted’s future growth.
Its acquisition of Ostwind, a developer of onshore renewables in the German and French markets, and its entry into the Spanish
renewables market earlier in the year, are meaningful steps to executing this strategy. It’s onshore position now covers four key
European markets alongside its established footing in the US.
Please also see our recent Insight that analyses why offshore wind will deliver 25% higher cash margins than upstream oil and
gas, using our new metric – operating cash flow per GJe.
Shell and Ecopetrol confirm Colombian offshore gas province
Raphael Portela, 11 August 2022
The facts: Shell’s Gorgon-2 appraisal well verified the presence of gas in Colombia’s southern Caribbean ultra-deep waters.
With a water column of about 2,400 metres, the largest carried out in Colombia, the well confirms the extension of the Gorgon-1
gas discovery made in 2017 in Block COL-5 and the existence of an offshore gas province in Colombia, in which the Kronos
(2015) and Purple Angel (2017) discoveries were also made. Shell operates blocks COL-5, Purple Angel and Fuerte Sur with a
50% stake. Ecopetrol holds the remaining interest. The announcement comes just a few days after Petrobras found gas further
northeast in the Tayrona Block (44% WI), also partnered with Ecopetrol (56% WI).
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Our take: Offshore Colombia is regaining momentum. We believe deepwater gas will become an important theme for the
country as its supply-demand gap widens starting in 2024. Ecopetrol and its partners are pursuing high-impact exploration for
large gas resources to tackle dwindling domestic reserves and supply the local market.
Colombia: offshore block operatorship
But the challenges are many. We currently classify offshore Colombian gas as contingent resources. It is a frontier area which
will require costly infrastructure buildout. Politics is another obstacle. Gustavo Petro became Colombia’s president this week,
and his criticism of the fossil fuels industry was a key part of his campaign. Remarks hinted at an end to new licensing rounds
and opposition to fracking.
We feel the path forward will be one of compromise. Tough regulations or bans would adversely impact no company more than
the state-owned Ecopetrol. Colombia is not a key region for Shell or Petrobras. On the other hand, Ecopetrol is betting on
offshore and unconventionals to replenish its mature domestic resource base. And we are starting to see a moderation in
Petro’s stance. Ocampo, the newly appointed finance minister, has stated that it was fundamental for Colombia to continue
exploring for gas. Still, there is no doubt that these regulatory risks will be factored into medium-term business decisions.
Devon Energy rings the bolt-on bell again
Dave Clark, 9 August 2022
The facts: Devon Energy announced an all-cash US$1.8 billion “bolt-on” acquisition of Validus Energy, an Eagle Ford pure-play
assembled from assets previously purchased from Ovintiv in March 2021. The deal involves 42,000 net acres in Karnes County
proximate to Devon’s position in DeWitt and Karnes Counties. The acquisition also adds 35 kboe/d of oily (70% of mix)
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production, as of July, and about 350 drilling locations (with a kicker of 150 “high-quality refrac candidates”). Deal is expected to
close at the end of Q3.
Our take: This deal is the second major mature basin bolt-on in just two months for Devon, following one about half this size in
the Bakken in June (RimRock, US$865 million, see 10 June CWiB story). The Validus acquisition essentially doubles Devon’s
position in the Eagle Ford, now 82,000 net acres, ~73 kboe/d of production. Devon highlights that the acquisition, like the
RimRock deal, is valued at about 2x cash flow at strip pricing, and will be accretive to all cash flow, earnings and value metrics.
Devon has reduced book gearing from 40% at year-end 2020 to about 23% as of Q2 2022, and this all-cash deal will nudge it
back up towards 28%. But the company emphasizes that net debt/EBITDAx will hardly budge and should be at 0.4x by yearend. Given Devon’s formidable cash generation, gearing could easily be back down towards 20% by Q1 2023. Devon highlights
about US$50 million of annual synergies/efficiencies, which will have NPV10 of US$200-300 million depending on how many
years we assume they can capture that benefit.
A big question for the large cap E&Ps, most of whom are generating massive free cash flow, has been what to do with all the
cash. Returning cash to shareholders is obviously the primary investor mandate, but once balance sheets have reached an
optimal state, even a 75% payout of free cash flow via dividend and buyback leaves a large 25% slug of FCF. For some it may
mean just paying out close to 100% of FCF instead of only 50-75%. Some are choosing to build cash on the balance sheet as
insurance against a recession. Others are easing organic spending a bit higher.
Devon's strategy for that "windfall cash" is increasingly clear – chunky strategically-aligned bolt-ons that leverage their mature
basin positions, where infrastructure is in place, synergies and optimization potential exists, and inventory life can be extended
efficiently. Barred by the market from organic growth, inorganic growth from reasonably-valued bolt-ons with strategic fit is a
sound strategy. The market approved – DVN stock was up 2.6% on the day versus the broader E&Ps ~+1%.
Record-breaking quarter for L48 E&Ps could mark a peak
Dave Clark, Alex Beeker, Robert Polk and Raphael Portela, 5 August 2022
The facts: 29 US independents reported Q2 results this week, including key large caps ConocoPhillips, Occidental, EOG,
Pioneer and Devon. We take a look at the aggregated data for these plus the seven that reported last week, adding some
qualitative thoughts on trends in the quarter.
Our take: It was a quarter of huge, record-breaking earnings and cash flow for most. But there were some hiccups, and the
stocks faced some headwinds over the last two weeks due to falling commodity prices. Hedging was much less of a dark cloud
in Q2, but inflation and service constraints certainly remain. Below we highlight some key takeaways:
Cash flow generation: Aggregate operating cash flow (ex-working capital) of US$44 billion was up about 18% q/q for the
group. Three companies delivered more than US$3 billion of OCF and together accounted for over a third of the peer group total
– ConocoPhillips (US$7.8 billion), Occidental (US$5.1 billion) and Pioneer (US$3.5 billion).
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Q2 2022: sources and uses of cash
Source: Wood Mackenzie Corporate Service
Distributions: Shareholder distributions went through the roof in Q2, climbing 60% q/q from US$9.5 billion to US$15.2 billion.
Annualized, that is an over 10% yield on the group’s aggregate market cap as of 5 August. Both dividends and buybacks
climbed, but repurchases took the lead in the quarter (US$7.7 billion vs US$7.5 billion dividends).
Budgets, activity, inflation – Most of the group has now raised capex either in Q1 or Q2. By our count, only four US E&Ps
have stuck with their original 2022 budgets through Q2 – Occidental, EOG, Chesapeake and Range Resources. Inflation
remains the primary driver of increases, though a handful of companies have modestly increased activity. Overall reinvestment
rates remained at the same level as Q1 (33%).
L48 change in capital expenditure guidances
Source: Wood Mackenzie, company reports. *SilverBow has raised its guidance by 66% but primarily due to acquisition. To improve chart
readibility, its capex uplift is capped.
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Balance sheets – Aggregate gearing ratio went from 32% to 28% in the quarter. Net debt fell more precipitously (-US$9.6
billion vs -US$5 billion drop in Q1), but was offset by a US$3 billion build of cash on the balance sheet. There was some
opportunistic buying of discounted bonds as interest rates rose (Diamondback, Antero and Ovintiv, among others).
LNG/gas strategies. LNG continues to be a major theme for the US E&Ps. ConocoPhillips signed a high-profile HoA with
Sempra to develop Port Arthur LNG, but other companies made some LNG-related moves as well. Chesapeake signed a gas
supply deal with Golden Pass LNG commencing in 2024.
Preliminary 2023 outlook: Still too early for anything firm, but everyone has started contracting early. Numerous companies
said they would have activity levels similar to 2022. For some, that means another year of “stay flat” mode (e.g., FANG, MRO).
Pioneer sees 10% inflation next year. Some headwinds to growth are emerging, including Texas power disruptions and
Haynesville bottlenecks.
For more detail on US independents’ Q2, see our Earnings Summary inform.
Accelerating corporate decarbonisation through the Inflation Reduction Act
Rachel Schelble, 5 August 2022
The facts: If passed, the Inflation Reduction Act (IRA) will result in a large boom in decarbonisation over the next 10 years. This
is one of the largest public investment proposals in the history of the United States energy sector, and will impact power,
emerging decarbonisation technologies and commodity supply.
One of the biggest impacts of the IRA on oil and gas corporates is a proposed increase in the 45Q tax credit for point-source
carbon capture and dedicated storage to a flat USD$85/tonne starting in 2023. Proposed increases for direct air capture (DAC)
range from USD$130/tonne for enhanced oil recovery (EOR) projects and USD$180/tonne for subsurface storage.
Another potentially impactful part of the IRA on corporates is the proposal to impose a methane fee on facilities with a methane
intensity greater than 0.2%. The initial fee would be USD$900/tonne in 2024, with a planned increase to USD$1,500/tonne in
2026.
Read more about Wood Mackenzie’s take on the IRA in our insight, Pedal to the metal: The Inflation Reduction Act will
accelerate decarbonization in the United States.
Our take: The energy industry has been lobbying for increases in the 45Q tax credit for years as they struggle to scale-up their
decarbonisation projects from the planning or pilot phase. We will see large-scale projects like ExxonMobil’s USD$1 billion
planned Houston Ship Channel carbon sequestration hub accelerate with the certainty of a supportive incentive structure.
Additionally, if the IRA bill passes, leases that were awarded in the November 2021 Gulf of Mexico Lease Sale 257 would be
reinstated. This lease sale, the largest in US history, brought a spotlight onto offshore carbon capture and sequestration (CCS)
in the Gulf Coast with a record number of bids for shallow water shelf blocks (water depth less than 200 metres). Offshore
storage of CO2 is critical for large-scale Gulf of Mexico CCS projects to progress.
Direct air capture is one of the most expensive decarbonisation technologies being tested, and Occidental Petroleum is leading
in the development of this technology. It’s USD$800 million to USD$1 billion Permian DAC facility will begin construction in H2
2022, and the 45Q tax credit is a critical profitability lever that will progress Oxy’s DAC project to commercial scale. In addition to
45Q, Oxy has other profitability pathways including leveraging the carbon markets, and through the sale of “net zero” oil. Read
more about how Oxy can leverage DAC tied to EOR projects in the carbon markets.
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The US oil and gas industry has a razor-sharp focus on reducing operational emissions. The “carrot” for reducing methane
emissions has been the ability for companies to implement solutions that can be cost recovered by the additional revenue
generated from natural gas sales. The IRA methane fee will act as a “stick” for those companies that are moving too slowly with
implementing change.
Sval acquires Suncor's Norway portfolio
Neivan Boroujerdi and Scott Walker, 5 August 2022
The facts: on 5 August 2022, Suncor Energy announced it had sold its Norwegian business to Sval Energi, a HitecVisionbacked vehicle, for US$320 million. The portfolio contains two commercial assets: Oda and Fenja.
The commercial effective date is 1 March 2022, and the deal is expected to be closed before the end of the year. The
transaction is subject to approval from the relevant Norwegian authorities.
Our take: we value the portfolio at US$257 million (NPV10, US$60/bbl long-term, March 2022), a 20% discount to the
consideration. This suggests Suncor has achieved an attractive exit price, particularly considering the majority of our valuation is
associated with under development Fenja asset which still carries execution risk. But while both Oda and Fenja have suffered
reserve downgrades since FID, the portfolio is cash-generative and there is upside to go after.
With a gearing ratio of 29%, Suncor is by no means a cash strapped seller but having been active in Norway since 2016, the
business had reached a crossroads. Exploration efforts – including a brief foray into the Barents Sea – have largely
underwhelmed and delivering further growth beyond Fenja has been a challenge.
For Sval, the deal will add 4,000 boe/d of production in 2022, increasing to 7,000 boe/d in 2024 following the ramp up of Fenja.
It takes Sval's total output up to 95,000 boe/d in 2024, just shy of its 100,000 boe/d target.
Sval is part of HitecVision's "VII" fund which closed in 2019, so it has time on its hands to ready the vehicle for monetisation. A
merger with its UK-focused vehicle NEO Energy is a potential next step, which could help build a bigger, more diversified panNorth Sea independent prior to an eventual IPO.
APA Corporation acquires Permian acreage for US$555 million
Raphael Portela, 4 August 2022
The facts: APA Corporation confirmed rumours of a tuck-in Delaware Basin acquisition. The assets, primarily in the Loving and
Reeves counties, are near existing operations and include a mix of PDPs, several wells in the drilling and completion process,
and an inventory of undrilled locations. The seller was not disclosed but is likely the private player Titus Oil & Gas.
Our take: For APA, the Permian is all about upkeep. Focus on the region is slowing as activity in Suriname and Egypt ratchet
up. The current ambition is to keep output flat, though the Permian remains APA’s top producing province.
Within that context, the E&P’s latest portfolio decisions hope to streamline its Delaware position. Initial dealmaking focused on
non-core divestitures, such as the US$850 million mineral rights sale in February 2022. But this latest move is accretive,
renewing the company’s commitment to stabilising output – US production dropped from 242 kboe/d in Q2 2021 to 200 kboe/d
this quarter.
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Our initial read is positive. Knowledge of adjacent acreage allows APA to exploit several zones with lower-than-usual risk while
leveraging existing infrastructure. The acquisition also comes bearing gifts – a high-quality rig and experienced crew, something
hard to come by in this tight service environment.
And APA needs those quality service contracts. New crew inefficiencies and increased regional competition for experienced
employees have taken a toll on its outlook. Despite the acquisition’s 12-14 kboe/d uplift, production guidance for 2022 has been
revised downward by 2%. Delays to well completion schedules in the Permian and Egypt were cited during its earnings call.
Results from the Austin Chalk delineation also came back mixed – that rig will now move back to the Permian.
*Average production curves in the Loving and Reeves countries within the Delaware Basin.
Saudi Aramco to acquire Valvoline lubricants business
Kavita Jadhav and Yuqi Hu, 3 August 2022
The facts: Saudi Aramco has agreed to buy the lubricants division of a US company Valvoline in an all-cash purchase of
US$2.65 billion, subject to regulatory approvals. It will own the Valvoline brand for all products globally.
Our take: Aramco’s upstream portfolio dominates its overall business, but it has big ambitions to diversify through downstream
growth. Completion in 2020 of the US$69 billion acquisition of a 70% share in SABIC transformed Aramco into one of the
world’s leading petrochemicals players, highlighting the scale of its ambitions.
The acquisition of Valvoline’s lubricants division marks another step change in Aramco’s downstream expansion. The deal
provides access to the global lubricants market through a strong brand with global recognition. This would have been difficult for
Aramco to achieve organically.
The acquisition also enables the direct sale of Aramco crude into more complex, high-value products. Like the Majors, Aramco
can now develop its own high-quality lubricants and base oils business.
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BP earnings soar but guidance holds
Luke Parker, 2 August 2022
BP rounded out the Majors’ Q2 reporting season with another set of bumper earnings. Underlying profits of US$8.5 billion came
in way ahead of sell side analyst expectations, buoyed by an exceptional quarter for refining and oil trading. Shareholders will
see a 10% hike in the dividend and buybacks amounting to 60% of surplus cash flow this year.
But leadership was keen to emphasise continued discipline amid uncertainty. The business is being run at a cash balance point
of US$40/bbl Brent, with seemingly no prospect of the purse strings loosening any time soon.
Read our Reported results analysis for detail.
Euromajors Q2 results round-up
Luke Parker, 29 July 2022
It was another quarter of huge profits for the Euromajors. Excess cash continues to be directed toward strengthening the
balance sheet and increasing shareholder distributions. But investment plans for this year and beyond held firm – no one is
hiking spend just yet. Strategy, guidance and capital allocation priorities remain largely unchanged.
BP: Underlying profits of US$8.5 billion came in well ahead of analyst expectations, falling just shy of a new record for the
company. Results in the Customers and Products segment stood out, underpinned by eyewatering refining margins (BP’s RMM
was US$45/bbl) and an “exceptional” quarter for oil trading. Shareholders reaped the benefit, seeing a 10% hike in the dividend
and buybacks amounting to 60% of surplus cash flow (in line with previous guidance).
Eni: Strong commodity prices led to another spectacular quarterly performance. This time downstream also popped due to
buoyant refining margins and high utilisation rates. Shareholders were the big winner. Lofty oil prices have triggered bumper
distributions from the variable scheme, with €2.4 billion of buybacks in addition to range-topping dividends.
Equinor: Adjusted net cash on the balance sheet climbed to US$12 billion, equivalent to net gearing of -39%. Shareholders
distributions got another boost, with Equinor increasing both the 2022 buyback programme and extraordinary dividend. Total
distributions will now exceed US$13 billion this year, compared to a pre-pandemic 5-year average of US$3 billion.
Shell: Earnings and cash flow from operations hit record levels for the second successive quarter. Investors are reaping the
rewards. Dividends and buybacks will hit a record $8 billion in Q3 alone, and Shell expects shareholder distributions to stay
above 30% of CFFO for as long as current market conditions persists.
TotalEnergies: Deleveraging continues, with gearing down to 10% and a new target of 5%. But the French Major ruled out
large-scale M&A for now – multiples for big renewables targets are still too high. The 2022 budget nudged up by US$1 billion,
but guidance remains at US$14-16 billion per year to 2025. TotalEnergies said it will exclude Russia from its strategic plans at
its Investor Day in September, perhaps signalling that an exit is looking more likely?
Repsol: The Iberian Mini-Major had a tougher time of it. Repsol’s share price slid 5% as earnings came in below expectations
and the company suffered a €1 billion refining impairment. The risks associated with a Spanish windfall tax were probed by
analysts.
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Chevron and ExxonMobil earnings smash previous records
Alex Beeker and Tom Ellacott, 29 July 2022
The facts: Chevron and ExxonMobil Q2 earnings beat analyst expectations and broke previous records from 2008. Share
prices of both companies were up significantly on the day with Chevron shares up 8% and ExxonMobil shares up 4.5%.
The balance sheet and buybacks are benefiting from the improved results. Gearing fell meaningfully during the quarter – now
8% for Chevron and 13% for ExxonMobil. Chevron raised the top end of its annual buyback program to US$15 billion – which is
now in-line with ExxonMobil’s target of US$30 billion through 2023.
Our take: strong earnings were anticipated given the surge in oil and gas prices during the quarter. But even so, the results
were phenomenal. ExxonMobil is capitalizing on higher prices to accelerate its high-grading program and is investing in new
refining capacity in the US.
Chevron is parking excess cash on the balance sheet for now – US$12 billion at the end of Q2. But buyback targets can’t
absorb all excess cash flow at current prices. Do we see either company increase new energies capex guidance? Or do both
companies feel content with the steps they’ve taken to address energy transition risk? CCS and low emissions fuels were hot
topics on both calls but commercialisation opportunities remain a ways off.
US Independents Earnings – Week 1
Dave Clark and Robert Polk, 29 July 2022
The facts: the initial round of Q2 earnings for US Independents included four gas-focused Appalachian Basin producers Antero Resources, CNX Resources, EQT Corporation, Range Resources – and three more oil focused producers – Continental
Resources, Hess Corporation, and Matador Resources. All companies turned a profit in the quarter and aggregate free cash
flow totalled US$4.1 billion.
Our take: strong earnings and cash flow are not surprising given the price backdrop in Q2. Common drivers lifted each producer
and will continue with the rest of the peer group in coming weeks. However, the early results highlighted some divergence
between oil-focused names and gas-focused names.
Five of the seven early reporters revised capex guidance higher. Range held the line, but Antero, CNX, and EQT all bumped up
estimates due to inflationary pressures. CNX in particular felt the wrath of investors with a 17.5% increase to capex (at the
midpoint) contributing to underperformance versus its peers and a 10% overall tradeoff. Pipeline constraints in the Northeast
virtually eliminate opportunities for increased activity levels, and the gas peer group outlined plans for maintenance activity in
2023.
Revisions to capex for the oil-focused group reflect more willingness and ability to ramp up activity levels and capture elevated
returns at current prices. Matador’s US$125 million capex increase reflects an 18% increase, but investors seemed more
comfortable with the incremental spend coming from an additional rig and an accompanying impact on H2 and 2023 production.
Hess has telegraphed adding a fourth Bakken rig all year, but it still occurred sooner than anticipated. Continental’s plans did
not change; however, the company already outlined increased spending and activity last quarter (the company also appears to
want to maintain the status quo while assessing its take-private offer).
Increasing oil activity in H2 is a logical and potentially emerging trend, but we would caution against extrapolating too much too
soon. Continental and Matador historically have proven more willingness to buck trends and may not be the best indicators for
the whole group. Hess’ action was ultimately expected.
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While most of the inflation discussion has revolved around capex, inflation is hitting opex as well with modest revisions to per
unit operating costs. Higher realizations absorb these costs, but we expect to hear more tweaks to opex guidance as more
companies report.
Other trends like debt reduction and steadily rising shareholder returns remain persistent focal points as well. Profits in the
quarter across the gas group underscore that the worst of the unrealized hedge losses are likely in the rearview even as losses
on cash settled derivatives continue to accumulate.
Results from another 27 US Independents next week will shed further light on the critical issues companies are facing in the
second half of the year.
Eni adds more volumes in Côte d’Ivoire and Abu Dhabi
Greig Aitken, 29 July 2022
The facts: Eni announced two discoveries on back-to-back days. A 27% increase in volumes at Baleine (Côte d’Ivoire) was
followed by a second significant gas discovery offshore Abu Dhabi.
Our take: Baleine East-1 was the first of two appraisal wells (although referred to as an exploration well by the operator) on the
giant Baleine discovery. A third well will now be drilled. The three wells will form part of an early production scheme, expected
online in H1 2023. Subsea infrastructure is scheduled for installation next year and the FPSO is undergoing conversion
activities.
Based on the initial exploration well results, we expected around 600 million barrels of oil to be recovered (a 30% recovery
factor). This could now increase to 750 million barrels. The gas oil ratio is also higher, meaning that the field could support the
country’s growing domestic gas market for decades to come.
The discovery of 1.0 to 1.5 tcf of raw gas in place, in a deeper zone, in its first exploration well in Offshore Block 2 Abu Dhabi,
United Arab Emirates (UAE) takes aggregate total gas in place to 2.5 to 3.5 tcf.
We expect the gas is likely sour, like nearby fields, but early development could be possible if the field can be tied back to the
Dalma project, which is currently underway.
Both discoveries serve to reiterate that while Eni is on a committed energy transition path, its historic competitive advantage –
exploration – remains a core part of near- to medium-term strategy.
Seven discoveries so far in 2022 on Guyana’s Stabroek block
Justin Rostant and Julie Wilson, 29 July 2022
The facts: on 26 July 2022, two additional discoveries on the Stabroek block were announced. Seabob and Kiru-Kiru are
added to the list of 2022 discoveries. This brings the total number of discoveries on the block to 28, adding to the recoverable
resources of almost 11 billion barrels equivalent.
Our take: a total of seven discoveries have been made on the Stabroek block, year to date. Two were announced in January,
three in April, and two in July. The partners planned 12 exploration and appraisal wells this year on the Stabroek block and are
off to a very good start.
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The Seabob-1 well encountered approximately 40 meters of high-quality oil-bearing sandstone reservoirs. The partners did not
release resource estimates, but we assume approximately 200 mmboe. The well is approximately 19 kilometers southeast of
the Yellowtail field and outside of the main fairway of discoveries. This well adds further support for oil prospects inboard of the
main fairway. In April, the Barreleye well also successfully tested the inboard trend encountering 70 meters of oil-bearing
sandstone.
An additional two wells, Banjo-1 and Yarrow-1 are currently drilling in the inboard trend. Banjo is about 10 kilometers northwest
of the Barreleye discovery and Yarrow is about 15 kilometers to the southeast, the furthest inboard well on the Stabroek block.
The Kiru-Kiru well was drilled 5 kilometers southeast of the Cataback gas-condensate discovery and encountered approximately
30 meters of high-quality hydrocarbon bearing sandstone. We assume that the reservoirs encountered so far contain volatile oil
and gas/condensate and we estimate the resource size of 150 mmboe. Given its location in the southeast section of the trend
between Cataback and the Lau Lau gas discovery, the fluid quality may not have been a surprise. The well continues to be
deepened, perhaps in search of black oil in older horizons.
ExxonMobil recently submitted environmental plans for a 35-well campaign in the Stabroek block starting in 2023 and
concluding in 2028. Exploration will be the main focus, but appraisal will also be important for firming up the development
sequence.
Additionally, ExxonMobil has applied for permits to drill 12 wells each in the Canje and Kaieteur blocks, which are adjacent to
the Stabroek block. Non-commercial hydrocarbons were discovered on the Kaieteur block with the Tanager-1 well in 2020.
Similarly, three wells were drilled on the Canje block, where no commercial discoveries were made.
Stabroek net pay for discoveries
US Independents Q2 2022 earnings preview
Alex Beeker, Dave Clark and Robert Polk, 22 July 2022
The facts: US independent earnings start next week with Hess, Continental and Matador reporting alongside four Appalachian
gas-focused companies. Most of the group reports the following week (1-5 August), with at least a dozen US producers
reporting on August 4th.
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Our take: We’ve identified five key themes to watch for:
1. Guidance and activity updates: About 1/3 of US E&Ps increased capex guidance in Q1, mostly reflecting inflation
adjustments and not increased activity. Others maintained initial plans but guided towards the high-end of the outlook range.
We expect more increases, but do not envision revised drilling plans for the most part. Halliburton indicated equipment
conversations for next year started early, and that the 2023 service market looks even tighter. This dynamic could drive
management teams to disclose more preliminary thoughts on 2023 activity levels than are typically shared at mid-year.
2. Inflation / service constraints: Guidance and activity updates will reflect external pressures governing producer behavior.
Inflation was a predominant theme in Q1; does that continue? Our Lower 48 team expects cost pressures to ease in H2 –
especially with the rollover in broader commodity markets in recent weeks. Labor remains a challenge. We continue to hear
stories of truck drivers leaving to get paid more delivering bread. Halliburton’s strongest completion and production operating
margin since 2014 suggests costs remain significant. Fortunately for the producers, abundant cash flow helps absorb these
costs.
3. Cash flow and returns: Q2 should be another sequential quarter of record free cash flow. Last quarter saw 10 base dividend
increases among 23 dividend paying US independents. Additional increases are assured. Diamondback and Ovintiv already
doubled return frameworks, and EQT just announced a 20% dividend increase. Variable payments will continue to move
higher. A recent slide in equities primes companies for even more buyback activity. Chesapeake doubled its authorization,
and Southwestern introduced a new program earlier than anticipated.
4. Hedging: Hedging losses undermined Q1 earnings and cash flow. US$26 billion in cumulative derivative losses in Q1
included nearly US$7 billion in realized cash settlements. Realized losses should be higher still in Q2, though those will be
offset by higher pre-hedge realizations. Massive unrealized losses in the quarter should moderate some. Roll-offs and fewer
new hedge additions counteract higher mark-to-market liabilities on remaining derivatives. Gas-focused names should once
again be more impacted than oil producers
5. US LNG: Appetite for US LNG exposure remains high. ConocoPhillips announced a non-binding agreement for a stake in
Sempra’s Port Arthur LNG facility, including both supply and offtake commitments. Offtake agreements are beyond the scope
of many US independents, but long-term supply and potential access to premium international pricing was a common focus
in Q1. LNG developments continue to rapidly proceed, and the role of the US Independents remains critical. Others are
evaluating equity investments as well. Strong cash flow positions much of the peer group to enter the LNG value chain.
Shell and ConocoPhillips reportedly eyeing GoM disposals
Luke Parker, 22 July 2022
The facts: Reuters has reported that Shell and ConocoPhillips are exploring the sale of assets in the US Gulf of Mexico. Shell
has apparently opened a data room for its interests in Auger and Conger. ConocoPhillips is said to be considering the sale of its
interests in Ursa and Princess. These reports come from unnamed “sources”. Neither company has commented.
Our take: The reports seem credible, and the stories entirely plausible. Both disposals, should they materialise, make sense
from a strategic perspective.
Shell is the biggest producer in the US Gulf of Mexico, with the steepest growth outlook. Output is expected to reach 500,000
boe/d in 2023-2024. The company’s interests in Auger (100%) and Conger (37.5%) are non-core to the portfolio and to the
growth story. Both are mature assets with limited upside. Shell has been clear that peripheral assets are under scrutiny as it
moves to cut global oil production. WoodMac’s base valuation of Shell’s stake in Auger and Conga is US$1.4 billion (NPV10,
US$60/bbl long-term Brent).
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For ConocoPhillips, the sale of its 15.9% equity in the neighbouring Ursa and Princess fields would represent an exit from the
US Gulf of Mexico. No surprise there – the company's strategic withdrawal from the deepwater has been underway for years.
WoodMac’s base valuation of those interests is US$730 million (NPV10, US$60/bbl long-term Brent). ConocoPhillips is chasing
a US$4-5 billion disposal target, initiated in the wake of its US$9.5 billion acquisition of Shell’s Permian business in 2021.
Disposals announced to date – in Indonesia and the Permian – amount to US$1.8 billion.
For more details on key rumoured and potential deals, plus a deep dive into recent trends in upstream M&A, see Global
upstream M&A: H1 2022 review and outlook (M&A Service subscription required).
NNPC begins life as a commercial entity
Yuqi Hu and Kavita Jadhav, 22 July 2022
The facts: NNPC has become Nigeria National Petroleum Company Limited, a limited liability company which intends to
operate independently of government, without access to public funding. Nigeria wants this commercial entity to transform into
Africa’s largest and a global energy company. Announced plans include tripling retail fuel stations and gas growth. There is an
intention to IPO in 2023.
Our take: NNPC will continue to be wholly owned by the state, with the Ministry of Finance and the Ministry of Petroleum
Resources holding 50% each. The advantages of a standalone legal entity are only possible if NNPC is not encumbered by
government debt and subsidies.
The ongoing process of sorting out the assets and liabilities of the old company could run until the deadline of February 2023.
This vital step should enable the new entity to start life unencumbered by debt. NNPC management has said that it will no
longer be required to shoulder subsidies on Nigeria’s gasoline imports.
Incorporation will bring higher levels of corporate governance, transparency and financial reporting. A healthy balance sheet
would enable the company to raise capital to meet its growth ambitions. Improving operational performance will also be
essential, as our analysis shows that NNPC has one of the highest operating costs per barrel relative to other NOCs.
NNPC sees gas as a critical part of its energy transition strategy and has referred to investing in renewables. The next step
would be for the entity to set its own emission targets.
Read our Inform – NNPC Limited unveiled in glittering ceremony – for more detailed analysis.
Expanded coverage...Corporate Resilience and Sustainability Indices
(CoRSI)
Luke Parker, Alex Beeker and Robert Polk, 21 July 2022
Which US Independents are best positioned to navigate the energy transition over the coming decades? Which would be best
placed to handle a shock to markets in the next few years?
CoRSI is the analytical tool from Wood Mackenzie that seeks to answer these questions. Underpinned by deep analysis
spanning all aspects of Resilience and Sustainability, CoRSI rates corporate positioning in the face of uncertainty and risk. Our
expanded coverage includes 25 of the largest US Independents – in addition to the Majors and IOCs. The latest report is
available now: Benchmarking the US Independents: Resilience and Sustainability
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Corporate week in brief
Aker BP sets out decarbonisation plans and growth outlook
Zoë Sutherland, 21 July 2022
The facts: Aker BP, which only last month completed its merger with Lundin Energy’s O&G assets, has announced its Q2 2022
results, and a new decarbonisation plan. The company is aiming to be net zero from Scope 1&2 on an equity basis across all
operations by 2030. It has also pledged to reduce absolute emissions by 50% by 2030 and by 100% by 2050. A Scope 3 target
will be announced later this year.
Aker BP is also forecasting strong growth. Production in 2022 will reach 400 kboe/d and will grow to over 450 kboe/d in 2023
and 525 kboe/d by 2028, an increase of over 30%. The company is on track to sanction development of 900 mmboe of reserves
this year.
Aker BP will also increase its dividend to US$2.0/share for 2022, up 48% from 2021, with the ambition to grow it by at least 5%
each year.
Our take: Aker BP’s new net zero target brings it in line with Wintershall Dea, Tullow and Kosmos. The assets acquired from
Lundin Energy had an industry-leading carbon intensity of 2.9 kg CO2/boe and will help Aker BP reach its goal of less than 4 kg
CO2/boe next year, down from its current 4.8 kg CO2/boe. This is well below even Equinor’s carbon intensity which is 7 kg
CO2/boe.
Electrification will be key, along with the retirement of older assets. After 2030, it will offset emissions using carbon credits. It has
all the carbon credits it needs out to 2032 and around 50% of the credits it needs out to 2040 through two reforestation projects
acquired from Lundin.
Aker BP is also looking into carbon capture and storage (CCS) as a standalone business opportunity and as an option for longer
term decarbonisation.
The Majors' Q2 results preview: a record-breaking quarter
Tom Ellacott, Luke Parker, Greig Aiken, Alex Beeker, 21 July 2022
The facts: the Majors will break more earnings and cash flow records in Q2. Integrated companies will benefit from a rare
combination of soaring oil and gas prices and record refining margins. Capital allocation plans for the huge cash windfall will
dominate the results calls.
Our take: in Q2 Brent averaged more than two and half times the US$43/bbl price the Majors need to break even in 2022 after
announced buybacks and M&A. But refining results will outshine both upstream and trading.
Global refining margins hit new peaks during Q2. The Majors with scale and complexity are most exposed to this super-normal
quarter (ExxonMobil, Shell and BP). Petrochemicals will be the one performance drag, although high oil prices will support the
US Majors’ chemical earnings from ethane cracking in the US and Middle East.
The risk is that the Majors may be too profitable. Headline-grabbing record earnings will attract public and political scrutiny,
raising the likelihood of more windfall taxes. Will the Majors respond by increasing investment, prioritising spend aimed at fasttracking decarbonisation?
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We expect them to increase investment guidance towards the top end of the ranges laid out for 2022. Some players may break
rank and reveal bigger increases above the rate of cost inflation, if not this quarter, then in the second half of the year assuming
sufficient support from investors. This could trigger spending increases across the board in the coming quarters.
A record quarter for buybacks seems likely and would give more leeway to boost investment. The Majors are also likely to
expand their share repurchase programmes in H2. But buybacks will fall well short of absorbing all the surplus cash at current
prices. Net debt reduction will accelerate. Perhaps more Majors will join Equinor with a net cash positive balance sheet.
Balance sheet strength will raise questions on the prospects for a fresh wave of M&A to put cash to work. Analysts will probe the
potential for inorganic growth to fast-track low carbon strategies. US LNG expansion plans will also be under the spotlight
following big offtake agreements during the quarter (Chevron, ConocoPhillips). High-grading plans will be another important
theme with higher prices already spurring increased activity (ExxonMobil). And Eni will face questions on the strategic
implications of its delayed IPO of Plenitude.
Q2 prices and margins
Offshore wind will deliver 25% higher cash margins than upstream
Akif Chaudhry, Tom Ellacott, Erik Mielke 19 July 2022
As electrons are set to replace hydrocarbon molecules in Big Energy portfolios, how do offshore wind margins stack up against
key upstream resource themes? Can the Majors balance risk, return and margin in offshore wind? Will a growing offshore wind
cash flow wedge change portfolio dynamics?
The latest Insight Why the Majors need to consider margins in weighing up offshore wind uses Wood Mackenzie’s new metric
for this analysis – operating cash flow per GJe.
Offshore wind's outperformance against the Majors' new field upstream developments shows that the financial prize in
renewable power is more than simply long-duration, steady cash flows.
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Corporate week in brief
Weighted average operating cash margin (real), pre-production assets, 2025-2040:
* Upstream – combined comprises conventional, deepwater and LNG resource themes
ConocoPhillips partners with Sempra on US LNG
Robert Polk, 15 July 2022
The facts: ConocoPhillips entered into a Heads of Agreement (HOA) with Sempra to acquire a 30% equity stake in Sempra’s
Port Arthur LNG facility. As part of the deal, Conoco entered into an offtake agreement for approximately 5 million tonnes per
annum (Mtpa). Conoco will supply the gas for its offtake and could support additional supply for the initial phase. The first phase
contemplates two liquefaction trains for 13.5 Mtpa.
Additional facets of the deal include plans to work together to evaluate and potentially development related CCS infrastructure
tied to the larger development. ConocoPhillips will also have the option to acquire additional equity ownership and offtake from
future developments and phases planned at the Port Arthur LNG site.
The HOA is preliminary and non-binding.
Our take: In our recent note on Conoco joining Qatar’s North Field East expansion (22 June 2022), we highlighted greater
portfolio concentration following two major Permian Basin acquisitions. The proposed deal reinforces Conoco’s diversification
strategy and positions it to further capitalize on the US LNG boom.
The structure compliments its US and Permian Basin acquisition strategy and provides an opportunity to drive greater value and
cash flow from associated gas growth tied to higher Permian output. The supply and offtake arrangement increases exposure to
international gas prices and provides Conoco’s marketing department with attractive flexibility.
Numerous US producers have discussed the possibility of direct equity investments in LNG developments across the US Gulf
Coast. Conoco was always a logical candidate given its diversification strategy, unmatched scale among US independents,
financial capacity, and supply stability. We still expect to see additional producers invest directly in export facilities, but it is
unlikely that many are as large as this contemplated transaction.
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Conoco noted the deal is consistent with its “Triple Mandate” of reliable and secure energy delivery, competitive returns, and its
2050 Scope 1 and Scope 2 net zero ambitions. Evaluating additional CCS potential supports its pathway to net zero operated
emissions.
Again, the agreement is non-binding, but Conoco’s partnership and offtake significantly improves overall project viability.
Additional engineering, contracting, financing, and additional offtake are critical aspects of the development that still need to
mature. However, a bluechip equity partner that has already agreed in principle for offtake equivalent to nearly 40% of initial
planned capacity is a strong step forward.
The wheels of Willow start turning
Rowena Gunn, 14 July 2022
The facts: The Bureau of Land Management (BLM) has issued a revised draft environmental impact statement (EIS) for
ConocoPhillips’ (COP) proposed Willow development in the National Petroleum Reserve (NPR-A). The supplemental EIS
addresses deficiencies identified by the US District Court ruling to vacate permits previously granted by the BLM and US Fish
and Wildlife Service in August 2021. The document proposes several development alternatives, including a scenario shrinking
the project to three drill sites from the originally proposed five and ConocoPhillips relinquishing lease rights in the Teshekpuk
Lake Special Area (TLSA), an ecologically important wetland.
Our take: In 2021, ConocoPhillips committed to resolving deficiencies raised by the US District Court ruling rather than
appealing it. This latest draft seeks to do just that, and secure Willow with the green light to proceed with development.
Environmental challenges and stipulations are common on the Alaska North Slope, with operators continually striving to reduce
above-ground footprint. COP had already laid out a reduced three-drill site development plan for Willow back in June 2021,
utilizing a modular design for facilities. The company has been pushing the limits in extending reach drilling on the North Slope
using its custom-built ‘Beast’ drilling rig. The equipment recently completed the longest onshore North American well at Fiord
West, reaching over 35,500 ft MD.
We believe the three-drill site development is the most likely scenario going forward. Taking advantage of its newfound
expertise, ConocoPhillips’ modified plan should have no impact on production or reserves. Wood Mackenzie models a
development cost of US$6.8 billion including central processing facilities with a capacity of 180kbd. We value the project at
US$1.5 billion post-tax NPV10 with a Brent breakeven price of US$48/bbl.
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Source: ConocoPhillips 30 June 2021 Market update presentation. Dashed pink line Wood Mackenzie approximated Eastern boundary of
Teshekpuk Lake special Area.
But we do not account for any lease rights ConocoPhillips may relinquish in the TLSA. The operators current acreage within the
TLSA covers the Bear Tooth Unit and the Willow project as well as several other NPR-A prospects highlighted by the operator.
While stricter environmental stipulations across these leases are likely, relinquishing them altogether would come as a blow to
the operator. COP paints Willow as the next great infrastructure hub on the North Slope and a tie back processing location for
up to 3 bnboe of nearby prospects or leads such as West Willow and Harpoon.
This supplement EIS is an initial step, a draft statement open to public comment and likely to be amended before any final
decisions are made. But with construction on the North Slope limited to the winter season, ConocoPhillips and the BLM will be
hoping for fast turnaround.
Petrobras signs its first sustainability-linked loan
Raphael Portela, 13 July 2022
The facts: Petrobras signed a sustainability-linked loan (SLL) for US$1.25 billion to mature in July 2027. The operation was
signed with the Bank of China, MUFG and Scotiabank. Loan terms were not disclosed, but Petrobras will pay a lower interest
rate if it improves corporate KPIs such as GHG and methane intensity in E&P as well as GHG intensity in refining. This is
Petrobras’ first contracted financing associated with its sustainability targets.
Our take: Though a milestone for Petrobras, we expect the impact on its finances to be minimal. Terms may not have been
disclosed, but SLL discounts for meeting KPIs average out to 25 basis points globally and are even lower in more analogous
parts of the world (e.g., North America at 5-15 basis points). On top of that, Petrobras’ SLL is a revolving credit facility, which
means that a portion of its revolver will likely never be drawn, further reducing any incurred pricing benefit.
The move does reinforce Petrobras’ commitment to decarbonisation. The company already boasts a relatively carbonadvantaged portfolio and is allocating about 5% of its corporate budget towards lowering emissions, well ahead of NOC peers.
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Assuming loan targets align with its corporate goals, we believe that the company will meet at least a portion of the markers. We
estimate GHG intensity in E&P will fall 12% by 2027 but lowering refining intensity remains trickier.
With global financial institutions increasing ESG commitments, it is not hard to envision a future where Petrobras revisits this
type of instrument. We anticipate that the SLL market will continue to grow and mature. In fact, we've seen that originators of
sustainability-linked loans or bonds tend to become serial issuers.
Equinor adds battery storage to US low-carbon offering
Akif Chaudhry, 12 July 2022
The facts: Equinor has signed an agreement to acquire a 100% stake in privately held battery storage developer, East Point
Energy LLC. East Point Energy has a US East Coast focus with a 4.1 GW pipeline of battery storage projects at “early to midstage” of development.
The transaction is expected to complete in Q3 2022 when East Point Energy will become a subsidiary of Equinor.
Our take: Equinor’s new energy strategy is focused on offshore wind development – it aims to become an “offshore wind
major”. However, its business development activity will include selected acquisitions that complement the core renewables
business.
The acquisition of battery storage developer, East Point Energy, does exactly that with its focus on flexible generation solutions
to the power market. Equinor is broadening its new energy offering on the US East Coast, where it currently has over 2 GW net
capacity in offshore wind generation assets under development. It holds a 50% stake in the Empire Wind and Beacon Wind
projects, alongside BP.
In 2018, Equinor acquired Danske Commodities – an electricity trading house. Trading activity will play a more important role as
Equinor’s offshore wind portfolio comes online and the sector incorporates more merchant exposure. Boosting its short-term
storage offering through East Point Energy will further complement its electricity trading business.
Equinor is not new to the battery storage market. In December 2021 it acquired a 45% stake in Noriker Power Limited, a battery
storage developer in the UK (with an option to acquire the full company).
Further details of Equinor’s strategy, benchmarking and valuation in new energy can be found in our latest Equinor corporate
new energy profile.
TotalEnergies to exit Kharyaga oil project in Russia
Michael Moynihan & Ashley Sherman, 7 July 2022
The facts: TotalEnergies is to exit the onshore Kharyaga project, one of three PSCs in Russia, where it has been a shareholder
since the 1990s. Its 20% stake will transfer to Zarubezhneft, the state-owned oil company. The news follows Equinor’s disposal
of a 30% interest in Kharyaga to Zarubezhneft (see 27 May post). Zarubezhneft will own 90% of the project once all deals are
complete.
Our take: TotalEnergies is likely to have taken this step in response to the EU embargo on Russian oil imports. But the move is
also in line with its stated intentions following Russia’s invasion of Ukraine.
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Kharyaga is a relatively small, and oil-focused, part of TotalEnergies’ Russia portfolio. Despite this exit and its recent US$4.1
billion impairment, largely linked to Arctic LNG-2 (see 4 May post), Russia remains both strategically and operationally
important. Particularly projects like Yamal LNG and TotalEnergies’ 19.4% direct equity stake in NOVATEK.
A full-scale exit from Russia would be a big value blow for TotalEnergies. Just under 10% of its capital employed is in the
country. Much will depend on how France’s relations with Russia evolve. As a member of NATO and the EU, France is likely to
be viewed as an ‘unfriendly’ player by Moscow. Should Russia-EU relations deteriorate further, a rethink of the company’s
commitment to Russia may be needed.
ExxonMobil, Shell preview soaring earnings in Q2 2022
Tom Ellacott, 7 July 2022
The facts: Two of the Supermajor’s previewed huge earnings jumps in Q2. ExxonMobil’s earnings could climb as much as
US$9.3 billion quarter-on-quarter to hit US$18.1 billion in Q2 2022 according to its quarterly earnings pre-announcement. The
company is projecting that rising refining margins will drive an additional US$4.4 to US$4.6 billion of earnings from its Energy
Products division. Surging oil and gas prices will add a further US$2.5 to US$3.3 billion of Upstream earnings relative to Q1
2022. Shell outlined a large jump in downstream earnings as well, driven by an almost tripling of indicative refining margins.
Our take: ExxonMobil could deliver a record-breaking quarter at the corporate level. The company’s consolidated net income
previously peaked at US$17.6 billion in Q2 2012 when Brent was averaging above US$100/bbl. ExxonMobil’s preliminary
projections provide a glimpse of what’s shaping up to be a record quarter for key financial metrics across the sector.
Integrated companies will benefit not only from soaring oil and gas prices but also a huge jump in refining margins in Q2 2022.
Shell expects downstream earnings to rise sequentially by US$800 million to US$1.2 billion, with indicative margins rising from
US$10.23/bbl in Q1 to US$28.04/bbl in Q2. Shell also increased commodity price assumptions going forward, which will result in
a post-tax impairment reversal of US$3.5 billion to US$4.5 billion.
US Independents will also have a stellar quarter, as capital discipline continues to run strong. The soaring earnings and cash
flow across the sector will inevitably feed into the US windfall tax debate.
Berkshire Hathaway’s big bet on Occidental
Robert Polk, 6 July 2022
The facts: Warren Buffett’s Berkshire Hathaway continues to grow its stake in Occidental Petroleum (“Oxy”). Berkshire
disclosed the purchase of 9.9 million additional shares on 5 July 2022. Berkshire now owns 163.4 million shares, or nearly
17.5%, of Oxy common stock. The position is worth US$9.3 billion as of 6 July 2022 and has been built almost entirely in H1
2022.
Our take: Berkshire Hathaway’s US$10 billion 8% preferred equity investment was instrumental in Oxy’s bid for Anadarko
Petroleum in 2019. Recent activity suggests the famed investor sees another value opportunity.
There has been a particularly aggressive build recently as energy equities have fallen with recession fears and a corresponding
pull back in commodities. Occidental stock is down 17% over the past month, but Berkshire’s activity helped prop the stock up.
Most other large cap peers are down at least 30% over the same period. The most recent 9.9 million share purchase took place
over just 3-days in late June.
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Wood Mackenzie values Oxy’s upstream assets at US$83 billion at a long-term real US$60/bbl Brent price and values the total
business at US$111 billion. Oxy’s current enterprise value of US$93 billion (based on a trailing 30-day volume weighted average
price as of US$62.41/share) represents a 19% discount to our valuation.
There is speculation that Berkshire is targeting a >20% stake, which would allow it to account for a proportional share of Oxy’s
profits in its earnings under the equity accounting method. As such, Berkshire would directly benefit from windfall upstream
profits in its earnings. Incremental purchases coupled with Oxy’s planned US$3.0 billion buyback make a 20% stake for
Berkshire very feasible near term. (Berkshire also owns 83.9 million in warrants but exercising those seems unlikely near term
without the share-price stabilizing well above the US$59.62 strike).
Berkshire’s US$106 billion cash stockpile illustrates its capacity to acquire all of Oxy’s equity. There is no indication currently
that this is Berkshire’s goal. However, Harold Hamm’s offer to take Continental private placed a spotlight on perceived public
market limitations.
Folding into Berkshire could relieve some of those pressures in theory. Investor pressures on Oxy might not be as strong as a
subsidiary that’s part of a much larger diversified holding company as they are as a standalone producer. Oxy does not
comment on discussions it has internally with its shareholders, but we will continue to closely monitor Berkshire’s activity and
hope to hear more from Berkshire later this month with earnings.
Update, 8 July 2022: Berkshire Hathaway disclosed purchases of 12 million additional shares during the week for roughly
US$700 million. The incremental shares push Berkshire's ownership stake up to 18.7%.
Shell takes FID on Holland Hydrogen I
Luke Parker, 5 July 2022
The facts: Shell has taken FID on Holland Hydrogen I, which will be Europe’s largest renewable hydrogen plant once
operational in 2025. The 200 MW electrolyser will be constructed in the port of Rotterdam and will produce up to 60,000 kg of
renewable hydrogen per day (0.02 million tonnes per year). That hydrogen will supply the Shell Energy and Chemicals Park
Rotterdam, where it will part-replace grey hydrogen usage in the refinery.
The power for the electrolyser will come from offshore wind farm Hollandse Kust Noord, owned by the CrossWind consortium –
a JV between Shell (79.9%) and Eneco (21.1%). The 759 MW CrossWind project is under development, expected online in
2023.
Our take: This is an important milestone for Shell in building a global clean hydrogen business – a key strategic focus for the
company. Shell is targeting a “double digit” share of the global clean hydrogen market by 2035.
By today’s standards, Holland Hydrogen I is a huge project. Once operational, it will be one of the largest clean hydrogen
projects on the planet, and the largest in the company’s portfolio by a distance. Shell’s existing projects – including a 20 MW
electrolyser in China and a 10 MW PEM electrolyser in Germany – already account for around 10% of current global capacity of
installed hydrogen electrolysers.
But Holland Hydrogen I is a step in the road to building a much larger business, on both the supply and demand side. The
biggest project in Shell’s development pipeline is the NortH2 green hydrogen project in the Netherlands. Shell is part of a
consortium – alongside Equinor, Eneco, Gasunie, RWE and Groningen Seaports – working to move NortH2 to FID. Fuelled by
offshore wind, NortH2 will supply industry with 4 GW of green hydrogen by 2030, ramping to more than 10 GW by 2040 – green
hydrogen output of around 1 million tonnes per year.
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Shell joins Qatar’s giant North Field East LNG project
Luke Parker, 5 July 2022
The facts: Shell has become the fifth IOC to enter Qatar’s North Field East (NFE) project. Shell and QatarEnergy will form a
25%/75% joint venture, which in turn will hold a 25% share in the entire NFE project. The four train mega project has a
combined nameplate LNG capacity of 32 mmtpa. Shell will hold a 2 mmtpa net equity share. As with previous agreements,
commercial terms were not disclosed, nor were details of whether Shell will offtake LNG from the project.
Our take: Shell’s participation is no surprise. The Major is aiming to grow top line gas production and to maintain market share
in global LNG. NFE was the biggest discovered resource opportunity on the company’s radar. Commercial terms are unlikely to
be made public, but presumably meet Shell’s Integrated Gas investment criteria of a 12% IRR and payback before 2040. Shell
might also have an eye on future conversations around the renewal of its existing contracts in Qatar – Qatargas 4 (LNG) and
Pearl GTL – which are due to expire in 2036.
This appears to mark the end of the NFE carve up, for now at least. The five JVs that QatarEnergy has announced – with Shell,
ExxonMobil, TotalEnergies, ConocoPhillips and Eni – account for 100% of the NFE project. It looks like Chevron – the sixth IOC
to have expressed an interest – will not be involved. It also seems that QatarEnergy will not, for the time being at least, be
bringing in companies with access to key markets – China, India, South Korea, etc. But that’s a bargaining chip that might prove
useful further down the line.
North Field East JVs: net equity interest (%) and share of LNG capacity (mmtpa)
XTO Canada sold to Whitecap Resources for US$1.3 billion
Scott Walker, 1 July 2022
The facts: Whitecap announced the acquisition of XTO Canada from ExxonMobil and Imperial Oil. Whitecap acquires 32
kboe/d of production and a large land position of 672,000 acres (639,000 net acres) in the Duvernay and Montney formations.
ExxonMobil and Imperial Oil will receive US$1.5 billion in an all-cash offer, which is offset by positive working capital of US$155
million for a total consideration of US$1.3 billion.
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Our take: ExxonMobil and Imperial announced intentions to divest their Canadian unconventional gas assets at the start of the
year, with the position non-core to both companies. ExxonMobil has been high-grading its portfolio for a number of years as the
company looks to prioritise its low-breakeven oil assets in the Permian and Guyana. Imperial has been evaluating its
unconventional portfolio as it looks to focus on its key oil sands assets.
ExxonMobil fell short of its planned US$15 billion disposal programme between 2019 and 2021, completing around US$7 billion
of upstream sales during this period. Progress has picked up in 2022, with sales announced in Nigeria, Romania and the
Barnett shale. Following its sale in Canada, divestment proceeds for the year will total around US$4 billion.
Read our Deal Insight for a more detailed analysis.
Oxy’s low carbon subsidiary acquires pore space for sequestration hub
Zoë Sutherland, 1 July 2022
The facts: Occidental's Low Carbon Ventures subsidiary 1PointFive has entered into a lease agreement with Manulife for
27,000 acres of Timberland in Western Louisiana. This will give access to pore space to develop and operate a carbon
sequestration hub. Two Class VI injection permits for the site have already been applied for.
Our take: this is an important step for Occidental towards its goal of establishing at least three carbon sequestration hubs by
2025. The hubs are expected to have a combined storage capacity of 18 Mtpa. During its Low Carbon Ventures day in March,
Oxy commented that interest is high from emitters who could tap into the hubs. It is reportedly working with 50 projects with over
40 Mtpa of capture potential. However, Oxy acknowledged that only a small subset of volumes are economic at present and a
‘moderate’ increase in incentives would be needed to unlock larger volumes.
The sequestration infrastructure will initially be used for point source industrial emitters. However, it could also service
1PointFive’s Direct Air Capture (DAC) facilities in the future. The company’s first DAC facility is due to start-up in 2024 in the
Permian, but Oxy sees potential to have as many as 70 DAC facilities in operation by 2035.
CNOOC, ExxonMobil and Shell sign CCUS MoU as NOC accelerates netzero targets
Yuqi Hu and Andrew Harwood, 1 July 2022
The facts: CNOOC has signed a memorandum of understanding (MoU) with ExxonMobil, Shell and the Guangdong Provincial
Development & Reform Commission to initiate China’s first large-scale offshore CCUS project with an annual capacity of up to
10 million mtCO2e/year at Daya Bay, Guandong. The company also updated its energy transition plan with more ambitious
goals and a bigger budget.
Our take: CNOOC will accelerate its peak emission date from 2030 to 2028 and has brought forward its corporate net-zero to
2050 from 2060. Scope 1&2 emission intensity will be cut by 10%-18% by 2025, compared to the 2020 level. Net zero by 2050
brings CNOOC in line with PetroChina and Sinopec, but peak emission by 2028 remains behind its national peers.
To support these accelerated targets, CNOOC has increased capital allocation for renewable energy investments, from 5%-10%
of the total capex (2021-2025) to 10%-15% (2026-2030). Clean energies will account for more than half of total output by 2050.
CCUS is a major part of CNOOC’s decarbonization strategy, having recently completed China’s first offshore CCUS project in
the Enping field. The Daya Bay CCUS project aims to capture 3-5 million mtCO2e/year in phase 1 and 5-10 million
mtCO2e/year in phase 2 and would be one of the world’s first projects to sequester emissions from the petrochemical sector. It
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will leverage oil majors’ international experience and technology, pilot the commercialization of CCUS and signal a friendly
environment for foreign investment.
Eni's Vårgrønn gets Dogger Bank, expands scope and ambition
Greig Aitken, 1 July 2022
The facts: Plenitude (Eni) and HitecVision announced an expansion of their Norwegian renewable energy company, Vårgrønn.
The partners’ joint ambition is to build Vårgrønn into a material full cycle offshore wind player, targeting 5 GW of installed and
sanctioned offshore wind capacity by 2030, with a focus on key Northern European markets.
As part of the agreement, Vårgrønn will acquire Plenitude’s 20% interest in Dogger Bank (UK), as well as Plenitude’s other
early-stage initiatives in Vårgrønn’s key markets. Moreover, HitecVision will increase its ownership share in Vårgrønn from
30.4% to 35% through the transaction, while Plenitude will retain the remaining 65%.
Vårgrønn was first announced in 2020. Its original goal was to reach 1 GW of offshore wind capacity by 2030, in Nordic markets.
It is the second partnership between Eni and HitecVision, following upstream-focused Vår Energi, which was formed in 2018
and listed on the Olso stock market earlier this year (Eni remains the majority shareholder).
Our take: the Vårgrønn announcement comes only one week after Eni pulled its planned IPO of Plenitude (gas and power
retail, renewables and e-mobility) due to turbulence in equity markets. The speed at which the Vårgrønn deal has followed
suggests that it had already been planned to take place if Plenitude successfully IPO’d, rather than it being the pursuit of a new
alternative following the IPO’s postponement.
Plenitude has not changed its renewable capacity targets, which include 15 GW by 2030. It obviously believes that giving up a
minority interest in Dogger Bank and other northern European assets will be offset by additional growth and opportunities that a
beefed up Vårgrønn can deliver.
Eni has formed a number of individual entities in order to expedite its core strategy. Splitting out separate organisations gives
clarity of focus and access to appropriately priced capital. Vårgrønn is equity-accounted.
Q2 2022
Equinor and SSE acquire Triton Power, stepping up UK hydrogen ambitions
Norman Valentine, 29 June 2022
The facts: Equinor and SSE have agreed to buy Triton Power from Energy Capital Partners for a consideration of GBP 341
million (US$413 million). Equinor and the SSE subsidiary SSE Thermal will each hold a 50% stake in a joint venture that will
acquire Triton Power. Deal completion is expected in September 2022.
Our take: this deal is about commercialising hydrogen in the UK power sector. Triton Power’s main asset is the 1.2 GW
capacity Saltend power station in the Humber region of eastern England. Saltend is a gas fired facility but Equinor and SSE plan
to fuel the plant with 30% hydrogen by 2027. The longer-term ambition is 100% hydrogen-based power. Hydrogen supply will
come from Equinor’s H2H Saltend blue hydrogen project.
For Equinor, the deal marks its entry into utility scale thermal power. Vertical integration into power generation will secure
demand for hydrogen from Equinor’s Saltend hydrogen project. This will bypass the challenges of a nascent hydrogen market
and puts Equinor on track to deliver one of the world’s first large-scale hydrogen fuelled power projects.
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The deal also deepens the partnership between Equinor and UK utility SSE. The two companies are already partners in the
Dogger Bank offshore wind project in the UK. They are also collaborating on additional UK based low-carbon power projects in
the Humber area and at Peterhead in Scotland. Look out for further deals between the two companies that expand and align
their interests through the hydrogen, CCUS and power generation value chain in the UK.
Shell acquires operated stake in Gulf of Mexico oil development
Luke Parker, 29 June 2022
The facts: Equinor has sold a 51% operated stake in North Platte, which will be renamed Sparta, to Shell for an undisclosed
amount. Equinor will retain 49% interest in the 400 mmboe oil field, which we expect will receive FID in 2024.
Our take: this deal had been on the cards since Equinor’s previous partner – TotalEnergies – walked away from the project in
February 2022. Equinor was never going to sole risk a US$5 billion development, and Shell was our pick for most likely to farm
in.
We value the 51% stake at US$1.1 billion (NPV10, US$60/bbl long term), but suspect that the purchase price (undisclosed) was
heavily discounted. Equinor was up against the clock, with the Suspension of Production (a permit that helps secure the lease
past its original expiration date) due to expire in October 2022. Bringing in Shell will help move the project forward. The US GoM
remains core for Equinor, and the company retains a higher working interest (49%) in Sparta than it held under the previous JV
with TotalEnergies (40%).
The acquisition marks Shell’s entry to the Inboard Lower Tertiary (Paleogene), which holds some of the largest resource
potential in the US GoM. The company will gain first-hand technical knowledge of the reservoirs, and operational expertise in
deploying 20,000 psi-rated equipment technologies. Sparta volumes will help Shell to offset projected decline in production from
the region beyond 2024.
See our Deal Insight for deeper analysis.
US deepwater Gulf of Mexico production by company
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Wood Mackenzie forecasts. Net entitlement basis. Only top four 2030 producers highlighted. Dotted lines show Shell and Equinor positions prior
to North Platte / Sparta transaction.
US shareholder returns continue to climb
Robert Polk, 24 June 2022
The facts: multiple US independents announced either new or expanded shareholder return frameworks. Southwestern Energy
introduced a new US $1.0 billion share repurchase authorization, while Chesapeake Energy doubled its buyback authorization
from US $1.0 billion to US $2.0 billion. Diamondback Energy expanded its framework to return at least 75% of free cash flow, up
from 50%. The expanded return includes a 7% increase in the base dividend to US$3.00/share annually.
Our take: these actions are not surprising on the back of strong prices and record free cash flows. More increases are likely to
follow with the quarter end and subsequent earnings near. We’ve previously highlighted the enormous amounts of excess cash
flow US independents generate in the current environment.
Continuing to expand cash returned to shareholders only reinforces that the shift in capital allocation is structural and long-term.
It is imperative to continue offering investors an overwhelming value proposition. The growth in returns since the 2020 bottom
demonstrates strong progress, but it takes more than 18-24 months of delivery to offset skepticism developed from years of
underperformance.
A long-term and growing return proposition is necessary to continue rebuilding trust, but it is also necessary to compete in the
energy transition. US independents are exploring low-carbon solutions, but they are not changing their core competencies. An
exploration and production focus drives a higher cost of equity capital, which in turn requires increased returns to compensate
investors for their risk capital.
These actions indicate that leading US independents recognize this, and the current environment positions them to carry out the
strategy.
For additional information on cash flow outlooks and other key considerations, please refer to our recent corporate profiles for
Diamondback Energy and Southwestern Energy.
Eni postpones Plenitude IPO
Greig Aitken, 24 June 2022
The facts: Eni has postponed the IPO of Plenitude, its renewables, gas & power retail and e-mobility business. The Italian
Major had been intending to list a minority stake on Euronext Milan. It reasoned that “market conditions have deteriorated since
Plenitude and Eni announced the Intention to Float on 9 June”. Eni has not given any indication of how long it expects this delay
to last, stating only that “it was concluded that the volatility and uncertainty currently affecting the markets require a further
phase of monitoring”.
Our take: in recent weeks, market volatility has heightened as recession worries piled onto existing inflation fears amid central
bank tightening. Markets were already in tumultuous form when Eni announced the float on 9 June, but the company clearly
anticipated that it would still be able to get an IPO away at that point (and probably feared, ironically, that any delay could drag
on for an indeterminate period, given the clouds that were gathering over global markets). Delaying make sense in the current
circumstances.
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While an IPO seems to have been Eni’s preferred path for Plenitude for some time, the postponement will undoubtedly lead to
some inbound interest from third parties. Repsol recently sold a 25% interest in its renewables business to Crédit Agricole
Assurances and Energy Infrastructure Partners, for what appears to be a solid valuation.
However, Eni is not under financial pressure to do any deal. The sell-down is a strategic choice, for reasons which include
receiving a mark-to-market valuation of the business and allowing Plenitude to access capital at an appropriate cost. If the IPO
postponement does extend for a protracted period (2023+), this should have a compound benefit on Plenitude’s eventual
valuation – market valuation multiples should be increasing, rather than contracting, and the nascent renewables and e-mobility
businesses should be trading off a larger base.
Chevron signs US LNG offtake agreements
Alex Beeker, 23 June 2022
The facts: last week, Chevron announced 4 mmtpa of LNG supply deals. Alongside the Corpus Christi Stage 3 FID
announcement, Cheniere signed two LNG sale and purchase agreements (SPAs) with Chevron for a combined 2 mmtpa of
LNG.
In addition to the 2 mmtpa from Cheniere, Chevron agreed to a 2 mmtpa deal with Venture Global. Our insight, US LNG goes
into overdrive covers the full spectrum of deals that were announced recently.
Our take: this represents a change in strategy for Chevron, a company who has traditionally favoured project and point-to-point
marketing.
Until now, Chevron has avoided investments in US LNG and has taken a hands-off approach to trading LNG on a portfolio
basis, in contrast to European peers. It is not clear yet if Chevron had been prepared to bid aggressively enough to secure
access to Qatar’s North Field East project, where TotalEnergies, ExxonMobil, ConocoPhillips and Eni have all recently
announced deals.
With a large and growing US gas position - Chevron’s 2022 US gas production is just above 2 bcfd, linked to its position in the
Permian - these deals bring Chevron additional exposure to international LNG prices, to the tune of or in the range of
approximately 600 mmcfd albeit indirectly.
ExxonMobil and ConocoPhillips selected as partners for Qatar North Field
East LNG
Tom Ellacott and Dave Clark, 22 June 2022
The facts: ExxonMobil and ConocoPhillips have joined the parade of partners for Qatar’s North Field East (NFE) LNG project,
following announcements in the previous two weeks for TotalEnergies and Eni. The massive 32 mmtpa four train expansion is
expected to see first cargoes in the middle of the decade, and will take Qatar’s LNG capacity from 77 mmtpa to ~110 mmtpa. An
additional two trains are planned to increase capacity to a 126 mmtpa plateau by 2027. Both companies will enter into separate
25%/75% JVs with QatarEnergy. The ExxonMobil-QE JV will in turn hold a 25% stake in the entire NFE project (therefore XOM
will hold a 6.25% net position, equivalent to about 2 mmtpa), while the ConocoPhillips-QE JV will hold a 12.5% stake (COP will
hold a 3.12% net position, or about 1 mmtpa).
Our take: both of these companies are incumbents, and the ExxonMobil award in particular is no surprise. ExxonMobil has
partnered in Qatar since the first LNG projects were launched and has an equity stake in nine of Qatar’s 14 current LNG trains.
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Along with a recent 2 mmtpa off-take agreement with Venture Global in the US, the NFE partnership will bolster ExxonMobil’s
medium-term LNG outlook, and re-establishes some momentum after delays in Mozambique. ExxonMobil remains the “oiliest”
Major though (62% of production in 2022), and faces the steepest declines in natural gas production in the peer group over the
next decade. We believe the company will continue to pursue opportunities to push the portfolio towards gas to support longterm sustainability. We think ExxonMobil is likely to bid for equity in the upcoming North Field South project as well.
For ConocoPhillips, the opportunity to partner on the North Field expansion addresses two key risks that have been heightened
by the Concho and Shell Permian acquisitions – portfolio concentration and under-exposure to natural gas. Those deals pushed
US Lower 48 onshore’s share of portfolio value to over 60%. Nearly 80% of company value, and almost all of COP’s growth,
resides in Alaska and the Lower 48.
Natural gas will be about 34% of COP production in 2022. Wood Mackenzie expects that number to slip to 31% by 2030 with the
current portfolio, with the oil-focused development in the Permian and Alaska driving liquids growth. COP recently exercised
pre-emption rights to bump up its stake in APLNG from 37.5% to 47.5%. Along with its current 30% stake in Qatargas-3,
collaboration (and potential equity stake) in MPL LNG, and the participation in the North Field expansion, COP’s global LNG
business will be a third major value and growth center to go along with the Permian and Alaska.
Eni joins TotalEnergies in Qatar’s giant North Field East LNG project
Greig Aitken, 20 June 2022
The facts: Eni has become the second Major to officially enter Qatar’s North Field East (NFE) project, the 32 mmtpa four train
LNG expansion project which is expected to come onstream in the middle of the decade. Eni and QatarEnergy will form a
25%/75% joint venture, which in turn will hold a 12.5% in the entire NFE project. This gives ENI a 1 mmtpa net equity share.
The move follows TotalEnergies’ entry the prior week (The French Major picked up a net 2 mmtpa stake). Other Majors are
expected to be announced as new entrants in due course.
Our take: Eni's entry into NFE and Qatar had long been expected. The Italian Major has worked hard to build its relationship
with Qatar over a number of years, with QP farming into a number of Eni's upstream exploration projects in the late 2010s.
Inclusion in the NFE project will boost Eni’s long-term decarbonisation strategy, which envisages a hydrocarbon production
balance of 90% gas by the mid-2040s (and 60% in 2030), from around 53% currently.
Eni is seeking to grow its contracted LNG volumes from ~8mmtpa in 2021 to 15 mmtpa in 2025. It is not yet clear if entry into
NFE will aid this ambition, as it has not been disclosed whether Eni can offtake volumes from the project. Eni has existing LNG
growth options in the pipeline in areas such as Angola, Egypt, Indonesia and Nigeria, plus the fast-track modular development in
Congo, where first LNG is expected next year. Eni also achieved first gas at Coral FLNG offshore Mozambique and LNG
exports are expected before the end of 2022. However, Rovuma LNG is still being assessed for cost optimisation.
Continental Resources founder offers to take the company private
Robert Polk, 16 June 2022
The facts: Continental Resources founder and Chairman Harold Hamm and his family offered to take the company private with
a tender offer for the 17% of shares outstanding not controlled by the family. The US$70.00/share proposal values the equity at
US$25.4 billion. Continental’s Board of Directors will establish an independent commitment to evaluate the proposal.
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Our take: we published a rapid response insight detailing the motivations for the Hamm family and implications for Continental’s
go forward operating strategy. An internal message to employees stated “…the opportunity today is with private companies who
have the freedom to operate and are not limited by public markets”. Those limitations include pressures not to grow production
despite soaring commodity prices and the likelihood of enhanced emissions reporting requirements.
Many management teams across the US surely share similar thoughts and would appreciate the flexibility that comes from
operating as a private company. However, do not expect this to kick off a “going private” trend. No other peer has an existing
ownership structure remotely comparable to Continental’s. Another key attribute is the company's ability to self-finance coupled
with ample drilling inventory.
Large Caps typically have an institutionalized and diversified investor base. Select Small or Mid Cap companies possess
ownership structures that make it more feasible in theory, but those companies do not have the depth of inventory. In fact,
stock-based transactions among smaller producers illustrate the need to maintain a public equity as a form of currency for deals
to boost inventory.
The last obstacle for others to follow is private capital. The Continental proposal is not contingent on any financing. Any other
comparable going private transaction would require a substantial amount of private capital. While many might prefer to follow
Continental’s lead, Mr. Hamm and the company he founded remain unique.
BP takes 40.5% operated stake in the Asian Renewable Energy Hub
Luke Parker, 16 June 2022
The facts: BP has announced its entry into the Asian Renewable Energy Hub (AREH), assuming a 40.5% operated stake.
Commercial terms were not disclosed.
The proposed mega-project in the Pilbara region of Western Australia will generate 26 GW of renewable energy – a mix of
onshore wind and solar. Of that, 23 GW will be used to produce green hydrogen and ammonia for domestic and export markets.
At full capacity, AREH is expected to be capable of producing around 1.6 million tonnes of green hydrogen or 9 million tonnes of
green ammonia, per annum.
The other partners in AREH remain, their interests diluted by BP’s entry: InterContinental Energy (26.4%), CWP Global (17.8%)
and Macquarie Capital and Macquarie’s Green Investment Group (15.3%).
Our take: this is big news for AREH and BP. At 23 GW, AREH is among the largest proposed green hydrogen projects on the
planet. Having been on the drawing board since 2014, steadily moving through the development process, AREH is targeting FID
in 2025 and first exports in 2027/28. However, there are big challenges to overcome before then:
•
Commercial: There are no projects anywhere near this scale in existence today, and there is justified scepticism as to
whether it can be done. There are big risks around costs, logistics and supply chain. Procuring electrolysers, for example, will
not be straight forward – our hydrogen research group puts the backlog for electrolyser manufacturers at 43 GW and the
pipeline at 304 GW.
•
Regulatory: The project still needs approvals. In June 2021 the Australian government rejected AREH on environmental
grounds, despite having previously given it Major Project Status (aka ‘fast track’ status), and despite it having already
received state level environmental approvals.
The arrival of BP on the scene represents a big vote of confidence in the project, and a huge boon in moving it forward. GIC
(Singapore’s sovereign wealth fund) invested in InterContinental Energy earlier this year. The backing of these two
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heavyweights makes financing doable and elevates the credibility of the project in the eyes of suppliers, government, and
potential off-takers. The challenges don’t go away, of course, but they appear to diminish.
BP sees hydrogen playing a key role in the decarbonisation of power, industry and transport, achieving nearly 20% of final
energy consumption by 2050. The company has ambitions to be a player, with a near-term aim to capture a 10% share of
hydrogen in core markets (the US, UK, Europe, China and Australia) by 2030. A 40.5% stake in AREH transforms BP's low
carbon hydrogen project pipeline, and would – if brought to fruition – take the company a long way towards achieving its target.
Given the early stage of development, and the value in simply having BP lead the project, up-front entry cost to BP is likely to be
minimal. However, with total development costs mooted at over US$30 billion, AREH could become a huge investment for the
Major over the second half of this decade. Entering at this stage makes sense. If all goes to plan, buying in five years from now
will prove a lot more expensive.
AREH is big, but big is what the Majors do. This is the type of project that will be needed if the world is to meet 1.5 degree
ambitions, and if companies like BP are to meet their own decarbonisation objectives.
Low carbon hydrogen; projected gross output, based on proposed, identified projects
Source: Wood Mackenzie Hydrogen Market Tracker. BP and TotalEnergies include newly announced interests in AREH and ANIL respectively.
TotalEnergies initiates new Indian hydrogen drive with Adani
Tom Ellacott, 15 June 2022
The facts: TotalEnergies has announced it will acquire a 25% stake in Adani's green hydrogen subsidiary, Adani New
Industries Limited (ANIL).
ANIL is targeting the production of 1 mmtpa of green hydrogen by 2030. The company is already planning a 1.3 mmtpa project
to generate urea from green hydrogen for the Indian domestic market. This will require investment of around US$5 billion in a 2
GW electrolyser fuelled by 4 GW of wind and solar.
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Our take: TotalEnergies has ambitions to pioneer the mass production of green hydrogen as part of its expansion of low
emissions fuels to around 50 mmtpa by 2050. The company’s renewable hydrogen business development activity has, to date,
been more limited than some of its Euro Major peers. This deal could signal the start of a more active phase to lay a foundation
for the strong growth that will kick in next decade.
The net initial US$1.25 billion of investment in the proposed Urea project is a meaningful starting point in what is a potentially
large market - especially for low carbon ammonia. There could be much more to come. ANIL has ambitions to deliver the
world’s largest green hydrogen ecosystem. TotalEnergies’ entry brings more credibility to that goal.
The deal is also further evidence of how TotalEnergies has successfully used its relationship with Adani to build a broad low
carbon pipeline including renewables power, LNG, gas distribution and now hydrogen.
TotalEnergies' 2050 vision for production and sales
Trade sale failure drives BHP to accelerate thermal coal mine closure
James Whiteside, 15 June 2022
The facts: BHP announced it will retain Australia’s largest thermal coal mine, NSW Energy Coal, and cease mining by mid2030. The decision comes after the completion of a trade sale process that did not result in an acceptable offer. BHP’s
assessment of the resource economics and investment requirements determined that an early closure would provide the optimal
financial outcome for the mine.
Our take: the decision will effectively complete BHP’s exit from thermal coal with only a small portion of by-product from met
coal at Blackwater remaining from 2030. This follows spinoff of all remaining petroleum interests and sales of multiple coal
interests announced in 2021.
NSW Energy coal is a significant asset in BHP’s shrinking portfolio and we expected it to make up 4.3% of BHP equity
attributable production from all commodities in 2030. In bringing forward the mine’s closure by twelve years, the company’s
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concentration in iron ore will grow, adding impetus to the search for growth options in future facing commodities (including
copper, nickel, and potash).
BHP’s announcement comes as operating costs at Mt Arthur soared to record highs last year. While profits are going to be
exceptional this year due to sky-high prices, we expect the cost base will continue to swell owing to stronger diesel prices and
labour cost pressure. Fast forward to 2026 and we anticipate price falls will challenge economics again.
But not too long ago this would have been considered a “world-class” asset. Except for 2020, the mine generated a positive
operating margin every year since it opened in 2002. And it has the potential to operate for another 20 years at today’s
production rate. The lack of a viable offer indicates a shrinking pool of buyers at a time of record margins in the sector.
Private equity players are lacking debt providers to finance thermal coal buyouts. Cashed-up producers would struggle to justify
a low margin acquisition against pressure to invest in decarbonisation. The fact BHP did not receive an acceptable offer may
mark a turning point for thermal coal assets.
Cenovus and BP swap oil sands for offshore
Scott Norlin, 13 June 2022
Cenovus Energy is acquiring the remaining 50% in the Sunrise project from BP for a cash consideration of Cdn$600 million
(US$462 million), a variable payment worth up to Cdn$600 million over the next two years, and Cenovus’ 35% working interest
in the Bay du Nord project. The quarterly variable payment is based on Cdn$2.8 million per every dollar that WCS exceeds
Cdn$52/bbl (US$40/bbl).
Sunrise currently produces 50,000 b/d with expectations of hitting the nameplate capacity of 60,000 b/d in coming years under a
multi-year development plan. The acquisition increases Cenovus’ net production by 25,000 b/d.
Bay du Nord is a pre-FID project offshore Newfoundland. BP is already in partnership with Equinor on neighbouring block EL
1156, where the partners have made the Cambriol and Cappahayden discoveries and are drilling two exploration and appraisal
wells this summer. The plan is for those discoveries to be tied back to the planned Bay du Nord FPSO.
Read our Deal Insight for detailed analysis, including valuation and strategic rationale.
TotalEnergies secures a stake in Qatar’s giant North Field East LNG project
Luke Parker, 13 June 2022
The facts: TotalEnergies has been awarded a 25% interest in a new joint venture, alongside QatarEnergy (75%). The new JV
will hold a 25% interest in the 32 mmtpa North Field East (NFE) LNG project. In other words, TotalEnergies will hold a 25%
stake in 25% of NFE, equivalent to a 2 mmtpa net equity share. The terms of the agreement were not disclosed, nor were
details of whether TotalEnergies will offtake LNG from the project.
QatarEnergy will announce more partners in the coming days/weeks, having already agreed final terms with as-yet unnamed
companies. TotalEnergies was among six IOCs – alongside ExxonMobil, Shell, Chevron, ConocoPhillips and Eni – that bid for
an equity interest in NFE. Others may also be involved, if QatarEnergy sees value in diversifying its partner base and bringing in
companies with access to key markets – China, India, South Korea, etc.
Our take: the award keeps TotalEnergies on track to achieve its target to double LNG sales by 2030 (vs 2020). NFE, along with
other recent moves in North America – where TotalEnergies is taking equity and offtake position’s with Sempra at Cameron (US
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Gulf Coast) and Vista Pacifico (Mexico) – will help offset ‘lost’ growth in Russian LNG, following the company’s move in Q1 to
cease investment in development projects in the country.
The move fits with TotalEnergies’ longer term decarbonisation strategy. The company still plans to be selling 25-30 mmtpa of
LNG in 2050, and NFE volumes will contribute to that. These are the type of ‘advantaged’ molecules – low risk, low cost, low
carbon (the project will utilise CCS to minimise Scope 1 emissions) – that are best placed to survive energy transition, whatever
form it takes.
The lack of clarity on commercial terms is a worry, but not unexpected. It’s safe to assume that TotalEnergies’ won’t be making
stellar returns. NFE awards in general will not be nearly as generous to IOC partners as earlier waves of Qatari LNG
development (e.g. TotalEnergies’ 8.35% stake in Qatargas 2). But the opportunity is exceptional, and companies may be willing
to compromise on returns for rare access to those advantaged molecules.
While commercial terms were not released, we did learn how the project will be structured. Having separate JV’s, each with a
share in NFE, allows development of the four-train project as one entity, but specific terms to be negotiated with each of the
IOC/NOC partners joining. It’ll be interesting to see whether this structure is maintained for the North Field South project too,
which is expected to take FID later this year.
PetroChina charts course to a National Energy Company
Kavita Jadhav and Yuqi Hu, 13 June 2022
The facts: PetroChina released an updated Green and Low-Carbon Development Action Plan 3.0, following previous editions in
2012 and 2019. This substantive update quantifies targets, provides interim targets for decarbonisation and renewable energy
capacity and notably, includes Scope 3 emissions.
PetroChina low-carbon plan 3.0
Our take: by including Scope 3 emissions, majority state-owned PetroChina joins a handful of companies in the sector –
European Majors, Occidental and Ecopetrol. All other companies limit targets to Scope 1 and 2 emissions reduction. Execution
of this plan could chart the course for transition from a National Oil Company to a National Energy Company.
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Earlier plans have been qualitative with limited information on how interim and 2050 targets will be achieved. This update is
holistic, covering all aspect from methane and CO2 emissions reduction targets to increasing decarbonisation spend –
electrification, biofuels and CCUS – and building renewable capacity – solar, wind, green hydrogen and geothermal. This
revision also adds a near-term target stating that new energy will account for 7% of total output by 2025. Previously, the
company included medium-term targets for new energy to increase to one-third of total output by 2035 and half of total output by
2050.
PetroChina’s strategy also provides a significant insight into China’s energy transition approach. It highlights that energy
transition will retain priority alongside a heightened focus on energy security. Due to its scale, PetroChina has material impact
on emissions reduction. PetroChina holds the largest global upstream budget at ~US$30 billion in 2022, even ahead of Saudi
Aramco and is China’s largest producer and supplier of gas, supplying over 70% of China’s gas demand. This strategy is an
important signal that China will continue to engage globally on climate change despite differences elsewhere.
Record downstream results expected in Q2, as refining margins soar and
volatility boosts trading
Gerrit Venter, 13 June 2022
The facts: elevated market volatility since the start of the year saw companies with strong trading arms report exceptional
earnings in Q1. Following Russia's invasion of Ukraine, Wood Mackenzie's global composite refining margin has soared to
record levels during Q2, as many regional gross refinery margins remain at unprecedented highs.
Our take: the Euro Majors reported a much stronger uptick in downstream earnings for Q1 compared to their US counterparts,
as their well established trading units exploited profitable opportunities arising from a disrupted refining system struggling to
satisfy refined product demand. However, the extremely high refining margins being reported since late Q1 and continuing into
Q2 is expected to boost earnings for all Major refiners this quarter, remaining elevated for the rest of the year.
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Downstream earnings vs global refining margin
Devon Energy adds bolt-on in the Bakken
Dave Clark and Brandon Foteh, 10 June 2022
The facts: Devon Energy announced an all-cash deal for the Williston Basin leasehold interests and related assets of RimRock
Oil and Gas (a Warburg Pincus portfolio company) for US$865 million. The transaction includes 38,000 net acres in the Fort
Berthold Reservation portion of Dunn County, North Dakota, with current production of 15 kboe/d (78% oil). The position is
directly adjacent to Devon’s current Williston position, and the company described the deal as a bolt-on. Expected close in Q3
2022, with an effective date of 1 April 2022.
Our take: given the combination of high commodity prices and capital discipline, we have been expecting to see more cashdriven M&A along the lines of this deal. For the sector consolidators, the massive cash surge is an opportunity to extend
adjacent inventory and gain some inorganic growth while the market frowns on organic growth.
Devon says the acquisition will be immediately accretive to cash flow. The company’s metrics at current strip (2.2x cash flow,
FCF yield over >25%) imply about US$390 million of annual operating cash flow and US$215-$240 million of free cash flow
from the acquired assets. To reiterate the near-term accretion, Devon is increasing its base dividend by 13% once the deal
closes, and indicated a likely boost to the variable dividend as well.
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The acreage is estimated to provide an additional 100 locations, which represents about five years of running room at current
completion rates. Devon will allocate an additional US$100 million of capex this year, increasing company budget range to
US$2-$2.3 billion. Prior to this deal, Devon had maintained its initial 2022 budget, even as many peers have nudged spending
plans up due to inflation.
Repsol unlocks ‘see through value’ for its renewables business
Tom Ellacott, 10 June 2022
The facts: Repsol has agreed to sell a 25% stake in its Renewables business to Crédit Agricole Assurances and Energy
Infrastructure Partners (EIP). The €905 million consideration implies an overall valuation of €4.4 billion for Repsol’s renewables
business.
The transaction is effective from 1 January 2022 and Repsol expects it to close before year-end.
Repsol’s share price was up 0.3% in early trading the day after it announced the deal, outperforming Eni and TotalEnergies
(both down 3%).
Our take: this is an important deal that places a mark-to-market price on Repsol’s portfolio which is well ahead of our
expectations. The company has demonstrated that it’s effectively created a business valued at US$4.6 billion since launching its
renewables expansion in 2018.
We argued that oil and gas companies must convince investors they can make new energy business models work in Why are
the energy transition leaders not (yet) being rewarded by oil and gas investors?. Repsol’s impressive value growth in just five
years is a convincing proof point.
Recent asset rotation provides some insight into the valuation breakdown. Repsol achieved a valuation range of US$1.0-$1.6
per MW capacity in selling 49% stakes in its Valdesolar solar project and Delta onshore wind farm. That implies a valuation of
US$0.4 to US$0.6 billion for 25% of Repsol’s 1.6 GW of operational capacity.
Repsol’s renewables pipeline may therefore account for over half the consideration. Surging power prices may have propped up
the valuation of this growth potential given the optionality to take merchant risk on these projects. Relatively de-risked capacity
includes 0.6 GW under development, 4.1 GW of Highly Visible Projects and 6.0 GW of Advanced Development projects.
Repsol’s enterprise value was US$28 billion on the day it announced the transaction. Stripping out the implied valuation of
Repsol’s renewables business places a price tag of US$24 billion on the oil and gas business. That’s nearly half our base-case
NPV10 of US$45 billion at US$60/bbl long-term real Brent.
Repsol may feel it needs to take more strategic action to unlock shareholder value. The company has a strong incentive to
consider the recently reported approach by EIG to purchase a 25% stake in its Upstream business, assuming EIG’s valuation
narrows the price-to-value gap (see below).
The spotlight will now turn to Eni’s floatation of its Plenitude renewables subsidiary on the Milan stock exchange in the coming
weeks. The other Euro Majors will be watching the price tag closely given worries about their discounted market ratings. Will
success in unlocking value hidden in the conglomerate oil and gas structure see more players reconsider their business models
for renewable power?
For more details on Repsol’s renewables portfolio, see Repsol Corporate New Energy Profile.
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Chevron advances low carbon opportunities
Alex Beeker, 9 June 2022
The facts: on 7 June, Chevron announced it signed a memorandum of understanding (MoU) with KazMunayGas to explore
potential low carbon business opportunities in Kazakhstan. The release specifically mentioned opportunities in CCUS,
hydrogen, energy efficiency, methane management, and carbon financial disclosure methodology.
The following day Chevron announced an agreement to supply renewable natural gas for a Walmart demonstration of Cummin’s
new 15-liter natural gas engine for heavy duty trucks.
Our take: these are Chevron’s 12th and 13th press releases this year relating to low carbon partnerships and/or opportunities.
The company had four releases relating to low carbon/new energies over the same period last year.
Not every announcement has been transformational, and the company still lags the Euro Majors in terms of low carbon targets
set and capital committed. But it's clear management is placing growing emphasis on new energies this year.
We recently wrote about how Chevron’s new energies strategy had become California-centric. Which is what makes the MoU
with KazMunayGas especially interesting. Kazakhstan contributes US$28 billion (~10%) to Chevron’s NPV and represents 19%
of the company’s liquids production.
Decarbonizing the barrels it produces will be critical to supporting the longevity of its liquids portfolio. Chevron currently has the
second lowest gas ratio of the Majors, just ahead of ExxonMobil.
Repsol reportedly in talks to sell 25% in its E&P unit
Tom Ellacott, 8 June 2022
The facts: Repsol is reportedly in talks to sell 25% of its Upstream business to EIG, a US fund. It is reported the talks began
after EIG made an unsolicited offer.
Repsol has issued a statement saying that it “is analysing various opportunities and proposals related to this business, while no
decision has been taken in this regard”.
Our take: we value Repsol’s Upstream business at US$25 billion in Lens. But the company is under no pressure to raise
capital. Repsol has plenty of balance sheet capacity, with gearing of 13% at end Q1 2022 (excluding operating leases). We also
calculate that at US$100/bbl the company will generate over US$5 billion of surplus cash after dividends in 2022.
Establishing a mark-to-market price for the E&P business would be a much bigger driver in any potential transaction. Repsol
trades at a 37% discount to our base-case valuation, one of the most discounted ratings in our coverage.
Separating the E&P business from the group could unlock see-though value to help unwind some of this discounted rating. Eni
has already taken half a step in this direction, carving out two upstream subsidiaries (Norway’s Var and Angola’s Azule) – the
former of which was IPO’d earlier this year.
US Independents: cash flow framework
Alex Beeker, 2 June 2022
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One of the most difficult questions facing tight oil companies right now is what to do with all the excess cash flow they're
generating at current prices. Should they be reinvesting the windfall into drilling more wells? Investors and the US Administration
might disagree over the answer to that question. But regardless, tight oil companies look as strong as ever under the current
framework.
The latest iteration of our US Independent cash flow framework tweaks our prior “stay flat” approach and examines five-years of
tight oil company financials assuming 5% annual production growth. We test WTI price sensitivities from US$60 to US$100/bbl
WTI.
Although companies are inching higher from "stay flat" mode, all remain committed to capital discipline. Shareholder
distributions have risen quickly, and are set to soar at current prices, even amidst challenging cost inflation and supply chain
issues.
Tullow and Capricorn to merge
Scott Walker, 1 June 2022
The facts: Tullow Oil and Capricorn Energy have announced an all-share merger of equals to combine their mainly Africa
focused businesses. Capricorn shareholders will receive 3.8068 new Tullow shares for each Capricorn share, for an effective
offer price of £2.08. It prices Capricorn’s equity at around US$830 million, a 5% premium to the share price a day prior to the
announcement. Upon completion, expected later this year, Capricorn and Tullow shareholders will own 47% and 53%
respectively in the new as yet unnamed entity. Tullow’s CEO Rahul Dhir will lead the new group.
Our take: the trend of consolidation has been gathering pace lately and we think there’s clear logic to this tie-up. Both Tullow
and Capricorn were in danger of becoming irrelevant in their current strategic directions. Tullow (largely Ghana) and Capricorn
(Egypt) were essentially single country producers, exposed to a high concentration of operational risk, with limited development
options in the portfolios.
See our Inform for more details on the merger.
Cenovus and Suncor re-sanction the West White Rose project
Mark Oberstoetter, 31 May 2022
The facts: Cenovus and partners are moving forward with the gravity based structure at West White Rose offshore
Newfoundland & Labrador. Construction was suspended in March 2020 at 65% complete. Owner interests will reshuffle as was
reported back in June 2021. Suncor will increase its stake in the producing White Rose asset from 27.5% to 40.0% and in the
West White Rose expansion project from 26.125% to 38.675%, with Cenovus lowering its stakes in White Rose for a higher
Terra Nova stake and a payment to Suncor of Cdn$50 million. The Oil and Gas Corporation (formerly Nalcor) owns a 5% stake
in West White Rose.
Our take: the project has changed since we last discussed the timeline in From misery to muted optimism for Canada's offshore
projects. First production is now expected in 2026 and costs to complete will be between Cdn$3.5 billion to Cdn$4.0 billion.
When the project was originally sanctioned in 2017, first oil had been expected in 2022. Our asset update will be available
in Lens next week.
Incorporating the latest cost figures, the full cycle economics of the expansion are negative. But we long expected the project to
proceed given compelling point forward economics, government support and strong global prices. We calculated Cdn$3.3 billion
had been spent on the project between 2013-2021. This sanction decision delays decommissioning costs (over Cdn$1.6 billion)
into the next decade and adds 180-200 million barrels of oil recovery.
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At our base prices (US$60/bbl Brent long term), the West White Rose incremental phase adds Cdn$1.0 billion in remaining
PV10. This would be even higher once factoring in the delayed abandonment benefit at White Rose. Total PV10 for the phase
including previous spend has a negative PV10 of Cdn$3.1 billion. Given the construction delay and high upfront costs, post-tax
project IRR is 3%. The 2022 point forward IRR is a more respectable 16.5%.
With Terra Nova Extension work ongoing and Bay du Nord potentially heading towards FID, the regional outlook is positive
again. We are closely watching the three expected exploration and appraisal wells this summer, with the first one, Equinor and
BP's Cambriol J-31, spud on 16 May.
Shell sanctions Crux to backfill Prelude FLNG
Luke Parker, 30 May 2022
The facts: Shell has announced FID on the development of the Crux natural gas field, off the coast of Western Australia. Crux
will provide backfill gas supply to Prelude FLNG. The development will consist of a platform operated remotely from and tied
back to Prelude, around 160 kilometres to the south-west. Construction will start in 2023 and first gas is expected in 2027.
Our take: Crux has long been the leading candidate for providing new supply for Prelude FLNG. New volumes have always
been part of keeping the FLNG facility at nameplate capacity beyond 2030 - it’s been a case of when rather than if Crux would
be sanctioned. The Crux investment case has undoubtedly been strengthened by a higher outlook for global LNG demand,
caused by the war in Ukraine. You can read more on the project in our Inform.
Bigger picture, the sanction of Crux is consistent with Shell’s aim to increase gas production – in absolute terms and as a
proportion of total – to the end of this decade. The company has guided that liquids production will fall by 1-2% per year to 2030,
while gas will increase to at least 55% of total production over the same period (from 46% in 2021). But Crux was already in the
base, and accounts for a sliver on the chart. Shell will need to strengthen the outlook for gas – likely from outside the current
portfolio – if it is to hit guidance.
WoodMac base production forecast vs. Shell guidance for liquids and gas
Source: Wood Mackenzie Corporate Service. Shell liquids production guidance, as illustrated, assumes 2% decline per year (Shell's guidance is
1-2% per year).
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UK government introduces windfall tax; operators complain
Luke Parker, 26 May 2022
The facts: after months of political pressure, the UK government is increasing the tax payable on oil and gas production.
Instead of raising existing tax rates, it has added a third tax – the Energy Profits Levy (EPL) – which will increase the overall tax
rate by 25% to 65% from May 2022 until December 2025. To incentivise new investment, an allowance equal to 80% of capex is
allowed as an extra deduction for EPL.
Our take: the new tax achieves its primary aim – to redistribute the windfall that has arisen on the back of soaring oil and gas
prices. We estimate that the UK upstream will generate a record £40 billion of cash flow in 2022 at US$100/bbl Brent. That’s
around £13 billion more than would have been expected at the start of the year, when planning assumptions were closer to
US$70/bbl. Under the previous terms, two thirds of that £13 billion was headed into corporate coffers. The EPL effectively
reapportions the windfall 75:25 in the state’s favour – a swing of £5.3 billion.
UK upstream cash flow 2022: split of windfall between operators and government
Source: Wood Mackenzie Fiscal Service, doesn't include corporate overheads or hedging.
The four biggest UK producers – Harbour, TotalEnergies, BP and Shell – will account for just over half of that £5.3 billion swing.
•
For Shell and BP – lightening rods for much of the criticism of ‘profiteering energy companies’ in recent months – the extra
tax liability equates to less than 1.5% of projected global free cash flow in 2022 (all segments). Small change for BP's selfdescribed cash machine. While many commentators cited the global profits of these companies in calling for a windfall tax,
there was never any proposal, or mechanism, for taxing profits made outside of the UK.
•
TotalEnergies is slightly more exposed at 2% of projected global free cash flow in 2022 (all segments). It will generate more
cash flow in the UK upstream over the coming years – in absolute and relative terms – than either of its UK-headquartered
peers.
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•
Harbour and other UK-focused producers will be proportionately hit harder. Harbour is the UK’s biggest producer, its portfolio
dominated by domestic operations. The windfall tax will cost it nearly £800 million in additional tax liability across the 2022
fiscal year – equivalent to over 20% of its global free cash flow (although, with tax payments are typically made 6 months in
arrears, the cash impact will be felt in 2023).
What about the unintended consequences? Industry has cautioned that the tax will result in less investment, hastening the
decline in production and employment. It’s a nuanced argument, which may hold true in some circumstances, for some
companies. The fact that the EPL has no clear end-date – it could come before or after end-2025, contingent on what happens
to oil and gas prices – is the main problem, adding huge uncertainty to corporate decision-making.
But we don’t see Shell and BP changing course. BP has plans to invest US$23 billion in the UK to 2030; Shell to invest US$31
billion over the next ten years. In both cases, around three quarters of that spend is earmarked for zero and low carbon projects.
The UK is absolutely integral to both companies’ global energy transition strategies and, while there are barriers to overcome
before that investment can happen, the EPL is not one of them.
See our Insight – UK government swoops on North Sea windfall profits – for in-depth analysis.
Chevron announces new leadership structure
Alex Beeker, 26 May 2022
The facts: Chevron has announced a new organizational structure intended to strengthen execution and delivery on the
company’s objectives of higher returns and lower carbon.
The company will consolidate its Upstream, Midstream, and Downstream business segments under a new executive vice
president, Oil, Products & Gas, who will oversee the full value chain. Chevron will also consolidate its Upstream business into
two regions – Americas E&P and International E&P.
Strategy & Sustainability, Corporate Affairs and Business Development will also now sit under one roof and report to a new
executive vice president, Strategy, Policy & Development. The new energies vertical remains intact, reporting directly to CEO
Mike Wirth.
Our take: Chevron has long stressed the importance of capturing margin along the value chain. The company wants to remain
adaptable to the changing landscape.
The Permian is a prime example of an Upstream region that can’t operate in isolation. Midstream buildout and Downstream
considerations, including US LNG are critically important to the company’s target of 1.0 million boe/d by 2025 – and growth
thereafter.
Better alignment between Strategy & Sustainability, Corporate Affairs, and Business Development is important too. New
ventures like CCUS, hydrogen and renewable fuels are incredibly dependent on policy support. A clearer view around US and
global policy will help support sound business development and capital allocation in new energies.
TotalEnergies makes its largest US renewables acquisition to date
Tom Ellacott, 25 May 2022
The facts: TotalEnergies has agreed to acquire a 50% stake in Clearway Energy Group (CEG) from Global Infrastructure
Partners (GIP).
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CEG is the fifth-largest renewable energy player in the US. The company is a developer of renewables projects. It also controls
and owns a 42% stake in its listed subsidiary, Clearway Energy Inc (CWEN). CEG drops projects into CWEN once they are up
and running commercially.
CEG’s portfolio includes 7.7 GW of wind and solar capacity in operation and a 25 GW pipeline of renewable and storage
projects, of which 15 GW is in an advanced stage of development.
The consideration comprises US$1.6 billion in cash and an interest of 50% minus one share in the TotalEnergies subsidiary that
holds its 50.6% ownership in SunPower Corporation. This interest is worth US$0.8 billion based on the US$18 per share
assumption used in the deal.
Our take: TotalEnergies’ renewables business development is picking up momentum after a quieter spell. The busy start to
2022 extends the company’s peer leadership on our wind and solar capacity metrics.
The US is a priority market. The company estimates that its US renewables portfolio will jump to more than 25 GW with this
transaction. TotalEnergies should easily hit its objective for the US to account for at least 25% of its 100 GW global gross
capacity target for 2030.
The transaction round ups TotalEnergies’ US portfolio in a balanced way. Onshore wind accounts for around 55% of CEG’s
operational capacity, complementing TotalEnergies’ 4 GW US offshore wind pipeline. CEG also adds utility-scale solar and
energy storage assets to TotalEnergies’ existing 8 GW solar portfolio built over the last 18 months. Further differentiating the
portfolio, the company owns distributed solar assets through SunPower, which typically deliver higher returns.
TotalEnergies brings its power trading capabilities to the partnership with GIP, allowing for improved value optimisation. The
company will also give CWEN priority on the farm down of its projects, providing a vehicle to boost returns through asset
rotation.
The transaction is another signal that renewables M&A is gaining pace. The Majors may turn to more meaningful deals to fasttrack their low carbon strategies, buoyed by record cash windfalls. This will, in turn, present challenges including ensuring a
smooth integration process into increasingly complex renewables portfolios.
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Net renewable power capacity
Petrobras loses another CEO
Raphael Portela, 24 May 2022
The facts: Brazil’s Ministry of Mines and Energy (MME) announced on Monday that it would remove Petrobras’ CEO Jose
Mauro Ferreira Coelho. Coelho had been in charge for only 40 days and will potentially be replaced by Caio Mario Paes de
Andrade, a former Secretary of Debureaucratization in the Ministry of the Economy. This will be the fourth leader at the NOC’s
helm during President Bolsonaro’s term.
Our take: with presidential elections looming, high commodity prices have turned Petrobras’s CEO position into a hot seat.
Pressure from the majority stakeholder (the Brazilian government) is focused on the company’s pricing policy, which currently
follows import price parity. For now, we expect strong governance controls to hold thanks mainly to a 2016 law that renders
state company executives legally liable for any politically motivated decisions. But a newly appointed head of the MME has
criticised Petrobras’ pricing strategy, which may lead to more shuffling in Petrobras’ board of directors and C-suite.
Woodside shareholders approve BHP Petroleum merger
Andrew Harwood, 23 May 2022
The facts: Woodside shareholders voted overwhelming in support of the merger with BHP’s oil & gas business at its AGM on
19 May. 98.66% of votes submitted were in favour, with the transaction expected to complete on 1 June 2022. Trading of the
new shares issued to BHP shareholders will begin on the Australian Securities Exchange on 2 June.
Woodside’s ADR shares will also begin trading on the New York Stock Exchange on 2 June, with a main market listing on the
London Stock Exchange beginning 6 June 2022.
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Our take: as detailed at the time of the initial merger announcement, this is a deal of the times, with energy transition writ large
in the rationale of both Woodside and BHP. The deal provides financial strength, portfolio optionality, resilient cash flow and a
top quartile carbon emissions rating, with which to navigate the uncertainty of the energy transition. Indeed, Woodside has
already taken advantage of its improved balance sheet strength to sanction the Scarborough LNG growth project, while
committing US$5 billion of investment towards low carbon opportunities this decade.
With the merger complete, immediate focus will be on portfolio integration and optimization. Woodside has stated its intention to
sell down upstream stakes in Scarborough and the Sangomar project in Senegal. Careful project management of the
Scarborough LNG development will also be a priority, as the winds of global supply chain inflation threaten timelines and
budgets.
Medium-term, there is renewed momentum behind the Browse resource, a perennial contender for backfill supply at the mature
NWS LNG plant. Carbon capture will be a key facilitator for the development of Browse; Woodside has recently engaged in
several pilot studies to add carbon capture to its low carbon capabilities. To further emphasize its energy transition goals,
Woodside has also announced its intention to change its name to Woodside Energy Group Ltd (ticker: WDS).
Chevron announces CCS project in California
Alex Beeker, 20 May 2022
The facts: on Wednesday, Chevron announced it plans to launch a CCS project in the San Joaquin Valley, California. The
project would aim to instill post-combustion CO2 capture equipment on existing oil and gas facilities and store the CO2
thousands of feet underground. The initiative would begin at Chevron’s Kern River Eastridge cogeneration plant. Storage
capacity and project costs were not disclosed.
This is the second CCS project announced this month by Chevron. Two weeks prior, Chevron announced an MOU to join Talos
Energy and Carbonvert in their efforts to develop the Bayou Bend CCS offshore hub (5 to 15 Mtpa) at the US Gulf Coast.
Our take: Chevron produces approximately 100 kb/d of oil in California which is nearly one-third of existing production in the
state. The oil it produces there has some of the highest emissions in its portfolio. Decarbonizing operations sends a positive
message to locals and state regulators.
California is becoming increasingly important to Chevron’s new energies strategy, a possible reflection of the state policies in
place that support low carbon fuels. Chevron already produces renewable fuels and renewable natural gas in California and has
plans to grow both over the next decade. Reducing the intensity of its upstream emissions is a natural addition to compliment
these strategies. Could we eventually see a net zero barrel of oil that is produced, refined, and consumed within the state?
Chevron has lagged peers on CCS projects announced and capital committed. But the company is quickly gaining momentum
in the space and the two recent announcements are likely a reflection of the increased attention CCS is receiving within
Chevron. The company’s CCS efforts have been more US-led at the moment, which is possibly related to the support of the
45Q tax credit.
ExxonMobil to sell its Barnett shale portfolio for US$750 million
Tom Ellacott, 20 May 2022
The facts: ExxonMobil has agreed to sell its operated and non-operated Barnet shale gas assets to BKV Corporation for
US$750 million, with an additional US$50 million contingent on future natural gas prices. The company expects the deal to close
in Q2 2022.
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Our take: the Barnett sale does not come as a surprise. ExxonMobil removed the assets from its development plan in 2020.
The Supermajor has taken advantage of soaring US gas prices to exit a non-core asset.
The consideration comes in ahead of our base-case valuation of the portfolio. It is also higher than the US$400 to US$500
million price tag touted in the press when the assets were officially put up for sale in November 2021.
Though the divestment makes sense, it further weights ExxonMobil’s portfolio to oil. The sale of over 180 mmcfd of gas
production reduces the Supermajor’s gas-to-oil ratio from 38% to 37%, ranking as the most oil-weighted portfolio in its peer
group. Gas accounts for 47% of the 2022 production mix of the remaining Majors.
We expect ExxonMobil to focus on low-margin, emissions-intensive oil assets as high-grading momentum picks up. Gas-led
business development is also likely to feature more prominently as the company repositions its portfolio for the energy transition.
New commercialisation solutions for rising associated gas production in the Permian are a potential target area, including
potentially LNG and blue hydrogen.
Sinopec moves forward on green hydrogen
Kavita Jadhav and Yuqi Hu, 20 May 2022
The facts: Sinopec has awarded contracts for RMB1.07 billion (US$160 million) to procure 13 hydrogen electrolyser sets (out of
a total of 52 needed) for a green hydrogen project in Xinjiang province. This solar-to-hydrogen project will come online in mid2023. Total project cost is RMB3 billion (US$0.5 billion) and will feature a 300-megawatt photovoltaic plant and produce 0.02
Mtpa of hydrogen. The project will supply green hydrogen to Tahe Refining & Chemical, replacing fossil fuels and helping to
reduce emissions.
Our take: 0.02 Mtpa is small-scale, but the contract award makes it a firm project under construction. Wood Mackenzie’s
Hydrogen Market Tracker shows that out of a total global, risked low-carbon hydrogen pipeline of 29 Mtpa, only 2% or 0.6 Mtpa
is operating or under construction.
Hydrogen is core to Sinopec's low carbon business transformation. Most of Sinopec’s hydrogen production is blue and grey
hydrogen produced from fossil fuels. Current hydrogen production is 3.8 Mtpa, with about half coming as a by-product from its
refineries and a third made from coal. Sinopec plans to invest US$4.6 billion in hydrogen through 2021-2025 to boost green
hydrogen production capacity to 1Mtpa by 2025. Sinopec will have to increase investment by multiples to meet this 2025
aspiration.
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Low-carbon hydrogen project pipeline by project status (risked*)
Source: Wood Mackenzie. *Project pipeline capacities are risked accordingly: Operating or under construction projects (100%) Probable
projects (70%) Possible projects (50%) Speculative projects (30%)
Oxy’s momentum continues
Robert Polk, 13 May 2022
The facts: Occidental Petroleum’s strong Q1 earnings serve as a sort of ribbon at the end of a very healthy reporting season for
US Independents. Quarterly net income of US$4.7 billion is a company record; however, a US$2.6 billion non-cash tax benefit
boosts the bottom line. Oxy reported non-GAAP free cash flow of US$3.2 billion for the quarter, a record high for the fifth
sequential quarter.
Our take: Occidental is nearing an inflection point in its post-Anadarko corporate priorities. High prices, sound execution across
all business segments, and successful debt reduction position the company for a stronger pivot to shareholder returns, possibly
as early as the current quarter.
Oxy kept its dividend flat this quarter following an increase last quarter, but the company is poised to begin executing on its
previously announced US$3.0 billion buyback authorization. The current US$0.52/share annualized dividend on common stock
translates to a cash outlay of just US$487, so the planned buyback activity represents a material shift.
Continued debt reduction enables this shift. At the beginning of the year, Oxy indicated needing to make “substantial progress”
on US$5 billion in debt reduction before initiating buybacks. US$3.6 billion in absolute debt reduction year-to-date qualifies with
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more planned in the near term with significant free cash flow generation. For context, US$3.6 billion already executed is 54% of
the total amount of deleveraging throughout all of 2021.
Liability management will remain a top priority even after the share repurchase program begins, but Oxy’s improved positioning
alleviates the need to aggressively focus on paying down debt. It can now afford to be a little more opportunistic and patient and
balance free cash flow allocation between the balance sheet and shareholders.
Pricing obviously helps, but this shift reflects the quality of an asset base that is becoming less encumbered by an extraordinary
capital structure. All business lines reported strong results in Q1. US onshore momentum and completed turnaround projects
internationally and Deepwater Gulf of Mexico provide line of sight for strong execution throughout the remainder of the year.
TotalEnergies expands US Offshore wind portfolio
Tom Ellacott, 13 May 2022
The Facts: TotalEnergies has paid a consideration of US$160 million to win a bid to develop a 1 GW offshore wind farm
offshore North Carolina. The company expects to bring the project online by 2030.
Duke Energy was the winner for the other lease with a bid of US$155 million.
Our take: TotalEnergies has stepped up business development since 2020 to address its lack of exposure to the offshore wind
sector. The company initially focused on the UK, France and South Korea. This latest addition underscores the Supermajor’s
willingness to build its pipeline in emerging market areas.
The North Carolina deal follows the award of leases to develop 3 GW of offshore wind capacity on the US east coast in Q1
2022. TotalEnergies’ US$160 million/GW consideration in this transaction is lower than the US$265 million/GW implied for the
New York Bight leases. The difference likely reflects lower visibility on the route to market and the smaller power demand centre
in North Carolina.
TotalEnergies estimates it now holds over 10 GW of gross renewable capacity in the US, equivalent to one-tenth of its 100 GW
target by 2030. Offshore wind business development will play an important role in closing in on this guidance. Most recently, the
company announced that it is teaming up with Ørsted to submit bids in two Dutch tenders with nearly 1.5 GW of capacity.
Expanded coverage... Corporate Resilience and Sustainability Indices
(CoRSI)
Luke Parker, Alex Beeker and Robert Polk, 13 May 2022
Which IOCs are best positioned to navigate the energy transition over the coming decades? Which would be best placed to
handle a shock to markets in the next few years?
CoRSI is the analytical tool from Wood Mackenzie that seeks to answer these questions. Underpinned by deep analysis
spanning all aspects of Resilience and Sustainability, CoRSI rates corporate positioning in the face of uncertainty and risk. Our
expanded coverage includes 37 of the world's largest IOCs, and the latest report is available now: Benchmarking the IOCs:
Resilience and Sustainability
BP announces plans for Texas Gulf Coast CCS project
Luke Parker, 19 May 2022
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Corporate week in brief
The facts: BP has announced plans, in partnership with Linde (a leading player in industrial gases and engineering), to
advance a 15 Mtpa CCS project in Texas. The proposed project will capture and store CO2 from Linde’s existing hydrogen
production facilities, and others’ industrial facilities, in and around the greater Houston area. BP says the project could start up
by 2026.
BP will appraise, develop and permit the geological storage sites for permanent sequestration of CO2. BP aims to leverage
existing assets and capabilities to offer custom low carbon solutions, in working with Linde and trying to bring other industrial
CO2 emitters on board.
Our take: this is BP’s first CCS venture in the US. Proposals to date have focussed on the UK. But the idea is the broadly same
– BP is effectively offering a CO2 aggregation and storage service to industrial emitters. Linde needs to turn the grey hydrogen it
currently produces blue, and might be viewed as the ‘anchor’ CO2 supplier for BP’s project. But there are many more emitters
along the Texas Gulf Coast industrial corridor that need to decarbonise, which BP will be targeting.
BP’s plans seem to be in direct competition with the ExxonMobil-led Houston Ship Channel CCS Innovation Zone – a proposed
project to develop 50 Mtpa of CCS capacity by 2030, rising to 100 Mtpa by 2040. Linde is among fourteen companies, including
Chevron and Shell, that are reportedly backing the project. BP is not on the list. But the CCS Innovation Zone suffered a setback
in early 2022 when a court nullified the award to ExxonMobil of 541,440 acres of shallow water offshore blocks thought to have
been intended for CO2 storage. Chevron has since announced its own plans to join another competing Gulf Coast CCS project
– the Bayou Bend CCS offshore hub (see 5 May story below). Although none of these projects are very advanced, competition
for Gulf Coast CO2 is hotting up.
Aramco delivers record quarterly results
Norman Valentine, 16 May 2022
The facts: Saudi Aramco’s net income increased 82% year-on-year to hit a quarterly record of US$39.5 billion, driven by higher
realised oil prices (+62% year-on-year to US$98/bbl), increased oil and gas output (+13% y-o-y to 13 million boe/d) and
improved downstream margins.
Surging quarterly free cash flow (+68% y-o-y to US$31 billion) supported further deleveraging. The closure of the US$15.5
billion sale of Aramco’s gas pipeline network also strengthened the balance sheet. Gearing fell from 14% to 8% over the quarter.
Aramco maintained its quarterly dividend at US$18.8 billion but also has approval for a 1 for 10 bonus share issue, backed by
the capitalisation of US$4 billion of retained earnings.
Our take: Aramco’s bumper quarterly figures came with few other surprises. The company reasserted its plan to invest US$4050 billion this year, despite a fall in current quarterly investment compared to 2021. Expansion of upstream production capacity
is the company’s primary focus but Aramco is also making strategic progress in downstream.
This quarter saw Aramco agree on a deal with PKN Orlen to acquire downstream assets in Poland including a 30% stake in the
210,00 b/d Gdansk refinery, 100% in an associated wholesale business and 50% in a jet fuel marketing JV. Aramco has also
recently agreed to participate in the development of a 300,000 b/d refinery and petrochemical unit in northeast China with
Aramco planning to supply 210,000 b/d of crude oil feedstock. These deals extend Aramco’s efforts to secure future offtake of
Saudi crude and invest through the value chain in a range of downstream markets.
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Corporate week in brief
Shell announces first Russia disposal
Luke Parker, 12 May 2022
The facts: Shell has agreed to sell its retail and lubricants businesses in Russia to Lukoil. No price has been disclosed. The
deal includes 411 retail stations and the Torzhok lubricants blending plant, along with 350 staff who will transfer to the new
owner.
Our take: this is the first disposal in the wake of Shell's decision to exit Russia, which will see the company extract itself from
five joint ventures. The company’s 50% stake in the Gydan exploration JV will liquidated. Nord Stream 2 is effectively a
bankruptcy process. That leaves a 50% stake in the Salym Petroleum Development (oil) and a 27.5% stake in the Sakhalin-2
LNG project – both JVs with Gazprom. These are the big-ticket items and more complicated exits, but Shell is reportedly in
negotiations with Chinese NOCs regarding its stake in Sakhalin-2. The fact that a deal has been announced, albeit the lowhanging fruit, will be welcome news to Shell and the other IOCs looking to exit Russia. The acquisition will increase LUKOIL’s
retail capacity by around 10% to just under 5,500 sites.
2022 AGM shareholder resolution votes on a different track than last year
Dave Clark, 12 May 2022
The facts: ConocoPhillips shareholders voted down a proposal this week that would have compelled the company to set
emissions goals that aligned with the Paris Agreement, including specific goals to get to Net Zero on Scope 3 emissions by
2050. The shareholder proposal was sponsored by Follow This (Dutch climate activist group) that led successful proxy
proposals in 2021 with ConocoPhillips, Phillips 66 and Chevron.
Last year a milder non-binding proposal, also put forward by Follow This, was approved via a 58% vote. ConocoPhillips followed
later in the year with Net Zero by 2050 targets for Scope 1 and 2. This year’s proposal received support from about 39% of
shares voted.
Shareholders also voted overwhelmingly against Follow This’s proposal for BP this week (~15%), and voted in favor of BP’s
current energy transition strategy (88%), which is the most aggressive among the majors.
Similarly, last Friday Occidental shareholders rejected a Follow This resolution that would have required more ambitious shortterm and medium-term emissions targets. OXY is the only US independent with a Scope 3 Net Zero by 2050 target. Just 17%
of the vote supported the proposal.
Our take: numerous shareholder resolutions regarding emissions targets were successful last May, and many companies
accelerated their emissions reduction plans, and offered greater clarity on their energy transition strategies, in the wake of those
results. We are obviously in a much different place in terms of commodity prices, fundamental supply-demand balances and
geopolitical impact on supply this year.
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BlackRock, the largest asset manager in the world and the institutional investor bellwether, said this week that it will likely
support fewer climate-focused shareholder resolutions this year than it did last year, when it voted in favor of 47% of ESG
proposals. Its rationale is that many resolutions this year are “implicitly… intended to micromanage companies” and aren’t
“consistent with our clients’ long-term financial interests.” BlackRock did say that they would support measures that enhance
company disclosure regarding climate-related risks and performance – specifically on quantitative Scope 1 and 2 data and
targets.
The remaining Majors hold their AGMs last week of May, and Shell, Equinor, ExxonMobil and Chevron will each have a Follow
This-sponsored resolution up for vote.
Our view is that energy transition-related risks will continue to rise, and the stakeholder expectations for oil and gas companies
will ratchet up over time. But the trajectory won’t be linear or smooth. This proxy season seems likely to be a “pause and
assess” moment for shareholder pressure, after last year’s “big leap forward.” The signal to the sector from shareholders may
mean we won’t see major changes to targets or strategy this year.
Equinor sells US$1 billion Norway asset package
Norman Valentine, 11 May 2022
The facts: Equinor has agreed to sell its non-operated stake in the Greater Ekofisk Area and a 19% share in the Martin Linge
field to HitecVision-backed Sval Energi.
The deal sees Equinor exit Ekofisk but retain a 51% stake and operatorship of Martin Linge. The sale also includes Equinor’s
18.5% interest in Norpipe Oil, part of the Ekofisk oil export infrastructure.
The deal includes a cash consideration of US$1 billion and contingent payments linked to realised oil and gas prices for both
assets in 2022 and 2023.
Our take: for Equinor, this deal is about portfolio optimisation. It highlights Equinor’s willingness to use asset sales to manage
its asset base even in the current high oil and gas price environment. With record cash on the balance sheet, Equinor is under
no financial pressure to sell. This is about managing the portfolio for the longer term.
Ekofisk is mature and a relatively high carbon intensity asset. As a tail-end asset in the Equinor portfolio, it was an obvious
divestment candidate.
Equinor’s 70% interest in Martin Linge also made the early-life field a likely sell-down target. The deal sees Equinor reduce its
exposure to a complex, large-scale asset. The sell-down to a 51% operated stake is consistent with Equinor’s risk management
approach in other parts of the portfolio. The deal also sees Equinor recoup some of the unexpected investments it has made in
Martin Linge’s challenging and delayed development since it increased its stake from 19% to 70% in 2017.
With Martin Linge expected to produce at peak levels over the next few years, realising value from this deal will critically depend
on the agreed structure of contingent payments as well as near-term field performance.
Look out for our M&A team’s Deal Insight for further analysis and views on the importance of the deal to Sval Energi’s rapidly
growing North Sea business.
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Canada oil sands Q1 recap - earnings top Cdn$9 billion; Suncor responds to
Elliott
Rowena Gunn, 10 May 2022
Q1 Canadian oil sands earnings season featured record earnings, dividend hikes, higher operating costs stemming from gas
price and some production disappointments. Ourfull insight tracks price realisations, project production, operating costs and
more. Two issues especially stood out: how cash will be used and Suncor's response to an activist investor.
The five largest oil sands producers reported net earnings of Cdn$9.2 billion for Q1 2022. They paid Cdn$1.7 billion in
dividends, repurchased shares worth Cdn$2.7 billion and paid down Cdn$3.3 billion in debt. Distributions to shareholders will
continue to climb in Q2. Cenovus, Imperial and Suncor all announced dividend increases, with the Cenovus amount tripling. And
share buybacks will remain in swing, with Imperial initiating a substantial issuer bid returning of up to $2.5 billion and CNRL and
Suncor both looking to buyback as much as 10% of their floated shares.
Activist hedge fund Elliott Management's recently launched campaign to prompt change’s at Suncor is getting close attention.
Among other actions, Elliott is pushing for board seats, a potential change in management, greater return of capital to
shareholders and a sale or spin of the company’s retail network. Suncor management responded on their conference call: "the
board and management team look forward to engaging in constructive discussions with Elliott as we do with all of our major
shareholders to better understand their perspective.” When pressed on Elliott's proposed exit of the retail business,
management reiterated strong cash flow coming from downstream and retail being a key component of their full value chain
integration, “intertwined with our wholesale and industrial businesses.”
PetroChina Q1 earnings restrained due to price subsidies
Kavita Jadhav and Yuqi Hu, 9 May 2022
The facts: net income increased by ~40% year-on-year, primarily due to higher price realisation for the upstream segment.
Upstream performance compensated for material declines in the natural gas and refining and chemicals segments. Production
was up 3% and capital spend increased 40% y-o-y.
Our take: in a sea of record sector earnings from high oil and gas prices, PetroChina had a muted quarter compared to IOCs
and to peer CNOOC Ltd. which reported an increase in net income of over 130% y-o-y. PetroChina was held back due to price
subsidies in the natural gas segment, which do not allow full passthrough of imported natural gas prices and margin squeeze in
chemicals from high feedstock costs. PetroChina is ramping-up capital spend in order to increase domestic production to help
ensure supply security.
•
Net income: increased to 39 billion yuan (US$5.8 billion) due to a 200% increase in upstream earnings. Overall earnings
were held back by a 52% decrease in the natural gas segment and a 27% decrease in refining and chemicals, despite an
increase in natural gas sales volumes and chemicals output.
•
Production: oil and gas production rose 3% to 4.7 million boe per day behind peers CNOOC at 10% and Sinopec at 4%. The
increase was due to domestic production as overseas production fell 6.8% - production share from PSCs was lower due to
higher prices.
•
Capex: PetroChina’s capital expenditure was 52 billion yuan for the quarter up 40% y-o-y, much higher than peers CNOOC
and Sinopec at 6% and 10% respectively. The company said it plans to boost its exploration and production efforts to
increase supply. PetroChina has spent 20% of FY 2022 spend in Q1.
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•
Russian business: PetroChina has 10% equity in the Arctic 2 LNG project for which TotalEnergies has taken an impairment
due to sanctions impacting the ability to continue with project development. PetroChina did not take any charges for its
investments in Russia. The company clarified that it is not seeking any discounted Russian oil and gas and is only purchasing
fuel through its existing contracts (settled in U.S dollars or euros), with no intention of signing any new contracts.
US independents Q1 results week 2: budget bumps and climbing cash
David Clark, Raphael Portela, Alex Beeker and Robert Polk, 6 May 2022
The facts: over 20 US independents reported results this week, including ConocoPhillips, EOG, Pioneer, Devon and
Continental. There are still a handful of US E&Ps to report next week (Occidental, Ovintiv), but 34 out of the 39 L48 companies
we track have reported.
Our take: with WTI averaging about US$95/bbl in Q1, times were good for the group, but the road wasn’t without bumps.
Among the hurdles to cash nirvana were hedging losses, severe service/equipment/material constraints, higher than expected
cost inflation, and off-the-charts geopolitical turbulence. Below we highlight some key takeaways from the quarter:
Budgets, activity, inflation – about a third of the companies increased their 2022 budget this quarter, with an average increase
of 9% (range of +3-18%). Most were driven by higher-than-expected inflation rather than incremental activity. Anecdotally, the
consensus appears to be around 20%. Others held to initial guidance but expect to be closer to the top of the range. We
anticipate another wave of upward revisions in the Q2 reporting. Group reinvestment rate was 33%, but was 40% for the gasfocused names, and just above 30% for oilier names. A handful of companies were below 27% – ConocoPhillips, Devon,
Marathon Oil, Pioneer and Coterra.
Cash flow generation & distributions – operating cash flow (ex-working capital) was up about 25% q/q in aggregate. Three
companies delivered more than US$3 billion of OCF – ConocoPhillips (US$7 billion), EOG (US$3.4 billion) and Pioneer (US$3.2
billion). By our count, nine companies now pay a variable dividend, and eight of them were up q/q, from +10% (Coterra) to over
100% (Pioneer and ConocoPhillips). Another eight announced a base dividend increase. Total Q1 return of capital to
shareholders across the group was about $8.6B, which is, surprisingly, about flat with Q4. Total return of capital was about 27%
of OCF in Q1 (~33% in Q4).
Hedging – large hedging losses again undermined earnings and cash flow for some. US$14 billion of the US$24 billion of
quarterly hedging losses came from the eight gas-focused producers, and five of those reported a loss of over US$1 billion.
Cash settlements were about a quarter of the overall losses. The biggest hedging losses were from EQT (-US$3.1 billion) and
Southwestern (-US$3.9 billion). Only one oil-focused company reported a hedging loss over US$1 billion – EOG at -US$2.8
billion. And only one of the 34 had no hedges, and therefore no hedge losses – ConocoPhillips.
Balance sheets – net debt reduction slowed again in Q1, just -US$2 billion (OXY reports next week). In Q4, the group delevered by US$4.7 billion, after reducing net debt by US$15 billion in Q2/Q3 2021. Net gearing did continue to fall, with
aggregate debt/book capital falling below 30% (~34% in Q4). For the most part, companies are now paying debt when it comes
due, though there were a couple of refinancings/early retirements, notably ConocoPhillips.
M&A commentary – high commodity prices mean companies are flush with cash and have largely mended balance sheets.
Consolidators are in a good position in that regard. Yet the tone on potential M&A remains muted. Some (e.g., Diamondback)
even went so far as to say major M&A is off the table for now. Sellers don’t need or want to sell unless they get a premium price,
while buyers aren’t interested in paying up during the upcycle. There are many small and mid-sized asset packages on the
market, and for now we expect M&A to focus more on bolt-on/tuck-in type deals rather than corporate acquisitions.
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BP, Equinor and Shell round out the Majors’ Q1 reporting season
Luke Parker and Norman Valentine, 6 May 2022
BP, Equinor and Shell delivered broadly similar messages during their Q1 results. Surging profits grabbed the headlines, but
there was no change to guidance or strategic direction. Balance sheets continue to strengthen, shareholder distributions are
building as promised and capital discipline remains tight. All three companies saw positive share price movements on the day
they reported.
All three reported write-downs as a result of phased exits from Russia, BP’s by far the largest, coming in at US$24.4 billion posttax. Equinor’s exposure to European gas prices was notable – the company’s average invoiced gas price was nearly
US$30/mmbtu in Q1. Shell announced that it expects distributions for H2 2022 to exceed 30% of CFFO – details to come at Q2
results. And both BP and Shell made a point of highlighting plans for investment in the UK over the coming decade – US$23
billion and US$31 billion respectively, mainly in zero and low carbon.
One theme that continues to bubble under is cost inflation and supply-chain capacity. All three companies played down impacts
to date but cautioned that rising pressure at certain points could impact the pace of growth in both upstream and renewables.
The Majors have looked to strengthen resilience in this area over recent years. As outlined in a recent Insight from our Supply
Chain team – Cost inflation is here – exposure depends on what you’re doing, where you’re doing it and the relationship you
have with your suppliers.
Chevron announces proposed JV at US Gulf Coast CCS project
Alex Beeker, Zoe Sutherland and Rachel Schelble, 5 May 2022
The facts: on Tuesday, Chevron announced an MOU to join Talos Energy and Carbonvert in their efforts to develop the Bayou
Bend CCS offshore hub. The project is located in Texas state waters, encompasses 40,000 gross acres, and has the potential
to sequester 225 to 275 million metric tons of CO2. The hub is expected to have a storage capacity of 5 to 15 Mtpa. The Bayou
Bend CCS is the US’s first and only offshore lease dedicated to CO2 sequestration.
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Upon closing, Chevron will retain 50% equity ownership in the project and Talos Energy will remain the operator. The terms of
the deal were not disclosed. Chevron would contribute cash at closing and contribute to a cost carry through FID – anticipated
for late 2025.
Our take: Chevron is aiming for 25 Mtpa of carbon capture and offsets by 2030, the most ambitious near-term CCS target within
the Majors’ peer group. It plans to achieve this through the development of large CCS hubs such as the one proposed at Bayou
Bend. It already has operational CCS facilities at Gorgon in Australia and Quest in Canada, but these are small stand-alone
projects with a capture capacity of only 2 Mtpa net to Chevron. Adding the Bayou Bend hub would bring its net capture and
storage capacity to between 5 to 10 Mtpa. Although a step in the right direction, this is still some way off its target.
The other potential CCS hub in Chevron’s development pipeline is the Houston Ship Channel, but this project appears to be less
well advanced. During Federal GoM Lease Sale 257, the operator of the project ExxonMobil acquired 541,440 acres of shallow
water offshore blocks, which are speculated to have been intended for CO2 storage. However, in early 2022 the blocks were
nullified under a court ruling that concluded the decision to hold the sale had been based on a flawed environmental analysis.
Chevron’s step into the Bayou Bend CCS hub follows its recent investment in carbon offsets. In March, it announced plans to
collaborate with Restore the Earth Foundation to replant up to 8,800 acres of forest in Louisiana which will generate high-quality
carbon credits. The strides that Chevron is making in both CCS and offsets positions it to be an emerging leader for the energy
transition in the US, where oil and gas companies have been in catch up mode compared to their European peers.
ExxonMobil exits Romania
Kevin Swann and Tom Ellacott, 3 May 2022
The facts: on 3 May, Romgaz formally agreed to acquire ExxonMobil’s 50% interest in the giant Neptun Deep Black Sea gas
project. The potential deal was first announced in October 2021, but a string of Romgaz shareholder meetings and approvals
has been required to reach this point.
The consideration is up to US$1.06 billion and the deal is expected to close in Q2. Upon completion, existing partner OMV
Petrom (50%) will become operator of Romania’s flagship upstream project with 3.5 tcf of resources.
Our take: the end is now in sight for what has been an extremely protracted process. And the transaction looks to be a good
one for both parties. We value the 50% stake at US$1.1 billion (NPV10 at January 2022, unrisked).
ExxonMobil’s exit from Romania has been on the cards ever since fiscal and regulatory disruption prevented Neptun Deep FID
in 2018. It follows the company’s withdrawal from Chad and rationalisation in the North Sea and Nigeria.
ExxonMobil still has a deep pool of rationalisation candidates. Soaring prices have blown the bid-ask spread for upstream M&A
out of the water. High-grading activity may pause until buyers and sellers re-align their price expectations. But a reset in implied
prices to ~US$60/bbl would present a tremendous opportunity for ExxonMobil to accelerate high-grading and sharpen its
portfolio around advantaged assets.
Shell makes US$1.55 billion renewables acquisition
Luke Parker, 2 May 2022
The facts: Shell has acquired Indian renewables player Sprng Energy for US$1.55 billion. Sprng has 2.9 GW of renewables
generation capacity in India, comprising 2.5 GW of solar (of which 1.6 GW is operational) and 0.5 GW of onshore wind (all
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operational). On top of this, Sprng has a further 7.5 GW of renewable capacity in the development pipeline. The seller is Actis, a
UK headquartered global investment firm which set up Sprng in 2016 with committed funding of US$450 million.
Our take: this is the second sizeable renewables acquisition that Shell has made in the space of five months, following its
purchase of Savion in late 2021 (price not disclosed). The pace of growth in new energies is quickening. Shell has guided that
investment in its Renewables and Energy Solutions segment will be around US$3 billion in 2022, rising to as much as US$6
billion by 2025. That guidance could rise in the coming weeks, with record oil and gas cash flows emboldening Shell to
accelerate investment in new energies.
Sprng itself is notable on a few counts. Firstly, it’s a relatively mature, cash generative business, the addition of which triples
Shell’s operational renewable capacity overnight. It takes Shell’s overall renewables capacity (including projects under
development) to around 15 GW by our estimates, which, in the context of Shell’s “asset light” strategy, is starting to look like a
big number.
Secondly, the acquisition of Sprng marks Shell’s entry to India’s renewables space; a foothold in a massive and rapidly growing
market for clean energy. The only other Major with a material presence is TotalEnergies (which acquired a 20% stake in Adani
Green Energy Limited in 2021). More broadly, the deal marks Shell’s first foray into non-OECD renewables. Hitherto, its growth
strategy had focussed almost exclusively on Europe, the US and Australia.
Finally, the deal provides an interesting testbed for Shell’s customer-centric integrated strategy. While Sprng is set to operate as
a wholly owned subsidiary of Shell, retaining its existing branding, Shell India will look to leverage existing customer-facing gas
and downstream businesses to create new growth opportunities.
Renewables portfolios
Buybacks increased as Majors’ earnings soar
Greig Aitken, 2 May 2022
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The facts: Chevron, ExxonMobil, TotalEnergies and Eni all reported results last week (as did Repsol). All reported highly
profitable quarters. However, both ExxonMobil and TotalEnergies booked material charges on Russia, suffering hits of US$3.4
billion and US$4.1 billion respectively.
Buybacks were high up the agenda for capital allocation: TotalEnergies expanded its H1 buyback programme by US$1 billion,
Chevron raised its guidance to a US$10 billion annual run rate and ExxonMobil's revision was even more impressive – now
US$30 billion through 2023. Eni had already set out its intention in March’s strategy day – 30% of excess free cash flow will be
allocated to additional buybacks
Our take: for Chevron and ExxonMobil, the outlook remains positive despite cost inflation and weather related headwinds.
Balance sheets are quickly approaching fortress levels and as a result, M&A was a hot topic during Q&A.
TotalEnergies has moved swiftly to adjust its portfolio to replace lost Russian LNG growth. An expansion in US LNG will go
some way to plugging the gap left by Arctic LNG 2. More business development is in the pipeline. The French company is also
contributing to help support Europe's urgent need to secure alternative gas – something which Eni has also been working hard
at in North Africa.
Despite surging hydrocarbon prices, all five companies have continued leaning into low-carbon ventures this year. Chevron and
TotalEnergies have announced material acquisitions in biofuels and generation respectively. Eni has boosted its generation
pipeline and co-sponsored an energy transition-focused special purpose acquisition company. Repsol farmed-down a domestic
solar project to boost returns and announced the formation of a Spanish hydrogen network group. Meanwhile, ExxonMobil took
FID on expansion at its LaBarge CCS project and announced plans for a blue hydrogen project in Baytown.
US Independents Q1 Earnings: gas producers focused on supplying LNG
expansion
Robert Polk, 29 April 2022
The facts: Q1 2022 earnings started for the US Independent’s with eight companies reporting. Those included five gas-focused
producers – Antero, CNX, EQT, Range, and Southwestern – as well as three oil-focused companies – Hess, Matador, and SM.
Our take: LNG markets, infrastructure constraints, and hedging emerged as consistent themes in a week weighted towards
natural gas. All five Appalachian Basin-centric producers posted net losses for the quarter due to US$10.7 billion in aggregate
derivative losses. As noted in last week’s preview, large hedge portfolios across the peer group, coupled with the sharp increase
in natural gas prices drove US$8.4 billion in non-cash unrealized mark-to-market losses.
Despite hedging headwinds, price uplift on the unhedged production, paired with reinforced commitments to maintenance
capital create a robust cash flow outlook for the group. Antero increased its 2022 free cash flow outlook by 56% from US$1.6
billion to US$2.5 billion. EQT’s forecast increased nearly 50%, while Range’s guidance increased 40%. CNX and Southwestern
are more constrained due to a greater percentage of hedged production. Overall, the peer group reinvestment rate for Q1 2022
was just 39%, with momentum to move lower in subsequent quarters.
Healthy balance sheets will become pristine with accelerated deleveraging. CNX discussed eliminating any reliance on debt
capital markets. Repurchase authorizations will also be exhausted quicker as rallying equities are not slowing repurchase
activity. It is easy to envision much of the peer group introducing base dividends in 2023. Producers are not adding more
hedges amid high prices and conveyed bullish sentiment towards a long-term structural shift in gas prices.
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Part of the adherence to maintenance spending is takeaway constraints. Sticking to the plan also helps mitigate against some
accelerating oilfield service inflation. The market has tightened since the beginning of the year when the maintenance designed
programs were largely contracted.
LNG was a unanimous focus, with broad policy appeals as well as discussion on positioning and contracts to supply expanded
export capacity. EQT and Southwestern also discussed openness to direct equity investment in liquefaction facilities. EQT has
been the most vocal proponent for US natural gas and LNG, but its peers are more actively joining in the chorus for constructive
collaboration on pipeline infrastructure to support LNG expansions.
Record cash flows from hedged gas producers hints at what is to come with more oil-focused US producers reporting soon.
Oilier companies initially seem a bit more open to deploying excess cash flow back to the drill bit. Hess confirmed plans to add a
fourth Bakken rig later this year. Continental Resources pre-released revised production guidance with an associated 15%
increase in spending. Matador reiterated guidance, but it set growth objectives with its initial guidance.
While some modest upticks in activity might accompany oil results, expectations are that discipline holds. The outcome will be
even more free cash flow and greater returns of capital.
Activist investor comes at Suncor
Rowena Gunn and Jonah Resnick, 29 April 2022
The facts: activist hedge fund Elliott Management is calling for a strategic review of Suncor Energy. Elliott now owns 3.4% of
the Canadian operator. In a letter to Suncor’s board, and via a presentation posted to a dedicated website, Elliott points to a
chronically underperforming share price, which has remained relatively flat since 2019 despite climbing oil prices.
Elliott's demands include adding five new independent directors to the board, a management review, exiting the retail business,
overhauling operational and safety culture and increasing return of capital to shareholders from 50% to 80% of discretionary
cashflow after capex and dividends.
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Our take: Suncor has high quality assets but has been beset by operational and safety underperformance. Operational
setbacks at Fort Hills, missed guidance and a sharply reduced dividend have all contributed to the share price lagging against
its peer group.
Suncor is the third-largest Canadian operator in terms of production and reserves, now trailing the acquisition-busy Canadian
Natural Resources and Cenovus. Its portfolio is heavily oil sands-weighted with over 88% of 2022 production from the resource
theme, notably higher than Cenovus or CNRL which are closer to 55% oil sands-weighted (excluding Lloydminster heavy
contributions). Suncor still produces the largest volume of upgraded synthetic oil (485,000 b/d) and has a country-leading
refining position.
The bulk of Suncor’s remaining upstream value lies in its interests in three oil sands mining projects (Suncor Base Mine, Fort
Hills and Syncrude) and the Firebag SAGD project. Our recent insight analyzing the Oil sands at high oil prices highlighted the
opportunity this high oil sands weighting can bring in elevated price environments. Suncor’s upstream portfolio is amongst the
best-positioned to maximize value at our high price scenario, improving in value by 82%.
Suncor’s in situ assets stack up well against others. Our oil sands key play report conveys that. Suncor benchmarks less
favorably on their key focus area – mining projects. Older mining projects have unique challenges and higher operating costs
than those built after 2000. Suncor's mining production has been variable and operating costs are above the sector average.
There are steps underway to improve this, including recently taking over operatorship of Syncrude, making use of the now
operational Suncor/Syncrude interconnecting pipelines and the coke fired boiler replacement. These projects will improve
reliability and reduce emissions. Fort Hills is finally ready to produce at its intended levels after years of government curtailment,
the pandemic-driven low oil price causing the shutdown from two trains to one and, most recently, water and slope integrity
issues.
The company has been addressing many issues. On the safety front, CEO Mark Little has taken ownership of improving the
company’s safety and operational performance. In addition, a new management appointment to the mining and upgrading unit
was made in March, and the company is selling its Norwegian offshore and Canadian wind businesses (see 8 April Corporate
week in brief entry).
The letter released by Elliott indicates even more will be needed to satisfy investors. Suncor releases its Q1 2022 results on 9
May. Cenovus just tripled its dividend. Given peer moves, and the explicit pressure from Elliott, we expect Suncor to materially
increase shareholder returns next week. Other Elliott demands could get contentious.
As a reminder, Elliott has been involved in numerous activist investor efforts in the energy space over the last eight years,
including a high profile campaign with Hess, a successful push to dis-integrate Marathon Petroleum, and less confrontational
influence efforts with Devon Energy and QEP. At the moment, Elliott’s approach with Suncor appears to be closer to the Hess
and Marathon Petroleum model (a retail spin/sale was also a key component with the Marathon campaign).
Strong Q1 for CNOOC Ltd., Sinopec Corp subdued due to downstream
Kavita Jadhav and Yuqi Hu, 29 April 2022
The facts: CNOOC reported a strong quarter more than doubling net income on higher prices and volumes. Sinopec Corp
reported a modest increase as its dominant downstream segment suffered from higher feedstock costs. The outlook for CNOOC
is robust with support from higher prices and new projects coming online. Sinopec will continue to face pressure from higher
prices and lower demand due to lockdowns in China.
Our take: CNOOC has the highest upstream exposure of China’s three national oil companies, shielding it from the drag of
higher feedstock prices on downstream operations. CNOOC has had an eventful first quarter with a successful listing in
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Shanghai, followed by stellar results and a generous special dividend. Sinopec Corp was dragged down by higher feedstock
costs which it could not pass through due to regulatory price controls.
•
Net income: Net income increased 132% for CNOOC and 24% for Sinopec Corp. Sinopec’s upstream segment benefitted
from higher prices and volumes with a threefold increase in net income, while its vast refining segment posted a modest
increase of 15%.
•
Production: CNOOC production increased 10% y-o-y, mainly due to higher domestic production as new projects came
onstream while output from its overseas projects dropped by 3%. CNOOC said its focus was to ramp up domestic activity,
though it would also have strong growth from Guyana where partner Exxon Mobil has made new discoveries and raised total
recoverable resources. Sinopec production rose by 4%, driven by shale gas success as gas output increased 7.7%
compared to a 1% rise in oil production.
•
Downstream: Sinopec’s refinery throughput increased 2.7% to 5.2 million barrels per day. The company has cut refining
runs in March but expects demand for refined oil products to recover in 2Q as COVID-19 outbreaks in the country are
gradually controlled.
•
Capex: CNOOC spent RMB$16.9 billion in Q1 2022, up 6% y-o-y, and Sinopec Corp spent RMB$25.4 billion, up 10% y-o-y.
Both companies underspent in the quarter but confirmed previous guidance for 2022. Sinopec has planned a record annual
spend, its highest ever of RMB198 billion this year.
•
Shareholder returns: CNOOC announced a special dividend of HK$1.18/share, consisting of the 2021 year-end dividend
and the 20th-anniversary special dividend.
•
Portfolio: CNOOC said it was not targeting any areas for withdrawal, but would hone its portfolio based on operational
strengths and weaknesses. Both companies did not mention any impact from Russia-Ukraine on operations.
•
Other: CNOOC announced that CEO Xu Keqiang has resigned because of work commitments and would be replaced by
Zhou Xinhuai.
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ExxonMobil upgrades Stabroek reserves to 11 billion boe
Tom Ellacott, 29 April 2022
The facts: ExxonMobil has upgraded its resource estimate on the Stabroek from 10 to 11 billion boe. The upgrade follows the
announcement of the Barreleye, Lukanani and Patwa discoveries, which bring the total number of discoveries on the block to
26. The SuperMajor also gave a positive progress update on the schedule for the Payara development. The third FPSO is five
months ahead of schedule and is forecast to start production before the end of 2023.
Our take: we analyse what the latest discoveries mean for the block partners ExxonMobil (45%, operator), Hess (30%) and
CNOOC Ltd (25%). in A trio follows an early duo in Guyana’s Stabroek block.
Petrobras sells Albacora Leste to PetroRio for US$2.2 billion
Raphael Portela, 28 April 2022
The facts: on Wednesday, Petrobras agreed to sell its 90% stake in the Albacora Leste field for a total consideration of US$2.2
billion, including contingent payments of up to US$250 million. The deepwater field is located in the Campos Basin, and current
production stands at approximately 30 kbbl/d. Repsol owns the remaining 10% interest in the asset.
Our take: the Albacora and Albacora Leste fields were put up for sale back in 2020. Though not as marginal as Petrobras’ other
disposal targets, the cluster is part of the Campos Basin revitalisation, an effort which has been deprioritised in recent years.
Instead, Petrobras is focused on developing greenfield pre-salt assets. Albacora Leste became an attractive disposal candidate
because it straddles the line between non-core and material.
And it is this materiality that has piqued PetroRio’s interest, a move that will essentially double the Brazilian independent’s
production. The work needed to revitalise Albacora Leste is also the E&P’s bread and butter. Extending the field’s economic life
will require workovers and new drilling. Identified pre-salt prospects could also be key to the operator’s success in the long term.
PetroRio is in negotiations with Petrobras for the Albacora field, an even more highly prized asset.
The transaction sheds light on how level-headed the market has remained despite sky-high prices. Many were sceptical that the
deal would go through after the war in Ukraine broke out. But both parties managed to agree a deal which we estimate will
break even under a long-term price assumption of US$62/bbl Brent (with full contingent payments paid at US$90/bbl in 2023
and US$80/bbl in 2024).
Stay tuned for an upcoming Deal Insight with proprietary, in-depth analysis.
CNRL hits Cdn$100 billion market valuation milestone
Rowena Gunn, 28 April 2022
On 20 April 2022 Canadian Natural Resources (CNRL) became the first E&P company listed on the Toronto stock exchange to
surpass C$100 billion in market value, equivalent to US$79.3 Billion. Midstream giants Enbridge and TC Energy were already
past that milestone. In this video we take a look at CNRL's portfolio, what's driving the value, the historic growth trajectory and
portfolio risks.
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CNOOC triggers upper circuit breaker on Shanghai market debut
Kavita Jadhav and Yuqi Hu, 22 April 2022
The facts: CNOOC Ltd. shares priced at RMB10.8 per share rose as much as 44% to a high of RMB 15.55, hitting the daily
limit. They eventually closed 28% higher on the first day of trading. CNOOC raised capital of RMB28.08 billion (US$4.3 billion).
Our take: CNOOC’s IPO was well-timed, taking advantage of the correlation with prevailing high oil and gas prices and defying
broad market weakness from geopolitical tensions and lockdown in Shanghai. The Shanghai sale enables the company to raise
capital from the domestic market after it was delisted from the NYSE due to US sanctions.
Capital raising fell short of the total RMB35 billion on offer including the greenshoe option, which allows underwriters to sell up to
15% more shares than the original amount set by the issuer. The RMB28 billion raised represents just over a third of planned
2022 capital spend. The capital will be used on various domestic and international new projects, including the Payara oil
development in Guyana and the Liuhua 11-1/4-1 oil project in China.
This year has many calls on capital for CNOOC as it plans to spend RMB90-100 billion to sustain annual production growth of 56%, pay at least 40% of profits in dividend, pay a 20th anniversary special dividend (in addition to the year-end regular dividend)
and start a share buyback programme.
Offshore wind: Europe’s leading companies
Norman Valentine and Akif Chaudhry, 22 April 2022
Offshore wind capacity in Europe’s most advanced markets is set to quadruple this decade. Only China will surpass aggregate
offshore wind capacity in Belgium, Denmark, France, Germany, the Netherlands and the UK through this decade.
A diverse group of six companies is set to drive European offshore wind growth. Market leader Ørsted along with RWE,
Iberdrola, Vattenfall, SSE and Equinor will account for around 40% of capacity in Europe’s established offshore wind markets
through to at least the mid-2020s.
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But increasing competition means asset returns are set to fall. Companies will need to go beyond current commercial portfolios
to sustain operational cash flow growth beyond the mid-2020s. Read our Insight to benchmark the leading companies in
European offshore wind and gain our views on key trends in this important renewables growth sector.
Alekperov steps down from LUKOIL
Scott Walker, 22 April 2022
The facts: LUKOIL announced that company president Vagit Alekperov has resigned from his role. The move comes a week
after Alekperov was sanctioned by the UK, which included a travel ban and asset freeze. Alekperov, 71, will retain a direct and
indirect minority shareholding in LUKOIL, with no voting rights, totalling 8.55%. First executive vice president, Vadim Vorobyev,
has been appointed temporary president. The board proposes to make his appointment permanent at its EGM on 30 May 2022.
Our take: while sudden, and probably a direct response to protect LUKOIL from the impact of sanctions on himself, Alekperov
had stated in 2018 that ‘the time is coming’ to find a successor, with 2023 – set to be his 30th year – suggested as a likely
timeframe. In this regard, the company will have been planning for his retirement for a number of years. Moving quickly to
appoint Vorobyev as temporary president, with a permanent appointment expected next month, will ensure as frictionless a
transition as possible.
Santos outlines new capital management framework
Scott Walker, 22 April 2022
The facts: Santos announced an updated shareholder return policy that will see the company commit to a dividend of between
10-30% of free cash flow (post capex, exploration spend and interest) up to US$65/bbl Brent and at least 40% above US$65/bbl
Brent. Santos will also initiate a US$250 million share buyback during 2022 and will target a gearing ratio of between 15% to
25%, down from 26% at the end of the Q1 2022.
Our take: Santos’ policy of returning 10-30% of free cash by way of a dividend has been in place since 2018. Increasing this to
a minimum of 40% above US$65/bbl Brent – along with its US$250 million buyback – sends a positive message to shareholders
that Santos is committed to capital discipline in a higher oil price environment and can deliver value post-merger with Oil
Search.
In 2021, Santos paid a dividend of US$0.085 per share, up 70% from the previous year. At US$65/bbl Brent in 2022, we
estimate Santos would sustain a similar yield assuming 30% of free cash flow is recycled to the dividend and post buyback. At
US$80/bbl and US$100/bbl Brent, our modelling shows that Santos would increase its yield to around US$0.2 and US$0.3
respectively if 40% of the incremental free cash flow is redeployed to pay the dividend.
Free cash flow falls between 2023 and 2025 as key development projects enter capital intensive phases, but from 2026 we think
Santos could sustain a dividend of around US$0.3 per share at US$65/bbl Brent under the financial framework, buoyed by cash
flow from new projects.
US Independents' earnings preview
Robert Polk and Dave Clark, 21 April 2022
The facts: the US Independents' results begin next week with multiple gas-focused producers and Hess reporting Q1 earnings.
The reporting period runs through the week of 9 May 2022 with the prominent US tight oil producers reporting in subsequent
weeks.
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Our take: the sector is poised for another quarter of record free cash flow, especially for oil producers. While a rising tide lifts all
boats, the full impact of the steep run up in commodity prices will be somewhat muted for early reporting gas producers. EQT,
CNX Resources and Southwestern all have substantial hedges limiting full upside benefit. Antero Resources and Range
Resources carry gas hedges as well, but do possess more exposure to unhedged NGL production.
Oil producers are not as constrained. Pioneer and Hess even paid upfront premiums earlier in the year to unwind hedges. Early
anecdotal evidence supports this distinction. Murphy Oil already announced a 17% increase to its base dividend while EQT
maintained at the prior quarter’s level.
Outside pressure to reinvest high cash flows and grow production has garnered a lot of attention. Strong earnings will further
amplify discussion, but we do not expect any deviation from set plans just one quarter into the year. Messaging from
management teams has been consistent throughout the quarter, and that will not change simply with another period of reported
results.
Earnings calls should contain more details about the challenges to pivot anyway. Halliburton indicated on its Q1 call this week
that its frac crews are completely sold out for the remainder of the year, and that the broad market is extremely tight. The labor
market is universally tight. While supply chain constraints help reinforce preexisting drilling programs, inflationary pressures and
oilfield service pricing power does stress capital budgets. Companies signaled modest inflation expectations earlier this year
(perhaps 10% for full year) and highlighted offsetting efficiency gains. Now expectations have moved closer to 20%. It will be
more difficult for companies to downplay cost pressures this quarter. While guidance won’t budge yet, we are likely shifting
towards the high end of capex ranges.
Even with budget pressures, the cash flow uplift will be impressive. The return of capital framework is working well, and the
environment is conducive to incremental dividend increases and expanded repurchase authorizations. However, companies will
be measured with base dividend increases to maintain sustainable levels. Furthermore, rallying stock prices will now push back
on the narrative that buying back stock is the most efficient use of capital.
It is not a long-term solution, but we expect to see elevated cash balances held on the balance sheet this quarter. M&A activity
has slowed down amid price volatility, but consolidation continues to be a major theme and building up a war chest for future
deals could serve as a future differentiator.
Markets typically do not like surprises, but we don’t expect many from Q1 results – though the cash generation at US$100+/bbl
could be eye-popping. Inflation-driven budget updates, if needed, are more likely to come on Q2. US Independents continue to
execute according to plan, and supportive commodity prices facilitate excellent expected results.
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The Majors’ Q1 results preview – a record quarter for free cash flow?
Tom Ellacott, Luke Parker and Greig Aitken, 20 April 2022
The facts: the Q1 earnings season gets into full swing next week with TotalEnergies, Eni, Chevron and ExxonMobil reporting.
BP, Shell and Equinor announce their Q1 results the following week. All eyes will be on capital allocation plans for the huge
cash windfall from surging oil and gas prices.
Quarterly oil and gas prices and refining margins
Our take: the Majors face a difficult balancing act in this results season. They will tone down the ‘cash machine’ rhetoric but still
have to find a home for what could be record quarterly free cash flow.
The Majors reported their second-highest free cash flow ever in Q4 2021. But Brent jumped 27% quarterly-on-quarter in Q1 to
average more than double the peer group’s cash flow breakeven of US$48/bbl (post dividends and US$30 billion of announced
buybacks). Refining and Chemicals will also have generated lots of cash last quarter, especially in the US.
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The Majors' quarterly reported free cash flow
Bumper underlying earnings across all segments and in trading will strengthen the financial performance. But the decisions to
exit Russia will hit headline earnings – BP and Shell have guided for up to US$25 billion and US$4 to 5 billion of write-downs
respectively. Inventory effects will also dampen refining earnings while high gas and carbon emissions costs will weigh on
European margins.
Capital allocation plans will be under the spotlight. Most companies still have some wriggle room to increase spend in the
guidance range provided for the year. But growing cost inflationary pressures may force some players to nudge up investment
ceilings. Watch out too for incremental investment in short-cycle oil, advancing gas and LNG projects (e.g. TotalEnergies in US
LNG and Eni in North Africa to plug the gap left from Russia) and accelerated renewables activity.
Yet we don’t expect any Major to announce a big capex upgrade. Deleveraging may also slow to avoid balance sheets
becoming inefficient. That sets the scene for expanded buybacks and potentially meaningful dividend hikes. We expect the
Majors to build momentum to smash the previous the annual combined buyback record of US$62 billion set in 2006.
CNOOC homeward-bound with Shanghai IPO
Kavita Jadhav and Yuqi Hu, 18 April 22
The facts: CNOOC opened subscription for its Shanghai IPO priced at RMB 10.8 per share to raise up to RMB 35 billion
(US$5.2 billion). With the over-allotment option of 15%, the issue would represent ~5.5% of the company’s enlarged share
capital. The shares will be on par with the company’s Hong Kong-listed shares.
Our take: CNOOC has pursued this Shanghai listing following suspension of trading of CNOOC’s ADRs on the New York Stock
Exchange in March 2021. This suspension and subsequent delisting, has impacted access to capital and weighed on CNOOC’s
shares listed in Hong Kong.
The domestic IPO opens a new capital market for CNOOC, attracting Mainland China investors who are not curtailed by US
sanctions against the company. IPO proceeds would represent a quarter of the company’s 2022 capital spend of US$14-15
billion. CNOOC intends to use proceeds from the IPO to fund mostly oil projects in China and overseas. CNOOC specifically
refers to funding of the ExxonMobil operated Liza and Payara developments in Guyana.
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There have been reports that CNOOC has carried out a global portfolio review ahead of the listing and will exit UK, US and
Canada assets. These assets taken together represent less than 10% of remaining company value in our base case valuation,
versus Guyana by itself representing 10% of remaining value (NPV 10, January 2022). Disposal proceeds would add further
capital at the company’s disposal, to orient towards higher-growth, material investments in Latin America and Africa.
CNOOC’s share price has underperformed relative to peers despite strong financial results, top-quartile growth and dividend
yield. The company has stressed that it will actively manage share price by paying a special dividend, implementing share
buybacks in 2022 and maintaining an annual dividend payout ratio of 40% from 2022-24. If the IPO is oversubscribed at the
current 15% premium to trading price in Hong Kong today, it will be a confirmation of investor demand.
LUKOIL CEO sanctioned by the UK
Scott Walker and Erik Mielke, 18 April 2022
The facts: Vagit Alekperov, CEO and president of Russia’s second largest oil producer, LUKOIL, has been sanctioned by the
UK. Mr Alekperov is subject to a travel ban and asset freeze. LUKOIL itself has not been sanctioned by the UK, and neither
Alekperov nor LUKOIL are currently subject to sanctions by the EU. The list of 206 individuals added to UK sanctions also
include Vladimir Bogdanov, CEO of Surgutneftegas, Russia’s fourth largest oil producer.
Our take: there is no indication that LUKOIL will be directly affected by UK sanctions against Alekperov at this stage. If they are
forthcoming, however, LUKOIL’s large operational footprint outside Russia, both upstream and downstream, gives it a different
exposure profile than its Russian peers. On one hand, it provides a more geographically diverse cash flow stream if Russian
operations are affected. On the other, LUKOIL’s international assets could be impacted if sanctions escalate.
The company’s financial strength – gearing of 5% and a breakeven under US$30/bbl Brent – would insulate against any nearterm shocks, but the longer-term implications could impact LUKOIL’s strategic direction. International expansion has been a
core growth pillar for LUKOIL for over two decades, with a broad Caspian portfolio and recent acquisitions in Congo, Azerbaijan
and Mexico. Across its upstream business, we estimate LUKOIL’s overseas assets account for 29% of upstream NAV and a
quarter of operational cash flow out to 2025. As domestic production declines, this will increase to over a third by the end of the
decade.
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In downstream, LUKOIL holds interest in three refineries in the Netherlands, Italy and Bulgaria, which have capacity of around
600 kb/d – slightly over a third of total company capacity. Feedstock is largely supplied through its Swiss-based trading
business, Litasco, which has reportedly already scaled back operations to predominantly focus on marketing its own production.
LUKOIL international portfolio NAV
Upstream mergers and acquisitions activity slows in Q1
Greig Aitken and Scott Walker, 18 April 2022
The facts: global deal activity slowed in Q1 2022. Deal count fell by over one-third versus the previous quarter. Disclosed spend
of US$18 billion was down 56%. While there was a reduction in activity across most regions, it was the asset market outside of
North America that shrunk the most.
Corporate consolidation in US unconventionals reached over US$9 billion, with the largest deals seeing Oasis and Whiting
merging in the Bakken and Chesapeake acquiring Marcellus player Chief Oil and Gas. Global conventional spend centred on
Latin America and Africa. Petrobras raised US$1.9 billion from two more domestic divestments, while ExxonMobil exited its noncore shallow water assets in Nigeria in a US$1.3 billion with Seplat.
Our take: we had anticipated that deal flow would increase year-on-year, however we hadn’t anticipated the war in Ukraine.
We’ve long observed how commodity price volatility stymies deal flow, by increasing uncertainty and opening up a bid-ask
spread as buyers and sellers grapple to reach a consensus on pricing.
Price issues can be overcome with deal structures if both buyer and seller are committed to executing a deal, but inevitably
some potential transactions fall through as would-be buyers and sellers reassess.
Previously non-core assets will be throwing off considerable free cash flow at today's prices, allowing companies to strengthen
balance sheets and return cash to shareholders organically. If the price isn’t “right”, sellers will think twice. Yet buyers in today’s
market will be reluctant to extrapolate the near-term pricing environment into a longer-term paradigm shift.
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M&A Service subscribers can find more details on M&A trends, plus information on individual deals and rumoured transactions,
by accessing the Global upstream M&A in brief or the M&A Tool.
Global M&A – Q1 2022
Excelerate Energy IPO debut highlights US LNG momentum
Robert Polk and Rachel Schelble, 15 April 2022
The facts: floating LNG terminal provider Excelerate Energy completed a US$384 million IPO on 13 April 2022. The offering
was the first NYSE debut in any sector since Russia’s invasion of Ukraine. Shares were priced at US$24/share (at the high end
of preliminary indications), and immediately shot up 17% and closed the day up 12%. Shares closed up another 5% on the
second day of trading.
Our take: it’s hard not to infer market support for LNG infrastructure. Recent research meetings relayed skepticism regarding
both execution risks and capital available for numerous proposed project developments. Excelerate’s assets are not a direct
comparison to greenfield development or brownfield expansion plans, but the market response is a bullish indicator.
To be fair, geopolitical volatility slowed equity capital markets, so the immediate performance also likely reflects some pent-up
demand for new issue supply. Nevertheless, US LNG momentum continues to grow. Reducing Europe’s reliance on Russian
gas is a paradigm shift driving alignment from policymakers and industry alike. This alignment supports expansion and informs
investment decisions, and a successful IPO is another data point demonstrating the necessary capital support to finance
additional infrastructure.
Murphy Oil reaches first oil at King’s Quay
Robert Polk, 14 April 2022
The facts: Murphy Oil announced first oil from its deepwater Gulf of Mexico Khaleesi, Mormont and Samurai fields. Production
is now flowing though Murphy’s operated King’s Quay floating production system (FPS). Field development and the associated
FPS were sanctioned in August 2019 after Murphy acquired the assets from LLOG Bluewater.
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Our take: Murphy stands to benefit from the convergence of good execution and fortuitous timing. Bringing new production
online with oil prices hovering above US$100/bbl drives material cash flow expansion. US GoM production is set to increase 8%
to 66 kboe/d in 2022, and 2022 net cash flow is poised to more than double to US$1.2 billion from US$550 million in 2021. The
projects remained on schedule and within budget despite Covid and supply chain disruptions. Murphy’s excellent execution
allows the company to take advantage of favorable pricing.
The expansion in cash flow positions Murphy to accelerate stated corporate objectives. Murphy just increased its base quarterly
dividend 17% to US$0.175/share but has been open about its desire to return to its pre-pandemic quarterly base of
US$0.25/share. This was likely a 2023 occurrence, but the cash flow uplift easily covers the incremental ~US$47 million
annualized dividend outlay necessary to return to the targeted level. We expect Murphy to continue gradually increasing the
quarterly payout in subsequent quarters.
Excess cash flow will also further expedite debt reduction plans. Murphy is targeting a reduction in absolute debt by ~US$1.0
billion over the next three years. Murphy can comfortably cover the near term US$300 million reduction planned for H2 2022.
Note that Murphy also sold down its equity in the actual FPS facility in 2021 and used $268 million in proceeds to support
deleveraging.
Murphy’s success highlights its development expertise, but its US GoM exploration remains challenged. Over the last three
years, four GoM exploration wells yielded three dry holes. The ExxonMobil operated Cutthroat well in Brazil was also
unsuccessful. Tieback opportunities exist in the Gulf, but Murphy’s next development program remains unclear. Additional M&A
is always a possibility with Murphy and Petrobras is selling its stake in MP Gulf of Mexico, the JV it formed with Murphy in 2018.
Equinor adds to resource base in Norway heartlands
Greg Roddick and Norman Valentine, 08 April 2022
The facts: Equinor has made an oil and gas discovery at its Kveikje exploration well near the Fram field in Norway. Initial oil
resource estimates are in the range of 28 to 48 mmboe with gas in an overlying reservoir providing resource upside. Kveikje is
the second discovery in the Troll and Fram area during 2022 and the sixth since 2019. This latest find pushes gross discovered
resources in the area to over 420 mmboe, though the range of uncertainty is wide at this time.
Our take: Equinor’s strategy of exploring in the mature Troll and Fram area is delivering material results. Its net share in
discovered resources is now over 200 mmboe. Close to existing infrastructure, these discoveries have the potential to provide
attractive returns, short paybacks and low emissions.
We calculate that Kveikje has an indicative standalone IRR of 21% at a long-term Brent price of US$60/bbl (2022 real terms).
This assumes a mid-point resource of 38 mmbbl, FID in 2024 and start-up in 2027. Synergies will be found if the field is
developed as part of a larger Fram and North of Troll Area (FANTA) project that would tie the fields into existing infrastructure at
Troll. It could be the largest project in Norway after NOAKA and Wisting are sanctioned in late 2022.
For further details, please refer to Europe Upstream in Brief.
Euro Majors form new offshore floating wind partnerships
Norman Valentine and Akif Chaudhry, 8 April 2022
The facts: Eni, Equinor and Repsol have entered into partnerships that will target new opportunities in the offshore floating wind
sector in Italy and Spain.
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Eni, through its Plenitude subsidiary, and its joint venture partner CDP Equity, have signed an agreement with Copenhagen
Infrastructure Partners (CIP) to develop two floating offshore wind farms in Sicily and Sardinia. The planned projects will have a
total capacity of around 750 MW and could be online in 2026 (Sicily) and 2028 (Sardinia).
In Spain, Repsol has agreed to partner with Ørsted to explore joint development of floating wind opportunities in the country.
Meanwhile, Equinor has signed an agreement with Naturgy to explore offshore floating wind development ahead of an expected
wind auction in the Canary region in 2023.
Our take: these agreements position the European oil Majors for growth in floating offshore wind in new markets in their own
back yard. These alliances see the Euro Majors partner with companies that have either substantial offshore wind experience or
local development knowledge. We expect more floating wind partnerships to be formed as companies build exposure to the
sector, prepare for government tenders and look to share the risks and the costs of scaling-up new technology.
Suncor's wind stops blowing but 2050 net zero on track
Jonah Resnick, 8 April 2022
The facts: Suncor announced the planned divestiture of its wind and power business. The Canadian company has over 300
MW of wind power assets producing or in development. Online projects are located at Chin Chute, Magrath, SunBridge and
Adelaide, with 111 MW of capacity. Suncor is also completing the first phase of the Forty Mile Wind project in southern Alberta,
with a start-up date at the end of 2022 and 202 MW of capacity.
Earlier this year, Suncor also announced the planned divestiture of assets within the E&P business. This included all the
exploration and production assets within the Norwegian North Sea and reducing interests in Rosebank (UK North Sea).
The wind power and upstream asset exits are planned to complete later this year.
Our take: Canada’s second-largest oil and gas producer by market cap is getting more focused. Suncor had indicated that they
are now focusing on hydrogen and renewables as part of the energy transition. Rapid progress on the Oil Sands Pathways to
Net Zero alliance creates a mid to long-term route towards zero emissions from its core oil sands business while developing
technology solutions for the energy transition.
Of the large Canadian integrated operators, Suncor has one of the most diverse investment portfolios. The divestment
represents a more focused strategy, aligning with Suncor’s core competency as an integrated oil sands producer, and allows
better capture of the full value chain of products. The company is still high on ambition compared to North American E&P and
refining peers. And we still see wind as a viable route for other companies – especially when global scale, power trading or
offshore large project expertise can be applied.
Suncor is still involved heavily in other energy transition projects:
•
Hydrogen: In May 2021, Suncor and ATCO announced collaboration on a blue hydrogen project near Fort Saskatchewan,
Alberta. The project is planned to produce 5,161 b/d of hydrogen (300,000 tonnes per year), primarily for integration with
Suncor’s Edmonton Refinery. This will reduce overall emissions intensity. In addition, the spare hydrogen will be sold as
hydrogen markets further develop.
•
Biofuels: Suncor has been producing commercial biofuels since 2006. The Canadian large-cap operates the St. Clair
Ethanol Plant in Ontario producing approximately 400 million litres of ethanol per year (~6,893 b/d) and is co-venturing on a
waste & biofuels project at Verennes, Quebec led by Enerkem with a planned 125 million litres per day (~2,154 b/d) of biofuel
capacity. Suncor is also invested in Lanzajet, a company looking to convert alcohol to synthetic aviation fuels with small scale
pilot projects in America and Europe.
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Capital budgets for 2022 to grow 18%
Raphael Portela, 1 April 2022
Q4 earnings have come to a close. The late-coming Chinese NOCs reported budgets this week. And with that our final tally has
ballooned to 136 E&Ps with investments of US$315 billion in 2022, or 18% more than estimates for 2021.
Back in 2021, the Asian NOCs became the biggest spending peer group in oil and gas, surpassing even the Majors. In 2022,
history is repeating itself, though margins have thinned. PetroChina continues to hold the largest upstream budget at US$29
billion, ahead of even Saudi Aramco.
How are global capital budgets and production outlooks stacking up for this year? Read the final iteration of our Insight to find
out more.
Capex for 2021 is based on either the latest updated company guidances for 2021 or realized 2021 spend. Capex may be estimated. Midpoints are
used for companies that disclose guidance ranges. Our data attempts to isolate upstream exploration and development, with other expenditure items
(e.g., downstream and M&A) excluded where possible.
EQT upgraded back to investment grade
Robert Polk, 1 April 2022
The facts: EQT regained coveted investment grade status following recent rating agency upgrades. The company was
originally downgraded to high yield in January 2020 due to lower natural gas prices. S&P upgraded EQT’s corporate credit
rating to BBB- from BB+ on 28 March 2022. Fitch Ratings upgraded EQT earlier in March. Achieving investment grade credit
ratings from two of the three primary rating agencies unlocks many commercial benefits, the most significant of which is
unlocking access to international gas pricing.
Our take: higher commodity prices and increased scale set EQT on a trajectory back to investment grade. While not a surprise,
it is still an important milestone. Reduced letter of credit obligations eliminate costs and free up liquidity. There are also
contractual and cost of capital advantages. However, the most material opportunity is that it opens access to premium
international gas benchmarks.
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Project finance lenders and the LNG shippers require credit-worthy counterparties on the long-term supply agreements
necessary to underwrite large-scale project financing. Obtaining the accepted standard now allows EQT to pursue contracts tied
to TTF or JKM pricing net of shipping costs in exchange for its stable supply of certified responsibly sourced gas. Some of the
most financially secure US oil producers (EOG for example) enjoy these benefits on their gas production. Gas-weighted US
producers generally have not held the necessary financial standing. EOG now possesses a distinct advantage and differentiator
relative to its gas-focused peers.
Europe’s race to diversify its gas supply coupled with environmental benefits relative to other power sources like coal create
significant momentum for US LNG. Even before Russia’s invasion of Ukraine, EQT CEO Toby Rice had become a vocal
champion for increased US LNG exports. The company recently established an advocacy campaign titled Unleashing US LNG.
Multiple facilities are expected to take FID in 2022. Armed with a restored investment grade credit profile, EQT is now better
positioned to capitalize on this push.
Chevron enters carbon offsets markets
Alex Beeker and Rachel Schelble, 1 April 2022
The facts: on 28 March, Chevron announced a collaboration with Restore the Earth Foundation on a carbon offsets
reforestation project in Louisiana. The project will restore up to 8,800 acres of forest in St. Charles Parish, Louisiana. Figures
around capital investment and offsets generated were not released. It is also not immediately clear whether Chevron plans to
use the offsets to reduce the carbon intensity of its own portfolio, whether the offsets will be sold to third-parties, or if the offsets
will be used to offset their products or customer use.
In a separate release, Chevron announced the Caltex Carbon Offset Programme in Singapore. The move will allow customers
the option to purchase offsets for fuel they consume at Caltex branded retail stations. The move mimics what many of the Euro
Majors have been doing across Europe for several years.
Our take: Chevron has joined the ranks of Shell, TotalEnergies, Eni and BP with their leap into reforestation to generate highquality carbon offsets. The investment in offsets comes on the back of the formation of Chevron New Energies in 2021 with a
focus on hydrogen, CCUS, and offsets. Chevron’s entry into the carbon markets, while expected, is a sign that US companies
are now at the point of developing confidence in the future path of the voluntary carbon markets as a decarbonisation tool.
By 2028, Chevron expect to spend US$2.0 billion of its US$10 billion low carbon budget on carbon offsets. It has previously
announced its interest in exploring carbon sequestration projects in nature-based solutions, such as soil carbon storage,
reforestation and mangrove restoration. Nature-based solutions began to dominate the carbon market starting in 2021 as these
projects provide permanent carbon sequestration rather than avoid emissions like for example in renewable energy projects.
Chevron have not announced how they plan to use the offsets, but there are many different use cases that it can explore as it
builds up its portfolio – ranging from holding the offsets as financial collateral to using the offsets to compensate for its
emissions. More information on the options is available in Wood Mackenzie’s insight, Carbon offsets II: The strategies driving
the net zero of tomorrow.
TotalEnergies and Sempra expand North American strategic alliance
Tom Ellacott, 1 April 2022
The facts: TotalEnergies and Sempra have signed two Memorandums of Understanding (MoUs) for the development of LNG
exports and renewables. The first provides TotalEnergies the option to offtake one third of the LNG from the proposed 4 mmtpa
Vista Pacífico LNG export project in Mexico. TotalEnergies could also take a minimum 16.6% stake in the project.
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The second covers the co-development of renewable projects in North America. These include:
•
Sempra’s potential acquisition of 30% of TotalEnergies’ stake in an offshore wind project in California that is preparing for an
upcoming auction
•
TotalEnergies’ potential acquisition of 30% of Sempra’s interest in onshore renewable projects that are under development
along the US Mexico border
Our take: TotalEnergies’ move to expand its US LNG presence will help offset lost Russian LNG growth from the company’s
decision to cease investment in development projects in the country, including Arctic LNG 2 (19.8 mmtpa with TotalEnergies
holding a 10% direct stake). The company is targeting the acceleration of US LNG and its operated Papua LNG project in PNG
to ensure it still hits its target to double LNG sales by 2030.
Vista Pacífico could be a relatively quick mid-scale new LNG project in west Mexico. Regulatory risk is a factor, but potentially
mitigated through a project JV agreement with CFE, Mexico’s state-owned electric utility. The project will source Permian gas
via existing pipelines and offers geographic advantages for supply into Asia – a core market for TotalEnergies.
The combination of LNG and renewables is also a good fit for the Supermajor. TotalEnergies has been at the forefront of signing
cross-sectorial business development deals, for instance in Libya and Iraq. We expect this trend will gather momentum across
the oil and gas sector. The alliance also gives Sempra Infrastructure, a newly spun off subsidiary of Sempra that combines its
LNG and Mexico energy business, greater strategic direction.
Cepsa outlines ‘Positive Motion’ strategy to transform its downstream
business
Tom Ellacott, 1 April 2022
The facts: Cepsa has outlined a strategic plan to 2030 aimed at becoming a leader in sustainable mobility and energy in Spain
and Portugal. Highlights include:
•
Investment of €7 to 8 billion this decade, of which sustainable businesses will account for more than 60%
•
Sustainable businesses generate more than half of Cepsa’s EBITDA by 2030
•
Reduce Scope 1 and 2 emissions by 55% and Scope 3 by 15-20% by 2030. Reach net zero by 2050 and aim to become net
positive (removing more carbon from the atmosphere than they are emitting)
•
Develop 2 GW of green hydrogen, 2.5 mmtpa of biofuels production and 0.8 mmtpa of sustainable aviation fuels by 2030.
•
Build a 7 GW wind and solar pipeline that Cepsa will largely dedicate to supporting its own assets
•
Create the largest e-mobility network in Spain and Portugal with at least one 150 KW charger every 200 kilometres on key
inter-city corridors and hydrogen refueling stations every 300 kilometres across all the main road transport corridors.
Our take: allocating 60% of total investment to sustainable businesses underscores the scale of Cepsa’s ambitions. Although
not directly comparable, low carbon accounts for 35% of Repsol’s budget in its five-year plan – a proportion that ranks ahead of
all the Euro Majors. Cepsa also has more aggressive 2030 targets than Repsol for hydrogen (2 GW versus 1.9 GW) and
biofuels (2.5 mmtpa versus more than 2 mmtpa).
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These goals are indicative of what’s needed for Cepsa to adapt its asset base to support its decarbonisation targets. But the
strategy is not without risk. The plan hangs on Cepsa transforming its refineries from traditional fuels to low carbon alternatives.
The technology for that is not certain - success will require the development and deployment of second-generation biofuel
routes.
Cepsa did not change its E&P and Chemicals strategies. The company will run E&P as a cash engine to fund the downstream
transformation. Chemicals will remain an aromatics speciality business but with up to 30% of sales from low-carbon products by
2026.
Chinese NOCs report a strong 2021, energy security dominates 2022
outlook
Kavita Jadhav and Yuqi Hu, 1 April 2022
The facts: Sinopec Corp, PetroChina and CNOOC Ltd reported stellar 2021 annual results, propelled by demand recovery post
the pandemic and higher prices. Profits were many multiples of 2020, which was subdued due to the pandemic, but also much
higher compared to pre-pandemic levels in 2019. All three companies announced generous dividend payouts.
Our take: putting the pandemic behind, Russia’s invasion of Ukraine has brought energy security into even sharper focus for the
Chinese NOCs. The outlook for 2022 is dominated by increasing production, raising capital spend and investing in low carbon to
reduce emissions and diversify.
•
Net income: net income in 2021 relative to pre-pandemic levels in 2019, increased by 23% for CNOOC Ltd., 34% for
Sinopec Corp and 115% for PetroChina, benefitting from rising energy prices and higher volumes. Sinopec Corp and
CNOOC Ltd. saw net income increase to previous record levels seen in 2011.
•
Production: CNOOC Ltd. the upstream growth engine saw production increase by 9% and Sinopec Corp driven by shale
gas success had production rise by 5%. PetroChina’s upstream production is three times the level of its peers and it
maintained production steady at this scale. PetroChina and Sinopec Corp increased the share of gas in their portfolio, with oil
production declining since 2020; both are targeting a 5% increase in gas production for 2022.
•
Capex: CNOOC spent US$14 billion in 2021, up 19% y-o-y, Sinopec Corp spent US$26 billion up 31% y-o-y and PetroChina
spent US$41 billion up 9.5% y-o-y. Sinopec Corp announced it will raise capital spend in 2022 to US$30 billion, making it the
biggest annual capital budget in its history. This increase will shift focus to the upstream as Sinopec has already invested
heavily in the downstream over the last few years. CNOOC Ltd. will increase 2022 capex by 7% and maintain capital at this
level until 2025 to support a production CAGR of 5-6%. PetroChina will reduce overall capex by 3% y-o-y, with downstream
seeing the reduction.
•
Energy transition: CNOOC confirmed earlier guidance to spend 5-10% of annual capex on energy transition. PetroChina
announced that it would double energy transition capex in 2022 from RMB3 billion in 2021. PetroChina laid out a timeline to
reach net zero and outlined a strategy which will combine oil, gas, clean power, hydrogen and CCS such that oil, gas and
new energy each account for one-third of production capacity by 2035.
•
Shareholder returns: Sinopec Corp had the highest 2021 dividend payout ratio of nearly 80%. PetroChina declared a
dividend payout of 45%. CNOOC will declare year-end dividend after completion of its Shanghai listing, but confirmed that
the payout would exceed 40%. Sinopec Corp has for the first time proposed a share buyback and will repurchase 10% of its
shares.
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Net Income
Capex
Source: Wood Mackenzie Corporate Service, company reports
Source: Wood Mackenzie Corporate Service, company reports
PTTEP latest NOC to join net zero club
Andrew Harwood, 1 April 2022
The facts: Thailand’s PTTEP is the latest national oil company (NOC) to announce a net zero emissions target, setting 2050 as
the date by which it will go carbon neutral. PTTEP’s target covers Scope 1 & 2 emissions for assets under operational control. In
support of this goal, PTTEP aims to reduce Scope 1 & 2 emission intensity by 30% by 2030, and by 50% by 2040.
Our take: PTTEP’s latest 5-year plan will see it invest US$4.4 billion in renewable and low-carbon businesses during 20222026, equivalent to 14% of its expected spend over the period. This low-carbon investment will be directed towards gas and
LNG to-power, offshore/onshore wind, solar, CCS/CCUS and hydrogen.
To reduce emissions, PTTEP will increase its emphasis on natural gas, and factor emissions intensity into future investment
decisions. The share of gas in PTTEP’s annual output is set to rise to 50% by 2026, while our emissions modelling shows net
equity intensity falling from 37 kgCO2e/boe in 2020 to 24 kgCO2e/boe in 2030.
However, operated intensity will remain steady over the period at 17–18 kgCO2e/boe. Considerable investment will be required
to minimise emissions from mature operations in the Gulf of Thailand, and to apply CCS at the Lang Lebah gas project in
Sarawak, Malaysia.
PTTEP becomes the fifth Asian NOC to set a net zero target, after PETRONAS, CNPC, Sinopec (2050) and CNOOC (2060).
NOCs have thus far avoided the same level of scrutiny as their international oil compamy peers. But as governments set
national climate targets in the wake of COP26, pressure is growing on the NOCs to follow suit.
Low-carbon diversification is also increasingly important, particularly for importing NOCs such as PTTEP, not only to support
climate goals, but to improve energy security. As we highlight in our recent insight, National Oil Companies: strategies for the
energy transition, current commodity prices provide further impetus for finding new, sustainable and affordable sources of
energy.
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Q1 2022
Ørsted boosts IRRs through farm-down of 50% stake in giant 1.3 GW Hornsea 2
Akif Chaudhry and Norman Valentine, 28 March 2022
The facts: Ørsted has agreed to sell-down half of its current 100% holding in the giant 1.3 GW Hornsea 2 offshore wind project
in the UK for GBP3 billion (c.US$3.9 billion). AXA IM Alts and Crédit Agricole Assurances will each take a 25% stake.
The deal is being financed through debt and equity, with the financing being originated and structured by Ørsted.
Hornsea 2 is currently under construction. The transaction is expected to close in H2 2022 when the wind farm becomes
operational (subject to final regulatory approvals). Ørsted will provide O&M services for 20 years as well as balancing services
and a long-term route to market for electricity generated by the project.
Our take: at 1.3 GW, Hornsea 2 is a massive project by global standards and the farm-down forms a huge step in boosting
returns for Ørsted. We estimate the deal will ramp-up Ørsted’s project IRR to the low teens from our previous pre-deal estimate
of a single-digit asset return.
With a host of players such as utilities, investment funds and the oil and gas Majors on the hunt to add more offshore wind to
their portfolios, this is a great deal for Ørsted. Today’s announcement highlights the value-generation potential from assetrotation right now – it’s a key lever to pull for those with a more mature portfolio to play with.
Ørsted is executing well on its strategy to farm-down de-risked assets in which it holds a majority stake. The Hornsea 2 deal
comes hot on the heels of other material deals at Borsesele 1 & 2 in the Netherlands, Greater Changhua 1 in Taiwan and
Borkrum Riffgrund 3 in Germany.
The greater challenge for Ørsted and the wider market is how to boost payback from projects currently in the early development
stages. Competition is intensifying and returns from new project development have come under increasing pressure across the
market.
Look out for our upcoming Corporate Power and Renewables Insight benchmarking the leading European offshore wind
companies.
Our transactions database provides a comprehensive repository of global offshore wind asset transactions. Detailed asset-level
modelling of Hornsea 2 can be accessed through Wood Mackenzie’s Lens Power. Please contact your account manager for
further details.
SEC proposes mandatory climate-related disclosures
April Read, 25 March 2022
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The facts: on 21 March, the United States Securities and Exchange Commission (SEC) issued its long-awaited proposal for
mandatory reporting of climate-related disclosures. It joins the likes of New Zealand, the United Kingdom and European Union
moving from voluntary to mandatory reporting. The proposal includes information on what to disclose and timelines, such as:
•
Inclusion of disclosure in SEC required documents, like the 10-K, not just a standalone sustainability report
•
Climate-related risks and potential impacts on business operations, strategy, and outlook, along with how those risks are
managed
•
A company view of targets and goals in addressing climate-related risks, including physical and transition risk
•
Large companies will publish first reports in 2024 (with 2023 fiscal data), except for Scope 3 GHG emissions data, which will
be required the following year
Our take: the noise from the investing community requesting transparent, consistent and comparable sustainability data has
gotten louder and the SEC has listened. Moving quickly on the proposal, now in the 60-day comment period, could springboard
the US into the mandatory reporting early adopter’s group. There’s good, challenging and interesting information highlighted
in the SEC Fact Sheet.
The good news for upstream oil and gas is that the SEC proposal is closely aligned with the Task Force for Climate-Related
Financial Disclosure (TCFD). As TCFD is widely considered the gold standard, many upstream companies already align with the
TCFD framework in reporting Scope 1 and 2 emissions in their corporate sustainability reports.
The challenging? Inclusion of Scope 3 emissions, if material. And for oil and gas operators, Scope 3 emissions will be
material. The inclusion of Scope 3 emissions will likely receive a lot of public comment as there is uncertainty in how Scope 3
emissions should be allocated along the oil and gas value chain.
One interesting facet of the proposal is the requirement to include information about carbon offsets and internal carbon
pricing. The SEC proposed that understanding the role of offsets and internal carbon price is a key factor for investors in
evaluating a corporation’s climate change risk exposure. This will require a change of mindset for some corporations that view
carbon price as a commercially sensitive component of their strategy.
To learn more about how oil and gas companies are using carbon offsets to decarbonise their businesses, see our latest insight
on the corporate strategies driving the net-zero of tomorrow.
TotalEnergies outlines its vision for 2050
Tom Ellacott, 25 March 2022
The facts: TotalEnergies confirmed that its strategy is on track in its Sustainability & Climate – 2022 Progress Report. The
company has enlarged its ambition to become a multi-energy company. The report included new emissions reduction targets
and, in a first, a vision for its portfolio in 2050. New guidance in a content-rich presentation included:
•
Vision for 2050: the company outlined a production split of 50% renewable power, 25% decarbonised molecules (biofuels,
biogas, hydrogen and e-fuels) and 25% oil and gas (mainly LNG with only 0.2 to 0.3 million b/d of oil, down from 1.6 million
b/d currently).
•
Emissions reduction targets: reduce Scope 3 oil emissions by more than 30% from a 2015 baseline by 2030. The
company also upgraded its methane emissions reduction target to 50% by 2025 and 80% by 2030 (from a 2020 baseline).
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Corporate week in brief
•
Offsetting 2050 residual emissions: TotalEnergies will develop 50 to 100 mmtpa of CCS capacity by 2050 to offset its
residual Scope 3 emissions from its customers. The company will also use Nature Based Solutions to offset 10 mmtpa of its
Scope 1 and 2 emissions in 2050.
•
Capex guidance: the company increased the upper range by US$1 billion to give new guidance of US$13 to US$16 billion
between 2022 and 2025. TotalEnergies will allocate 5% of the total budget to low emissions fuels (“new molecules” in
TotalEnergies speak).
Our take: TotalEnergies gave a positive progress update in its Strategy, Sustainability & Climate presentation. The strategy is
unchanged: to maintain oil to 2030, increase LNG and grow renewables and low emissions fuels. But the 2050 vision provided
welcome clarity on how the portfolio mix will evolve to get to net zero.
The 25% contribution from new molecules and reduction in oil production underscore the scale of the portfolio transformation.
The 30% targeted reduction in Scope 3 oil emissions by 2030 – a big number equivalent to more than 105 mmtpa of CO2 – is
another indication of the seismic shift in TotalEnergies’ European downstream business that will gather pace this decade.
With no new targets, renewables wasn’t a big focus on the call. But management did outline why TotalEnergies is investing in
wind and solar in response to concerns around returns, rising costs and execution challenges. TotalEnergies’ response is to
take more risk to boost returns. That means taking more merchant price risk (30% merchant/70% PPA).
The US$1 billion increase in the upper range of the capital budget was a surprise given the decision to halt investment in
Russia. TotalEnergies has re-activated short-cycle spend to take advantage of soaring prices and will also leverage its
opportunity-rich portfolio in LNG to offset the lost growth in Russia. The implication is that the company will accelerate projects
in the US (e.g. Cameron Train 4 and other options) and PNG.
TotalEnergies' vision for 2050
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Storm damage at CPC Black Sea oil terminal highlights risk for Majors in
Kazakhstan
Alex Beeker, 23 March 2022
The facts: at the Caspian Pipeline Consortium (CPC)’s Black Sea terminal in Russia, two of the three single point moorings
(SPMs) are offline for repairs. Inspections revealed the scale of damage suffered during recent high winds.
To Kazakhstan's relief, tanker loadings resumed on 25 March from the third undamaged SPM. According to Russia's Energy
Ministry, remedial work will take more than a month. With two SPMs offline, up to half of the CPC terminal's 1.6 million b/d
capacity could still be available.
The CPC is Kazakhstan’s core liquids export route, via Russia transit. In 2021, more than 1.3 million b/d was shipped from its
terminal, almost 90% of which was from Kazakhstan. This is about 65% of all Kazakh liquids.
Our take: Chevron, ExxonMobil, Shell, TotalEnergies and Eni all have exposure to Kazakhstan upstream through megaprojects
Tengizchevroil, Kashagan and Karachaganak. Chevron has the largest exposure to the country which accounts for ~370 kb/d or
~20% of the company’s net liquids production. On 25 March, Chevron announced it was reducing production at Tengizchevroil
and would export crude in line with CPC's allocation.
The timing of the unplanned outage will certainly draw scepticism. At its recent Investor Day, Chevron fielded questions about
the pipeline’s vulnerability to the ongoing Russia-Ukraine conflict. The company acknowledged but downplayed the risk
involved.
Tengizchevroil and Kashagan both have expansion plans. Oil production from the megaprojects is set to grow from 880 kb/d in
2021 to 1.5 million b/d in 2032. The export terminal outage highlights the concentration risk involved with having a single primary
off-take option. Temporary alternative routes include the Baku-Tbilisi-Ceyhan (BTC) pipeline from Azerbaijan or the KazakhstanChina Oil Pipeline. But available capacity would cover just a fraction of the CPC volumes.
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Oxy Low Carbon Ventures Investor Day
Zoë Sutherland, 25 March 2022
Oxy held its Low Carbon Venture Investor Day this week where it laid out its strategy for its carbon management business.
Through its wholly-owned subsidiary 1PointFive it will focus on three elements of the market where it sees potential; point
source carbon capture, direct air capture (DAC) and low carbon aviation fuel.
To support point source carbon capture it is planning three carbon sequestration hubs to start-up by 2025, with a combined
storage capacity of 18 Mtpa. Interest from emitters which could tap into the hubs is high – Oxy is working with 50 projects with
over 40 Mtpa of capture potential. However, it acknowledged that only a small subset of volumes are economic at present and a
‘moderate’ increase in incentives would be needed to unlock larger volumes.
Oxy remains on track to bring its first DAC facility online in late 2024, with an initial capture capacity of 0.5 Mtpa. The capital
cost of the facility is expected to be between US$800 million and US$1 billion. Under current market conditions, it sees potential
to have 70 DAC facilities in operation by 2035, and with more supportive policy this could almost double to 135. However, it
estimates a carbon abatement cost of US$250/for DAC today, making it a lower cost solution for only the hardest to decarbonize
industries where abatement cost run as high as US$1,000/t. If the abatement cost of DAC could be halved, this would triple the
size of the market. Lowering costs is a key focus.
Oxy also plans to tap into the low carbon fuels market, locating fuel synthesis facilities alongside its DAC facilities to produce
low-carbon fuels. It expects DAC could facilitate the lowest cost sustainable aviation fuel by 2050. However, in the nearer term it
sees more potential for DAC to generate carbon offsets for the aviation market, with DAC credits 30% to 40% cheaper than
current sustainable aviation fuels.
Lastly, Oxy highlighted the potential to use captured CO2 in its EOR operations in the Permian to lower costs and produce ‘net
zero’ oil.
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The company revealed less detail on how much capital it would direct towards its low carbon business. This year it will spend
US$100-300 million, only 7% of its total spend. It gave no guidance on future years making clear it wanted to remain flexible
going forward. To meet its projections of 70 DAC facilities would undoubtedly require project financing, presale of carbon
removal credits or a sell down of 1PointFive equity.
This cautious approach is unsurprising given the company’s balance sheet remains stretched. Investors are unlikely to support
Oxy directing large sums of capital to a business that is as embryonic as carbon capture.
Oxy has said that its low carbon business could eventually be bigger than its petrochemical business. But, despite questions on
the value proposition dominating the Q&A session, Oxy gave little away. It may just be too early to quantify. While the longerterm potential is clear, there are still many unknowns. Substantial advancement in technology, policy and market support are
needed before CCUS can become a profitable, scalable business. Predicting the pace at which these complex drivers evolve is
extremely difficult.
TotalEnergies outlines new steps in Russia
Tom Ellacott, 23 March 2022
The facts: TotalEnergies has laid out principles of conduct for managing its Russian business. The main points are:
•
Ensure strict compliance with current and future European sanctions. The company will gradually suspend its activities in
Russia.
•
Provide no additional capital for development projects in Russia. This includes the Arctic LNG 2 project, for which
TotalEnergies will no longer record proved reserves in its accounts.
•
Do not unwarrantedly transfer value to Russian interests by withdrawing from assets. TotalEnergies outlined that
“abandoning these interests without consideration would enrich Russian investors, in contradiction with the sanctions’
purpose”.
•
TotalEnergies will continue to supply LNG to Europe from the Yamal LNG plant as long as Europe’s governments consider
that Russian gas is necessary. However, the company will halt all its purchases of Russian oil and petroleum products as
soon as possible and no later than end 2022.
Our take: the key measure, perhaps clarification, announced by TotalEnergies is that it will cease investment in Arctic LNG 2.
The company had previously said it would not make any new investments in Russia but was vague on what constituted “new”
investment. Either way, halting investment in Arctic LNG 2 is a meaningful move.
TotalEnergies’ 10% equity stake in the project represents the fourth largest development in its portfolio. It has already invested
US$1.2 billion in Arctic LNG 2 and was due to spend another US$485 million this year (on an equity basis). The decision to halt
investment increases the risk that first production, scheduled for 2023, will be pushed back. The company’s stake may also be
at risk of dilution by not continuing to invest in the asset.
Phasing out Russian crude oil purchases was the other new measure announced by TotalEnergies. That aside, TotalEnergies’
‘principles of conduct’ were a defence of its continued presence in Russia – through its directly held asset interests and its
19.4% equity stake in NOVATEK.
We have previously discussed how TotalEnergies has most at stake in the country, both strategically and from a valuation
perspective. The Supermajor has outlined the issues it faces with exiting Russia and how its exposure is manageable. But this
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announcement is unlikely to draw a line under the matter. TotalEnergies will continue to face pressure over its stance – one that
stands out from BP, Shell, ExxonMobil and Equinor which have all announced intentions to exit.
Eni boosting gas, reducing emissions, increasing distributions
Greig Aitken, 21 March 2022
The facts: at its Capital Markets Day, Eni upgraded emissions targets, updated its shareholder distribution policy for the higher
price environment, and announced the creation of a new dedicated sustainable mobility company. The Italian Major also
clarified its longer-term capital allocation plans, which will see 60% of capex allocated to new energies by the end of the decade.
Responding to the European gas crisis, Eni is working on increasing both third-party and equity gas volumes into the region
over the short- to medium-term
Our take: there was a raft of updates and upgrades, all complementary to its existing long-term ambitions. Highlights include:
•
Creation of a dedicated sustainable mobility business incorporating biofuels and fuel stations. This was a surprise but is in
line with Eni’s wider corporate restructuring towards more discrete business units. Worth noting however that Eni’s previous
target of 2 mmtpa of biofuels capacity by 2024 has been pushed back to 2025 after permitting and other delays (now
apparently resolved).
•
Upgraded emissions targets. Now targeting net zero on a Scope 1&2 basis by 2035 (previously 2040) with enhanced interim
targets. Interim Scope 3 targets have also been increased. Eni already had some of the most stringent and detailed targets of
all the Majors.
•
Capex is largely unchanged in the four-year plan. But longer-term targets showed how the green revolution will accelerate –
Eni intends to funnel 60% of capital to new energy solutions by the end of the decade, rising to 80% by 2040. This is again
the most aggressive target among the Majors.
•
Eni has tweaked the parameters of its variable distribution policy. The maximum dividend per share rises from €0.86 to
€0.88. The previous maximum is also reached at a lower reference price (US$61/bbl, versus US$65/bbl previously). The
maximum buyback increases from €800 million (at €66/bbl Brent) to €1,100 million (at €80/bbl Brent). In historical terms,
these are strong distributions, though some might have expected a higher maximum DPS, or additional levels of sensitivity,
given current prices.
The current energy crisis was also a key topic, and Eni is focused on accelerating gas into Europe (both third-party and equity
gas). It has 14 tcf which it believes it can make available in the short-to-medium term. Congo LNG, for example, was not in our
base case when the fast-track project was announced at last month’s Q4 results, with an intended 2023 start-up. In the nearer
term, there will be additional volumes from Algeria and Libya, while further out, Mozambique has likely moved up the agenda.
Aramco's earnings more than double
Norman Valentine, 21 March 2022
The facts: Saudi Aramco’s annual net income increased 124% year-on-year to US$119 billion, boosted by higher oil prices,
improved downstream margins and the consolidation of SABIC full-year results. Average annual oil and gas production was
broadly flat at 12.3 million boe/d.
Surging annual free cash flow (+119% y-o-y to US$108 billion) supported dividend commitments (US$75 billion) and higher
annual capital expenditure (+18% y-o-y to US$32 billion) with cash from pipeline asset sales strengthening the balance sheet.
Gearing fell from 17% to 14% in the final quarter of the year and is now within the company’s target range of 5-15%. Aramco
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maintained its quarterly dividend at US$18.8 billion but will reward shareholders with one bonus share for every ten held. This
will be backed by the capitalisation of US$4 billion of retained earnings.
Our take: Aramco’s outlook for rising investment was the most notable takeaway from its annual results. With finances back in
shape, Aramco has committed to a renewed phase of investment, primarily in new oil and gas production capacity. The
company has set its 2022 investment budget at US$40-50 billion, a level that exceeds the company’s pre-2020 oil price crash
spending ambitions.
The primary investment goal will be the expansion of Aramco’s maximum sustainable oil production capacity to 13 million b/d.
Aramco expects this to be achieved over the next five years. Increasing gas output by 50% by the end of the decade is another
core strategic objective, underpinned by growing output from the Jafurah Basin. Renewables, CCS, hydrogen and energy
efficiency investment have also moved up the investment agenda following Aramco’s commitment to achieve net zero scope 1
and 2 emissions by 2050.
OMV announces new net-zero target and plan to transition away from oil &
gas
Zoë Sutherland, 18 March 2022
The facts: OMV has published its new strategy to 2030. It re-emphasised its goal to become a leading, integrated sustainable
fuels, chemicals and materials company with a strong focus on the circular economy. As part of its shift to a low-carbon
business it will reduce oil and gas production by 20% by 2030 and stop oil and gas production for energy use altogether by
2050. The company also expanded its 2050 net zero target to include Scope 3 emissions.
Our take: by setting a Scope 3 net zero target, OMV has placed itself ahead of most IOCs. Outside of the Euro Majors, only a
handful of O&G companies have made such a bold commitment. Oxy and Denbury are the exceptions among the
Independents, both with plans to establish large CCUS businesses to offset emissions.
OMV’s decision to wind down its E&P business will be key to reaching its Scope 3 target. It had previously said it would deemphasise oil and gas, but it has now set clear measurable goals and a timeline for doing so. Upstream spend will drop from
around US$1.5 billion per year currently to US$800 million per year post-2025. OMV has said cashflow from its oil and gas
portfolio will help support the company’s transformation, but we cannot rule out an opportunistic sale if the right buyer could be
found.
The military conflict in the Ukraine has added to the pressure of the energy transition and OMV has made clear its assets in
Russia are no longer core. We estimate OMV has close to 20% of its remaining value in Russia through the South Russkoye
field. Today, around 20% of its production comes from Russia, so an exit would allow it to immediately meet its target to reduce
hydrocarbon output by 20%.
OMV is planning significant growth in its low-carbon business which will focus on geothermal energy and carbon capture and
storage (CCS). The company has set a big ambition in the former, targeting energy production of 9 TWh by 2030 in a
commitment that differentiates it from other oil and gas companies. OMV is also aiming to capture 5 Mtpa of CO2 by 2030. For
CCS these are also big targets, on par with TotalEnergies and Eni.
To support the transition, OMV is ramping up spend on its low-carbon business across three segments. It forecasts low-carbon
spend will surpass E&P spend in the second half of the decade, growing from near zero to 27% of total capex (US$1 billion per
year) out to 2025, and increasing to 53% of total capex (US$1.9 billon per year) post-2025. This runs ahead of all the Majors in
the second half of the decade – BP bookends the peer group with 50% of its 2030 budget earmarked for low carbon.
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National Oil Companies: strategies for the energy transition
Raphael Portela, Yuqi Hu, Liam Yates, Andrew Harwood, Kavita Jadhav, 14 March 2022
National Oil Companies (NOCs) have avoided the same level of scrutiny on decarbonisation plans and emission targets as their
International Oil Company (IOC) peers in recent years. National obligations and a different set of stakeholders provide for
differing strategic priorities.
But given their scale and financial resources, NOCs will have an increasingly crucial role in the energy transition. Matching the
Majors in their low carbon capital allocation would result in a four-fold increase in investment in new energies and
decarbonisation. As intergovernmental and investor pressures rise, is the National Energy Company of the future about to
emerge?
Read our Insight for benchmarking of NOCs on energy transition progress and our view on the critical role NOCs will need to
play for net zero to be reality.
Eni and BP finalise new Angolan JV
Greig Aitken, 13 March 2022
The facts: Eni and BP have agreed to combine their Angolan businesses to form a new 50/50 independent company, Azule
Energy. This follows the memorandum of understanding between the companies agreed in May 2021. Eni will receive US$422.5
million on completion of the deal, plus an additional US$235.5 million one year later. Azule Energy will be equity accounted by
BP and Eni.
Azule will produce ~200 kboe/d. It will hold stakes in 16 licences, as well as participating in the Angola LNG joint venture. It will
also take over Eni’s stake in Solenova, a solar company jointly held with Sonangol.
Our take: though macro circumstances have clearly changed significantly since the MoU was announced last May, the
transaction remains aligned with each companies’ strategy. As both BP and Eni increasingly diversify their businesses beyond
upstream, their Angolan operations will gain a new lease of life, with the autonomy and capital structure to be more dynamic,
efficient and effective.
We previously commented that the Angolan portfolios were well-matched resource-wise, with each company contributing
around half of the combined reserves and both portfolios having similar 75/25 oil to gas splits. We did note that Eni’s portfolio
carried a higher value, which has been recognised in the cash payments to the Italian Major.
For further analysis of the combination, see our earlier video Insight.
Eni targets energy transition with green SPAC
Greig Aitken, 13 March 2022
The facts: Eni-backed special purpose acquisition company New Energy One Acquisition Corp Plc (NEOA) has IPO’d in
London, raising £175 million (US$228 million). LiveStream LLC, an investment company, is sponsoring the listing alongside Eni,
which is contributing 10% of the ordinary share capital and ~25% of the sponsor capital. NEOA will pursue a business
combination with targets that are positioned to participate in or benefit from the energy transition.
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Our take: Eni is using every tool in the corporate structure box to execute its long-term decarbonisation strategy, which is
perhaps the most stretching of all the Majors' net zero targets. Plenitude, which is intended to spin-off this year, will focus on gas
and power retail, renewables, and e-mobility. But the group will continue to decarbonise operations and chase other low-carbon
opportunities. The establishment of this SPAC offers yet another route for Eni to accelerate its low-carbon exposure.
OGCI expands partnership to eliminate methane emissions by 2030
Anuj Goyal, 11 March 2022
The facts: the Oil and Gas Climate Initiative (OGCI) launched its Aiming for Zero Methane Emissions Initiative to reach near
zero methane emissions from operated upstream assets by 2030. The partnership plans to achieve this through avoiding
methane venting and flaring, repairing detected leaks, and improved emissions monitoring and reporting. This adds to OGCI’s
existing goal of lowering methane intensity to below 0.2% by 2025.
Our take: this announcement highlights the growing industry consensus that lowering methane intensity is the fastest and most
cost-effective way for companies to lower total emissions. Since meeting this goal relies of proven technologies, companies can
set firm budgets for these projects and demonstrate tangible progress towards broader emissions targets.
Meeting these goals will require coordination across the upstream value chain – oilfield services, E&Ps, and midstream
companies. Operators are benchmarking third part flaring due to planned and unplanned maintenance at their gathering
partners. At the same time, operators' urgency to meet this target creates opportunities for the oilfield services sector to provide
identification, mitigation, and measurement services with a focus on air emissions. For example, Schlumberger recently
launched a dedicated business line to provide customers end-to-end services to meet their methane and flaring emissions
targets.
Shell announces its complete withdrawal from Russia
Luke Parker, 8 March 2022
Shell has announced its intent to withdraw from its involvement in all Russian hydrocarbons, including crude oil, petroleum
products, gas and LNG. The company will:
•
stop buying Russian crude oil on the spot market, and will not renew term contracts
•
remove Russian volumes from its crude oil supply chain (i.e. no more third-party Russian volumes through Shell refineries)
•
shut down Shell service stations, aviation fuels and lubricants operations in Russia
•
withdraw from Russian petroleum products, pipeline gas and LNG
Some of these things will happen immediately, others will require a longer transition.
Shell had already moved to exit its upstream interests in Russia. This latest announcement effectively severs all ties to the
country.
Continental Resources invests in carbon capture
Robert Polk, 4 March 2022
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The facts: Continental Resources agreed to invest US$250 million over two years in Summit Carbon Solutions US$4.5 billion
carbon capture and storage project. The project will capture CO2 from ethanol plants and other agriculture operations
throughout the US Midwest and transport the CO2 to North Dakota for permanent storage. Continental’s investment will primarily
support the sequestration infrastructure in North Dakota’s subsurface. Initial storage capacity stands at 12.0 MMtpa and the
project currently has commitments of > 8.0 MMtpa from 31 ethanol facilities.
Our take: limited details make it difficult to understand all the benefits to Continental beyond return on investment, but this
illustrates a notable shift in strategy. Continental’s admirable emissions reductions contrasted with relatively weak targets
compared to its tight oil peers. The expansion into CCS and partnering with other industries shows a broader commitment to
low-carbon solutions beyond its own operations.
The annual investment represents ~5% of Continental's annual budget. While material, Continental is entirely unhedged on oil
and can easily fund the incremental investment out of operating cash flow without impeding any other corporate objectives.
Continental’s scale, geological understanding, and regulatory experience in North Dakota add value to the project. Less clear is
whether the sequestration will take place in Continental’s depleted reservoirs and what else Continental receives (offsets, tax
benefits, etc.) for its capital and knowledge.
ConocoPhillips and Occidental have utilized carbon capture for EOR operations for years, while EOG recently announced a
project to reduce emissions from its production. There will be many more opportunities for US independents to partner with
carbon capture projects. Excess cash flow across the sector can facilitate. Continental’s investment showcases a repeatable
template to contribute subsurface expertise in addition to capital.
Wintershall Dea responds to Russia-Ukraine conflict
Zoë Sutherland, 3 March 2022
The facts: Wintershall Dea has announced its response to the Russia-Ukraine conflict. The company has decided:
•
not to pursue any additional gas and oil production projects in Russia, and to stop all planning for new projects
•
to basically stop payments to Russia with immediate effect
•
to write off its financing of Nord Stream 2
While payments in and out of the country will stop, operations at its Russian fields will continue and it will remain part of its
existing Russian JV's.
The company has postponed any decision on its dividend until further notice.
Our take: we estimate Wintershall Dea’s remaining value in Russia at US$8.7 billion or just over 40% of its total value (NPV10,
US$50/bbl long-term Brent). This makes Wintershall Dea, proportionally, the most exposed IOC to Russia. Around 37% of its
cashflow in 2022 was to come from its Russian assets. It will now be heavily reliant on its second largest producing region,
Norway, which contributes close to 50% of cashflow.
Wintershall Dea’s balance sheet is in good shape. At the end of Q4 2021 gearing had fallen to 24%. But the loss of Russian
cashflow, combined with the €1 billion (US$1.1 billion) write-down on its investment in Nordstream 2 will still be a significant
blow. Postponing its decision on its dividend makes sense - it is one option for Wintershall Dea to save cash. The company
payed out a total of €686 million (US$760 million) in dividends in 2021.
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In the short term, Wintershall Dea’s plans to IPO are likely to be affected. The date for the IPO has already been delayed as it
waited for market conditions to improve post-covid. The latest developments are potentially more damaging to its market
valuation.
The situation has implications for Wintershall Dea’s longer-term strategy. Gas is central to its energy transition strategy and its
aim to tackle Scope 3 emissions through investing in hydrogen and CCS. Over 50% of the gas it produces comes from Russia.
Without it, the gas share of its energy mix falls from 70% to 60%.
ExxonMobil’s 2022 Analyst Day
Tom Ellacott, 4 March 2022
The facts: ExxonMobil left no doubt that the energy transition is driving its strategic thinking at its 2022 Analyst Day. The
session was also an opportunity to showcase the performance improvement drive underway in the oil and gas business.
Our take: the Supermajor devoted two full sessions to low carbon and decarbonisation, slotting the Low Carbon Solutions
session before the Upstream and Product Solutions breakouts. The presentations shed more light on a coherent strategy that
has emerged over the last year – one that plays to ExxonMobil’s competitive strengths and emphasises flexibility.
The Supermajor is concentrating on biofuels, CCS and hydrogen.
ExxonMobil believes the scale of the investible market in these technologies would be sufficient to grow earnings and cash flow
even in a Paris-aligned scenario in which the legacy business is shrinking.
In practise, the low carbon strategy is still in its infancy. Biofuels projects are progressing through the opportunity hopper, but the
other technologies are longer-dated portfolio options. ExxonMobil’s announcement of the Baytown Blue Hydrogen project on the
call is part of a commercialisation strategy that leverages its existing legacy infrastructure. The company also continues to
monitor other technologies, including offshore wind.
An improving margin mix, volume growth and aggressive cost-cutting are driving portfolio improvement across the Upstream
and Product Solutions businesses. This underpins plans to double earnings and cashflow by 2027. The Supermajor also
outlined how its cash flow breakevens fall to US$30/bbl by 2027, giving further confidence in the sustainability of the dividend.
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Chevron’s 2022 Investor Day recap
Alex Beeker, 3 March 2022
The facts: higher returns and lower carbon were again major themes at Chevron’s 2022 Investor Day. The combination of
higher prices and capital discipline are resulting in record free cash flow generation for the company.
There were no big changes in strategy, possibly reflecting Chevron’s level of contentment with its portfolio at US$100/bbl Brent.
The company has worked hard to position its portfolio to outperform at low and high prices. But the company will not increase
investment at current prices and is still preparing for a US$50-60/bbl Brent environment long-term.
Chevron extended capex guidance of US$15-17 billion through 2026 and raised its 2022 buyback guidance range to US$5-10
billion, up from US$3-5 billion previously. The company’s goal is to set share repurchases at a level at which they can be
sustained through the cycle with the balance sheet absorbing cash outburn during downcycles.
Our take: the most difficult question Chevron may face over the next 12 months is what to do with excess cash flow at
US$100/bbl Brent. Record free cash flow generation is enticing but a lower-carbon future can’t be ignored.
At US$88/bbl Brent this year, we forecast Chevron to generate US$33 billion in cash flow (post-dividend), far above its current
US$5-10 billion buyback target. But there is no obvious use of the excess cash as the balance sheet is already in good shape
and its capex budget is relatively fixed.
If prices hold, we think Chevron has potential to increase buybacks even further. But M&A could also receive increased
attention. Any upstream deals would likely address Chevron’s concentration risk and possibly add more gas to its portfolio.
Deepwater exploration, downstream, and new energies are all areas into which Chevron could expand.
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Chevron 2022 Investor Day
Capital budgets solidify growth in 2022
Raphael Portela, 2 March 2022
Q4 earnings are nearing a close. And our tally has ballooned to 119 E&Ps with investments of US$229 billion in 2022 or 21%
more than estimates for 2021.
The past couple of weeks were dominated by L48 earnings calls. Close to 25 E&Ps reported and provided their outlooks for
2022, contributing to the second-highest uplift in upstream investment by peer group (+US$6.6 billion, +26%) alongside
Focused International players (+US$6.6 billion, +39%) and right behind the Majors (+US$9 billion, 16%). Nevertheless, we
remain 12% below 2019 levels, when oil prices averaged US$64/bbl Brent.
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Today, the biggest question in our minds is whether capital budgets will remain steadfast in the face of higher oil prices. We
have registered a slight increase in price assumptions for 2022 from September through now, but we are nowhere near current
spot price levels. While early announcements operated under an average US$65/bbl Brent, that number has crept up to US$7075/bbl.
History would suggest rampant capital expenditure revisions to the upside in this environment, but so far adjustments are far
and few between. Instead, E&Ps have chosen to highlight higher cash flow projections and lower reinvestment rates instead of
allowing capex plans to flex in relation to price. Capital discipline seems to be holding firm for now.
Price assumptions are inflating but remain >US$30/bbl below spot prices
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ExxonMobil to exit Sakhalin-1 in Russia
Tom Ellacott, 2 March 2022
The facts: ExxonMobil has announced that it is beginning the process of discontinuing operations at its operated Sakhalin-1
asset in Russia. The company is developing steps to exit the Sakhalin-1 joint venture with Rosneft and will not invest in any new
developments in the country.
Our take: all the Majors with commercial value in Russia’s upstream sector have now issued their response to the conflict in
Ukraine. ExxonMobil’s move to exit Sakhalin-1 comes as no surprise and mirrors Shell’s decision to exit its three joint ventures
with Russian NOC Gazprom.
Sakhalin-1 is ExxonMobil’s only commercial asset in Russia. We value the Supermajor’s interest at US$2.2 billion, equivalent to
just 1% of its global upstream value. The book value is also modest at US$4 billion. An exit will have relatively limited impact on
ExxonMobil even if it isn’t able to find a buyer.
But Russia does have strategic value as a potential future LNG supply play for ExxonMobil. Sakhalin-1 is earmarked to supply
gas to the proposed Far East LNG project (ExxonMobil, 30%) for which FEED was completed in December 2021. Exiting the
Sakhalin-1 venture will remove an LNG development option that could help the Supermajor rebalance its oily portfolio towards
gas in the latter half of this decade. However, we do not value this project.
ExxonMobil fell short of announcing an exit from Russia. As with TotalEnergies’ statement, it’s not clear whether the decision to
halt investment in new developments is a temporary or permanent commitment.
PETRONAS back in black, going green
Andrew Harwood, 2 March 2022
The facts: PETRONAS’ preliminary results for 2021 show a solid return to profit, after the impairment-led loss of 2020. Steady
production, improved prices and continued cost control contributed to a 93% uptick in operating cashflows.
The NOC also announced its intention to launch two new business units; an as yet unnamed entity to focus on renewable,
hydrogen and green mobility solutions, and the Carbon Management Unit to manage PETRONAS’ growing portfolio of capture
and storage opportunities.
Our take: the results confirm PETRONAS’ emergence from the unprecedented events of 2020 on a stronger financial footing. A
20% capital allocation to ‘step-out’ opportunities over the next five years reflects PETRONAS’ low carbon growth ambitions. If
reserved for only new energy opportunities, this level of allocation would be comparable with some Euro Majors and ahead of
the US Majors. But PETRONAS is also sticking to capital discipline, in the face of rising cash reserves, as it balances
investment with shareholder obligations.
Financials: revenues were up 39% to RM248 billion (US$60 billion), almost a third of which came in the fourth quarter. A fullyear loss after tax of RM21 billion in 2020 was transformed into a profit of RM48.6 billion in 2021; net impairments contributed
RM2.3 billion to income, versus the RM32.7 billion of write-downs in 2020. Cash flow from operations rose 93% to RM78.6
billion; PETRONAS highlighted its CFFO-to-Revenue ratio at 32% was nearly double that of the Majors.
Despite adding RM14.9 billion (US$3.6 billion) of new debt during the year, net cash rose to RM56.7 billion, up from RM42.3
billion. PETRONAS declared a dividend to be paid in 2022 of RM25 billion, in line with its 2021 payout.
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Operations: entitlement production was down 3% to 1.57 million boe/d, and gross LNG sales were down 1% to 32.7 million
tonnes. Upstream exits from Azerbaijan and Chad were confirmed, as the legacy portfolio is reshaped to focus on core
positions. Other operational highlights included eight new discoveries in Malaysia, Indonesia and Brunei, the award of a stake in
the Sepia field in Brazil’s second transfer of rights round, and the 12,000th LNG cargo delivered from the Bintulu LNG plant
since it began operations in 1983.
On the low carbon front, eight GHG reduction projects completed in Malaysia are expected to reduce domestic emissions by
3.8 million tCO2e (a 9% reduction on 2020 reported emissions), solar capacity in operation or under development reached 1
GW, and several MoUs and joint-studies have been kicked off to explore carbon capture and green-methane opportunities.
Strategy: there were no spectacular new strategic announcements. PETRONAS remains committed to its disciplined approach
to reinvestment in pursuit of its three-pronged approach to maximise cash generation, expand its core business and step out
into new low-carbon areas.
A strong financial platform could support an acceleration of investment in new energies, with the move to set up a separate
entity to focus on renewables, hydrogen and green mobility perhaps a hint in this direction. But until more details are revealed
later, we expect PETRONAS to remain prudent, conscious of its obligations to support Malaysia’s wider economic recovery.
Record bids in US offshore wind lease sale
Norman Valentine, 28 February 2022
The facts: a total of US$4.4 billion in winning bids were submitted for six offshore wind lease areas in the New York Bight lease
sale. The highest bidder was Bight Wind Holdings, a joint venture of RWE and National Grid which bid US$1.1 billion for the
largest lease area covering 126,000 acres.
Other successful bidders included partnerships between Total and EnBW (US$795 million for 84,000 acres), Shell and EDF
(US$780 million for 79,000 acres) and EDPR, Engie and GIP (US$765 million for 72,000 acres). The round’s other two leases
were won by Invenergy (US$645 million for 84,000 acres) and Copenhagen Infrastructure Partners (US$285 million for 43,000
acres).
Our take: these record breaking bids once again highlight the growing competition over the last few years for offshore wind
acreage in established and committed markets. The previous record for an US offshore wind lease, set in 2018, was US$135
million for each of three leases covering 127,00-132,000 acres offshore Massachusetts.
European utilities and the Euro Major oil companies dominated the latest lease round, highlighting their appetite for large-scale
opportunities that will support ambitious 2030 renewables capacity growth targets.
High bidder RWE is a case in point. As one of the leading players in European offshore wind, it has used the New York Bight
lease round to enter the US offshore wind for the first time. The potential development of up to 1.5 GW of net capacity at its New
York Bight lease area will support its goal to triple its net installed offshore wind capacity to 8 GW by 2030.
But other European players are shunning globalisation to focus their expansion efforts on the European market. EnBW has
announced it will sell its US wind business, including its stake in the newly won New York Bight lease, to its bid partner
TotalEnergies. For an in-depth view on the varying strategies and portfolios of the leading offshore wind companies in Europe,
look out for our forthcoming Insight on Europe’s Offshore Wind Leaders.
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Chevron agrees to acquire Renewable Energy Group for US$3.15 billion
Alex Beeker, 28 February 2022
The facts: on Monday, Chevron agreed to acquire Renewable Energy Group (REG) for a total consideration of US$3.15 billion,
including the assumption of US$400 million in debt. The deal price of US$61.5/share represents a ~90% premium to Renewable
Energy Group’s share price on 22 February 2022, the day before deal rumors surfaced.
The deal is 100% cash and represents one of the largest new energies acquisitions to-date by a Major. REG’s CEO, CJ Warner,
is expected to join Chevron’s Board of Directors. Chevron expects the transaction to close in the second half of the year.
Our take: REG is the country’s leading biofuels producer and this deal underscores Chevron’s ambitions in low-emissions fuel.
Biofuels is happening now, in contrast to hydrogen and CCUS which are longer dated technologies. Chevron expects REG’s
business to generate US$500 – 600 million of EBITDA by 2025. Chevron clearly believes REG offers a way to scale its liquid
biofuels business quickly as it has offered multiples far in excess of a conventional refining business, reflecting the challenges
are not in biofuels processing, but in securing reliable low carbon feedstock supplies and capturing maximum value from their
production.
REG expands Chevron’s renewable fuels footprint, especially renewable diesel production. In 2020, REG produced ~33 kb/d of
biodiesel and renewable diesel. Chevron is currently targeting 100,000 b/d of renewable diesel and sustainable aviation fuel by
2030. In addition to existing production, REG provides Chevron with incremental sources of feedstock, including animal waste
and used cooking oil, which will be critical to reaching the 2030 target. Through its Bunge JV, Chevron has access to 7,000 tons
per day of soybean feedstock, growing to 14,000 tons per day by 2024.
The acquisition is equivalent to nearly one-third of Chevron’s low-carbon budget out to 2027. Chevron’s capex budget is
relatively fixed, gearing is already below its target range, the dividend was recently increased by 6%, and buybacks are
expected to be US$5 billion this year. Even after all that, we expect to Chevron to generate US$28 billion in excess cash flow
this year at an average Brent price of US$88/bbl. More new energies acquisitions seem likely if current prices hold – potentially
pushing the low-carbon budget higher.
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Chevron - Renewable Energy Group
BP to exit Rosneft shareholding
Luke Parker, 28 February 2022
The facts: BP has announced that it plans to exit its 19.75% shareholding in Rosneft. BP CEO Bernard Looney and former
CEO Bob Dudley have resigned from Rosneft’s board of directors with immediate effect. BP will also exit its other businesses in
Russia – three directly held upstream joint ventures. BP has not given any indication of how and when these exits will take
place.
Our take: BP’s holding in Rosneft has always been an oddity. The relationship was always going to end – a question of when,
not if – and there was always a risk that it would end badly. Now, under mounting political pressure due to the situation in
Ukraine, BP’s holding in the state-controlled behemoth has become untenable. With the writing on the wall, BP has moved
swiftly and decisively to mitigate reputational damage and salvage some residual value.
Read our Inform – BP to exit Rosneft shareholding – for analysis.
What next for oil and gas companies present in Russia?
Wood Mackenzie, 28 February 2022
The facts: Equinor has already followed BP and said they’ll exit Russia in an orderly fashion. The company expects to take
impairments on the US$1.2 billion in non-current assets it held in the country at year-end 2021. How will other IOCs operating in
the country respond?
Our take: the events in Ukraine, and the moves by BP and Equinor, will force Russia to the top of the boardroom agenda for the
other companies operating in the Russian oil and gas sector. Russia accounts for just 2% of our valuation of Equinor’s upstream
portfolio. Other IOCs have much more at risk.
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Corporate week in brief
Russia is hugely important for TotalEnergies, both strategically and operationally. The company has shaped a portfolio that is
the lynchpin of its LNG growth strategy through a 19.4% stake in Novatek, and direct stakes in Yamal LNG (20%, onstream) and
the Arctic LNG-2 growth project (10%, first train onstream 2023). The portfolio delivers 135 kboe/d of additional output by 2026,
ranking Russia as TotalEnergies’ most important growth engine and underpinning the company’s 3% per annum growth target
over this period.
Shell and ExxonMobil are the only other Majors with commercial assets in Russia – but they have much less exposure. Shell’s
main asset is a 27.5% stake in the mid-life Sakhalin-2 LNG project, in which Gazprom is the main shareholder (50%).
ExxonMobil operates the Sakhalin-1 project in partnership with ONGC, Rosneft and a consortium of Japanese companies. Both
companies will likely have to put their respective Sakhalin-2 expansion and Far East LNG projects on hold.
Wintershall DEA is proportionately the most exposed IOC through its two large upstream JVs South Russkoye and Achimgaz
with Gazprom – and the current crisis could influence the timing of its planned IPO. OMV’s position in Russia is held solely
through its 25% stake in the giant South Russkoye gas fields, acquired from Uniper in 2017, also a JV with Gazprom.
Russia upstream exposure: WM estimate of NAV and share of total upstream NAV in Russia
The Nord Stream 2 suspension could also impact Shell, Wintershall DEA, OMV, Uniper and Engie that have each provided
approx. US$1.1bn in financing. Impairments may follow, as already indicated by Uniper.
For further analysis on the implications for global commodities, please see:
What the situation in Ukraine means for global commodities – deep dive
US Independent results advance shareholder returns
Alex Beeker, Dave Clark, Raphael Portella, Robert Polk, 25 February 2022
The facts: US Independent earnings reached a crescendo with 17 companies in our coverage reporting fourth quarter and fullyear results. Notable results this week included EOG, Diamondback, Occidental, APA, Coterra, and Ovintiv among many others.
A few remaining producers in our coverage report next week.
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Our take: quarterly and full-year results illustrate the free cash flow momentum propelled by disciplined spending and rising
prices. Aggregate reinvestment rates of 42% for the year came in well below the early 2021 consensus targets around 70%. The
quarterly trend demonstrated sequential declines with Q4 reinvestment standing at just 34%.
Shareholder returns continue to accelerate. Aggregate dividends and buybacks increased a staggering 85%, or nearly US$3.5
billion, quarter over quarter. Even more telling is the ongoing trajectory. Of the 18 companies covered and reported that pay a
regular base dividend, two-thirds announced increases. That does not include new, reinstated, or indicated future dividends
from EQT, Range Resources, and post-restructuring Whiting and California Resources. Variable dividend payments largely
increased as well.
New or refreshed share repurchase authorizations totaled over US$12.0 billion. Coterra Energy represents the largest new
authorization announced this week at US$1.25 billion. Previously announced programs remain substantial and management
teams consistently touted the ongoing appeal of buybacks.
Low net debt / EBITDA ratios provide cover for increased returns and prompt a lessened priority on debt reduction. Perhaps the
most symbolic example is Occidental’s decision to increase the quarterly base dividend from US$0.01/share to US$0.13/share
and reactivate share repurchases. The approximate US$450 million absolute dollar increase in dividend payments for
Occidental does not constrain further deleveraging, but the shift in return of capital encapsulates the broad sector theme.
However, low cash flow leverage on a trailing or forward year basis at elevated prices does not fully distinguish balance sheet
quality. Producers cannot be content with 1.0x leverage in the current environment. Our bias remains with gearing ratios that
measure cumulative capitalization, and many producers possess capacity to drive gearing down further. EOG and Magnolia are
both now at negative or effectively zero net debt, and Pioneer has repeatedly indicated a preference to reach zero net debt.
Expect companies to continue to economically and opportunistically reduce absolute debt.
The peer group guided towards organic production increases of 3% on 20% higher overall spending when adjusting for
acquisitions. Inflation drives budget increases, but additional investments in emissions abatement also contributed to higher
spending.
Larger US producers generally committed to maintenance or low-growth capital programs. Occidental and Diamondback both
provided midpoint production guidance 1% below 2021 full-year levels. EOG suggested 3-4% year-over-year growth.
Relatively smaller producers are more willing to step out and pursue growth. Matador Resources was one of the companies that
did not increase its dividend, instead increasing D&C capital to grow production nearly 20%. Other Permian pure-plays
Centennial and Callon also guided towards production growth. It appears the mindset is that a lower contribution to absolute
growth is acceptable while the larger US peers adhere to flatter profiles.
Lastly, management teams continue to field questions regarding what it would take to alter plans. Management teams largely
made it clear that any deviation would originate the shareholders.
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US Independent 2021 sources and uses of cash (US $ billions)
Source: Wood Mackenzie, Company filings (30 core US Independent producers)
ExxonMobil high-grades in Nigeria with a US$1.6 billion deal
Tom Ellacott, 25 February 2022
The facts: ExxonMobil has announced that it will sell its interest in Mobil Producing Nigeria to Seplat Energy for US$1.283
billion plus a contingent payment of up to US$300 million. The deal includes only the SuperMajor’s shallow-water affiliate;
ExxonMobil will retain its deepwater assets.
Our take: ExxonMobil appears to have secured a good price for the transaction. The deal is also strategically compelling. The
assets sold have a higher emissions intensity and lower cash margins than ExxonMobil’s portfolio average. The sale will
therefore deliver underlying portfolio improvement.
ExxonMobil’s high-grading campaign is gathering momentum. Indeed, the company has sold more assets than most peers
since the start of 2021. Current prices could trigger even higher activity, concentrating the portfolio around advantaged assets
such as Guyana and the Permian.
TotalEnergies announces a giant oil discovery offshore Namibia
Tom Ellacott, 25 February 2022
The facts: TotalEnergies capped off a stellar week of exploration newsflow with the announcement of a giant light oil and
associated gas discovery in ultra-deepwater Namibia. The Venus-1X well surpassed the company’s pre-drill recoverable
estimate of between 1.5 and 2.0 billion barrels.
The partners in the well are TotalEnergies (40%, operator), QatarEnergy (30%), Impact Oil and Gas (20%) and Namcor (10%).
Our take: our recoverable oil estimate of over 3 billion barrels makes Venus Sub Saharan Africa’s biggest ever oil discovery.
We assume the partners will develop the field over multiple phases with several FPSOs to exploit the full resource.
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The barrels are economically advantaged. We calculate a first phase of development targeting 920 million to deliver first oil in
2028 breaks even at US$31/bbl on an NPV,10 basis. This phase alone delivers a return of 22% and NPV,10 of US$3.5 billion at
US$50/bbl (30% and US$6.3 billion at US$70/bbl).
The development will also need a low carbon intensity to hit TotalEnergies’ investment criteria. Venus’ associated gas could
displace diesel power generation to help lower intensity. But it could also complicate the development given its water depth
(3,000 metres) and a lack of commercialisation options in the under-developed regional gas market.
The scale of the discovery has strategic implications for the partners. We estimate the initial phase of development will require
investment of over US$13 billion. Operator TotalEnergies’ already has an opportunity-rich investment pipeline. But Venus would
be a top-three ranking project in terms of investment scale. The SuperMajor may have to re-prioritise projects if appraisal is
successful.
See our Inform for more details on the discovery and the implications for TotalEnergies and its partners.
TotalEnergies announces fifth oil strike offshore Suriname
Tom Ellacott, 23 February 2022
The facts: TotalEnergies and APA Corporation have announced a fifth oil discovery on Block 58 with the Krabdagu-1 well. The
well encountered 90 metres of net oil pay in Maastrichtian and Campanian reservoirs. TotalEnergies will carry out a drill-stem
test and plans to spud at least three further exploration and appraisal wells on the block in 2022.
Our take: the successful result supports the installation of a large-sized FPSO with 220,000 b/d of oil processing capacity
targeting the eastern discoveries of Sapakara, Keskesi and Krabdagu. We had previously assumed a smaller FPSO with
120,000 b/d of oil processing capacity.
TotalEnergies recently walked away from the North Platte development in the US Gulf of Mexico. We had expected the project
to be sanctioned in 2022 but the development was at the limit of the company’s screening criteria of capex and opex of less than
US$20/bbl or a breakeven of less than US$30/bbl.
But the Krabdagu discovery will boost the commercialisation prospects of Block 58. We calculate a potential development
satisfies TotalEnergies’ cost criteria and also delivers an emissions intensity that’s lower than the average of its existing
portfolio. We anticipate a final investment decision in Q4 2022.
See our Inform for further details on the development and future exploration activity.
Tullow contingent payments: nothing gained, nothing lost?
Scott Walker, 21 February 2022
The facts: Tullow announced updates on two contingent payments – one credit and one debit – for a net loss of one dollar. In
credit, TotalEnergies reached FID on the Lake Albert oil development in Uganda, triggering a US$75 million payment on top of
the US$500 million Tullow received upfront for its sale in 2020.
While following arbitration, Tullow is to pay US$76 million to Norwegian private equity fund HitecVision, relating to discoveries
made offshore Norway between 2013 and 2016. Tullow acquired explorer Spring Energy in 2012 from HitecVison for US$372
million, with bonuses payable in the event of a commercial discovery on any of four specific prospects.
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Our take: the timing of the arbitration is unhelpful for Tullow. Even prior to the announcement, we calculated Tullow had one of
the highest cash flow breakeven points in its peer group at US$60/bbl Brent. This included the impact of proceeds from the
Uganda contingent payment. We expected FID at Lake Alberta and viewed the payment more as deferred than contingent.
Tullow’s relatively high breakeven in 2022 owes a lot to legacy decommissioning liabilities in the UK and Mauritania, totalling
US$100 million.
We calculate the cash outflow from the arbitration agreement will increase Tullow’s breakeven to US$66/bbl. While Tullow will
still generate free cash in our base case, it will slow much needed deleveraging. But with breakevens set to average US$44/bbl
between 2023-2025, the near-term financial outlook should still improve – especially if current prices are sustained.
US Independents' Q4 results – week 1
Alex Beeker, Dave Clark and Robert Polk, 18 February 2022
The facts: week one of the US Independent's Q4 earnings included six companies in our coverage (Pioneer, Continental,
Devon, Marathon, Comstock and Antero). Hess, ConocoPhillips, EQT and Murphy reported in previous weeks. The remaining
~15 are reporting over the next two weeks.
Our take: the dominant theme of the week was that E&Ps are sticking with the program. All four large cap oil-focused
companies laid out “maintenance level” capital programs this week. Guidance calls for flat production year-on-year. At the high
end, Pioneer guided to 2-5% overall production growth, but its oil outlook is flat year-on-year. We think the market would have
accepted mid-single digit growth this year, but companies are understandably cautious to raise guidance given their track
record.
Companies also see little incentive to change course. Their current strategy is working. Equity performance has been
outstanding, and shareholders seem to be endorsing the approach. Executives and employees are enjoying large variable
dividend payments. Capital discipline may need to hold for at least another year before growth can resume. Even then, growth
beyond mid/high single digits would likely test investor tolerance.
But such unwavering commitment to capital discipline could cause problems for the macro supply-demand picture down the
road. Producing nearly 10 million b/d, the US Lower 48 will likely be called upon to help balance the market (pending what
happens with OPEC+ spare capacity, Iran negotiations, Russia-Ukraine conflict, etc.). For now, companies seem unwilling to
take the bait. CEO Scott Sheffield said Pioneer plans to stick to 0-5% growth even if oil prices reach US$150/bbl.
Debt reduction
A second theme thus far is that net debt reduction is slowing, after several quarters of meaningful deleveraging. In fact, for the
eleven US independents that have reported, net debt was up US$3.0 billion quarter-on-quarter, mostly due to deals
(ConocoPhillips and Continental, offset by Pioneer). Excluding those deals, aggregate net debt was essentially flat. Part of the
issue is that the easy-hanging fruit has been picked, gearing has moved below alarm-bell levels, and companies are now
inclined to wait for maturities to retire notes rather than pay early payment penalties.
Shareholder distributions
So, with an aggregate reinvestment rate of just 36% and negligible debt reduction, where did all this excess free cash flow go?
The answer is shareholder distributions.
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Corporate week in brief
Capital to shareholders (both dividends and buybacks) from the seven oil-focused companies more than doubled quarter-onquarter, from US$2.5B to US$5.3B. There have also been several increases in buyback authorizations, including US$4 billion
for Pioneer. Look for increased repurchases as cash flow steps up along with the oil price.
Gas-focused companies have reported zero dividends and minimal share buybacks. But the tune is quickly shifting. Many have
discussed implementing a returns framework later this year – some of the better positioned companies start paying variable
dividends in Q1.
Most of the remaining companies will report in the coming days – so stay tuned for next week’s recap.
Most notable quotes from the week:
“Long-term we’re still in that 0-5% [growth rate]…We’re not going to change, as I said. At US$100/bbl, US$150/bbl, we’re not
going to change our growth rate. We think it’s important to return cash back to the shareholders.” – Scott Sheffield, CEO,
Pioneer Natural Resources
“…[W]e think, for us, the 5% [growth] that we laid out at the time of the announcement of the merger still holds. That’s the max.”
Rick Muncrief, CEO, Devon Energy.
Eni floats Var Energi and reports soaring earnings
Greig Aitken, 18 February 2022
The facts: a bumper end to 2021 year saw Eni deliver full year adjusted net profit of €4.7 billion – its best result since 2012.
Upstream was the engine, fuelled by higher prices. Net debt fell by 22% across the year; gearing now stands at 17%.
Earlier in the week, Eni's joint venture Var Energi was successfully listed on the Oslo stock market for a premium valuation.
Our take: it was no surprise to see Eni deliver a stonking quarter. The other Majors have all reported similarly buoyant Q4
results due to high commodity prices.
In this environment, capital allocation is a key point of interest but Eni didn’t provide a formal outlook (that's due next month).
However, management did hint that additional capital will be returned to shareholders under continued high prices.
Continuing its outstanding track record of fast-tracking exploration successes, Eni has taken FID on Baleine in Cote D'Ivoire just
five months on from discovery. We view Baleine as the best large development project in Eni's hopper. Additionally, Eni laid out
a surprise plan to monetize associated gas at Marine XII in Congo through domestic supply and LNG export in just two years
time. With feedstock gas already available and using leased modular equipment, this is a low-capex way of quickly bringing new
volumes into a tight market.
Portfolio restructuring was also on the agenda. The potential upstream joint venture with BP in Angola is expected to complete
later this year and Plenitude continues to target a 2022 IPO. Meanwhile, the listing of Var Energi will net Eni around US$500
million. Eni remains the majority shareholder in Var but will continue to equity account for the stake. With Var's market valuation
coming in at a substantial premium to our NPV10 base case valuation, this looks to have been a good piece of business for Eni.
See our Q4 results write-up for more details on Eni's results, and our Inform for more details on the Var Energi IPO.
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Repsol finishes the year on a high
Tom Ellacott, 18 February 2022
The facts: Repsol’s adjusted net income in Q4 2021 soared 116% to beat analysts' expectations. Full-year adjusted net income
of €2.5 billion was the highest since 2008. Gearing fell from 22% to 20%. The company announced a 5% dividend hike and
expanded buyback programme for 2022.
Our take: Repsol is running ahead of schedule in the first year of its strategic plan. Better-than-expected upstream cash flow is
allowing the company to accelerate the low carbon pivot and increase distributions. But a disappointing year for production
meant that Repsol wasn't able to fully capitalise on the positive price environment.
Repsol's €3.8 billion budget for 2022 is up 27% year-on-year. A 40% jump in upstream spend is the main driver as the company
starts to develop a new wave of projects and increases US unconventional activity. The investment injection will flow through to
a production recovery and drive portfolio improvement through boosting cash flow margins.
The company made rapid high-grading progress during the year, reducing the number of countries in which it has an upstream
presence from 21 to 15. All the exits were small, non-core positions. We review the outlook for additional high-grading and
business development in our Q4 results write-up.
TotalEnergies delivers record cash flow
Tom Ellacott, 11 February 2022
The facts: TotalEnergies’ operating cash flow hit a quarterly high in Q4 to cap off a record year. Net income soared to levels
last seen in 2008. Investors were rewarded with a 5% dividend hike in 2022. TotalEnergies also guided for US$2 billion of
buybacks in the first half of the year.
Our take: TotalEnergies' multi-energy strategy came together in Q4. Cash flow surged across oil, integrated LNG and
renewables, driven by the favourable environment for oil, gas and European power. A standout performance from the Integrated
Gas, Renewables and Power division stole the show.
Management outlined how 2021 confirmed the role of gas as a transition fuel and that the energy transition is adding complexity
and volatility. This presents opportunities for TotalEnergies' multi-energy model, including taking on more power pricing risk for
its growing renewables portfolio. We take a look at how the company is adapting its strategy in our Q4 results write-up.
Oil also got a decent amount of airtime on the call. No peer has been able (or willing) to match TotalEnergies' pace of business
development over the past year. But the company is sticking with its strict capital allocation criteria and making tough decisions
to drive further portfolio improvement (see below).
TotalEnergies walks away from the North Platte project
Tom Ellacott and Norman Valentine, 11 February 2022
The facts: on 10 February 2022, TotalEnergies decided to withdraw, effective immediately, from the North Platte project as 60%
working interest partner and operator. Equinor is the only other partner in the project and will assume operatorship. We had
assumed the partnership would sanction the project in 2022.
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Our take: TotalEnergies believes it has better opportunities in which to allocate capital following an intense period of business
development. North Platte lies at the limit of its screening criteria of capex and opex of less than US$20/bbl (US$22/bbl) and a
breakeven of less than US$30/bbl (US$36/bbl on an NPV10 basis). TotalEnergies will also reduce its capex commitment by
US$3.5 billion over the next five years at a time when, on our numbers, Group spend is rising.
North Platte was TotalEnergies’ sole operated project in the US Gulf of Mexico. The region only accounts for 2% of the
company’s overall upstream value. Could walking away from its main development be a precursor to exiting the province or will
the company still see value in its high-margin production?
Equinor does not have much time to react as the FID milestone is set for February and the suspension of production period for
North Platte expires in October 2022. FID will be pushed to 2023 at the earliest assuming Equinor secures a licence extension.
But the discovery could sit on the shelves for a long time if the lease expires and future Gulf of Mexico lease sales continue to
be delayed.
World first for Santos, includes CO2 storage in 2021 reserves statement
Andrew Harwood, 11 February 2022
The facts: Santos has reported 100 million tonnes of CO2 storage resource in its annual statement of reserves, thought to be
the first time CO2 storage has been booked in accordance with standards set by the Society of Petroleum Engineers.
Our take: Santos has booked 9 million tonnes of proven and probable storage capacity following FID at its 1.7 Mtpa Moomba
CCS project in the Cooper Basin. A further 91 million tonnes of contingent storage resource has been identified, highlighting the
potential to develop Moomba into a hub for other industries. For perspective, we estimate oil and gas production in the
Cooper/Eromanga Basin, unabated, will result in 21 million tonnes of CO2 emissions out until 2040.
The move to include storage resource in its reserves reporting emphasises the role of carbon capture in Santos’
decarbonisation strategy. Visibility on the potential of its CCS business will help attract partners and investment, and allow for
greater clarity on its contribution to Santos’ market value.
Globally, 2021 saw 200 new CCS proposed which could lift operating capacity from its current 61 Mtpa to around 700 Mtpa.
That’s still a long way off the 6.5 Btpa needed by 2050 in our accelerated energy transition 1.5 scenario. But Santos’ has put
itself at the forefront of developments in this crucial decarbonisation technology.
Greater transparency on CO2 storage capacity is also part of the wider industry trend towards improved reporting on
sustainability metrics and targets. While companies continue to employ varying reporting methodologies, our Corporate
Resilience and Sustainability Indices brings clarity and objectivity to benchmark corporate resilience and sustainability on a
consistent basis.
Equinor Q4 results: buyback boost
Norman Valentine, 10 February 2022
The facts: Equinor’s adjusted Q4 earnings of US$4.4 billion beat analyst expectations and propelled annual earnings to a tenyear high. Net cash generation surged on higher prices and strong Norway production, where quarterly gas output jumped 17%
compared to a year ago. Deleveraging accelerated, and adjusted gearing fell below zero for the first time since 2008.
Shareholder distributions got a big boost. Equinor hiked its share buyback programme to US$5 billion in 2022, up from US$1.3
billion in 2020. The company will also double its quarterly dividend over the next four quarters via an extraordinary quarterly
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dividend of US$0.2 per share. All-in-all, shareholder distributions in 2022 are set to hit US$10 billion, up from a pre-pandemic
payout of US$4 billion in 2019.
Our take: Equinor's decision to return US$10 billion to shareholders this year grabbed the headlines. At current prices, we think
it is affordable. Our corporate cash flow breakeven estimate is US$61/bbl for 2022, including US$5 billion of buybacks and this
year's special dividend. The outlook beyond 2022 is more uncertain. We estimate Equinor would need US$100/bbl for cash
flows to break even if distributions are maintained at US$10 billion a year out to 2026, partly as a result of rising investment.
But a rejuvenated, cash positive, balance sheet gives Equinor financial flexibility to sustain distributions if prices remain
elevated. If oil prices stay above US$80/bbl, we think the company could absorb US$10 billion in annual distributions over the
next five years while maintaining gearing at the lower end of the company's 15-30% target range.
With a major strategy update delivered in mid-2021, there was limited change to the broader strategic direction in this call. The
most notable update was a new goal to reduce scope 1 and 2 operated emissions by 50% before 2030, of which 90% will be
absolute reductions rather than offsets. This puts Equinor back among the leaders on emissions reduction goals within the
Majors peer group.
Read our reported results analysis for more.
INPEX returns to profit in 2021, updates transition strategy
Andrew Harwood, 10 February 2022
The facts: INPEX announced its 2021 results on 9 February, highlighting a 61% increase in turnover, and a return to profit on
the back of higher prices and lower impairments.
INPEX also released its Vision@2022 strategy, a more detailed update of its 2021 “Business Development Strategy”, which had
signalled a stronger emphasis on gas and low-carbon business development.
Our take: having invested heavily in development over the previous decade, INPEX is now well placed to benefit from rising
LNG output in Australia and stable low-cost crude production in the UAE. Financial deleveraging in the near term provides the
opportunity to scale up energy transition ambitions, in support of Japan's long-term climate targets.
Financials: 2021 turnover hit ¥1244 billion (US$11.3 billion), reflecting a 70% increase in realised crude prices, and a 37%
increase in gas prices. Net income reached ¥214 billion (US$1.9 billion), vs a loss of ¥103 billion (US$975 million) in 2020. Net
cash from operating activities rose to ¥445 billion (US$4 billion).
INPEX’s efforts to build a resilient business are bearing fruit, with the low-cost Middle East segment benefiting from higher crude
prices to account for nearly half of overall turnover, and nearly 60% of operating income. Strong cash generation resulted in a
reduction in gearing from 29% to 26%, reducing balance sheet stretch.
Operations: production rose 1.7% to 584 kboe/d as the Ichthys LNG project shipped 117 LNG cargoes and the UAE continued
to provide stable oil output.
Other operational highlights included a major discovery at Onshore Block 4 in Abu Dhabi, and the acquisition of a 50.5% stake
in Idemitsu Snorre Oil Development Co., giving INPEX a platform for growth in Norway. INPEX also highlighted its withdrawal
from Venezuela and DR Congo during 2021, subsequently followed in early 2022 by its exit from Angola.
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Strategy: INPEX's Vision@2022 provided more granularity on 2021’s Business Development Strategy, laying out 2022-2024
targets, medium-term goals (2030) and long-term ambitions (2050). Highlights included:
•
A greater role for gas – capital allocation for gas will shift from 50% to 70% by 2030
•
Core focus areas – Japan, Australia, Southeast Asia, Middle East and Europe (Norway) will provide the platform for a
stable, low emission upstream business and low-carbon expansion
•
‘5 net zero businesses’ to contribute 10% of operating CF by 2030 – capital allocation for hydrogen, CCUS, renewables,
methanation and forest conservation will reach 20% by 2030.
•
Clear financial framework – 2022-2024 cash flow to be prioritised in order of debt reduction, shareholder returns and then
growth investments.
•
Shareholder returns – INPEX is targeting a total payout ratio of 40%, with a minimum annual dividend per share of Y30.
We’ll provide more analysis of INPEX’s latest strategic update in our upcoming INPEX corporate profile.
TotalEnergies adds to its US renewables business
Tom Ellacott, 10 February 2022
The facts: TotalEnergies is acquiring SunPower’s Commercial & Industrial Solutions business for US$250 million, including
US$60 million of earn-out subject to regulatory evolution. TotalEnergies has a 50.83% stake in parent company SunPower
which will not change with this transaction.
Our take: the deal is another example of how the Majors are using equity investments in companies to capture renewables
opportunities.
TotalEnergies will strengthen its US distributed generation business through the potential to develop over 100 MW of additional
capacity per year (the company currently has nearly 500 MW of global operational capacity). TotalEnergies will also look to
capture synergies with its growing US solar portfolio, for which it is targeting 4 GW of capacity by 2025. The company will focus
on the growing commercial market and opportunities like community solar and front-of-metre storage.
The acquisition will provide capital for Sunpower to allow it to focus on growing its US residential business. TotalEnergies will
continue to benefit from its majority equity holding in the company.
BP Q4 results: soaring earnings, strategy update and guidance to 2030
Luke Parker, 9 February 2022
BP rounded out 2021 with another strong set of results, beating analyst expectations for the fourth quarter in a row and sending
full year earnings to an eight-year high. What a difference a year makes. But the windfall will not sway BP from a cautious,
disciplined line in 2022: strengthening the balance sheet remains a top priority, and there is no change to guidance on
investment or shareholder distributions.
BP also updated progress against strategy and announced new, detailed guidance to 2030. The broad message was that, two
years in, BP’s conviction to the transformation from IOC to IEC has only strengthened. There is no change of course. Rather,
BP is ‘leaning in’ to the transition. Guidance to 2030 is for accelerated growth in transition themes, underpinned by sustained
contribution from an evolving oil and gas business, feeding through to increasing Group EBITDA, margins and returns.
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See our reported results analysis for full details.
Pioneer reinforces fortress balance sheet commitment
Robert Polk and Dave Clark, 9 February 2022
The facts: Pioneer Natural Resources elected to redeem US$750 million of 0.75% notes due in 2024 and US$500 million in
4.45% notes due 2026. Cash proceeds from the late 2021 sale of its Delaware Basin acreage will fund the redemption.
Our take: this action is consistent with CEO Scott Sheffield’s repeated preference to have zero long-term debt. Pioneer already
possessed a pristine balance sheet with Q3 21 pro forma gearing around 12% following the Delaware divestiture. The liability
management trade is net debt neutral, but it reduces absolute debt by 18% and begins to chip away at the incremental 2021
debt assumed in the Parsley and DoublePoint acquisitions.
Using US$750 million in recycled capital to eliminate the very low coupon 2024 notes in particular indicates continued restraint
despite attractive prices. With already low leverage and gearing, Pioneer did not have to do this. The economic return from
putting that capital to the drill bit would undoubtedly exceed the low savings on fixed interest charges.
Pioneer is positioned to do it all – modestly grow production, continue to improve the balance sheet, and deliver increasing
shareholder returns. While many US independent peers are accelerating returns of capital to shareholders, one of the leading
and most financially secure US independents is demonstrating the enduring importance of fortifying the balance sheet. EOG is
the only other large cap US independent with a visible near-term zero net debt balance.
Increasing commodity prices drive low cash flow leverage metrics on a trailing basis, but a persistent focus on the balance sheet
ensures stability and flexibility through the cycle. Pioneer's actions emphasise its belief that a best-in-class balance sheet
creates long-term differentiation.
Low-carbon and hydrogen industrial hub alliance
Rachel Schelble, 6 February 2022
The facts: an alliance that includes EQT Corporation, Equinor, GE Gas Power, Marathon Petroleum (including MPLX),
Mitsubishi Power, Shell Polymers, and U.S. Steel will be developing a shared vision for a low-carbon and hydrogen industrial
hub.
The hub will be in the Northern Appalachian region of the U.S. in Ohio, Pennsylvania, and West Virginia, and includes hydrogen
production and utilisation along with a focus on carbon capture, utilisation, and storage.
Our take: this partnership brings together an A-team of companies that are at the forefront of different parts of the hydrogen
value chain. The collaborative approach to developing the Appalachian hydrogen hub leverages companies with expertise in
natural gas drilling, transportation, and hydrogen infrastructure, possibly providing solutions to decabonise the steel industry.
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Hydrogen milestones from 2021 to today by alliance members
Source: Wood Mackenzie
2022 capital budgets strengthen uptrend
Raphael Portela, 4 February 2022
Q4 results are slowly trickling in, and with them, budgets. The tally for 73 E&Ps has investments at US$149 billion in 2022, or
22% more than estimates for 2021. However, we remain well below pre-crash levels: 2022 budgets are down 14% (-US$25
billion) compared to 2019.
The past week featured some noteworthy announcements. ExxonMobil's corporate budget came in at US$21-24 billion versus a
preliminary US$20-25 billion figure. Shell wants to spend almost US$2 billion over last year's E&P budget despite selling off its
core Permian region. ConocoPhillips confirmed a 31% uplift in capex. Cost inflation featured in several plans and average
planning prices jumped from US$52/bbl Brent in 2021 to US$66/bbl in 2022.
See our company guidance tracker for detail on 2022 investment plans, volume targets and coverage of capital budgets beyond
upstream.
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Capex for 2021 is based on either the latest updated company guidances for 2021 or realized 2021 spend. Capex may be estimated. Midpoints are
used for companies that disclose guidance ranges. Our data attempts to isolate upstream exploration and development, with other expenditure items
(e.g., downstream and M&A) excluded where possible.
Shell makes huge oil discovery offshore Namibia
Luke Parker, 4 February 2022
The facts: the Namibian government has announced that Shell (45%) and its partners – Qatar Energy (45%) and Namcor
(10%) – have made a significant light oil discovery. Graff-1 was drilled in 1,900 metres water depth in the country’s Orange subbasin. No resource estimates were provided but we understand that the well met its pre-drill estimate of between 500 million and
1 billion barrels.
Out take: this is a game changer for Namibia – the country’s first ever oil discovery ends a streak of dry wells dating back to the
discovery of the Kudu gas field in 1974. And it’s big news for Shell. Our preliminary model values an assumed 700 million
barrels recoverable at US$2.8 billion (NPV10, Jan 2022, US$50/bbl long-term), generating a development rate of return of 23%.
That would put Graff well above Shell’s 18% upstream hurdle (at US$60/bbl). Development would be a welcome boost to
upstream longevity, but will come with its own set of challenges – below and above ground. Read our Inform for further reaction.
Shell Q4 2021 results: back on the front foot
Luke Parker, 3 February 2022
Shell bounced back in Q4, rounding out an up-and-down year for the company on a positive note. Management reaffirmed the
Powering Progress strategy and sent a strong message on shareholder distributions. Key messages:
•
Q4 and full year 2021 results: quarterly earnings of US$6.4 billion were up 55% on Q3, and full year cash flow from
operations (ex-working capital) hit a record high of US$55 billion.
•
Shareholder distributions: Shell confirmed US$8.5 billion of share buybacks for H1 2022, with the promise of more to
come, likely taking the company beyond the upper end of guidance on shareholder distributions.
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•
Powering Progress: Shell made big strides in 2022 against broader strategy and targets, and used the Q4 results
presentation to drive the message home. But the questions keep coming – on the transformation, the model and the value
proposition.
Read our reported results analysis for more.
ConocoPhillips Q4 2021 results: VROC and roll
Dave Clark and Matt Woodson, 3 February 2022
The facts: Q4 adjusted earnings were US$3.0 billion, up US$638m from Q3. Cash flow from operations climbed to US$5.9
billion from US$4.8 billion last quarter. Total production of 1.608 Mboe/d was above guidance of 1.53-1.57 Mboe/d. No changes
were made to December's 2022 outlook of US$7.2 billion capex and 1.8 Mboe/d production, but the company did bump the
planned 2022 return of capital up US$1 billion to US$8 billion (33% above 2021).
Our take: the US$1 billion increase in expected buybacks/dividends this year reflects growing management confidence that oil
prices will remain elevated. It also indicates their intention to stick to the budget regardless of commodity prices, and channel
incremental cash flow to shareholders or to net debt reduction (via debt paydown or cash on the balance sheet).
The company reinvested 28% of operating cash flow in Q4, and the full-year 2021 reinvestment rate was just 34%. That was
sufficient to generate ~2% pro forma production growth. The 2022 budget is expected to also drive low-single digits volume
growth, and management said at US$75/bbl WTI and US$3.75/mcf Henry Hub, they expect to capture about US$21 billion of
operating cash flow – matching last year’s 34% reinvestment rate.
Net debt/book capital rose from 17% to 24% as the company used cash on the balance sheet to pay for the Shell Permian asset
acquisition. Gross debt was US$19.3 billion in Q4, and management has a US$15 billion target for 2026. They will pay a
US$800 million maturity this year, and will look at some debt refinancing if it makes sense.
Overall the company returned 38% of operating cash flow to shareholders in 2021. Under the US$75/bbl WTI scenario, the
US$8 billion return of capital would again be 38% of OCF. Those distributions would likely be split roughly 50/50 between
buyback and dividend, though the company maintains the ability to shift that mix via the discretionary “VROC” dividend, the
“third tier” of ConocoPhillips’ capital return template. The US$0.30/share Q2 VROC announced this quarter is 50% above the
one payable in Q1.
In the Permian, ConocoPhillips produced 483 Kboe/d in Q4. The company was operating 20 rigs (and 9 frac crews) in the Lower
48 at year-end, and will add four more rigs in 2022 including rigs in the Bakken and Eagle Ford. They didn't say precisely what
they expect for Permian growth this year, but did say their long-term growth plan for the Permian is high-single digits. Given that
COP seeks “a sustainable growth rate”, that level of growth seems like a reasonable expectation.
ExxonMobil Q4 2021 results: roaring back
Tom Ellacott, 3 February 2022
The facts: ExxonMobil's share price jumped 6% on an impressive set of Q4 results that highlighted the scale of the Majors’
financial reset during the pandemic.
Our take: ExxonMobil roared back into action in Q4. Quarterly earnings hit a seven-year high. Annual cash flow from operations
rose to levels last seen in 2012 when Brent averaged US$113/bbl (US$71/bbl in 2021). The Supermajor paid off US$20 billion
of debt to restore gearing to pre-pandemic levels and kicked off its US$10 billion buy-back programme.
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The cash generation potential of the business was a hot topic. Management provided more granularity on how ExxonMobil
plans to be cash flow neutral at US$35/bbl out to 2027. That implies a much larger buyback programme at today's prices. We
outline the execution challenge the company faces in delivering on this guidance in our Strategy update.
The call was also an opportunity to look ahead. Strategic flexibility was a key theme. ExxonMobil’s US$21 to US$24 billion
budget for 2022 is part of that. And, longer-term, the company wants the optionality to shift capital between its legacy business
and low carbon operations according to the pace of the energy transition. We dive into more detail in our Q4 results analysis.
Ørsted delivers 2021 earnings in line with guidance but offshore wind
struggles
Akif Chaudhry and Norman Valentine, 3 February 2022
The facts: Ørsted reported EBITDA of DKK15.8 billion (excluding farm-downs) for 2021, a drop of 13% on the prior year but at
the top-end of expectations. This brought relief to a share price that has plummeted 40% over the last 12 months, jumping 4%
on the day.
Lower than average wind speeds, higher balancing charges and hedging costs drove the squeeze, buffeting its offshore wind
business. The company was bailed-out by its CHP plants and gas business, benefitting from strong generation, high power
prices and the performance of ancillary services. Asset farm-downs of DKK8.5 billion also helped the bottom line.
Our take: the 2021 results of the world’s leading offshore wind company demonstrate that it’s not plain sailing in the offshore
wind market.
Three points stand-out from yesterday’s announcement, with implications for other corporate power and renewables companies.
Diversification
Even in the fast-growing renewables sector, with strong long-term fundamentals, a concentrated portfolio brings a high degree
of risk and uncertainty. Competition in offshore wind is increasing, especially in more mature markets such as the UK.
Geographical and technological expansion are key to Ørsted’s future growth. It put in a stellar performance in tenders, winning
capacity in Poland’s fast growth, offshore wind market and in the US, where the opportunity lies across both offshore and
onshore (wind and solar) technologies.
Capacity growth outlook remains strong
Ørsted has 26 GW (gross) of firm capacity (including 13 GW (gross) of installed capacity). With additional pipeline and the
number of upcoming tenders over the next few years, it’s on track to meet its ambition of 50 GW (gross) installed capacity by
2030.
Competition for renewables assets is intensifying. Companies need to take careful note of where to bid, when to bid and what to
bid. But the opportunity to grow capacity remains strong.
IRRs are the big question and the big risk
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Inflation and interest rate impact dominated analysts’ questions. Existing projects receive varying degrees of protection through
indexed-linked subsidies or fixed nominal debt. But 2021 has shown that even these projects are at the mercy of weather
patterns.
Rising input and financial costs are, however, an ever-growing concern for projects not-yet-built and more so for those not-yetwon. With further pressure also coming from growing competition and increasing project development complexity, achievable
IRR levels are under the microscope.
Risk-adjusted returns have been a strong argument in favour of renewables. The near-term risk side of that equation is
creeping-up. This will undoubtedly test the strategies and project execution capabilities of companies in the sector.
You can read more on our near-term expectations for power and renewables companies in our recent insight: Corporate power
and renewables: 5 things to look for in 2022.
ExxonMobil unveils corporate restructuring
Tom Ellacott, 2 February 2022
The facts: ExxonMobil is planning to streamline its oil and gas business into Upstream and Product Solutions companies.
ExxonMobil Low Carbon Solutions will sit alongside these two companies. All three business units will be supported by a single
technology organisation. The move follows ExxonMobil’s restructuring of its business along value chains in 2020.
The Supermajor will also relocate its head office from Irving to its campus north of Houston.
Our take: the new streamlined organisational structure is a clear sign of how the Supermajor is rising to the energy transition
challenge. The move will elevate ExxonMobil’s low carbon business to underline the importance of this unit to the company’s
strategy. The consolidation of Chemicals and Downstream into one company will also enhance the synergies from a leading
integrated portfolio, helping to support an expansion into low-emissions fuels and chemical performance products.
Combining the research groups that supported upstream, downstream and chemicals into one organisation will help to facilitate
collaboration along the value chain, and cross pollination of ideas.
ExxonMobil will also look to drive further cost reductions. The company has made impressive progress since 2019, but still has
aggressive targets out to 2027 that it will need to achieve to hit its financial objectives. Consolidation of the corporate
headquarters was a surprise announcement that underscores how seriously the Supermajor is taking this cost reduction drive.
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The evolution of ExxonMobil's organisational structure
Source: ExxonMobil Q4 2021 results
TotalEnergies sanctions Uganda’s Lake Albert oil development
Tom Ellacott, 2 February 2022
The facts: on 1 February, TotalEnergies and its partners sanctioned the 1.4-billion-barrel Lake Albert oil development. FID on
the East Africa Crude Oil Pipeline was also confirmed.
The equity in the Lake Albert oil development is split TotalEnergies (56.67%), CNOOC Ltd (28.33%) and the Uganda National
Oil Company (15%).
Our take: this is one of the biggest oil projects to be sanctioned in the Energy Transition era with over US$8 billion of
investment to first oil in 2025. But it has taken over 15 years to achieve, highlighting the challenges of monetising large-scale
greenfield projects in the region.
The development now achieves TotalEnergies' investment hurdles. At US$10/boe, the upstream cost (capex+opex) is
competitive against the company’s cost criteria (<US$20/boe). The asset’s emissions intensity is comfortably below the average
of TotalEnergies’ upstream portfolio. And the development makes a 15% IRR under our US$50/bbl base-case price.
It’s also evidence of TotalEnergies’ dual growth strategy in action. The project will deliver 130,000 b/d of net output at peak in
2027, helping to underpin a peer-leading production growth trajectory during this period. For further details see At long last —
FID at Uganda’s Lake Albert oil development.
Petrobras sells Potiguar cluster for US$1.38 billion
Raphael Portela, 1 February 2022
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The facts: Petrobras has announced the sale of its 100% stake in the Potiguar cluster to 3R Petroleum. The set of 22 onshore
and shallow water fields located in the Potiguar Basin (Northeast Brazil) averaged 21 kboe/d (98% liquids) in 2021 and includes
infrastructure for processing, refining, logistics, storage, transport and outflow of oil and natural gas. Of note is the Clara
Camarão Refinery with an installed capacity of 39.6 kbbl/d.
Our take: high-grading the portfolio has been a priority for Petrobras since the 2014 price downturn. Recent emphasis has
shifted to mid and downstream disposals. The upstream assets on offer today are mostly mature onshore or shallow water
fields, with notable exceptions such as the Marlim and Albacora clusters.
A few sizable onshore assets remain on the docket, such as the Potiguar cluster. The transaction is the largest onshore deal
ever in Brazil. The sale of several legacy fields over the past years has improved Petrobras’ cost basis tremendously, helping
support its cost resilience platform. Onshore output now represents less than 5% of total oil production.
Stay tuned for an upcoming deal insight. Read our Brazil M&A series for a deep dive into Petrobras’ disposal programme. In
Part 1, we review how Petrobras’ asset sales fuelled M&A activity in Brazil. In Part 2, we analyse the corporate landscape to find
out who are the most likely buyers. In Part 3, we evaluate the ambitious plans of small operators that have snatched up
hundreds of Petrobras’ assets.
Lifting cost excludes production taxes but includes leasing costs.
Chevron reports best year of free cash flow in its history
Alex Beeker, 28 January 2022
The facts: Chevron posted a quarterly profit of US$5.1 billion, a decline of 16% compared with Q3-21 but significantly better
than a net loss of US$0.7 billion in the same quarter a year ago.
The company generated free cash flow, excluding working capital, of US$22.5 billion during 2021, up from US$3.3 billion in
2020. It was the best free cash flow year in the history of the company. Which speaks to Chevron’s commitment to capital
discipline amid rising commodity prices. US Upstream oil realizations were US$73/bbl during the quarter compared with
US$68/bbl in Q3 2021.
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Permian production grew 9% q-o-q to 681 kboe/d. The company remains on track for reaching 1.0 million boe/d by 2025.
Permian capex is expected to be up 50% this year to US$3.0 billion.
Our take: free cash flow was strong, but results were not positive across the board. Net income fell q-o-q despite oil price
realizations that were ~US$5/bbl better during the quarter. Weaker chemical margins weighed on downstream results and
unplanned downtime at Gorgon prevented Chevron from taking better advantage of a hot LNG spot market.
Still, Chevron remains well positioned for the year ahead and beyond. Debt levels are already below the targeted range and
2022 capex is expected to be at the low end of the company’s US$15-17 billion guidance range. Over the next five years, at our
high price assumption (which averages US$75/bbl to 2026), we model Chevron to generate US$86 billion of cumulative free
cash flow (post-dividend).
Chevron’s current buyback guidance is for US$3-5 billion per year. The company’s cautious approach to raising its buyback
program is understandable. But if oil prices stay elevated, we think Chevron could comfortably absorb a US$5-10 billion annual
buyback.
Hess beats Q4 earnings expectations and raises ’22 budget 42%
Alex Beeker, 26 January 2022
The facts: Hess reported Q4-21 net income of US$265 million or US$0.85 per common share vs consensus of US$0.73 per
common share. The company reported a net loss of -US$97 million in Q4-20. Hess generated full-year free cash flow of US$832
million (post-dividend) at an average realized oil price (including hedging) of US$60/bbl in 2021.
Hess released full-year capex guidance of US$2.6 billion, an increase of 42% vs 2021. The Bakken and Guyana will continue to
receive ~80% of investment, consistent with last year. Bakken capex will increase 50% from US$522 million in 2021 to US$790
million in 2022. The company added a third rig in the basin last September and expects to maintain that cadence through the
year.
Guyana investment will increase 30% from US$1.02 billion last year to US$1.33 billion in 2022. With the start-up of Liza Phase 2
this year, more investment will be directed towards Payara, Yellowtail and FEED for future developments.
Our take: exploration was a hot topic on the earnings call and 2022 already has the makings of another record setting year in
Guyana. Two new discoveries were already announced earlier this year – Fangtooth-1 and Lau Lau-1. Hess plans to participate
in 12 exploration and appraisal wells at the Stabroek Block this year. It also plans to participate in one well in Suriname and two
wells in deepwater GoM – after a two-year hiatus.
Most oil and gas companies are still reeling in exploration budgets in favor of capital discipline. But Hess gets a pass because of
its successful record at the Stabroek Block. And now might turn out to be a perfect time to be stepping on the exploration gas
pedal – with Brent passing US$90/bbl.
But Hess must remember a hard lesson from the US shale boom – production and reserves growth must be accompanied by a
detailed distributions plan. With leverage quickly improving, the company could unveil dividend and buyback plans as early as
Q2-22. The focus this quarter will be on the start-up of Liza Phase 2 and repaying the remaining US$500 million on its 2023
term loan.
Chesapeake Energy acquires Chief Oil and Gas for US$2.6 billion
Alex Beeker, 25 January 2022
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The facts: on 25 January, Chesapeake announced its second multi-billion dollar deal in the past six months – this time in the
Marcellus.
The company wasted no time getting back to its deal making roots since emerging from Chapter 11 early last year. Chesapeake
acquired Vine Energy in August 2021 propelling it (temporarily) to the leading Haynesville position. Now with the acquisition of
offset private operator, Chief E&D Holdings in Northeast PA, Chesapeake becomes the 5th largest producer in the Marcellus.
Total consideration of the deal was US$2.6 billion (US$2.0 billion in cash, US$0.6 billion in equity). To help fund the cash portion
of the deal, Chesapeake simultaneously announced the divestment of its Powder River Basin asset to Continental Resources
for US$450 million.
Our take: the acquisition of Chief Oil and Gas emphasizes Chesapeake’s renewed commitment to natural gas and sends a few
key messages to stakeholders. First, is that it has no plans of sitting still post-bankruptcy (the acquisition of Vine already
confirmed this to some extent). Second, is that while the Haynesville has been getting more attention lately, the Marcellus will
remain core to the company’s future – regardless of what happens with the pipeline situation. Third, is that capital discipline is
here to stay. Production growth was not a driver of this deal.
Emerging from bankruptcy has pumped new life into Chesapeake. The company now has in place a strong dividend framework
(base plus variable), a US$1.0 billion buyback program, a 2035 net-zero commitment and plans to be the US leader in
responsibly sourced gas (RSG). Chesapeake would not have been able to do the Vine or Chief deal if it hadn’t first focused on
ESG strategy and shareholder distributions.
US independents' Q4 results preview
Dave Clark, Robert Polk, Alex Beeker & Raphael Portela, 20 January 2022
The facts: a
five week stretch of Q4 2021 results begins next week for the US independents. Week one is
light, with the busiest weeks throughout February.
.Our take: after a remarkable 2021, the market will be watching Q4 commentary closely for indications that the industry-wide
capital allocation strategy shift will continue. Here are the key things we will be looking for over the coming weeks:
Investment and growth. Oil prices averaged ~US$8/bbl higher in Q4 compared to Q3. With companies still in stay flat mode,
expect another record low quarter for reinvestment rates. (Q3-21 was 42%). Tailwinds from DUC backlogs supported incredibly
low reinvestment in 2021. Maintaining such impressive results will be challenging with fewer DUCs and inflationary pressures
partially offsetting the benefits of WTI above US$85/bbl.
Improved financials allow for modest growth to re-enter the conversation. Will some operators test investor appetite by guiding
towards high single-digit or even low double-digit growth? Producers with fortress balance sheets can justify growth, but investor
preferences persist. High prices increase political and social pressures for US independents to help stabilize the market. How
much wiggle room will companies leave themselves to increase spending if prices continue to rise? We track capex and
production guidance here.
Balance sheets and cash return. Aggregate net debt fell over US$17 billion year-to-date through Q3, lowering group book
gearing from 44% to 37%. Year-end results should exceed the nine-month run rate on the strength of higher prices. Stronger
financial standing accelerates the pivot towards cash returns to shareholders for many. More cash return formulas and
announced buyback authorizations seem imminent.
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Hedging. Substantial hedging losses garnered scrutiny in Q3. Massive unrealized losses will moderate in Q4, but additional
realized cash losses will temper an otherwise strong quarter. New activity also merits attention. Pioneer closing out its 2022 oil
hedges sends a bullish message. Lower leverage alleviates the need for hedging for many, but companies with remaining
deleveraging goals should find the current strip sufficient to lock in a portion of production.
Costs. Budget details will push the conversation on cost inflation further forward. Our analysis indicates well input costs are
forecasted to increase 5% from 2021 levels. Modest inflation will be priced into updated guidance and the producers will tout
efficiency gains to offset some of these pressures. How will management teams react if these pressures surprise to the high
side?
Energy Transition. With net zero by 2050 now standard for the majors, there will be increasing pressure on US independents
to follow suit. The largest companies have also begun outlining transition budgets (Chevron ~US$1.25 billion/yr, ExxonMobil
~US$2.5 billion/yr, ConocoPhillips ~US$200 million/yr). Stakeholders will eventually push for similar transparency from US
E&Ps.
M&A: M&A discussions in earnings calls are usually pretty boilerplate, but flush cash flow should drive an active year for
consolidation. Cash-weighted deals gained momentum in H2 2021, and there are numerous non-core packages from larger
companies on the market. The buyer pool is deeper with mended balance sheets. There are also a few IPO’s queued up
(Colgate, Advance/Ameredev) with the potential for more.
Capex for 2021 is based the latest updated company guidances for 2021. Capex may be estimated or preliminary. Midpoints are used for companies
that disclose guidance ranges. Our data attempts to isolate upstream exploration and development, with other expenditure items (e.g., downstream and
M&A) excluded where possible.
The Majors’ Q4 results preview
Tom Ellacott, 20 January 2022
The facts: Chevron kicks off the Majors’ Q4 reporting season on 28 January. The remaining Majors report in February. The
quarterly and full-year financial numbers will impress. The Majors will also provide more colour on their capital allocation plans
for 2022 and beyond.
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Our take: the Majors will cap off the year with a strong quarter in all business segments. Underlying upstream earnings will
surge, with Equinor especially well placed to capitalise on soaring European gas prices. US-focused integrated refiners will have
a great quarter. High natural gas and CO2 costs will weigh on the performance of European refiners, taking the shine off a
decent Q4 for chemicals in Europe.
One-off items will puncture bumper underlying earnings (Equinor’s US$1.8 billion write-down on Mariner). But the leading
performers may deliver record quarterly and annual free cash flow. The majority will end the year with gearing below their target
range and some in single digits – a far cry from where they began 2021.
Capital allocation will dominate the airtime. We expect capital budgets to increase, although most only incrementally. All
companies will emphasise discipline in the face of sustained high commodity prices. Chevron may continue its 34-year streak of
annual dividend increases. Could TotalEnergies surprise with a dividend hike? Either way, share buybacks will be the primary
vehicle for moping up the surplus cash. It could be the best quarter in over a decade, led by Shell.
Other hot topics to watch out for include cost inflation, restructuring plans (BP, Shell, Eni), recent business development moves
(Shell, TotalEnergies, BP, Eni), above-ground risk (e.g. Kazakhstan, Mozambique), upstream portfolio high-grading (Equinor,
ExxonMobil) and legacy decarbonisation progress.
Average prices
2021
2020
Y-o-Y
Brent FOB SVT (US$/bbl)
70.8
41.9
69%
79.9
WTI Houston FOB (US$/bbl)
68.9
40.8
69%
Henry Hub (US$/mmbtu)
3.86
2.00
94%
3.1
1.8
72%
Global composite refining margin
(US$/bbl)
Q4 2021 Q4 2020
Y-o-Y
Q3 2021
Q-o-Q
44.2
81%
73.6
9%
78.3
43.6
80%
71.2
10%
4.73
2.49
90%
4.31
10%
4.97
0.93
436%
4.20
18%
Source: Refining margin - Wood Mackenzie, Prices - the Argus Media group
Woodside and Santos ride LNG spot wave
Andrew Harwood, 20 January 2022
The facts: Australian independents Woodside and Santos reported record revenues in their 2021 Q4 results, capping a strong
year of post-pandemic and price-crash recovery. Santos’s share price was up 0.8% while Woodside rose 1.5%.
Sky-high LNG prices and rising output combined to deliver a record US$2.85 billion of Q4 revenues for Woodside. Santos
reported sales of US$1.5 billion in the same period, taking annual turnover to US$4.7 billion for the year, up 39% on 2020 - the
company’s highest ever annual total.
Our take: the results come as little surprise, given unprecedented LNG prices through Q4. But they do highlight the
strengthening financial platforms from which Woodside and Santos can now build, following the transformational mergers of
2021.
Financials: capital discipline, a low-cost base and the first contribution from Oil Search, enabled Santos to translate its revenue
performance into a record US$1.5 billion of free cash flow in 2021, a doubling of its 2020 total. This was despite a 62% increase
in capex in 2021, up to US$1.4 billion.
Woodside’s best ever quarterly sales total was driven by a 22% increase in output, and an average realised LNG price of
US$16/mmbtu or US$93/boe.
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Operations: both updated on upcoming growth projects. Woodside has awarded FEED contracts for the Pluto T1 modifications,
following the Scarborough/Pluto T2 FID; the Sangomar Phase 1 development is 48% complete, with subsea installation set to
begin in Q2 2022, ahead of first oil in 2023. Woodside is guiding for US$4 billion of capex in 2022, up 52% on 2021.
Santos’s Barossa project has hit 20% completion, while FIDs are anticipated at Dorado and Pikka in Alaska by mid-2022. The
Papua LNG project also continues to progress, with a FEED decision expected in the first half of 2022.
Merger update: with the Santos-Oil Search merger effective from 11 December 2021, Woodside remains on track to execute its
deal with BHP in Q2 2022. BHP’s own operational update highlighted the deepwater Trion project’s progress towards FID in
2022, and the addition of new exploration in Egypt, providing further optionality to what will soon be a part of Woodside’s
portfolio.
Adapt to the energy transition or go out of business
Rachel Schelble, 19 January 2022
The facts: Blackrock CEO Larry Fink delivered his annual letter to CEOs with a message that sounded like a warning – adapt to
the energy transition or go out of business. This is Fink’s third letter to CEOs where the energy transition has been a key focal
point.
Blackrock is the largest institutional asset manager in the world with over US$10 trillion of assets, including shares of
ExxonMobil, Chevron, ConocoPhillips, and Marathon Petroleum, among others. In the letter, Fink comments that the next 1,000
unicorns will be start-ups that help the world to decarbonise. Companies can play a critical role in what Blackrock calls, “the
greatest investment opportunity of our lifetime.”
Larry Fink stated that Blackrock does not pursue divestment from oil and gas companies, specifically calling out the critical role
of the oil and gas industry in ensuring the supply of affordable energy through the transition – with natural gas for power
generation, heating, and the production of hydrogen most critical.
Our take: in this year’s letter, Blackrock declared that delivering long-term value to shareholders requires a transparent net zero
plan, with clear short, medium, and long-term targets for GHG reductions. It seems that ExxonMobil heard the message loud
and clear, recently announcing their ambition to be net zero for scope 1 and 2 emissions by 2050. In fact, it was market/investor
pressure like this that led both ExxonMobil and Chevron to ramp up their energy transition spending and decarbonisation plans
in the first place.
We’ve seen oil and gas majors, like BP, Shell, and Chevron increase their budgets for venture capital investments in start-ups in
a wide range of businesses – hydrogen, EV, new energies, biofuels, and direct air capture, among many others. Investing in
start-ups helps them gain valuable insight into new and innovative technologies and provides valuable capital and access for
start-ups to work directly with the oil and gas industry. It will be the oil and gas companies that disrupt their own business
models and partner with innovative start-ups that will find the next unicorn.
ExxonMobil announces net zero ambition
Tom Ellacott, 18 January 2022
The facts: ExxonMobil has announced its ambition to achieve net zero Scope 1 and 2 emissions from its operated assets by
2050. The company expects to complete net zero roadmaps, as it has done for the Permian already, for assets that cover
around 90% of its emissions by year-end 2022. The remainder will follow in 2023.
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The roadmaps will include the fuels, lubricants and chemicals businesses, with plans to provide products with lower life-cycle
greenhouse gas emissions. ExxonMobil has set a target to expand lower emissions fuels output to 40 kb/d in 2025, increasing
to 200 kb/d by 2030.
ExxonMobil’s Advancing Climate Solutions – 2022 Progress Report provides additional details on its net zero ambitions and
also highlights the projects that form the backbone of its low carbon investments in CCUS, hydrogen and low-emission fuels.
Our take: ExxonMobil is the last Major to set net zero ambitions for Scope 1 and 2 emissions. These ambitions cover its whole
business, going a step further than Chevron’s goal which excludes downstream. ExxonMobil’s Advancing Climate Solutions
report also hints at more to come.
In a first, the company guided that its absolute full-life cycle Scope 3 emissions would fall by 12% between 2016 and 2030 under
its 2021 business plan. Scope 3 emissions intensity could fall by 4% over the same period. A firmer ambition may only be a
matter of time as the low carbon strategy gains momentum and pressure to close the gap to the Euro Majors ratchets up.
The importance of strategic flexibility is stressed in the report – and could be an important differentiator for ExxonMobil. The
Supermajor will adjust investments between its deep inventory of oil and gas projects and lower-emissions opportunities to align
with the pace of the energy transition.
The company believes it could continue to grow cash flow under the IEA’s Net Zero Emissions by 2050 pathway through
increasing investment in chemicals, CCS, low emissions fuels and hydrogen to compensate for reduced oil and gas spend. Low
carbon solutions could account for half of ExxonMobil’s budget by 2040 under this scenario – underscoring the importance of
expanding the hopper of low carbon options.
Euro Majors boost UK wind portfolios
Norman Valentine, 18 January 2021
The facts: BP, Shell and TotalEnergies were among 17 winning partnerships from 74 applications in the ScotWind offshore
wind leasing round, the first in Scotland in over a decade.
BP, with partner EnBW, won one of the largest fixed bottom lease areas with a potential future gross generation capacity of 2.9
GW. TotalEnergies, as part of a consortium with Macquarie, also won one fixed wind lease with potential gross capacity of 2
GW. Shell focused on floating wind and was successful with two bids in partnership with Iberdrola that aim to develop up to 5
GW of combined gross floating wind capacity.
Other successful applicants included joint ventures led by SSE, Falck, DEME, Vattenfall, EDP/Engie, Iberdrola and Northland
Power. All of the winning bids included the maximum lease option fee of GBP 100,000/km2. The highest single lease option fee
of GBP 86 million was submitted by one of the Shell partnerships.
Our take: this is a further step along the Euro Majors’ journey to expand their renewables businesses. It was another strongly
competitive lease round in one of the world’s most established offshore wind provinces.
But ScotWind’s capped lease option fee meant the Euro Majors did not need to rely on big upfront bids to secure acreage. The
GBP 85.9 million option fee included in the successful BP/EnBW ScotWind bid is a fraction of the GBP 1.8 billion minimum total
option fee that the companies committed to pay in last year’s UK Lease Round 4 for areas with similar fixed bottom wind
capacity potential. Instead of high upfront fees, ScotWind differentiated bids on local content, operator experience and project
plan.
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The ScotWind results highlight differing offshore wind strategies among the Euro Majors. Shell’s focus on floating wind stands
out. ScotWind provides Shell with an opportunity to scale-up floating wind technology to a commercial scale. As well as
developing up to 5 GW of gross capacity in the UK, this could give it invaluable leadership credentials when it comes to
accessing floating wind opportunities in other parts of the world.
Woodside moves closer to first hydrogen project
Andrew Harwood, 18 January 2022
The facts: Woodside has entered FEED for the H2OK project in Oklahoma in the US, its first firm hydrogen project. Final
investment Decision on the initial 290MW facility could be taken in the second half of 2022, with first hydrogen produced in
2025.
Our take: Woodside’s investor update in November 2021laid out plans to invest a cumulative US$5 billion in new energy
products and low carbon services by 2030. As part of that update, Woodside highlighted four key hydrogen projects it was
advancing to FEED, expected to generate minimum returns of 10%.
H2OK will initially generate 90 tpa of hydrogen using power from Oklahoma’s grid, of which a large portion is generated from
wind. The project will supply liquid hydrogen to meet heavy-vehicle transport demand, and to fuel local fuel cell microgrids for
data centres and warehouses.
Hydrogen will become an increasingly important part of the energy transition in 2022, with its potential to displace existing
transport demand, while leveraging existing gas production and export value chains. Woodside is targeting 3GW of low carbon
energy capacity by 2030, to complement its existing LNG focused upstream business.
TotalEnergies and INPEX high-grade in Angola
Tom Ellacott, 17 January 2022
The facts: TotalEnergies and INPEX have agreed to sell their respective 50.01% and 49.99% interests in the Angola Block 14
B.V. to Angolan company Somoil. The Angola Block 14 B.V. company owns 20% in block 14 and 10% in block 14K. For INPEX,
the sale represents an exit from Sub-Sahara Africa following its divestment in DR Congo in October 2021.
Our take: the asset is non-core for TotalEneriges and INPEX. Current net oil production of 9 kb/d is immaterial and – while me
model a modest increase in 2023 – production will enter decline from 2024. The transaction is also another indication of
improving asset market dynamics.
Many similar non-core positions exist in the portfolios of larger players. We expect them to increase upstream high-grading to
focus their portfolios on material advantaged assets (high margin, low breakeven and low emissions). This will, in turn, present
growth opportunities for smaller regional players, emboldened by rising prices.
See our Global upstream M&A: 5 things to look for in 2022 for more details.
Equinor downgrades reserves at Mariner
Lucy King and Norman Valentine, 14 January 2022
The facts: the Major has revised reserves at its flagship UK, heavy oil project in the Northern North Sea from 275 mmboe to
180 mmboe. Equinor estimates an impairment in the region of US$1.8 billion as a result.
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Corporate week in brief
Partners in the development – Siccar Point, JX Nippon (soon to be NEO Energy) and ONE-Dyas – are reported to dispute the
downgrade.
Our take: this is the latest of several challenges that Mariner has faced. Start-up was delayed by two years by the late arrival of
the platform topsides and weather issues. It was then hit by another delay due to faults with electrical couplings on the platform.
Overall, development costs increased to over US$7 billion.
Reservoir performance has been a risk at Mariner since the get-go. Reserves are split between two reservoirs, Maureen and
Heimdal, with production to date primarily coming from the former. In addition to its ultra-heavy oil status, the complexity of both
reservoirs has posed uncertainties over exact volumes in place, and the field has subsequently underperformed against initial
expectations. Improved understanding of the Maureen reservoir and results from the first well into the Heimdal reservoir drilled
in Q4 2021 have led to the reserves downgrade.
Based on previous performance, we assumed a reserves downgrade in late-2021 to 235 mmboe. The subsequent revision to
180 mmboe wipes a further US$1 billion (NPV10, 1 Jan 2022) off our valuation, and represents a decrease of almost 50% from
our estimated reserves of 325 mmboe at sanction in 2012.
This downgrade puts Equinor’s UK upstream strategy into question. In our Equinor corporate report, we highlighted the
company’s 65% stake in Mariner as one of several possible asset sell-down options in its international portfolio. That possibility
now looks much less lucrative. Equinor will also have to face up to political headwinds in the UK that could threaten its plans to
develop Rosebank, its other principal asset in the country. The UK will remain a key international investment destination for
Equinor but its future looks increasingly about offshore wind, CCUS and hydrogen rather than oil and gas.
Enterprise acquires Navitas Midstream in US$3.25 billion deal
Rachel Schelble and Colette Breshears, 13 January 2022
The facts: Enterprise Products Partners announced the US$3.25 billion acquisition of Navitas Midstream, a Warburg Pincus
company.
This acquisition provides a point of entry for Enterprise into the Permian Midland Basin, where Enterprise has very little
infrastructure. The deal includes 1,750 miles of pipelines and 1 BCFD of cryogenic gas processing capacity.
The Navitas system is anchored by long-term contracts with a dedicated acreage position of over 440,000 acres and gives
Enterprise exposure to future growth in up to 10,000 drilling locations over the next 15 years.
Our take: this acquisition by Enterprise supports its strong position in the Permian, tying together its existing pipeline systems
with Navitas' strategic natural gas processing footprint.
This deal is immediately accretive to Enterprise, as the Navitas Midland Basin processing complex is well connected to a suite
of natural gas and NGL pipelines, including several Enterprise operates. Navitas' footprint is in an active sweet spot for Midland
Basin E&Ps, near existing assets with proven drilling locations. Long-term contracts underpin the facilities.
Navitas' Leiker Plant is a 240 MMCFD cryogenic gas processing facility that is planned to come online in Q1 2022. The plant
has special processing capability to accept gas heavy in CO2 and H2S and boasts enhanced technology to split out propane
and ethane.
The ability to process sour gas gives Enterprise an edge in enticing E&P customers and likely offers ESG benefits as it focuses
on building out its CCUS capabilities leveraging the 45Q tax credit.
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CNOOC Ltd 2022 Strategy Preview: Roaring into the year of the tiger
Kavita Jadhav and Yuqi Hu, 13 January 2022
The facts: China’s leading offshore producer increased production to 1.6 mmboe/d in 2021, a 9% year-on-year increase. The
company is targeting an output of 1.9 mmboe/d in 2024, with a CAGR of 6% over the next three years. Capital spend in 2022
will be maintained at the same level as 2021, in the range of US$14-16 billion. 5-10% of this capital will be spent on new energy
with targets to acquire 10-15 GW of offshore and onshore wind capacity by 2025, and install 1.5 GW of offshore wind and 0.5-1
GW of onshore wind and solar capacity in the same timescale.
CNOOC Ltd announced a plan to address the underperformance of its share price. Under this plan the company will pay a
special dividend to mark its 20th anniversary, implement share buybacks in 2022 and maintain an annual dividend payout ratio
of 40% from 2022-24. CNOOC Ltd's share price jumped 8% on the day following the announcement.
Our take: as China’s import dependency has increased, CNOOC Ltd along with other Chinese NOCs have invested heavily in
recent years to increase domestic reserves and production. The result is that CNOOC Ltd has unparalleled production growth in
the oil & gas sector relative to the 1-3% production growth for the Majors. This growth, however, is oil-weighted with gas
accounting for only 20% of current production. CNOOC Ltd announced that it would increase gas exploration, a step in the right
direction to meet its target of raising its share of gas to 50% by 2035.
This was the first time that CNOOC Ltd has detailed renewable plans for the capital it has earmarked for new energy. Delivery of
its plan to install 2-3 GW of capacity by 2025 would be a good start towards a material renewables business. CNOOC Ltd’s
target to capture a 12-18 GW development pipeline by mid-decade is ambitious and would put it on course to become a
sizeable player in the renewables sector by the end of the decade. Equinor which is the leading oil company in offshore wind,
has a target of 12-16 GW of installed renewables capacity by 2030.
CNOOC Ltd stressed that it would actively manage its share price upwards so that it reflects the value of the company, which
has been suppressed since it was delisted from the NYSE in 2021. The commitment to pay HK$ 0.7 per share implies a
dividend yield of 8%, which is one of the highest in the oil & gas sector. The company will also mark another first by being the
first Chinese NOC to embark on share buybacks.
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Corporate week in brief
ExxonMobil strikes European biofuels deal
Tom Ellacott, 11 January 2022
The facts: ExxonMobil has announced it is acquiring a 49.9% stake in Biojet, a Norwegian biofuels company.
Biojet plans to develop up to five facilities to produce biofuels and biofuel components from forestry and wood-based
construction waste. The company expects the first facility to commence commercial production in 2025.
The deal also includes offtake agreements for up to 3 million barrels per annum of biofuels, based on the potential capacity of
the five facilities.
Our take: ExxonMobil will take advantage of the opportunity from growing EU regulatory requirements for Sustainable Aviation
Fuels (SAF) with this deal. The EU proposal suggests a 5% SAF blend by 2030. This is equivalent to around 70 kbd, versus the
8 kb/d of second-generation biofuels that ExxonMobil will access if all the facilities are developed.
The move also expands ExxonMobil’s capabilities in biofuels, a key source of low carbon liquids for hard-to-decarbonise
sectors. To date, the company has focused on algae, which is a long-term play. The Biojet opportunity could materialise in the
2020s and is similar in scale to bio facilities of TotalEnergies (La Mede and Grandpuits, France) and Eni (Porto Maghera and
Gela, Italy).
We suspect the acquisition signals the start of a more aggressive second-generation biofuels growth strategy, in which
ExxonMobil will leverage its existing regional refined product distribution infrastructure.
Pioneer Natural Resources sends bullish price signal
Dave Clark, 7 January 2022
The facts: Pioneer Natural Resources indicated this week that it is liquidating its oil hedges for 2022. Based on Q3 reporting,
the closed-out hedges cover about 91kbd of production, or ~23% of current flowing oil production. Cash payments for the
terminated (or offset) 2022 positions are approximately US$180 million in Q4 2021, and about US$328 million in 2022 spread
across the year.
Our take: closing-out all of its oil hedges signals a bullish management outlook for 2022 oil prices. Most of the hedges were
Brent collars with ceilings of US$65-66/bbl or WTI collars with a ceiling around US$60/bbl. The potential cash settled derivative
loss in 2022 at our US$80 WTI scenario stood at ~US$650 million.
The decision perhaps also expresses a resolve not to repeat the very large hedging losses of 2021, and ensure the full capture
of upside should oil prices remain elevated (Brent strip is above US$75/bbl for every month in 2022, as of 6 January) or rise
even further. Pioneer was one of only two oil-focused US independents to report derivative losses of greater than US$2 billion
year-to-date through Q3 (the other independent was Ovintiv).
In the filing, Pioneer highlighted that the US$328 million cash payment in 2022 will be accounted for as changes in operating
assets and liabilities, or working capital in other words, and will thus not impact free cash flow calculations used to determine
quarterly variable dividends. This treatment coupled with higher anticipated realizations unburdened by hedge constraints would
drive variable dividend payments higher.
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US independents added oil hedges for 2022 in Q3 2021. Q4 additions are still largely unknown, but rising prices and the ability
to take advantage of current cash flows to offset upfront liquidation payments might prompt other well-capitalized independents
to take similar actions.
Repsol beefs up its Marcellus gas portfolio
Robert Clarke and Tom Ellacott, 7 January 2022
The facts: Repsol has paid US$222 million for 43,000 net acres and 110 mmcfd of Marcellus production from Rockdale’s
bankruptcy process. Shell originally developed the properties in Lycoming, Tioga, and Bradford Counties in Pennsylvania, but
Rockdale purchased them in 2017.
Our take: the transaction is another indication that the Euro Majors are still open to upstream business development, despite
their aggressive pivots to new energy. TotalEnergies was particularly active in 2021, with oil-led business development success
in Iraq, Libya and Brazil’s pre-salt sector. But this deal is about consolidating a core gas play.
Repsol has a far gassier production mix than any Major and the Marcellus is one of the top regions within its portfolio. But the
company’s gas:oil ratio declines from 61% in 2021 to 51% in 2030 as it moves forward with new oil developments in Alaska,
Brazil and the US Gulf of Mexico. This transaction will help sustain a peer-leading proportion of gas in its portfolio out to 2030.
Repsol’s new Marcellus wells will pay back rapidly at today’s strip. We calculate half-cycle NPV,10 Henry Hub breakevens for
Tioga PUD locations at around US$2.50/mcf. Repsol may also have secured a discounted valuation in picking up these
properties from a Chapter 11 process. And the company’s substantial midstream infrastructure in central Pennsylvania provides
opportunities to capture value chain synergies in the offset acreage.
Two new discoveries at the Stabroek Block
Alex Beeker, 6 January 2022
The facts: on Wednesday 5 January 2022 two new discoveries were announced at the Stabroek Block in Guyana (ExxonMobil
45%, Hess 30%, CNOOC Ltd 25%). The discoveries are the 22nd and 23rd at the Stabroek Block.
The Fangtooth-1 well encountered 50 meters of high-quality oil-bearing sandstone reservoirs and is located 18 kilometers
northwest of the Liza field. The Lau Lau-1 well encountered 96 meters of high-quality hydrocarbon-bearing sandstone reservoirs
and is located 13 kilometers southeast of the Cataback discovery.
Additionally, the operator announced the Liza Unity FPSO is undergoing hookup and commissioning. First production from Liza
Phase 2 remains on track for Q1 2022.
Our take: Guyana continues to deliver exceptional results with success rates exceeding 80%. Given Fangtooth’s proximity to
Liza and Payara, tie back options are possible. However, we estimate the field holds over 250 mmbbl of oil which is enough to
justify its own development cluster.
The Lau Lau-1 well is located in the southeast section of the corridor, where there is more gas and condensate present. The
presence of high-GOR oil and gas-condensate intervals will move the discovery further back in the development queue until a
gas market is developed.
With the startup of Liza Phase 2 this year, the Stabroek Block is expected to become a cash generator for its partners. This is
especially beneficial for Hess which is more leveraged to Guyana than the others. Hess’ debt levels reached precarious levels
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Corporate week in brief
during the pandemic but have improved considerably in recent quarters. As a result, we expect Hess to increase shareholder
distributions this year for the first time in nearly five years.
Expectations for Chevron and ExxonMobil to ramp Permian
Alex Beeker, 5 January 2022
Before the holiday break, we published an Insight outlining why the Majors might be surprisingly active compared to their
Permian competition in 2022. There were multiple December triggers for that analysis:
•
ExxonMobil reaffirmed its 2025 production goal
•
Chevron increased its 2022 Permian budget by 50% Y-o-Y
Combined, these pieces point to meaningful rig additions and volume growth. By our models, running the same number of rigs
as 2021 doesn't put either company on track to hit their targets. The aggressive DUC drawdown undertaken in 2021 isn't
sustainable.
Additionally, ExxonMobil has established a new Permian net zero target. Growing advantaged Permian volumes under this
operational framework will help lower average global GHG emissions intensity.
Perhaps more interestingly, an increase in activity would mark a differentiated approached to Permian Independents. Other
public Permian producers are leading their guidance with financial targets, where production volumes will be an outcome of
capital frameworks. But ExxonMobil and Chevron are keeping volume targets in-place.
Each company fully exercising the strength of Permian short-cycle barrels goes further beyond production targets, emissions,
and wellhead economics too. In the paper, we analyze crucial cash flow metrics. Click through to read why ramping rigs over the
next couple of years will help fund lower-carbon investments later in the 2020s.
Q4 2021
Aker BP buys Lundin Energy to create 'super' Norwegian independent
Scott Walker and Neivan Boroujerdi, 23 December 2021
The facts: Aker BP has agreed to acquire Lundin Energy. The transaction will be settled through cash of US$2.2 billion and
US$8.8 billion in equity reaching a consideration of US$14 billion including net debt.
Equity in the combined entity will be 57% Aker BP and 43% Lundin Energy. Aker BP CEO Karl Johnny Hersvik will lead the
combined company with the deal set to close in Q2 2022. Lundin will retain its renewables business.
Our take: Aker BP will now produce over 400,000 boe/d in 2022, increasing to over 500,000 boe/d in 2028 making it
comfortably the second biggest producer in Europe behind only Equinor. The portfolio is underpinned by a joint 31.6% stake in
Johan Sverdrup, which makes up over 50% of the value of the combined portfolio.
Combining Aker BP’s growth story with Lundin’s cash-generating portfolio is on brand with previous Aker BP deals, including the
landmark Det Norske-BP tie-up in 2016. Aker BP has paid a big premium to our valuation, but both companies had been trading
at historic highs and at high premiums to our base case NPV in our corporate coverage. Quality assets – and companies – have
long attracted a premium in Norway
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For a more detailed view see our Inform and look out for upcoming Deal Insight.
Rosneft targets net zero by 2050 and outlines strategy out to 2030
Michael Moynihan, 22 December 2021
The facts: On 21 December, Rosneft’s Board of Directors approved the new strategy “Rosneft-2030: Reliable Energy and
Global Energy Transition”. In addition to the commitment to net zero in scope 1 and 2 emissions by 2050, the key targets in
Rosneft’s new strategy are (by 2030, unless otherwise stated):
•
25% reduction in absolute emissions (scope 1 and 2 versus 2020 level)
•
Zero routine emissions
•
Methane intensity reduction to less than 0.2%
•
Growth in hydrocarbon production to 330 million toe (255.5 million toe in 2020)
•
Gas to make up 25% of total hydrocarbon production by 2025 (20% in 2020)
•
Maintain low production costs
•
Growth in light product yields in Russia to 69% (57.1% in 2020)
•
Double free cash flow.
Our take: Rosneft’s commitment to net zero by 2050 is the most eye-catching announcement and follows President Putin’s
announcement of net zero for the Russian economy by 2060. The company has made a good start by optimising its portfolio
over the past year and divesting several brownfield assets to NNK.
However, successful implementation of the new strategy will be tough for Rosneft. The company’s hydrocarbon production is
expected to grow out to 2030, driven by activity at Vostok Oil and gas projects like Rospan International and Kharampurskoye.
Russkoye, Yurubcheno-Tokhomskoye, North Danilovskoye and North Komsomolskoye were also mentioned by Rosneft in their
strategy announcement. Finding a way to achieve the targets with low-cost solutions will underpin the road to doubling the
company’s free cash flow.
The company is putting its faith in low-carbon power generation, zero routine flaring, use of energy saving technologies, carbon
capture and storage (CCS) technology and natural forest offsets. These are also areas of focus for the government and other
companies in Russia. CCS and natural forest offsets are in the earliest stage of assessment as possible solutions to Russia’s
emissions management. If Rosneft can make them work, the benefits to the wider upstream industry in Russia could be
extremely positive.
Majors and NOCs beef up their Brazilian pre-salt portfolios
Tom Ellacott and Luke Parker, 20 December
The facts: a TotalEnergies-led consortium beat Petrobras for the Sépia contract in Brazil’s second surplus transfer of rights
round. However, the NOC exercised its preferential rights and will maintain a 30% stake and operatorship for the area. The
Oeste de Atapu's project partners Petrobras, Shell and TotalEnergies presented the single offer for the Atapu contract.
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The winning bids for both contracts exceeded 30% of government profit share.
Winning bids in Brazil's second surplus transfer of rights round
Block
name
Winning consortium
Petrobras* (52.5%), Shell
Atapu (25%), TotalEnergies (22.5%)
Petrobras* (30%),
TotalEnergies (28%),
PETRONAS (21%),
Sépia QatarEnergy (21%)
Bids
Signature bonus Government share of profit oil
received
(US$ billion) Minimum bid (%) Winning bid (%)
1
728
5.89
31.68
2
1,298
15.02
37.43
Source: Wood Mackenzie
Our take: the leading role played by Petrobras’ in the licensing round comes as no surprise. The NOC needed to lock in the
discovered resource opportunity after recent high-profile pre-salt exploration wells failures. But the US$2 billion of combined
signature bonuses and winning bids highlights the strategic value that Shell, TotalEnergies, PETRONAS and QatarEnergy will
have seen in these opportunities.
•
Emissions intensity is lower than the average of each company’s portfolio – a core metric for all the bidders.
•
The projects have Supermajor scale and growth potential. We project combined oil production of around 140 kb/d in 2022,
rising to a peak of 325 kb/d in 2030.
•
We calculate Atapu and Sépia will deliver 12% and 11% IRRs respectively under our US$50/bbl long-term real base case
price (including signature bonuses and compensation payments to Petrobras). But both assets are already producing,
reducing project execution risk and providing upside exposure to sustained higher prices this decade.
TotalEnergies caps off a busy year of oil business development with its winning bid. Other high profile moves include
opportunity capture in Iraq and Libya. Shell’s involvement also underscores that Majors pivoting more aggressively to the Big
Energy business model are still open to advantaged upstream opportunities that drive portfolio improvement in core regions.
See our inform for a more in-depth analysis of the strategic drivers and value proposition for all the participants.
Budgets seeing a massive uptick
Raphael Portela, 17 December 2021
Upstream spend is set to jump in 2022. Out of the 38 companies that have released guidance so far, all but three are raising
their budgets. Combined, full-year guidance stands at US$72 billion or 20% more than in 2021. However, we are nowhere near
pre-crash levels: -30% (-US$30 billion) compared to 2019 and -28% (-US$28 billion) versus 2020's pre-crash guidance.
Keep in mind that results are preliminary for some. Several big hitters (e.g., ExxonMobil, TotalEnergies, Repsol) will provide
official 2022 numbers in Q4, with today’s estimates based on average multi-year guidance. But others have unveiled approved
budgets. Chevron's spend is up 20% to US$12.6 billion. Other notable announcements include ConocoPhillips (up US$1.7
billion or 32%), PTTEP (US$1.1 billion or 53%), Petrobras (US$700 million or 9%) and Suncor (US$430 million or 17%).
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Themes have also emerged from these initial announcements. Several companies are mindful of inflation risk and have baked
costs rising into their budgets. Updates to 2021 guidances were also widespread, particularly relative to production. Other E&Ps
admitted that they had pulled forward some of their 2022 spend into Q4 of this year.
Stay tuned for weekly updates to our recently published guidance tracker throughout 2022.
Capex for 2021 is based the latest updated company guidances for 2021. Capex may be estimated or preliminary (e.g., BHP likely to update guidance
after proposed merger with Woodside). Midpoints are used for companies that disclose guidance ranges. Our data attempts to isolate upstream
exploration and development, with other expenditure items (e.g., downstream and M&A) excluded where possible.
Shell boosts solar business with acquisition of Savion
Luke Parker, 17 December
The facts: Shell has acquired US solar developer Savion Energy. No purchase price was disclosed. Savion holds a portfolio of
“in development projects” totalling 12.5 GW of solar (87 discrete projects across 27 States) and 3.3 GW of energy storage (44
projects across 15 States). Within that, the company has 2 GW of solar and storage (27 projects in total) currently under
construction or operational.
Savion is a portfolio company of Macquarie’s Green Investment Group. GIG originally acquired Savion in 2019, from Enel Green
Power subsidiary Tradewind Energy. Shell emerged as the winner in a competitive bidding process that kicked-off with first
round bids in September.
Our take: This is a material acquisition for Shell. It certainly moves the needle on volume. As things stood (pre-Savion) Shell’s
solar portfolio totalled 1.65 GW of capacity. The addition of Savion bumps Shell’s solar capacity closer to that of TotalEnergies
and BP.
But the key, as always, is quality not quantity. That’s difficult to gauge, as is the likely price tag, given limited detail on the
commerciality and maturity of the project pipeline. Recent US solar transactions reflect the spread of potential valuations,
ranging from as little as US$24 million per GW of undeveloped capacity (BP-7X), to US$700 million per GW of developed,
contracted capacity (OTPP-NextEra). We’d estimate the Savion deal in the region of US$1 billion, ballpark. The fact that Shell
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felt the need to clarify that the acquisition falls within its US$2-3 billion 2021 guidance for Renewables and Energy Solutions
(RES) cash capex tells a story. We should learn more next year, when Shell begins RES quarterly disclosure.
Value creation potential is more nuanced. Shell is pursuing an “asset light” renewables strategy. The company is focussed on
‘enabling’ rather than owning assets; managing rather than producing electrons. Unlike peers, Shell has no target for building
GW capacity – its objectives are sales-based. So, the Savion projects that Shell brings to development will likely be sold down
or sold off in relatively short order, with Shell having contracted the electrons into its portfolio. The success, or otherwise, of the
Savion deal is tied up with Shell’s broader ‘customer-first’ RES strategy.
WoodMac estimates for net commercial renewables generation capacity
Source: The Majors - positioning in new energy
Suncor and Cenovus budgets rise in 2022, both expect modest growth
Scott Norlin, 17 December 2021
The facts: Suncor and Cenovus released preliminary guidance for 2022 in the last week. Cenovus offered upstream capex
guidance of Cdn$1.85 billion (US$1.45 billion) at the midpoint, while Suncor expects to spend Cdn$3.7 billion (US$2.9 billion).
These values are an increase in spending of 28% and 17% versus 2021, respectively. In the downstream business, Cenovus
expects to spend Cdn$900 million (US$709 million) at midpoint, while Suncor has budgeted Cdn$775 million (US$610 million).
Downstream guidance has decreased by 12% and 5%, respectively, versus 2021.
On the production side, Cenovus expects growth of 4% year-over-year at midpoint, reaching 800 Kboe/d. Suncor also expects
modest growth of just over 1% achieving 770 Kboe/d in 2022.
Our take: While both operators have increased their capital programs for next year, production growth is not the key focus. Both
Cenovus and Suncor continue to exhibit restraint, focusing on maximizing the value of produced barrels rather than pushing
towards pure growth. In contrast to other global peers, the majority of capital is focused on maintenance and sustaining lowdecline oil sands assets.
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Capital was focused on improving balance sheet resilience in 2021. Both operators are set to hit the new year at or below their
respective debt targets. As integrated operators, they are both able to leverage a downstream business to optimize flows to
achieve higher realised prices and self-determine utilization rates.
ExxonMobil and PETRONAS exit Chad and Cameroon
Tom Ellacott and Andrew Harwood, 17 December 2021
The facts: Savannah Energy has signed a Share Purchase Agreement (SPA) with ExxonMobil to purchase its entire upstream
and midstream portfolio in Chad and Cameroon for a consideration of US$360 million (excluding an oil-price contingent payment
of up to US$50 million).
In a separate transaction, the company also signed a SPA with PETRONAS to acquire its portfolio in Chad and Cameroon for
US$266 million. Both deals have an effective date of 1 January 2021.
Our take: the exits were no surprise. Chad contributed less than 1% of PETRONAS’ total production in 2021. Our estimated
emissions intensity of 40 tCO2e/kboe for the asset base is also at the upper end of the company’s portfolio. Divestment will
provide cash ahead of increased capital allocation towards building PETRONAS’ gas and new energies division.
The portfolio is even less material for ExxonMobil and one of the company’s most obvious divestment candidates. More broadly,
the move could signal that the Supermajor may now see a window of opportunity to sell while the selling is good. More country
exits seem likely to focus the portfolio on advantaged assets such as the Permian and Guyana.
EQT joins the US Independent buyback party
Robert Polk, 16 December 2021
The facts: EQT Corporation reinstated a quarterly dividend of US$0.125/share and authorized a US$1.0 billion share
repurchase plan. The buyback program is effective immediately and authorization lasts through 2023. Regular dividend
payments will resume in Q1 2022. The dividend was initially suspended in March 2020 and the last declared dividend was
US$0.03/share in February 2020.
Our take: US Independent buyback activity picked up significantly in H2 2021, but it was largely tight oil producers with modest
leverage driving the trend. EQT’s announcement coupled with CNX and Chesapeake’s recent buyback announcements further
demonstrate the return of capital framework has made its way to gas producers that might have previously been constrained by
leverage and/or hedges. Even with greater hedge constraints across the gas-weighted peer group, higher NGL realizations
boost cash flow.
As gas producers approach desired leverage levels, additional returns of capital appear imminent. Antero already alluded to a
likely buyback framework in 2022. Southwestern has two acquisitions to integrate, but shareholder returns will follow eventually.
Range Resources and Comstock have more deleveraging to do before shifting focus to shareholder returns. As with the oil
producers, the benefit of a stable balance sheet enables an acceleration in returns of capital.
EQT's gearing stands at ~40% and it targets paying down at least another US$1.5 billion of its existing debt of US$6.2 billion
over the next two years. There is still deleveraging work to be done, but a robust free cash flow outlook in a flat US$3.00/mmbtu
environment (US$1.9 billion in 2022, ~US$1.6 billion 2023+) should allow EQT to reach that target, pay the regular dividend,
and utilize a good portion of the discretionary buyback authorization.
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EQT’s significant hedge position garnered plenty of recent attention, as evidenced by its US$2.6 billion unrealized derivative
loss in Q3. While it missed out on the upside from the gas spike earlier this year, the hedge position provides visibility to cover
the base dividend requirements. Unwinding a portion of 2022 hedges also helped recapture some upside exposure to support
more discretionary buyback activity.
Woodside 2021 investor update: strategic refresh after transitional year
Andrew Harwood, 13 December 2021
What’s happened: Woodside‘s 2021 investor day on 8 December provided an update on the company’s strategy and value
proposition. Meg O’Neill, in her first strategy update, struck a confident tone, refreshing the company’s strategic focus, clarifying
the financial and capital allocation framework, and providing further details of its energy transition plans. It was also a chance to
highlight the significant progress made during 2021, setting up for a pivotal 2022.
•
Strategy refresh: Laying out her vision of Woodside’s future, O’Neill described the five characteristics that would deliver the
goal of ‘thriving through the energy transition’: low cost, lower carbon, profitable, resilient, diversified.
•
Financial framework: Woodside expects to be cash flow positive through to 2040, under a range of climate scenarios, with
indicative cash flow for the latter half of this decade set to ramp up significantly after the big investments required of
Scarborough and Pluto Train 2 during 2022-2026. Dividend payouts will be maintained at 50-80% of net profit after tax,
allowing for a near-term ramp up in investment over a larger portfolio of projects.
•
Capital allocation: Future projects, both upstream and new energy, will be required to generate unlevered returns in the
region of 10-15%, and payback period of 5-10 years, depending on the opportunity type.
•
Energy transition: The headline news was Woodside’s US$5 billion new energy investment target out 2030, with a focus
on hydrogen, ammonia and CCS. The company also shared details of its new energy opportunity hopper, projects that will
support its ambition to reach 3,000 MW of low-carbon power capacity by 2030. On the emissions front, offsets are already
in place to meet the 2025 reduction target of 15% lower Scope 1&2 net emissions, and studies are ongoing into new largescale CCS options to sequester not only carbon from Woodside’s business but also from other industrial sources.
•
2021 progress: Woodside also took the time to recognise the significant progress made during 2021, including the
transformational BHP merger announcement, and the recent final investment decision of the Scarborough/Pluto Train 2
development. All under the watch of a new CEO.The merger remains on track to complete in Q2 2022, setting up the
company for further integration savings, financial strengthening and portfolio optimisation.
Our take: As previous boss Peter Coleman exited in April, and a political coup in Myanmar impacted efforts to expand
internationally, Woodside’s shareholders would be forgiven for looking nervously at the remainder of 2021. An uncertain outlook
for Scarborough was causing tension for a portfolio devoid of alternative options.
However, the outlook is much clearer now under new CEO Meg O’Neil, who has seized the bull by the horns, announcing a
transformational corporate acquisition, derisking key projects and outlining a clear strategy for the energy transition. A
strengthened balance sheet has unlocked LNG growth, which, when allied with high-margin oil cash flows in the medium term,
paves the way for longer-term low carbon investment.
Woodside will focus on executing the revamped strategy in 2022, including integrating the BHP merger, further financial
strengthening via portfolio optimisation, and project progress not only in upstream, but also in new energy. We think Woodside
is well placed, particularly if commodity prices remain high, with plenty of financial firepower for further portfolio additions, or an
acceleration of new energy investment. It certainly makes for a strong first report card for Woodside’s new CEO.
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Shell makes another Perdido discovery, deepwater GoM
Luke Parker, 10 December 2021
The facts: Shell has made “a material discovery” in the Western Gulf of Mexico. Blacktip North is the company’s fourth Perdido
Corridor discovery in the past five years, following Whale (2017), Blacktip (2019) and Leopard (2020). The play is fast becoming
a growth engine for Shell in the US GoM.
Our take: Whale was sanctioned for development in July, and will generate a 22% IRR under our base modelling (at US$50/bbl
long-term Brent). By our estimates, Blacktip North takes total recoverable reserves at the other three, as yet unsanctioned
discoveries to 600 million boe. These barrels are the definition of 'advantaged', and a fast-track development would strengthen
Shell’s upstream portfolio sustainability. Our GoM team has published an Inform outlining the options and potential impact on
Shell’s GoM production profile.
The discovery is a reminder of Shell’s ongoing commitment to high impact exploration. Back in February, the company guided
for annual E&A spend of around US$1.5 billion between 2021 and 2025, over 70% of which will be directed towards deep water.
The US GoM is the key region. Interesting to note, however, that this discovery didn’t warrant a media release on Shell’s Global
website – a sign of the times, rather than an indication of materiality. It seems that high impact exploration is an increasingly low
profile undertaking for Big Energy players on a net zero pathway.
Santos and Oil Search complete merger
Jocelyn Vaskas, Andrew Harwood, 10 December 2021
The facts: final approval from the National Court of Papua New Guinea means the merger between Santos and Oil Search has
cleared the final hurdle. An overwhelming 95% majority of Oil Search shareholders voted for the deal earlier this week.
The merger is now effective, with Oil Search shares trading for the final time on Friday 10 December, before being delisted,
bringing the company’s 92-year history to an end.
Our take: in our earlier inform and deal insight we discuss the rationale for the deal, highlighting how "the complementary
nature of Santos and Oil Search's interests in Papua New Guinea will increase the combined entity's LNG-focus, a strategically
important resource theme for the transition to lower-carbon sources of energy".
With the merger complete, focus will switch to integration, realising corporate synergies and portfolio rationalization. An enlarged
portfolio provides opportunity to monetise non-core assets and farm-down equity to smooth out capital allocation. Oil Search’s
Alaska operations will rank lower in the merged portfolio, while an increased equity stake in PNG LNG could be an option for sell
down.
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Santos & Oil Search combined portfolio
Source: Wood Mackenzie Lens, Corporate Service; bubble size reflects NPV10
Equinor buys into battery storage
Norman Valentine, 10 December 2021
The facts: Equinor has agreed to acquire a 45% stake in Noriker Power, a battery storage developer in the UK, with an option
to acquire the entire company in the future. Equinor will also gain the opportunity to directly participate in projects being matured
by Noriker. Noriker has 250 MW of battery storage across the UK and has a project pipeline in excess of 500 MW in battery
storage, hybrid energy and stability service projects. The deal consideration was not made public.
Our take: we highlighted in our corporate look-ahead to 2002 that increasingly diverse acquisitions will be a growing feature of
oil and gas companies’ moves into new energy. This deal fits with Equinor’s growing exposure to power markets in the UK as it
develops its offshore wind portfolio. The country’s increasing dependence on variable output renewables provides Equinor with
the opportunity to use battery storage to capture value from future market volatility.
INPEX acquires stakes in Dutch offshore wind projects
Andrew Harwood, Norman Valentine, 10 December
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The facts: Japanese E&P INPEX has announced a deal to purchase stakes in two offshore wind farms, in the Netherlands.
INPEX will acquire 50% in the 129 MW rated Luchterduinen project, and 15% of the 732 MW Borssele III/IV development. No
consideration was given. The seller of both stakes was fellow Japanese player, Mitsubishi Corporation.
Our take: using Lens Power, we value the combined asset stakes at around US$500 million using a 7.5% nominal discount rate
(pre any project financing). This would reflect a material investment by INPEX in its renewable capacity. The Japanese operator
is however flush with cash, with the Ichthys LNG project ramping up to full capacity, and LNG prices reaching record highs.
Revamping its energy transition strategy, INPEX declared its intention to build out its renewable business in its “Business
Development Strategy – Towards a Net Zero Carbon Society by 2050” in January 2021. Offshore wind, alongside geothermal,
have been identified as opportunities that leverage INPEX’s oil and gas drilling and offshore construction capabilities.
The company generated 360 GWh of renewable electricity in 2020; this deal could treble that level of output. More deals are
likely to follow, with INPEX set to invest annually around 25 billion yen (US$220 million) in its energy transition strategy over the
next five years – equivalent to around 10% of overall spend.
Harbour Energy introduces dividend
Scott Walker, 10 December 2021
The facts: Harbour Energy is introducing a US$200 million annual dividend to be paid in two equal instalments. The payout
equates to 16 pence per share, or around a 4% yield to the current share price. Harbour will make an initial payment of US$100
million as a final dividend for 2021, to be paid in May 2022 following shareholder approval.
Our take: Harbour’s move leaves only Tullow and Kosmos out of our Mid Cap International peer group not paying a dividend
(inclusive of Cairn’s special dividend).
Post distributions, we calculate the company’s average cash flow breakeven between 2022 and 2025 will increase from
US$35/bbl to US$40/bbl. In our base case (US$50/bbl long-term), the company retains some running room – generating
average annual free cash flow of around US$1 billion during the same period. Harbour will allocate a portion to debt reduction,
which the company estimates could be eliminated by 2025 under current commodity prices.
ConocoPhillips swaps Indonesian gas for Australian LNG
Andrew Harwood, Dave Clark, 9 December 2021
The facts: ConocoPhillips (COP) has announced the sale of its 54% stake in the Corridor PSC in Indonesia to Medco Energi for
US$1.355 billion. Medco will also acquire COP’s interests in the associated Grissik and Transasia pipelines.
In parallel, COP has exercised preemption rights to purchase an additional 10% stake in its Australian LNG project, APLNG,
from partner Origin Energy for up to US$1.645 billion. At closure, this will increase its stake in APLNG to 47.5%, subject to
Foreign Investment Review Board clearance and partner preemption rights (Sinopec).
Both deals are expected to close in Q1 2022, with effective dates of January 1, 2021 and July 1, 2020, respectively.
Our take: This is a transformational transaction for Indonesia independent E&P Medco Energi, the largest deal yet in its
acquisitive spree of recent years. But the bigger story here is the ConocoPhillips combo-deal, a masterful example of
opportunistic portfolio optimisation.
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The mini-Major has effectively swapped a mature, emissions intensive asset in a challenging operating environment, for an
incremental stake in a long-life, lower carbon LNG asset, in a lower risk regulatory environment, and with exposure to market
upside.
A strong focus on portfolio high-grading, coupled with top-tier financial strength has enabled ConocoPhillips to execute
this switch, not long after completing the US$9.5 billion acquisition of Shell’s Permian assets (US$8.6 billion cash paid after
closing adjustments with 1 July 2021 effective date).
ConocoPhillips frames these two Asia Pacific deals as enhancing its “diversification advantage” by lowering company-level
decline rate and diversifying product mix. The deals actually increase portfolio concentration though – exiting Indonesia (where
they have operated for about 50 years), and increasing an existing stake at APLNG. But it is a positive concentration into
advantaged resource, inline with the company's focused low cost of supply strategy, and with a different cash flow and product
demand profile than the massive Permian position. The favorable emissions math of the "swap" is also clear - Wood
Mackenzie’s Emissions Benchmarking Tool indicates that APLNG has about half the estimated carbon intensity of Corridor (~33
tCO2e/kboe vs ~70 tCO2e/kboe).
The deal also signals ConocoPhillips' commitment to the Asia Pacific region, and importantly to its global LNG business.
ConocoPhillips remains on the short list of IOCs that could partner with Qatar Petroleum on the first phase of the North Field
expansion, with the partner selection decision for that project now likely in H1 2022.
Following the Shell deal announcement, ConocoPhillips increased its multi-year disposal target from US$2-3 billion to US$4-5
billion through 2023. The Corridor sale moves them well down the road on that objective heading into 2022.
Read our inform for more details on the Corridor transaction; we covered the initial APLNG transaction between Origin and EIG
in our deal insight.
Pemex benefits from multi-billion-dollar tax overhaul
Raphael Portela, 9 December 2021
The facts: Mexico’s Secretariat of Finance and Public Credit (Hacienda) announced a US$3.5 billion capital injection into
Pemex for 2022. The funds will help the state company manage its liabilities, swapping out short and medium-term debt with
long-dated bonds. More importantly, a reduction in the profit-sharing duty (i.e., DUC) from 54% to 40% was also approved.
Pemex plans on releasing a new five-year business plan in the coming months.
Our take: The measures undoubtfully improve Pemex’s financial outlook. We estimate the corporate breakeven for the
company in 2022 drops from US$110/bbl down to US$72/bbl Brent after accounting for the impact of both measures. The DUC
tax bill in 2022 should be around US$3.5-4.5 billion cheaper. But that is not the whole picture. For more detailed analysis, read
our recently published Inform.
ExxonMobil fills in more blanks on its low carbon strategy
Tom Ellacott, 8 December 2021
The facts: In an addendum to last week’s corporate plan update, ExxonMobil announced bold plans to achieve net zero Scope
1 and 2 emissions from its operated Permian assets by 2030. The target is part of the company’s broader goal to lower total
upstream emissions intensity by 40-50% by the end of the decade.
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The Permian roadmap includes eliminating routine flaring by year-end 2022, focusing on electrification of operations, and
increasing the scope and scale of methane monitoring.
ExxonMobil also announced that it had signed an MoU with SGN and Green Investment Group to explore the potential for a
hydrogen hub in Southampton. The JV is studying an initial 2 mmtpa carbon capture facility to produce 4.3 TWh of hydrogen as
early as 2030.
Our take: ExxonMobil’s focus on accelerated decarbonisation of the Permian has compelling strategic logic. The Permian is the
Supermajor’s flagship growth asset – and equally high profile from a regulatory and activist perspective. Current production of
500 kboe/d ranks second to Qatar in ExxonMobil’s portfolio. The Permian takes the top spot in 2025 and output grows to over
900 bkoe/d by the end of the decade in our base case.
ExxonMobil will want to demonstrate it can deliver this growth in a Paris-aligned manner. The net zero Scope 1 and 2 target for
2030 sets a new benchmark among Permian peers. It’s further evidence of the Big Oil business model in action – meeting future
demand with low carbon, low breakeven barrels.
The announcement could also have important implications for nascent carbon markets. ExxonMobil is evaluating the potential
utilisation of carbon offsets to help achieve the net zero goal. We expect the company to take a rigorous approach in selecting
only high-quality offsets, helping to set a high bar for the industry and support the development of a credible offsetting market.
The Southampton Hydrogen Hub capped off a good week in filling in more of the blanks in the low carbon strategy. ExxonMobil
has aligned itself with credible partners and added another low carbon opportunity to its hopper, one that has the potential to
help decarbonise its downstream operations.
Aramco agrees US$15.5 billion gas pipeline monetisation
Norman Valentine, 8 December 2021
The facts: Aramco will receive upfront proceeds of US$15.5 billion in a deal agreed with a consortium led by BlackRock and
Hassana Investment Company, the investment management arm of the General Organization for Social Insurance (GOSI) in
Saudi Arabia.
The consortium will acquire a 49% stake in a newly formed Aramco subsidiary, Aramco Gas Pipelines Company, that will lease
usage rights in Aramco’s gas pipeline network for a 20-year period. Aramco will retain a 51% majority stake. Aramco Gas
Pipelines Company will earn a tariff from Aramco for flows through the network, backed by minimum volume commitments.
Our take: this is another monumental infrastructure deal for Aramco, surpassing its US$12.4 billion oil pipeline transaction
earlier in the year (see Corporate Week in Brief 9 April 2021). We calculate Aramco’s gearing will fall to 13% assuming US$15.5
billion of asset sales proceeds, within its target gearing range of 5-15% across the cycle and down from 17% at end Q3 2021.
Sustained oil prices over US$75/bbl through Q4 should support further deleveraging by year-end, setting the scene for capital
investment and dividend increases in 2022.
A deal between Saudi Aramco and BlackRock, the world’s asset manager, is notable not just because of its huge scale.
BlackRock has been vocal in its calls for companies to take action on climate goals (see Corporate Week in Brief 29 January
2021). In the Aramco press release accompanying this deal, BlackRock CEO Larry Fink praises Saudi Arabia and Aramco’s
efforts to take steps towards renewables, clean hydrogen and a net zero future. Aramco’s recently set ambition to be net zero
on scope 1 and 2 emissions by 2050 could only have helped get this deal done. Other NOCs which have yet to set out
emissions reduction goals should take note.
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ConocoPhillips' 2022 budget and outlook
Dave Clark, 6 December 2021
The facts: ConocoPhillips announced its 2022 budget and outlook on Monday, following last week's close of the Shell Permian
asset deal. A 2022 capital plan of US$7.2 billion includes US$700 million of spending on the Shell assets, and US$200 million of
energy transition-related capital for Scope 1 and 2 emissions reductions and some early-stage new energies opportunities.
Expected 2022 production of 1.8 Mboe/d includes 200 kboe/d from the Shell assets, and represents “low single digits” growth
against pro forma 2021 volumes. COP also announced a base-case cash return plan of ~US$7 billion, including a new “variable
return of cash” payment (“VROC”), the first of which will be US$0.20/share payable on January 14.
Our take: Despite market turbulence in 2020 and early 2021, legal roadblocks in Alaska, and two major Permian acquisitions,
ConocoPhillips’ story of capital restraint, low cost of supply, returns and shareholder distributions has remained remarkably
consistent.
For the most part the 2022 outlook is in-line with expectations (~US$6.5 billion budget pre-Shell, ~3% long-term production
growth). One wrinkle in the announcement was the “three-tier” return of cash program, particularly the third-tier VROC, which
management had signaled they were considering, but which was by no means a certainty, given COP’s previous preference for
buybacks.
The VROC seems a nod to current market preference for actual cash return and reservations regarding the “curse of cyclicality”
inherent to buybacks. Unlike many other E&P variable dividends with clear “formulas” for pay-out, ConocoPhillips’ VROC
appears largely discretionary as part of its pledge to return >30% of operating cash flow to shareholders. The long-term
commitment appears to be to pay something (eight staggered quarterly payments per year, including the ordinary dividend), but
with flexibility to shift between share repurchases and the VROC.
For 2022, COP’s return of capital base case (likely built on ~US$60/bbl oil, though not explicit in the outlook release/slides) is for
US$1 billion VROC, complementing ~US$3.5 billion of buybacks (~US$1 billion funded by the sale of Cenovus shares), on top
of the US$2.4 billion base dividend. The ~US$7 billion total represents a ~7.3% cash return to shareholder yield.
Regarding the US$7.2 billion budget, there is an assumption of ~4% net impact from inflation (including some offset from
efficiencies) for the year. About 60% of that budget will flow to the Lower 48, and the other 40% to Alaska and international,
primarily Montney, Asia Pacific and Norway. That is roughly inline with the long-term plan laid out at the July 2021 Market
Update.
The US$200 million of energy transition spending is a positive in terms of transparency, but is light (~2.8% of capex, ~1.5% of
operating cash flow) relative to recent spending acceleration announced by the US majors (though well ahead of most US
E&Ps). A rising multi-year plan for energy transition capital allocation would be a sensible next step in the outlook evolution for
the company.
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handle a shock to markets in the next few years?
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spanning all aspects of Resilience and Sustainability, CoRSI rates corporate positioning in the face of uncertainty and risk. Our
inaugural report is available now: Benchmarking the Majors: Resilience and Sustainability
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Shell walks away from Cambo
Luke Parker, 3 December 2021
The facts: Shell has seemingly pulled out of the Cambo oil development, offshore West of Shetland UK. In a statement to the
media, Shell said that “After comprehensive screening of the proposed Cambo development, we have concluded the economic
case for investment in this project is not strong enough at this time, as well as having the potential for delays.” Shell held a 30%
non-operated stake in the asset. FID on a US$2.7 billon development had been imminent. Shell’s apparent exit leaves operator
Siccar Point as the sole participant.
Our take: The economic case for Cambo was marginal by Shell standards. Under the company's US$60/bbl (2020, real) Brent
planning assumption, our modelling implied an 18% development IRR. That’s bang on the upstream hurdle rate set by Shell at
its ‘Powering progress’ strategy day earlier this year. On balance, the risk is to the downside: Cambo would be the first field in
the UK developed in a water depth of more than 1,000 metres, with extreme conditions raising the likelihood of potential delays,
particularly with an inexperienced operator at the helm.
But Shell’s decision to walk away goes beyond economics. The PR case for Cambo was just as, if not more important. The
project faces strong opposition in the UK from politicians and the public, and Shell’s involvement was garnering a huge amount
of unwelcome attention.
The fact that this is not a disposal speaks to both truths. Walking away might suggest that Shell’s 30% stake is of marginal
economic value to anybody (except maybe Siccar Point). But it might also say something about the optics of selling the
‘problem’ to someone else. How the world has changed. Make no mistake – two or three years ago, Shell would not have
hesitated to green-light this project.
In context, Cambo is small beans to Shell. Since its February 2021 strategy day, the company has dramatically reshaped its
global development pipeline. It has sanctioned two projects – Whale (advantaged oil) and SK318 (LNG supply), and has exited
unconventional positions in the Duvernay (Canada) and the Permian (US). Walking away from Cambo – on the cusp of
materiality as well as commerciality – is no great wrench for Shell. Indeed, many stakeholders will welcome it as a progressive
move. Others, more invested in the broader UK oil and gas industry, will not.
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Shell Pre-FID portfolio: WoodMac modelling vs. Shell hurdle rates and expected average IRR
Source: Wood Mackenzie and Shell Strategy Day 2021. Lines reflect Shell guidance on IRR hurdle rates, IRR expectations and payback.
Bubbles are Wood Mackenzie analysis of Shell’s pre-FID projects (run under a US$60/bbl Brent assumption and assuming zero carbon tax);
bubble size is proportional to future development capex. Blue denotes Upstream; red denotes Integrated Gas.
ExxonMobil's corporate plan update
Tom Ellacott, 3 December 2021
The facts: New emissions reduction targets and a doubling in earnings and cash flow to 2027 were highlights in ExxonMobil’s
corporate plan update. Management placed a big emphasis on the flexibility to adjust the framework to market volatility
or changes in the pace of the energy transition.
The Supermajor extended its annual investment guidance of US$20 billion to US$25 billion out to 2027. Low carbon spend will
hit US$1.8 billion in 2023, rising to US$2.7 billion in 2025 and US$3.3 billion in 2027. The plan also included new emissions
reduction and financial guidance.
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Highlights from ExxonMobil's Corporate Plan Update
Our take: ExxonMobil put more meat on the bone in this strategic plan. It was a significant incremental update, rather than a big
reveal. The plan confirms that the company is still very much pursuing a Big Oil strategy – one that’s an attractive play on a
more gradual energy transition.
ExxonMobil has made only modest concessions to increasing stakeholder pressure to decarbonise. But it’s still early days for
the developing decarbonisation strategy. The rising low carbon budget underscores that ExxonMobil has big ambitions for its
Low Carbon Solutions business. The updated strategic plan is an opening salvo for bigger changes ahead.
The US$35/bbl cash flow breakeven guidance over the next six years is a confidence booster for the sustainability of
ExxonMobil’s dividend. It also points to a strong outlook for growing shareholder distributions. The company confirmed that
buybacks will begin in 2022, with up to US$10 billion of shares repurchased over 12 to 24 months.
We analyse the emissions reduction plans and how ExxonMobil can achieve a US$35/bbl cash flow breakeven in our Strategy
Update.
Petrobras unveils 2022-2026 strategy plan
Raphael Portela, 2 December 2021
The facts: Petrobras unveiled its latest five year strategy plan, covering ambitions for growth, capital allocation and
sustainability.
Our take: Petrobras’ new CEO Silva e Luna faced a lot of scepticism going into this strategy update. But the former Brazilian
army general turned CEO delivered on the stable message investors were looking for. The company has achieved its US$60
billion gross debt target a full year ahead of schedule, an amount 55% below 2014 levels. Petrobras will now focus on returning
US$60-70 billion to shareholders and investing in only the most resilient growth projects. For a detailed analysis, read our
recently published strategy update.
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Chevron increases buyback programme and releases 2022 capital budget
The facts: On Wednesday, Chevron released its 2022 capital budget and announced that it is increasing share buyback
guidance to US$3-5 billion per year, up from prior guidance of US$2-3 billion per year.
The company said it expects 2022 investment to be US$15 billion, up 20% from 2021 but still at the low end of its prior guidance
range of US$15 -17 billion. Upstream accounts for US$12.6 billion with US$3 billion going to the Permian (up from US$2 billion
this year) and US$1.5 billion for other shale and tight assets (most likely DJ Basin and Duvernay). US$1.5 billion is allocated to
exploration, early-stage development, midstream and carbon reduction opportunities.
Our take: The new buyback target does not come as a surprise – we’ve mentioned an increase was likely, given the amount of
cash Chevron is generating at current prices. At US$70/bbl Brent we model that Chevron generates more than US$10 billion
(post-dividend) of free cash flow in 2022, rising to US$17 billion by 2025. With gearing already below its target range, another
buyback raise is possible if high prices persist.
Chevron typically releases its annual budget in early December, but the timing of this release came slightly earlier than usual
and coincided with a strategy update from ExxonMobil. Chevron may have wanted to publish its 2022 budget before the
conclusion of the OPEC+ meeting last week – to reassure the group it’s staying disciplined.
A 50% increase in Permian spend was slightly higher than what we anticipated, even after accounting for delayed non-op capex
this year. The increase to US$3 billion could reflect greater inflationary pressures or more midstream spend. Either way, the
company seems well on track for 1.0 million boe/d by 2025.
The low carbon budget is US$800 million but US$600 million is allocated to the Bunge joint venture. Chevron will receive a
stake in Bunge’s soybean processing facilities in Louisiana and Illinois and the partnership will seek new growth opportunities in
other feedstocks.
The remaining $200 million allocated for the rest of low carbon investments may seem underwhelming after unveiling a US$10
billion new energies budget in September 2021. But the areas where Chevron is investing – hydrogen and CCUS - are longerdated options on the energy transition and won’t move the needle much in the near term.
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Lundin Energy rumoured to be considering a sale
Zoë Sutherland & Greg Roddick, 2 December 2021
The facts: Lundin Energy is rumoured to be reviewing its strategy and considering options, including a potential sale. The
company responded to press speculation by stating it does at times hold discussions with various parties, but no decisions have
been made in relation to any such discussions.
Our take: the speculation comes as a surprise and a deal, of any type, is still highly uncertain. Up until now, Lundin’s strategy
was clear. Continue producing oil & gas, but in a responsible way. It is the poster child for decarbonisation, well on track to meet
its net zero target (Scope 1&2) in 2023. But despite its impressive carbon credentials Lundin faces a longer-term challenge how to maintain scale into the late 2020s.
New projects and/or M&A will be needed and will require significant investment. This would have an impact on cashflow and
potentially future shareholder returns. Lundin’s portfolio is entirely focused on Norway, which limits the options for growth.
Stepping outside Norway could mean diluting the quality of its low-cost, low-carbon portfolio.
IOC’s with higher degrees of portfolio concentration and fewer options to mitigate the risks are also more vulnerable to the
mounting pressures of the energy transition. Lundin is a case in point. It can optimise its portfolio and double down on
decarbonisation, but longer term, it will need an exit strategy.
With the future of the sector looking increasingly uncertain, the Lundin family may see an opportunity to take advantage of
stronger commodity prices and its rising share price. But Lundin’s price tag could put off potential buyers. With an enterprise
value of US$11 billion, it is currently trading at a 75% premium to our base case valuation. On the flip side, it’s rating could
provide leverage if it decided to do an acquisition of its own.
Equinor exits Ireland
Norman Valentine, 1 December 2021
The facts: Equinor is selling its 36.5% stake in Corrib, Ireland’s only producing asset, to Vermilion Energy, the field operator for
a consideration of US$434 million, before closing adjustments. Vermilion has been a partner at the gas field since 2009, and
operator since 2018. Equinor has held a stake in Corrib since the mid-1990s.
This deal marks the end of Equinor’s time in Ireland, after also recently withdrawing from an early-stage offshore wind project.
The deal is expected to complete in H2 2022.
Our take: for Equinor, the sale marks another step in the high-grading of its international upstream portfolio. The stake in Corrib
was peripheral, accounting for 2% of international NPV10 according to our estimates.
With Ireland’s upstream sector offering no near-term growth, there was little scope for Equinor to grow its business in the
country, despite the potential of offshore wind. Equinor has chosen to concentrate on bigger investment opportunities
elsewhere. Refer to our corporate report for our views on the company's priorities.
BP planning green hydrogen project in the UK
Luke Parker, 29 November 2021
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Corporate week in brief
The facts: BP has announced plans to develop a new large-scale green hydrogen production facility – HyGreen Teesside – in
the North East of England. The proposed initial phase would see the development of 60MWe (megawatt electrical input) of
installed capacity. FID is expected in 2023. The suggestion is that multiple further phases could take total capacity to 500MWe.
Our take: HyGreen Teesside is the latest announcement in BP’s broader push to develop a low carbon industrial hub in the
region. BP is part of the Northern Endurance Partnership (NEP), alongside Eni, Equinor, Shell, Total and National Grid –
launched last year with ambitions to develop CO2 transport and storage infrastructure in the North Sea. NEP offshore
infrastructure will be utilised by two big CCUS projects – Net Zero Teesside (NZT; same partners) and Zero Carbon Humber.
At a potential capacity of 500 MWe, HyGreen Teesside represents the single largest project in BP’s green hydrogen pipeline.
The Major is also exploring potential projects at its refineries in Rotterdam in the Netherlands, Lingen in Germany and Castellon
in Spain. BP has big ambitions for growth in this space: it aims to have 10% of the clean hydrogen – green and blue – market by
2030.
Readers with access to WoodMac’s Corporate New Energies Service can learn more about the Majors’ emerging strategies and
portfolios in our positioning in new energy report and in our hydrogen benchmarking report.
Exploration success for Russians
Scott Walker, 26 November 2021
The facts: Rosneft has announced the largest discovery globally this year. Yermak Neftegaz – a JV between Rosneft (51%)
and BP (49%) – discovered the giant Zinichev onshore gas-condensate field in the Taimyr Peninsula, with estimated resource of
13.6 tcf. Elsewhere, compatriot LUKOIL made a discovery with its Yoti West exploration well on Block 12 offshore Mexico, which
contains oil initially in place of 250 mmbbl (LUKOIL operator 60%; Eni 40%).
Our take: with COP26 and Russia’s commitment to carbon neutrality only just in the rear-view mirror, Russia’s two largest oil
producers have shown that exploration is still front and centre. Both companies have been bullish on the need to sustain longterm supply, particularly in the face of the transition as exploration is de-emphasised among many of its peers.
How the Zinichev discovery sits with BP is less clear. In May this year the Major relinquished its 49% stake in two East Siberian
exploration blocks held under its Yermak Neftegaz JV. And while gas weighted, a massive greenfield development doesn’t
square with its strategy. Commerciality will also be challenging. Significant investment will be required for infrastructure build-out
to connect the gas, which will then have a saturated gas market and a Gazprom monopoly to contend with.
LUKOIL faces similar challenges in monetising its discovery. We estimate recoverable reserves of around 75 mmbbl – ideal for
a short-cycle opportunity, but with no near-field infrastructure we view a standalone development as sub-commercial. A cluster
development appears the most likely route to monetisation. Eni announced two similar sized discoveries this year on the nearby
Block 10 (LUKOIL 20% partner). Combined, we estimate the three fields hold approximately 280 mmbbl of recoverable
reserves. LUKOIL is planning to drill the Otomi West prospect on Block 12 in 2022. Further success will bring it closer to critical
mass.
ExxonMobil sets its sights on scaling up sustainable algae biofuels
production
Tom Ellacott, 25 November 2021
The facts: ExxonMobil has signed a joint agreement with Viridos, a privately-held biotechnology company. The partnership will
aim to commercially scale-up Viridos’ sustainable algae biofuels technology.
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Our take: this could be a precursor to a much bigger commitment to biofuels. ExxonMobil announced a US$15 billion low
carbon budget for 2022 to 2027 in its Q3 results. We’d expect low carbon fuels to feature prominently in the investment mix
given that ExxonMobil is the most exposed Major to downstream.
Recent advances in the productivity of Viridos’ technology could pave the way for commercial deployment to convert CO2 into
renewable diesel and sustainable aviation fuel. Commercial scale-up would fit nicely with ExxonMobil’s focus on technology-led
opportunities and help to decarbonise the heavy-duty transportation, aviation and maritime shipping sectors.
ExxonMobil may provide more details on 1 December, when it releases details of its capital plans to 2027 and upgraded
emissions reduction goals.
Eni names retail and renewables business "Plenitude" ahead of 2022 IPO
Greig Aitken, 25 November 2021
The facts: Eni held a Retail and Renewables capital markets day to shed light on the business ahead of a planned IPO next
year. The entity’s new name was revealed as Plenitude. Plenitude incorporates gas and power retail, renewables generation
and e-mobility. Eni intends to list a minority stake in Plenitude and will continue to report the subsidiary on a consolidated basis.
Eni intends Plenitude to be debt free at the start of next year and believes that cash flows from the retail business can be
leveraged to fund renewable and e-mobility growth. Eni is targeting Plenitude’s EBITDA to more than double from €0.6 billion in
2021 to €1.5 billion in 2025.
Our take: the session provided additional detail and clarity over Plenitude’s operations and strategy, though key targets and
ambitions appear in-line with existing plans.
Eni has previously promoted the merits of an integrated generation-to-retail value chain. But Plenitude clarified that it won’t
necessarily pursue this strategy beyond southern Europe, where its customers are concentrated. It views certain renewables
markets, such as the US and UK, as being attractive in their own right, due to a combination of government support, mature
markets, well-developed grids and reliable supply chains. Being able to leverage competitive advantages, such as the large
project management skills needed for offshore wind, is another draw.
The acquisition of Be Power (which completed earlier this month) makes Plenitude the second-largest Italian electric vehicle
charge point operator with 6,500 points. It intends to reach 27,000 points by 2025. Charge point stats were interesting –
Plenitude says each charge point breaks even within three years with a utilisation of 1.5 hours per day. It is expecting usage to
reach at least three hours per day by 2025.
We looked at the merits of restructuring in Should the Majors spin off new energy? and believe that listing a minority stake offers
a number of benefits over other potential structures. Plenitude will have a clear mandate and an autonomous balance sheet,
which it can fund with an appropriate cost of capital. Eni benefits from retaining majority exposure to the business and will gain a
see-through valuation on the subsidiary.
ConocoPhillips and TotalEnergies acquire Hess' stake in Libya's Waha
concessions
Martijn Murphy and Toushar Chakrabarty, 24 November 2021
The facts: ConocoPhillips and TotalEnergies have jointly acquired Hess Corporation’s 8.16% interest in the Waha concessions
in Eastern Libya. Upon completion, TotalEnergies and ConocoPhillips will each increase their equity holding to 20.41%. Hess
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will finally exit Waha. Conclusion and ratification of the deal are outstanding and not expected prior to elections scheduled for 24
December.
As part of the deal, the Waha partners will invest US$2 billion in North Gialo, Waha's largest undeveloped field, as well as
utilising gas which is currently flared.
Separately, TotalEnergies also signed an MoU with Libya’s electricity company to develop solar projects with a capacity of 500
MW to supply the national grid.
Our take: Hess will exit another non-core country through this deal, freeing up capital for deleveraging and providing more
flexibility to double down on its flagship Stabroek development in Guyana.
ConocoPhillips and TotalEnergies will increase their exposure to a low-cost asset with potentially huge upside. The French
Major also continues a trend of upstream business development linked to renewables opportunities in non-OECD countries. The
move will add a new country to a solar portfolio that is already the most diverse in the peer group.
For further details see our Inform.
Woodside green lights Scarborough LNG
Andrew Harwood, 22 November 2021
The facts: Woodside has taken a final investment decision on the US$12 billion Scarborough and Pluto Train 2 project, making
it the 4th largest upstream FID in 2021, and the largest LNG investment in Australia in a decade. The 11.1 tcf Scarborough field
will be developed via an expanded Pluto LNG facility; first LNG is scheduled for 2026.
Our take: project sanction, announced alongside confirmation of its merger with BHP's oil and gas business, caps a
rollercoaster year for the Woodside. CEO Meg O'Neill, less than six months into the job, has moved swiftly to secure
Woodside's future. Indeed, it is the merger with BHP that provides a stronger financial platform for Woodside to proceed with the
Scarborough and Pluto Train 2 investment.
Despite environmental opposition, Scarborough and Pluto Train 2 will be one of the lowest emission LNG plants in Australia. If
construction costs are kept in check, the project can compete against other new sources of LNG supply. Woodside has also
locked in a long-term source of LNG cash flows that will support net zero targets.
Read our insight for more of our take on why this project makes sense, but also why it might be the last major LNG investment
in Australia.
COP26 turns up the heat on corporates
Kavita Jadhav, Akif Chaudhry, 18 November 2021
The facts: At the end of COP26, nearly 200 countries signed the Glasgow Climate Pact, building on the 2015 Paris Agreement.
It marked another important step in the world’s efforts to get on a 1.5 °C glidepath, but the scale of the challenge remains huge.
We are currently headed for 2.5 °C to 2.7 °C of warming, and much work needs to be done, as quickly as possible. Notably, the
pact calls on countries to return one year from now with more ambitious commitments on 2030 emissions.
WoodMac has already published initial thoughts on COP26 key takeaways and implications for energy and natural resources.
Here we focus on the corporate perspective.
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Our take: Glasgow was the COP at which the fossil fuel industry really started to feel the heat. If there was any lingering doubt
on the need to accelerate the low-carbon pivot, that should be banished after Glasgow. The writing is on the wall.
Coal is first in the firing line – more than 40 countries have pledged to “phase down” coal-fired power generation over the next
few decades. But there was progress on oil and gas too – Glasgow delivered tangible outcomes with real world implications. We
highlight three key areas:
(i) Resolution of Article 6 – the framework for emissions trading
Agreement on Article 6 is a key step for companies to develop a carbon business stream. Meaningful carbon prices will support
commercialisation and scale of areas such as CCS that present a viable option for oil and gas companies to roll out a
sustainable decarbonisation strategy.
Currently, projected capacity in CCS is around 400 million tonnes per year. But Woodmac estimates this needs to expand to
nearly four billion tonnes per year of capacity even to hit a two-degree target. That would present a significant investible market
to oil and gas companies.
(ii) Glasgow Financial Alliance for Net Zero (GFANZ) membership soars
COP26 also delivered a jump in private capital committed to net zero that will further intensify investor pressure on oil and gas
companies. Asset owners, managers, lenders and underwriters responsible for assets of over US$130 trillion have joined
the Glasgow Financial Alliance for Net Zero. Members, and their portfolio companies, must set science-based near-term and
2050 decarbonisation targets, release supporting plans and report progress annually.
Glasgow Financial Alliance for Net Zero* to finance the energy transition
Source: Wood Mackenzie Corporate Service, GFANZ. *Includes UN-convened Net-Zero Banking Alliance, Net-Zero Asset Owner Alliance, the
Net Zero Asset Managers initiative, and the Paris Aligned Investment Initiative. Also, includes Net Zero Financial Service Providers Alliance and
the Net Zero Investment Consultants Initiative.
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(iii) Significant steps towards standardised disclosures
At COP26, IFRS Foundation announced the formation of the International Sustainability Standards Board to develop globally
consistent climate disclosure standards for corporates. Investors, and other stakeholders, have long called for more
comprehensive and consistent reporting of climate related risks. The implementation of such standards – a matter of when, not
if – will support deeper scrutiny and, in turn, add to pressure on oil and gas companies. COP26 moved that day a step closer.
You can also read our COP26 Briefing and Insight – published ahead of the conference – for more detail on these topics and
more.
Euro Majors and utilities look to floating offshore wind
Norman Valentine, 19 November 2021
The facts: in South Korea, Equinor has signed a memorandum of understanding with Korean East-West Power (EWP) to
cooperate on 3 GW of offshore wind projects. In Ireland, Shell has agreed to acquire 51% of the Western Star floating wind
project from Simply Blue Group. The partners will seek to develop up to 1.35 GW of capacity in a phased development. The
deal adds to the two companies existing offshore floating wind partnership at the Emerald project, also in Ireland.
Our take: these agreements mark further positioning by the European oil Majors for growth in floating wind. More and more
partnerships are being formed as companies build exposure to the sector, prepare for government tenders and look to share the
risks and the costs of scaling-up new technology.
Other companies also see a growth opportunity. Utilities RWE and SSE highlighted floating wind’s potential in strategy updates
last week as part of upgrades to their renewables growth ambitions. RWE, one of the leaders in fixed offshore wind, will target 1
GW of floating capacity by the end of the decade. It’s part of its plan to triple installed offshore wind capacity to 8 GW by 2030
and its wider renewables capacity to 50 GW over the same period. SSE also plans to treble its net renewables capacity over the
next ten years to exceed 13 GW by 2031.
TotalEnergies and Apache deliver mixed E&A results in Suriname
Tom Ellacott, 19 November 2021
The Facts: TotalEnergies’ 50:50 joint venture with Apache has made a non-commercial discovery with the Bonbini-1 exploration
well on Block 58, offshore Suriname. The JV had more positive news from the Sapakara South-1 appraisal well, which
encountered 30 meters of net oil pay in a good quality Campano-Maastrichtian reservoir. In other news, Tullow Oil announced
that it is exiting Suriname, relinquishing Blocks 47 and 54 following disappointing drilling results over the past few years.
Our take: the successful appraisal of Sapakara West proves up connected resource of 325 to 375 million barrels of oil in place
on the field. Using Lens Subsurface, Wood Mackenzie estimates around 80-95 mmboe of recoverable oil assuming a 25%
recovery factor.
TotalEnergies and Apache will now focus on the Krabdagu exploration prospect, located 18 km east of Sapakra South-1. An oil
strike could pave the way for a development hub to accommodate production from Krabdagu, Sapakara and Keskesi.
Bonboni-1 was the first exploration well in the northern portion of Block 58, around 45 km from the Maka Central, Kwaskwasi
and Sapakara West discoveries. The well result comes as little surprise given a lack of exploration success off the NW-SE
Guyana-Suriname trend. The disappointing results from the six wells drilled to date will no doubt have influenced Tullow Oil’s
decision to exit the country.
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ExxonMobil boosts GOM shelf acreage in a potential CCS-linked move
Rachel Schelble and Tom Ellacott, 18 November 2021
The Facts: ExxonMobil made a statement this week as the sole bidder for 94 shallow water Gulf of Mexico lease blocks. The
move is likely linked to the company’s ambitious CCS plans in the Gulf Coast area given the abundance of depleted reservoirs
on the shelf.
Our Take: ExxonMobil shared its intentions to build a scale-leading US$100 billion carbon capture and storage hub in the
Houston area earlier in 2021. The addition of 541,440 acres of shallow water offshore blocks could expand the company’s
carbon storage potential to help advance the proposed CCS hub.
The move follows ExxonMobil’s announcements to expand carbon capture and storage at its Labarge Facility in Wyoming, and
its commitment to invest US$15 billion in low carbon projects over the next six years. ExxonMobil is also working to advance
potential CCS hubs in Scotland, France, Belgium and the Netherlands and has been actively positioning itself for new
opportunities in the Asia Pacific region.
ExxonMobil has the deepest CCS pipeline in the sector. But it still faces the challenge of commercialising these opportunities to
cement its leadership in CCS. Collaboration, subsurface expertise and project management will be key success factors in
executing the carbon capture strategy.
Cairn begins share buyback
Scott Walker, 16 November 2021
Facts: Cairn Energy – soon to be renamed Capricorn Energy – is initiating a US$20 million share buyback programme. The
programme is Cairn’s first step towards returning US$700 million to shareholders after the successful conclusion of its Indian tax
dispute, which will see the company refunded around US$1 billion. On receipt of the proceeds, Cairn intends to return US$500
million to shareholders by way of a special dividend and will increase its buyback programme to US$200 million. It comes after
Cairn paid a special dividend of US$250 million in January this year, following the sale of its Senegal assets to Woodside in
2020.
Our take: With operating cash flow averaging only US$60 million annually out to 2025, it’s a significant distribution for Cairn
shareholders. In contrast to many of its peers – the other eight International Midcaps in our coverage have combined net debt of
US$32 billion and a weighted average gearing ratio of 65% – Cairn is in the enviable position of having zero debt on its balance
sheet, allowing it to prioritise shareholder returns over deleveraging. The next step is implementing a permanent dividend. To
support this, the remainder of its tax refund will be growth focused, with the company looking to build on its production base in
Egypt through acquisitions.
Woodside brings GIP aboard Pluto Train 2
Andrew Harwood, 15 November 2021
What’s happened: Woodside has sold a 49% non-operated stake in Pluto Train 2 to Global Infrastructure Partners (GIP).
Australian LNG is in focus – this is the US investment fund’s third deal over the last 12 months, having taken infrastructure
positions in QCLNG and GLNG.
GIP will fund its share of capital expenditure of the 5 mmtpa Pluto Train 2 project, equivalent to US$2.7 billion of the total
US$5.6 billion cost. In addition, by way of consideration, GIP will meet US$835 million of Woodside’s share of capital costs. But
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the terms of the deal protect GIP from key project risks – cost overruns (Woodside will fund up to US$835 million of GIP’s 49%
share of any overrun), schedule overruns, unforeseen emissions liabilities and regulatory barriers.
Our take: GIP gains access to a new, long-life source of steady returns, while limiting its exposure to the downside risks
associated with big LNG developments. That exposure stays with Woodside – the concession needed to entice an infrastructure
buyer into an unconstructed LNG plant and move the project forward. The Scarborough/Pluto Train 2 development is now a step
closer. Greater financial flexibility should allow Woodside to progress towards final investment decision with confidence. Look
out for an announcement before the end of the year.
Read our inform for more details of the transaction and the implications for buyer and seller.
Aker and BP sell 5% in Aker BP through private placement
Neivan Boroujerdi, 12 November 2021
The facts: the sale has been split in proportion with the sellers’ current holdings. Aker and BP will now hold 37.1% and 27.9% of
the company respectively, down from 40% and 30 % previously. The free float (Oslo stock exchange) increases to 35%. Based
on Aker BP’s share price as of 11 November, the sale will bring in proceeds of around US$640 million.
Our take: the timing is good from a valuation perspective: Aker BP shares are trading at historic highs, valuing the company at
more than double our base case NPV10 at US$50/bbl – one of the highest premiums in our corporate coverage. Peer-leading
ESG and growth metrics – combined with the recent price rally – have all played their part.
BP didn’t really need the cash. Having hit its net debt target in Q1, a year ahead of schedule, the company was well placed to
deliver on committed shareholder distributions. Still, the placement serves as a timely reminder of just how successful its
Norwegian spin off has been, at a moment when BP is looking at similar moves in Angola and Iraq. While the Major has no
immediate plans to sell its remaining stake in Aker BP – both parties’ remaining shares are locked in for six months – this
exercise will provide useful insight into the potential for a larger move further down the line.
Aker was perhaps more motivated. With Aker BP having climbed to reach 50% of Aker’s gross asset value, this monetisation
served to rebalance the portfolio and free up liquidity. The proceeds will be used to continue its expansion into new areas,
having spun off its Offshore Wind and Carbon Capture vehicles last year.
Tullow increases Ghana interest
Scott Walker, 12 November 2021
The facts: Tullow has exercised its pre-emption rights over a portion of Occidental’s US$550 million asset sale to Kosmos in
Ghana. Tullow has opted to acquire its full entitlement of the 11.05% interest transferred to Kosmos in the DWT Block, which will
give it a 7.7% stake for around US$143 million. PetroSA has also taken up its pre-emption rights and will increase its interest by
0.6%. The portion of the deal related to the WCTP Block is not included in the pre-emption.
Our take: we saw this as an attractive deal for Kosmos – breaking even at US$45/bbl Brent – and it’s proved too good an
opportunity for Tullow to pass up, despite recent financial constraints. Tullow has been pulling on all available levers to stabilise
its finances, with asset divestitures and debt refinancing improving the short-term outlook.
Gearing is still high at 108%, and has not been helped by underperformance in Ghana; but infill drilling programmes and
ongoing work to solve gas handling limitations have put the assets in a position to deliver strong cash flow. Showing resilience in
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our low case and strong upside in our high case, Tullow will look to harness the assets’ revived operational performance to
progress debt reduction.
ExxonMobil sanctions Chinese petrochemicals investment
Tom Ellacott, 12 November 2021
The facts: ExxonMobil has taken the final investment decision on a multi-billion-dollar chemical complex in the Dayawan
Petrochemical Industrial Park in Guangdong Province, China. The project includes the construction of a 1.6 mmtpa stream
cracker.
The facility will manufacture performance chemical products for packaging, hygiene, automotive and agricultural industries.
Our take: petrochemical projects form part of ExxonMobil’s strategy of concentrating near-term investment on advantaged
assets. The company estimates that it will make a 30% return on its future chemicals and downstream projects, delivering US$4
billion of annual earnings potential.
The Dayawan facility will be one of the few wholly internationally-owned complexes in China and the first from a Major.
ExxonMobil is also finalising a JV project with SABIC in the US.
ExxonMobil’s ethylene EBITDA peaks at US$7.0 billion in 2030 in our analysis, up from US$2.5 billion in 2020. New projects are
a core driver, with the company targeting 60% growth in high-value performance products by 2027. ExxonMobil’s large US
ethylene footprint and the increasing advantage of US ethane through 2030 will also drive earnings alongside capacity growth.
Sinopec chooses hydrogen to decarbonise transport
Kavita Jadhav, 12 November 2021
The facts: Sinopec shared its growth plans for hydrogen-powered fuel cell electric vehicles (FCEVs) to be cost competitive with
ICE vehicles by 2030. The company plans to overcome the challenge of high costs of FCEVs by increasing production of
hydrogen, establishing a hydrogen refueling network and cooperating with automobile manufacturers to lower cost. FCEVs are
to play a crucial role in decarbonizing China's transportation sector with the attraction of higher energy efficiency than
conventional ICE vehicles, and no exhaust emissions except for water vapors.
Our take: most of Sinopec's hydrogen production is grey and blue hydrogen produced from fossil fuels. It is initially leveraging
hydrogen from its refineries by retrofitting hydrogen purifying units to produce hydrogen fuel.
Sinopec also plans to invest US$4.6 billion in hydrogen through 2021-2025, aiming to boost green hydrogen production capacity
to 1mn t/yr by 2025. It has teamed up with solar manufacturer Longi Green Energy Technology to develop green hydrogen
projects. Sinopec currently has four green hydrogen projects in the pipeline with a capacity of 140,000 t/year, which will have to
increase tenfold by 2025. Wood Mackenzie estimates that green hydrogen will be competitive with fossil fuel hydrogen in
several markets by 2028 to 2033.
Sinopec will integrate hydrogen fuel provision at its domestic transportation fuel sale network with over 30,000 stations to
become China's top hydrogen supplier. It has equipped 31 stations with hydrogen refilling capacities and plans to build 1,000
hydrogen refilling stations by 2025. Sinopec has entered agreements with automotive manufacturer Great Wall Holdings to
explore the feasibility and demonstration of hydrogen fuel cell powered vehicles that will help decarbonise the transportation
sector.
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TotalEnergies and Daimler Truck ink decarbonisation agreement
Tom Ellacott, 12 November 2021
The facts: TotalEnergies and Daimler Truck AG have signed an agreement to develop a hydrogen ecosystem for road freight in
the EU. The intent is to demonstrate the attractiveness and effectiveness of powering heavy-duty trucks by clean hydrogen and
play a lead role in kickstarting the rollout of hydrogen infrastructure for transportation.
TotalEnergies is aiming to operate 150 hydrogen refuelling stations in Germany, the Netherlands, Belgium, Luxemburg and
France by 2030. Under the agreement, Daimler Truck will supply hydrogen-powered fuel-cell trucks to its customers by 2025.
Our take: this latest move is another example of TotalEnergies’ diverse approach to building a broad energy company. We
outline how, in hydrogen alone, the company is evaluating all aspects of the hydrogen value chain in our TotalEnergies
corporate new energy profile.
Partnerships and collaboration are playing a key role in executing the new energy strategy and enabling opportunities. A key
objective in this latest agreement will be to drive down the total cost of ownership of hydrogen truck operations to support its
commercial scale up.
US EPA methane regulation proposal
Ryan Duman, Dave Clark & Anuj Goyal, 12 November 2021
The facts: While the likely outcomes from COP26 appear to be a mixed bag, one of the clear steps forward from an energy
transition perspective was the pledge from over one hundred nations to reduce methane emissions by 30% by 2030. The US is
a signatory to the pledge, and the announcement was preceded by a sweeping set of proposed methane regulations by US
EPA.
Our take: The proposed EPA rules include enhanced detection and repair requirements, venting limitations and strict emissions
standards for upstream operations. Most notably the regulations include existing emissions sources – both new and existing
wells. Previous methane regulations had focused on new infrastructure. If finalized, the rules would likely go into effect in 2023,
and would target an absolute methane emissions reduction of 74% from 2005 levels by 2035.
The good news is that most operators are already actively working on methane emissions, and the rules may have little impact
on proactive companies by the time they take effect. For example, EOG has cut methane emissions by 80% since 2017, and
has targeted 0.06% methane emission intensity by 2025. Gas-focused operators like Comstock, Southwestern, and Antero
lead the pack among US operators, with an average methane intensity of just 0.053%.
While operators would undoubtedly incur a cost due to these rules, fixing methane leaks is not always cost-prohibitive,
especially for newer wells. Our estimates range between 5 and 15 cents per mcf for an operator to install monitoring devices
and repair most methane leaks. The increase in gas capture can often offset those costs, but the preference will be to focus on
newer, higher volume wells and pads.
These proposed rules may serve as a wake-up call for those not aggressively cutting methane emissions, such as Matador,
who had a methane intensity increase in 2020, rising from 0.58% in 2019 to 0.71%. The EPA’s well monitoring proposal applies
only to sites emitting an estimated three tons of methane per year or more, which will exclude some smaller sites. Still, an
estimated 300,000 well sites will need to be monitored, and that could be a tall order for some operators. For example,
Chevron, ExxonMobil, and Occidental have more than 25,000 wells alone in the Permian, averaging less than 15 bbl/d in Q1
2021. The additional costs could be greater on a per-barrel basis than newer production sources, and be significant enough to
render some of the many low-producing wells uneconomic.
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Repsol sells down its first operational onshore wind project
Tom Ellacott, 11 November 2021
The facts: Repsol has announced the sale of a 49% stake in its 335 MW Delta onshore wind farm to investment firm
Pontegadea. The company will pay a consideration of €245 million for the acquisition.
Our take: Repsol has achieved a rapid monetisation of its first operational onshore wind project in Spain. The company brought
Delta online in March 2021, having only acquired the asset in June 2019.
Repsol outlined that it expects to achieve a 9% IRR before asset rotation at its Low Carbon Day. This transaction should lock in
double-digit returns. The transaction also provides a positive valuation marker for Repsol’s renewable power business. The
implied €500 million valuation ranks Delta just outside the company’s top ten upstream assets by value.
The unit consideration of €1.5 million/MW highlights the value potential from derisking a deep renewables pipeline. Repsol has
1.7 GW of operational renewable power capacity and a further 4.1 GW under construction or attributed to projects with high
visibility. The total pipeline amounts to 49 GW including advanced development and early-stage projects.
YPF and Ecopetrol unveil upbeat results
Raphael Portela, 10 November 2021
The facts: YPF and Ecopetrol reported positive quarterly results on most fronts this Wednesday. Production grew 7% quarteron-quarter for the Argentinian NOC and 3% for Ecopetrol. Both recorded an uptick in gas production and commented on a
robust increase in domestic fuel demand.
Financial metrics also surprised to the upside. YPF recorded its first positive net income since the pandemic. Ecopetrol
registered its highest net income this decade. Both companies hinted at upgrading their capital budgets in the coming year.
Our take: Ecopetrol emerged from the pandemic on a solid footing. The transmission company ISA is now fully integrated into
the business and contributed marginally to the results – only one month of its operations was included in Q3. Absorbing the
business will be a drawn-out process, but Ecopetrol will use the integration to help it inform investment decisions outside O&G
and in different geographies.
YPF remains on its path towards recovery. Despite challenges, optimism has returned. The company is back at its optimal
leverage levels and will route gains in operating cash flow back into capex, likely not pursuing further deleveraging. Rumours
suggest the 2022 spend could be >25% higher versus 2021.
Going forward, some risks remain on the table. For both companies, cost inflation is creeping higher. YPF cut its cost-savings
target from 20% to 15%. Ecopetrol saw lifting costs inch back up to US$8.5/bbl in Q3 versus an average US$7.5/bbl in 2020.
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Australia CCS activity building as Santos, Woodside unveil plans
Andrew Harwood, 8 November 2021
The facts: In the same week as COP26, Santos and Woodside announced their first steps on the 'Australian Way', Australia's
plan to achieve net zero emissions by 2050. With a focus on technology, carbon capture and storage (CCS) and hydrogen will
form a key part of Australia's plans to fight climate change while maintaining the viability of its natural resources sector.
Santos has taken final investment decision on the 1.7 mmtpa Moomba CCS project in Australia's Cooper Basin. Woodside
announced, in partnership with BP, Mitsubishi Corporation and Mitsui, plans to conduct feasibility studies into a large-scale CCS
project near Karratha, Western Australia, the location of the NWS LNG facility.
Our take: Moomba CCS, by our metrics the 3rd largest dedicated CCS project in the world, is central to Santos' plans to reduce
emissions by 26-30% by 2030, and to reach Scope 1&2 net zero emissions by 2040. The project is one of the lowest cost CCS
projects in our analysis, harnessing its onshore location and existing processing infrastructure to deliver a full-lifecycle of less
than US$24/tonne. First injection is scheduled for 2024.
Woodside, having earlier announced a US$750 million project to build a hydrogen and ammonia production hub in Kwinana,
Western Australia, is now ramping up its efforts in CCS. Although at an earlier stage than Santos' Moomba project, Woodside's
Karratha plans could provide a multi-industry capture and storage solution, and could facilitiate the development of other lowcarbon industries, such as hydrogen or ammonia production.
In the same week, ExxonMobil and PERTAMINA announced plans to cooperate on research into potential sites for underground
carbon storage, as well as transportation technology. The rapid development of Australia's regulatory framework and policy
support for CCS has allowed it to steal a march on the competition in Asia Pacific. Other governments in Asia Pacific will now
have to play catch-up if they too are to attract decarbonisation dollars.
US independents Q3 results recap
Dave Clark & Robert Polk, 5 November 2021
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The facts: We reviewed Q3 earnings for 33 US independents to gauge sector performance in terms of cash generation, capital
discipline, deleveraging, shareholder returns, and preliminary thoughts for 2022. The peer group includes 23 oil-focused and 10
gas-focused names.
Our take: The group reported US$4.1 billion in aggregate earnings. Oil-focused companies earned US$9.0 billion, while gasfocused names lost -US$4.9 billion. ConocoPhillips, Occidental, EOG and Pioneer all topped US$1 billion in earnings. The
bifurcated result was largely driven by massive hedging losses for the gas names (-US$9.2 billion vs. -US$5.8 billion in Q2).
Overall hedging losses were -US$13.1 billion, including -US$5.0 billion of cash settlements.
Hedges limited cash flow for the gas producers. Aggregate OCF (ex-working capital) of US$1.9 billion fell from US$2.2
billion in Q2 despite average NYMEX gas increasing from US$2.94/mmbtu to US$4.36/mmbtu. For the oil-focused group, OCF
rose sequentially from US$18.7 billion to US$21.1 billion, as average WTI climbed from US$66/bbl to US$71/bbl.
For the second straight quarter, net debt reduction (-US$8.6 billion) exceeded capex (US$8.0 billion) for oil peers. Net debt
rose for the gassy names, due in part to assumed debt from private company acquisitions, but hedging hindered organic
deleveraging. The sector has reduced net and absolute debt by US$18 billion and US$11 billion respectively year-to-date.
Collective gearing improved to 37% from 39% last quarter and 44% at the start of the year. The best balance sheets are
arguably moving towards sub-optimal leverage (EOG now at 3.6% gearing, PXD will be ~11% post Delaware sale), though
those companies argue for near-zero leverage.
Discipline remains strong with several companies beating spend guidance and lowering full-year expectations. Continental was
notable in pulling some capex forward into Q4. US E&Ps reinvested just 42% of operating cash flow (38% for the oilfocused group). Expect that number to go even lower in Q4 given an average WTI over US$80/bbl so far in Q4.
Return of capital to shareholders jumped to US$4.2 billion ($2.6 billion via dividends and US$1.6 billion through buybacks), up
from US$2.2 billion and US$2.7 billion in the first two quarters. Oil producers were responsible for all but US$300 million of the
US$9.1 billion year to date total. Eleven companies increased base dividends, many of them for the second or third time this
year. Notably, EOG increased 82% to US$3/share per year.
Higher variable and special dividends payable in Q4 reflect robust Q3 free cash flow. Pioneer, Devon, and EOG delivered the
largest variable/specials. ConocoPhillips is most active on buybacks with US$1.2 billion in Q3 and US$2.2 billion year-to-date.
Several companies announced new or expanded buyback authorizations.
ESG messaging had been trending forward in earnings decks and prepared commentary, but those topics took a back seat to
shareholder returns this quarter across the group.
Shell Ventures announces US$1.4 billion fund for investment in transition
Luke Parker, 5 November 2021
Shell has created a dedicated US$1.4 billion fund for Shell Ventures to invest, over the next six years, in companies focussed
on accelerating energy transition. The money will support start-ups and scale-ups involved in renewable energy, storage and
utilization, mobility, transportation and logistics, circular economy, and nature-based solutions. While this isn’t a new thing for
Shell, it marks a step-up in the quantum and pace of investment.
Shell Ventures was established in 1996 (one of the first corporate venture funds in the oil and gas industry) and currently has
around 80 companies in its portfolio. Details are generally not made public, but at an average of US$15-$22 million of
investment per company (Shell numbers), Shell Ventures has invested around US$1.6 billion to date. The portfolio includes grid
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edge companies (GI Energy, Axiom Energy and Sonnen); energy storage solutions (Corvus Energy, Geli, LO3 Energy), off-grid
utilities (Husk, PowerGen), customer data analytics (innowatts, SteamaCo), solar energy financing (Sunfunder) and a series of
investments in fuels and mobility.
CNRL, Cenovus and Suncor deleveraging
Scott Norlin, 5 November 2021
The facts: the oil sands are deleveraging in a major way. CNRL has outlined its free cash flow (FCF) allocation policy. Once an
absolute debt target of Cdn$15 billion is achieved, FCF will be split 50% between share repurchases and additional debt
reductions. This target is expected to be met in Q4 2021. Cenovus has a near term debt target of Cdn$10 billion, and exited Q3
at Cdn$11 billion. Once this target is met, further FCF will be allocated towards shareholder return and pursuing a long-term
debt target of Cdn$8 billion. Suncor has a similar debt target as CNRL, aiming for absolute debt to be between Cdn$12-$15
billion by 2025. It expects to achieve the Cdn$15 billion target by the end of 2021. The company is on track to exceed its debt
and share repurchase targets for 2021.
Our take: what a difference a year makes. CNRL, Cenovus and Suncor were all forced to raise debt levels at the height of the
pandemic induced price crash and exited 2020 with a combined Cdn$53 billion (US$41 billion) in net debt. Since the beginning
of 2021, these three companies have paid down a total of Cdn$10.4 billion (US$8.3 billion) in debt and are expecting to exceed
debt targets that were set out earlier in the year.
Oil sands debt reduction
Source: Wood Mackenzie
With debt targets well within reach, the allotment of FCF is now being divided between shareholders and the business. All three
operators are focused on shareholder return. Suncor and Cenovus raised dividends in Q3. CNRL maintained its dividend during
the height of the pandemic. Overall, these oil sands weighted operators are in positions of financial strength with momentum to
further their debt targets or reinvest in their business. Given that all three operators are in the Pathways Initiative, some FCF
should be earmarked for R&D of emissions reduction technology and commercial implementation of successful pilots. Step one
of getting balance sheet health in order is now midway complete.
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Eni buys another stake in UK offshore wind farm from Equinor and SSE
Greig Aitken, 5 November 2021
The facts: Eni has bought a 20% stake in Dogger Bank C, the third phase of the UK’s largest offshore wind farm. Eni will pay
Equinor and SSE £70 million each (US$94 million) for a 10% stake. The deal will net Eni 240 MW of capacity when the project is
complete.
In December last year, Eni agreed a deal to pay the same sellers £405 million (US$540 million) for a 20% interest in Dogger
Bank A and B (480 MW net to Eni). All three partners are now aligned across all three phases (SSE Renewables, 40%; Equinor,
40%; Eni 20%). Phases A and B reached financial close earlier this year, Phase C is expected to reach financial close by the
end of this year.
Our take: Eni continues to accelerate growth of its renewables generation pipeline ahead of a planned IPO next year of its
integrated Gas & Power Retail and Renewables business. In Q2, Eni increased near-term capacity targets by 1 GW following a
series of wind and solar additions in Europe. It aims to develop more than 6 GW of installed capacity by 2025. As at the end Q3,
Eni had 834 MW of installed capacity. It expects this number to reach 1.2 GW by year end, with a further ~0.8 GW under
construction.
For Equinor, this is another monetisation of its early stage offshore wind portfolio. Asset rotation and sell-downs are part of the
company’s strategy to enhance returns from renewables.
ExxonMobil exits Romania
Tom Ellacott, 4 November 2021
The facts: ExxonMobil finally has a deal to exit Romania, selling its 50% operated stake in the pre-FID Neptun Deep gas project
to state-backed Romgaz. Commercial terms have not yet been disclosed. The transaction is expected to complete in Q1 2022.
Our take: we currently classify Neptun Deep’s multi-tcf gas fields as contingent resources and value a 50% stake (unrisked) at
US$643 million (NPV10 at January 2022).
ExxonMobil’s exit from Romania has been on the cards ever since fiscal and regulatory instability prevented Neptun Deep FID
in 2018. The sale is another small step in a US$15 billion global asset sales programme that has yet to gather momentum. But
that could be changing.
ExxonMobil hinted in its Q3 results that it expects rationalisation to increase. The company is already seeing a buyer response
that is more consistent with its pricing expectations. Closing the bid-ask spread will pave the way for more asset sales since this
has, so far, been the main barrier in closing transactions to streamline the portfolio. Potential asset sales candidates include
Malaysia, Germany, the Netherlands and Azerbaijan.
Continental Resources enters the Permian Basin
Robert Polk, 4 November 2021
The facts: Continental Resources entered the Permian Basin by purchasing Pioneer Natural Resources’ Delaware Basin assets
for US$3.25 billion in cash. The deal is expected to close in December 2021, and will be effective as of 1 October.
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Our take: the motivation for Pioneer is straightforward and was expected, but Continental’s rationale is less clear-cut. Pioneer’s
strategy is solely focused on the Midland Basin, and recycling Delaware capital from the Parsley deal fortifies an already pristine
balance sheet and further drives shareholder returns.
On Continental’s side, the deal consideration aligns closely with our Lens valuation, but poor initial market reaction raises
questions regarding strategy. This is the second new basin entry for Continental this year. Adding two new oil weighted assets
perhaps inadvertently undercuts confidence in its remaining Bakken inventory.
Most Permian transaction activity has been consolidation of existing positions, not new entry, but there are compelling factors.
Continental benefits from a balanced commodity mix, but production is now more weighted towards gas. Continental possesses
a bias towards oil, and this adds liquids inventory. At current prices, the forward year cash flow multiple is attractive.
Finally, there are clear long-term advantages in the Permian Basin and Continental previously stood in contrast to virtually all
large cap US independent peers without any Permian Basin exposure. The cash flow outlook provided a platform for a cash
purchase. This transaction previews a likely uptick in cash-based asset deals.
For complete thoughts on the transaction and the considerations for both Continental and Pioneer, please see our Deal Inform.
BP Q3 2021 results
Luke Parker, 2 November 2021
BP rounded out the Majors’ Q3 results season on a positive note. Earnings of US$3.3 billion beat analyst expectations for the
third quarter in a row, buoyed by surging prices, strong trading results and solid operational performance. The company
announced a further US$1.25 billion of share buybacks, supporting its "performing while transforming" narrative.
Read our results analysis for more, including thoughts on the possibility of a low carbon spin-off, cost inflation in offshore wind,
EV charging returns and an upgraded disposal proceeds target.
ConocoPhillips Q3 2021 results
Dave Clark and Matt Woodson, 2 November 2021
The facts: ConocoPhillips reported Q3 adjusted earnings of US$2.37 billion, up US$656 million versus Q2, with adjusted EPS
of US$1.77 easily beating analysts’ consensus expectations. Lower 48 adjusted earnings of US$1.58 billion contributed US$390
million of that sequential increase, powered by the Permian. Cash flow from operations was a robust US$4.8 billion (aided by a
+~US$700 million swing in working capital), Free cash flow (ex-WC) was ~US$2.8 billion. Total production of 1.544 Mboe/d was
above guidance of 1.48-1.52 Mboe/d.
Our take: over the last twelve months, ConocoPhillips has made dramatic portfolio changes, laid out ambitious long-term cash
return plans, and outlined Paris-aligned operational emissions targets. On this Q3 results call, with Concho fully integrated and
the Shell Permian deal near close, COP began the pivot from counter-cyclical transformation to upcycle execution. The pieces,
strategy and message are in place, now comes the work of executing on their top-tier ten-year plan of massive cash generation
and return of capital to shareholders.
The robust free cash flow in the quarter allowed the company to return ~US$1.8 billion to shareholders (~$1.24 billion buyback,
US$580 million regular dividend) while also reducing net debt by almost US$2 billion. Book gearing stood at just 17.2% at
quarter-end.
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With WTI averaging ~US$71/bbl in Q3, COP reinvested just 32% of operating cash flow (year-to-date 37%). Oil averaged about
US$10/bbl higher than that in October, and is ~US$84/bbl in early November – reinvestment rate should be meaningfully below
30% for the company in Q4. There will be a tremendous amount of free cash flow to allocate in this final quarter of the year. The
company should have no trouble meeting its US$6 billion return of capital target (~US$4 billion year-to-date through Q3).
No concrete 2022 guidance yet, but there was some commentary suggesting next year’s budget will be in line with the plan
outlined at the June market update (chart in that presentation suggested ~US$6-7 billion), plus Shell’s pre-deal run rate (we
estimate about US$560 million). Management said that anticipated inflation would mean they “adjust scope modestly” for 2022
to keep base capital at the outlined level. They will offer formal 2022 outlook in early December.
Majors' results round-up - Q3 2021
Tom Ellacott, 1 November 2021
The facts: the Majors’ financial recovery gathered serious pace in Q3. Earnings surged across the board, in some cases to
levels last seen in 2012 when the oil price averaged US$113/bbl (TotalEnergies, Equinor). Shell and Chevron notched up
quarterly free cash flow records. Rapid deleveraging was a key trend as balance sheets mopped up the surplus cash.
Our take: capital allocation plans dominated the results calls. Higher prices flowed through to expanded near-term buybacks
(Equinor) while ExxonMobil sweetened its strong results with the launch of a fresh share repurchase programme of up to US$10
billion and 1% dividend increase.
Analysts probed on the potential for future buybacks and dividend increases. TotalEnergies in particular faced some tough
questions about a lack of clarity on the timing of a dividend hike. But the Majors would not be drawn on when and by how much
buybacks or dividends would increase.
No Major broke rank to increase investment guidance. This cycle is, so far, very different to any other. The proportion of capital
allocation into low carbon also continues to increase. ExxonMobil announced a four-fold increase in its low-carbon budget to
US$15 billion out to 2027, equivalent to 10% to 20% of its overall spend.
Is it only a matter of time before overall budgets expand? All Majors have reduced their gearing below target. Chevron, Equinor
and TotalEnergies ended the quarter with gearing under 20%. They are also re-investing at well below historical rates.
The majority will favour additional deleveraging to strengthen financial resilience; and build up a war chest for potential low
carbon acquisitions. But how long can the deleveraging trend continue before balance sheets become inefficient? The Majors
will have to increase shareholder distributions, investment or both if prices are sustained at current levels.
Shell facing pressure from activist hedge fund to abandon transition strategy
Luke Parker, 1 November 2021
The facts: activist hedge fund Third Point has built a position in Shell reportedly worth US$750 million (equivalent to a 0.4%
holding). It is proposing that Shell break into two standalone companies – a legacy business (upstream, refining and chemicals)
and a growth business (LNG, renewables, Marketing) – in order to increase shareholder returns and accelerate emissions
reductions. Details are light. Thus far, Third Point’s only public disclosure on its new position in Shell is its Third Quarter Letter to
investors. Engagement is seemingly at the very early stages, with communication apparently going via Shell Investor Relations.
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Our take: this is an intriguing move from Third Point. The idea is not new of course. We wrote a note exploring it – Should the
Majors spin off new energy? – earlier this year. Eni has since announced plans to IPO its renewables business, and Repsol is
weighing up a similar move.
But Shell is a different animal altogether. It’s entire ‘Powering Progress’ strategy is built around integration – linking assets to
customers along value chains that span current and future energy systems, the cash generated by the former feeding growth in
the latter. Integration is integral. Indeed, Shell sees integration not only as a unique advantage through transition, but as a prerequisite for transition to happen.
Third Point is effectively pushing Shell to abandon its entire strategy for transition. A strategy that was approved by 89% of
shareholders at the 2021 AGM. That seems like a non-starter to us. We certainly expect strong pushback from management,
who will no doubt regard the intervention as an unhelpful side-show.
Still, the pressure is real, and mounting. Third Point is right to say that Shell is currently undervalued by the market, and that
investors have yet to be convinced of the value proposition. Changing that – by demonstrating progress and results – is Shell’s
number one focus. Third Point’s intervention serves to add more, very public pressure. And if the level of analyst interest on
Shell’s Q3 results call is anything to go by, the story will run for a while yet. Shell’s peers will be watching keenly. If Shell cannot
make the integrated ‘Big Energy’ model work, then who can?
Aramco's earnings soar
Norman Valentine, 1 November 2021
The facts: Saudi Aramco’s quarterly net income increased 158% year-on-year to US$30.4 billion, boosted by higher oil prices,
improved downstream margins and increased oil and gas output (-+4% y-o-y to 12.9 million b/d).
Surging quarterly free cash flow (+131% y-o-y to US$29 billion) supported dividend commitments and higher quarterly capital
expenditure (+19% y-o-y to US$7.6 billion) with excess cash flowing through to the balance sheet. Gearing fell from 19% to 17%
over the quarter. Aramco’s dividend proposal for Q3 was maintained at US$18.8 billion.
Our take: another strong quarter puts Aramco on course to hit its 5-15% gearing target by the end of the year. With the balance
sheet heading back into shape, dividend increases and further hikes in capital investment look likely in 2022, especially if
Aramco proceeds with more infrastructure sales.
Aramco certainly has no shortage of investment options for next year. Expansion of its maximum sustainable oil production
capacity to 13 million b/d will be the priority. Gas development is also a strategic objective with investment in the Jafurah Basin a
notable theme. Renewables, CCS and energy efficiency will also move up the budget agenda following Aramco’s recent
commitment to achieve net zero scope 1 and 2 emissions by 2050.
Q3 Results: CNOOC and PetroChina rally on higher prices, Sinopec faces
headwinds
Kavita Jadhav & Yuqi Hu, 1 November 2021
The facts: surging prices and production propelled CNOOC to a record quarter. PetroChina profited similarly from higher prices
despite a decline in oil production. Sinopec was held back by performance of the downstream segment.
Our take: CNOOC and PetroChina, with a large proportion of upstream assets, were able to capitalise on the oil price rally.
Sinopec with assets heavily weighted towards downstream, had a muted quarter due to domestic price controls.
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CNOOC stands out with it's counter-cyclical investment strategy. The company has steadily increased capex, doubling its
investment from 2017 to 2021. As a result, production has increased 10% y-o-y, allowing CNOOC to reap the rewards from
higher oil prices. PetroChina experienced a decline in oil volumes due to mature, legacy oilfields, but an increase in natural gas
production compensated for this. Sinopec's production increase was also driven by higher gas volumes.
CNOOC confirmed that the year-end dividend would reflect strong performance and exceed interim dividend. Sinopec
committed to maintaining a stable dividend payout. PetroChina doubled dividend in H1 2021 versus H1 2020, but did not
comment on the year-end dividend.
At the end of Q3, all three companies have capex spend hovering at around half their FY targets. To meet their FY guidance,
spend will have to ramp-up significantly in the final quarter.
The three NOCs have committed to net zero, with Sinopec and PetroChina aiming for 2050 and CNOOC for 2060. The first step
in their energy transition strategy is to increase the share of natural gas in their portfolio. PetroChina and Sinopec are already
making headway, but CNOOC will need to accelerate from current level of 20% gas in the portfolio.
See our reported results write-up for more detail on the Q3 performance of CNOOC, Sinopec and PetroChina.
Gas production ratio of the total production
Midstream consolidation: are private equity companies ready for the next
pivot?
Rachel Schelble, 29 October 2021
The facts: After a relatively quiet year for midstream M&A, it was a big week for sector consolidation, with the announcement of
three multi-billion-dollar deals.
Crestwood acquired Oasis Petroleum in a US$1.8 billion deal that expands its market share in the Bakken, Williston and
Delaware Basins. Crestwood’s private equity (PE) backer (First Reserve) shed their 25% equity stake in July 2021, and
Crestwood made good on their promise to grow their business.
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Altus Midstream (APA Corp, 79%) announced a merger with BCP Raptor Holdco (backed by Blackstone and I Squared Capital),
the parent company of EagleClaw, Caprock, and Pinnacle Midstream, to form the largest integrated midstream company in the
Delaware Basin, with an estimated enterprise value of US$9billion.
Finally, Phillips 66 announced an agreement to acquire Phillips 66 Partners in a US$3.4 billion all-stock transaction. Upon
completion of the deal, the PSXP will no longer be a publicly traded partnership, and will be a wholly owned subsidiary of
Phillips 66.
Our take: While all three deals are about control and consolidation, the Altus and Crestwood transactions are a sign that PE is
starting to pivot focus towards energy transition infrastructure. We have seen similar patterns in the past decade, particularly in
the Permian Basin. PE quickly moved to fill the commercial gaps, whether that be undrilled leasehold and appraisal projects,
water infrastructure, or gas processing, to name just a few. Private companies were built to fill gaps across the value chains,
maximizing value across their portfolio companies.
With the energy transition now at the core of private equity infrastructure strategies, firms are working to price climate risk into
their investments and work to fill the next set of value chain holes. For example, earlier this year Valero and BlackRock teamed
up with Navigator to construct a 1,200-mile CO2 pipeline system to permanently store 5 million t/yr. We expect the next wave of
private equity infrastructure investments will increasingly focus on CO2 and H2 projects.
Pemex and Petrobras continue recovery in Q3
Raphael Portela, 29 October 2021
The facts: Pemex’s output grew slightly (<1%) quarter-on-quarter, and EBITDA margins remained healthy (33%). But the
negative impact of high taxation, debt servicing and unfavourable exchange rate resulted in a net income loss of US$3.8 billion.
Pemex’s debt level should remain unchanged through 2021.
Contrastingly, Petrobras reached its US$60 billion gross debt target more than a full year ahead of schedule. That gave the
Brazilian NOC enough confidence to double its annual dividend payments, now at a cumulative US$12 billion or a 17% yield.
EBITDA remained roughly flat quarter-on-quarter (~US$11.5 billion or 50%), though net income fell by US$2.2 billion relative to
Q2 (primarily due to a US$4.9 billion currency impact).
Ecopetrol reports next week and YPF on November 10.
Our take: Both Latin American behemoths are on a path to recovery. But the difference in amount travelled is widening.
Pemex’s production continues its slow rise thanks to a slew of 25 new fields. And it impressively did so this quarter despite the
E-Ku-A2 incident. However, the decline rate of its mature base is proving tough to combat. On the financial front, taxes
accounted for 88% of its operating income despite a lower 54% DUC tax rate (65% in 2019). Yet another potential reduction to
the DUC (40% by 2022) is now being discussed in the Senate after being approved by the Deputies Chamber.
Petrobras is as streamlined as ever. We expect production and profitability levels to remain elevated in 2022. But like many
E&Ps, the company is sticking to capital discipline despite higher prices. The new five-year plan should see an uptick in spend,
but nothing radical. At the moment, the main area of concern is related to divestments – three refinery sales failed due to low
bids or inability of parties to agree on transaction terms. Petrobras plans on relaunching the process.
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US independents Q3 results – week 1
Dave Clark and Robert Polk, 29 October 2021
The facts: Week one of US Independent Q3 earnings included just seven companies in our coverage, four of which were
Appalachian gas producers (EQT, Range, Antero and CNX). Hess was the only large cap among the few oil-focused producers
that reported.
Our take: Gigantic hedging losses for the four gas-focused names (US$6.7 billion total, US$1.2 billion cash) were expected
and largely pre-announced – but were still attention-catchers. That formidable headwind drove bottom-line net losses of US$3.8
billion, and negligible free cash flow. Maintenance capex plans for 2022 and buyback intentions were other key themes on the
quarter.
Responses to the ugly hedging quarter differed. EQT exited about 20% of its hedges for Q4 2021, and 10% of its 2022 hedges,
in order to capture some price upside. Range has added 527mmbtu/d of hedges for 2022 since Q2 earnings, and have over
60% of 2022 expected volumes for next year hedged.
Aggregate reinvestment rate for the four gas producers was 62% in Q3, and the current stay-flat level of spending is set to
continue. There is no apparent appetite for growth. Antero and EQT released firm transportation capacity built on previous
expectations for growth.
Gearing ratios increased sequentially for all four names, as the decrease in book equity due to losses outweighed net debt
reductions. But in absolute terms deleveraging continued, and combined with restrained reinvestment, the peer group moved
closer to shareholder return of capital. CNX repurchased US$78 million, and authorized an additional US$1.0 billion. We expect
Antero and EQT to introduce a repurchase framework in the coming months. Range alluded to introducing a quarterly base
dividend.
Hess reported earnings of US$115 million in Q3, and FCF of US$245 million (including US$130 million of asset sale proceeds),
with only a modest hedging loss. Three new discoveries in Guyana drove an increase in estimated recoverable resource at the
Stabroek Block from 9 billion boe to 10 billion boe. The partners now plan to have at least six FPSO’s on the block by 2027.
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Though the official budget won’t come until later this year, Hess gave an early look into 2022, indicating that capex would likely
rise by ~US$700 million versus 2021, with US$500 million of that increase coming from the Bakken and Guyana.
Hess did acknowledge that inflation could affect costs at the Yellowtail project (Stabroek phase 4), but said the economics
remain robust (breakevens at or below US$32/bbl). Management declined to give a full project budget until the project is
approved and sanctioned. Hess has hedged 110Kb/d of 2022 oil production with two-way collars (US$60-65/bbl floor, $9095/bbl ceiling).
Eni considering IPO of Vår Energi
Greig Aitken, 26 October 2021
The facts: Eni and HitecVision-owned Point Resources announced a strategic review of the future ownership structure of Vår
Energi. The owners stated they will consider various options, including the possibility of an Initial Public Offering (IPO).
Vår Energi was created through the merger of Eni Norge and Point Resources in 2018. The joint venture partners own 69.85%
and 30.15% of the company respectively. Eni stated it will continue to retain a majority stake in the company.
Our take: In our Lens Upstream platform, we value the Vår Energi portfolio at US$6.7 billion at a long-term Brent price of
US$50/bbl (2021, real terms), increasing to US$10.7 billion under US$70/bbl.
Conditions for a strategic review appear favourable, with oil prices at their highest level since 2018, Vår's production set to enter
a period of growth and Norway’s position as a global leader in upstream carbon reductions. The timing also appears to fit the
investment cycle for private equity backed Point Resources (formed in early 2016) – a full or partial sale of its equity ownership
or IPO would likely be its preferred exit route.
This is one of a number of business structure changes which Eni is currently pursuing. It is in discussions with BP around an
upstream business combination in Angola and has also launched a process to IPO its gas and power retail and renewables
business next year.
These business structures are autonomous, self-funded entities with a much tighter focus than Eni. Floating or partially exiting
these ventures gives the Italian Major a transparent, arms-length valuation of the JV while allowing the listed business unit
additional access to growth capital, at the appropriate cost.
Aramco announces net zero ambition
Noman Valentine, 24 October 2021
The facts: Saudi Aramco has announced an ambition to achieve net zero Scope 1 and Scope 2 greenhouse gas emissions
across its wholly-owned operated assets by 2050. The announcement came on the same day that the Saudi Arabia pledged to
cut its carbon emissions to net zero by 2060.
Our take: these are highly symbolic announcements ahead of the COP26 summit that commences in Glasgow on 31st October.
We recently asked whether COP 26 will accelerate oil and gas companies’ pivot to low carbon? The answer from the world’s
biggest oil exporter is emphatically affirmative. Pressure on other national oil companies to follow suit and set carbon reduction
goals is now much more intense.
But Saudi Aramco has yet to detail how it will achieve its net zero ambition. Despite one of the most carbon efficient upstream
portfolios of any upstream producer, Aramco’s huge productive scale means its goal to reach net zero Scope 1 and 2 emissions
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will require greater absolute reductions than any other oil and gas company. For comparison, we estimate Aramco’s total
upstream emissions in 2021 will be approximately 50% greater than Shell’s.
There is no indication that Aramco will reduce hydrocarbon output to lower its emissions footprint. We expect decarbonization
efforts will focus on energy efficiency initiatives, the use of renewable energy in operations and most significantly, large-scale
CCS. Aramco plans to disclose further details on its emission reduction goals in a sustainability report to be issued next year.
US Independents - Q3 results preview
Dave Clark and Robert Polk, 22 October 2021
The facts: Q3 earnings begin next week for the US independents. While the week one schedule is a bit light, with seven
companies reporting (including four Appalachian gas names), a packed week two will have at least 24 E&Ps on the schedule.
Our take: Q3 always offers the first peek into the next year, and given the historically unprecedented disconnect between
commodity prices and growth, this year it is particularly interesting. Here are the five key things we will be watching for:
Preliminary 2022 budgets and outlook. The message from the L48 E&P sector in 2021, under firm insistence from investors,
has been “capital discipline and cash return to shareholders.” Budgets have been held to beginning-of-year levels despite a
US$30+/bbl increase in oil prices (and a near-doubling in natural gas prices as well). Capex will increase for next year, that is a
near certainty, but by how much? What oil price assumption will companies use for 2022 planning, and how much wiggle room
will they leave themselves to increase budgets if oil prices remain elevated? And how much growth is in the outlook?
H2 cash allocation. Deleveraging is happening a lot faster than companies planned for, as oil has risen to over US$80. E&P
reinvestment rates, in aggregate, were held to just ~46% in H1 when oil averaged a bit over US$60/bbl, aided by a nowexhausted DUC backlog. What will companies do with the H2 cash windfall from US$70-80/bbl oil and surging nat gas prices?
Could we see some companies pull spending forward into Q4, with some cover from cash return to shareholder increases,
including base dividends?
Hedging. Large hedging losses (~-US$11.1 billion overall, ~-US$2.9 billion cash) were a key theme in Q2, and they will be
again in Q3 as both oil and gas prices climbed further. Surging nat gas futures caught many gas-focused companies off guard,
and some – for example EQT – will be exiting a portion of their hedging (at steep cost) for Q4 and 2022.
Cost inflation and supply chain issues. Cost inflation was deceptively muted in H1, with steel and diesel price increases
largely offset by flattish trends elsewhere in the cost mix. Q3 saw steadily rising inflation across almost all categories. A tight
labour market is causing issues along the supply chain. Rising service costs through the summer were caused in part by the
quick ramp-up in private operator activity. But overall activity isn’t surging – cost increases are largely being driven by limited
capacity. Estimates put current cost inflation around 10%, with an expectation of that rising to ~20% y/y by the end of the year
and in to 2022. How are companies reacting to the cost pressure? And can they ramp activity meaningfully if they choose to,
given service capacity constraints?
ESG updates and regulatory risks. Many of the L48 E&Ps published 2021 sustainability reports over the last couple of
months. With COP26 around the corner and increasing investor focus on ESG, corporate energy transition strategy is now frontpage material for the E&Ps. Beyond emissions targets, companies are dealing with rising regulatory risk, to their own operations
and to midstream/downstream projects that impact transportation and demand. How are they thinking about these risks?
ExxonMobil eyes up US CCS Expansion
Tom Ellacott, 22 October 2021
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The facts: ExxonMobil has announced plans to increase carbon capture at its LaBarge facility by 1 mmtCO2pa. A final
investment decision on the proposed US$400 million project is expected in 2022, potentially paving the way for start-up in 2025.
Our take: LaBarge is ExxonMobil’s flagship CCS asset. The facility currently captures around 6-7 mmptCO2pa, equivalent to
nearly 20% of the global total. The asset underpins ExxonMobil 20% market share in global CO2 capture capacity.
But LaBarge is a unique CCS project. The asset is also one of the world’s largest sources of helium, providing an important
source of value. ExxonMobil will face different challenges in launching other large-scale CCS projects to establish materiality in
its Low Carbon Solutions business unit.
The Supermajor is pursuing opportunities in the US Gulf Coast, Europe and Asia. The company will need to secure regulatory
and fiscal support to ensure the economic feasibility of its initial projects. A market price for carbon offsets will be the key to
unlocking a global investment opportunity that could grow to US$50 to 100 billion per annum by the 2030s.
COP26: the impact on oil and gas companies’ strategies
Akif Chaudhry and Kavita Jadhav, 20 October 2021
The facts: COP26 kicks off in Glasgow on 31 October. The landmark conference brings together the world’s policy-makers,
businesses and NGOs to debate the future of international climate policy. The aim of COP26 is to finalise the Paris rulebook –
most notably, to sign-off Article 6 – with potentially profound implications for the oil and gas corporate sector.
Our take: Paris was about ambition. Six years later Glasgow has to be about action.
Stakeholder pressure has boosted corporate action in the run-up to COP26. Many companies have set Scope 1 and 2 net zero
targets by 2050 and more have set interim reduction targets notionally aligned with the Paris Agreement.
However, oil and gas companies are looking for more visibility on demand erosion.
More ambitious Nationally Determined Contributions (NDCs) will intensify focus on company interim and net zero targets and
will up the ante on Scope 3 emissions. Policy action to tackle demand, combined with investor pressure, will accelerate energy
transition strategies. More oil and gas companies would be forced towards our ‘diversify’ and ‘divest’ business models.
Finalising Article 6 – the framework for emissions trading – will also support new decarbonisation business models, as global
collaboration towards an effective carbon market will allow key technologies such as CCS to commercialise and scale up.
Will 31 October prove to be a watershed moment for oil and gas companies? Good COP or bad COP, the call on oil and gas
companies will be for more action, more quickly. The decarbonisation snowball will roll on regardless.
Please see our COP26 Briefing series and our latest insight for more detailed analysis.
The Majors’ Q3 results preview
Tom Ellacott and Greig Aitken, 20 October 2021
The facts: all the Majors except BP report their Q3 results next week. Bumper cash flows and earnings will inevitably raise more
questions on capital allocation plans.
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Our take: free cash flow and earnings will soar in Q3. Some players could notch up new quarterly highs on the back of surging
prices and stronger downstream margins. Highly-integrated Majors should outperform, especially those weighted to the US with
limited exposure to Hurricane Ida.
The pace of deleveraging will accelerate. All the Majors will enter Q4 in much better financial shape than they envisaged at the
beginning of 2021. The majority will end the quarter with gearing below 20% - providing a decent buffer to weather future
volatility. We expect a shift in tone towards rising optimism.
We’ll be watching for any change in the capital allocation narrative. Buybacks will stage a come back in Q3. Analysts will quiz
management on the potential to turbocharge distributions in 2022 if current prices are sustained. But high prices should, in
theory, be a siren call to invest. Will some players break rank and increase oil and gas investment in 2022? Or will they seize
the opportunity to accelerate decarbonisation and low-carbon investment?
Chevron has opted for the latter. The US Major has announced a net zero ambition and nudged its investment up by 7%
through to 2025 to accelerate its new energy expansion. A similar move by ExxonMobil would reinforce the sense that low
carbon will be the winner in the competition for capital. But higher prices may also prompt some analysts to challenge broader
strategies, including the merits of divesting versus harvesting oil and gas assets.
Quarterly oil and gas prices and refining markets
UK government announces first two CCS clusters to receive funding
Jessica Brewer and Kevin Swann, 20 October 2021
The facts: the East Coast Cluster and HyNet North West are the CCS projects selected in Track-1 of the UK government’s
cluster sequencing process. Both should be operational by 2025.
The East Coast Cluster will capture CO2 from industries across Humber and Teesside, with storage in the Endurance aquifer.
HyNet North West will capture CO2 from Northwest England and Wales into depleted oil and gas fields at Liverpool Bay.
Negotiations will now take place between the partners and government. If successful, the clusters will receive support via the £1
billion CCS infrastructure fund. If negotiations with either partner fail, the Scottish Cluster has been selected as back-up.
Our take: the UK government has set a target of 10 Mtpa of operational CCS capacity by 2030 from four clusters. These two
projects get it well on the way to meeting the target. More clusters will be announced in Track-2.
Five clusters were in the running for Track-1 funding. Key benefits of those selected include:
•
Scale: targeting up to 37 Mtpa of CO2 for capture and storage.
•
Diversity: both propose hydrogen production alongside CCS.
•
Geology: subsurface understanding is relatively mature in both cases.
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The Euro Majors partner in the transport and storage components at both clusters – BP, Eni, Equinor, Shell and TotalEnergies
at Endurance; Eni at Liverpool Bay. They bring deep pockets, subsurface knowledge and, in some cases, technical CCS knowhow from operational projects like Sleipner and Snöhvit in Norway (Equinor), and Quest in Canada (Shell).
The three unsuccessful Track-1 projects – DelpHYnus, Scottish Cluster and V Net Zero – will be considered for Track-2, along
with any new entrants. Activity continues across the remaining clusters and Harbour Energy was recently awarded a carbon
storage and appraisal licence in the Southern North Sea. This includes the Viking and Victor fields, which would act as storage
for the V Net Zero cluster.
Russia closer to net zero commitment
Scott Walker and Nikolai Novikov, 15 October 2021
The facts: The Ministry of Economic Development is reported to have revised its draft strategy for low-carbon development of
the Russian Federation. This is the third version of the strategy and still needs to be approved by other Ministries. The number
of possible scenarios was reduced from four to only two: a base (inertial) case and an accelerated (target) case. The
accelerated scenario envisages Russia achieving carbon neutrality by 2060 or earlier.
Our take: Russia articulating an accelerated scenario to carbon neutrality is an important milestone, and timely for the Russian
delegation heading to COP26 in Glasgow in two weeks’ time. As the second largest emitter of Scope 1 and 2 emissions out to
2030 in Lens and our Emissions Benchmarking Tool – and with the highest level of flared gas according to the World Bank –
Russia has been a noticeable absentee in terms of net zero ambitions.
Looking at the accelerated scenario, it appears that Russia will be a making a big bet on the absorption capacity of its forested
areas, the largest on Earth. What implications it will have for Russia’s two largest hydrocarbon producers, governmentcontrolled NOCs Rosneft and Gazprom, is not yet clear. But should Russia commit to carbon neutrality it should ultimately
translate into company net zero targets. In China, the government announced its 2060 net zero target in September 2020; within
one year the three Chinese NOCs had all made 2050 net zero commitments. We expect Rosneft and Gazprom would follow
suit.
CNOOC Ltd’s first attempt at floating wind
Kavita Jadhav, 15 October 2021
The facts: CNOOC Ltd has launched a selection procedure to appoint an advisor to classify its first floating wind project. The
Wenchang floating wind project will have a capacity of 6.25 MW and will be located in the South China Sea. It will provide
electricity to the Wenchang oil complex, and mark a first step in upstream electrification using offshore wind in China. CNOOC
Ltd has completed FEED for the project, but has not yet provided details on FID and start date.
Our take: floating wind is an emerging technology and scale of deployment is still limited compared to conventional fixed-bottom
technology. Wenchang floating wind is a pilot project and could be the first step towards larger projects, as technology is scaled
up and unit costs fall. China’s offshore wind giant, China Three Gorges, has only recently commissioned the country’s maiden
floating wind project with a capacity of 5.5 MW. Equinor’s Hywind (offshore Scotland), commissioned in 2017, was the first fullscale floating offshore wind farm and has a capacity of 30MW. Equinor is now developing the world’s first floating wind facility to
power oil and gas platforms, the 88 MW capacity Hywind Tampen project in Norway.
CNOOC Ltd returned to offshore wind in 2020, after a previous unsuccessful attempt at building a wind business in 2007. The
company is being innovative here with a plan to use abandoned offshore facilities such as jackets and to modify its vessels for
installation. It tested this previously when it built the Bohai Bay wind farm in 2007 on a jacket structure from its Suizhong oilfield.
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CNOOC Ltd announced in its H1 2021 results that it intends to spend 5-10% of its annual capex of US$14-15 billion on new
energy and emissions reduction, to reach its goal of net zero by 2050. Similar to Equinor, a key pillar of CNOOC Ltd’s energy
transition strategy is to leverage marine expertise gained from its upstream business to grow an offshore wind position. There
are synergies with upstream as offshore wind floater designs are familiar from the oil and gas industry. Wind is also central to
China’s carbon neutrality goal, with a target to commission 1,200 GW of wind & solar capacity by 2030.
Oxy sells Ghana assets for US$750 million
Zoë Sutherland, Scott Walker & Liam Yates, 14 October 2021
The facts: Occidental Petroleum has announced the sale of its Ghana assets to field partners Kosmos Energy (US$550 million)
and Ghana National Petroleum Corporation (US$200 million). The sale includes an interest in the Jubilee and TEN fields, which
produce around 22,000 boe/d net to Oxy. The Kosmos deal completed on announcement and the sale to GNPC is expected to
close in Q4 2021. Operator of both fields Tullow holds pre-emption rights which it can exercise within a 30-day period.
Our take: today’s sale price of US$750 million is significantly lower than Total's US$2.5 billion offer back in May 2019, before
that deal fell through; although higher than a rumoured US$500 million sale to Carlyle in April 2021. Some of the fall in original
valuation is due to reserve write downs. The Jubilee and TEN fields have faced issues with gas handling, reservoir performance
and equipment failures. While output has now been stabilised, future performance challenges cannot be ruled out. The partners
must also address high levels of flaring at the fields.
Oxy will be relieved to have found a buyer. It was likely holding out for more cash, but with a limited pool of buyers, it may have
decided this was the best it was going to get. The proceeds bring it another step closer to its debt reduction goal and mean it
has finally met the lower end of its post-Anadarko divestment target of US$10-$15 billion. See our latest Oxy corporate profile
for more on its deleveraging progress.
We think Kosmos got an excellent deal. The sales price represents a 14% discount to our valuation. Kosmos intends to fund its
portion of the acquisition cost with a US$400 million bridge loan facility and a US$140 million equity raise, with the equity
issuance helping to lower gearing slightly from 87% to 84%. And with the assets generating cash flow even in our low case
(US$30/bbl), Kosmos is well placed in the current price environment to allocate increased capital to deleveraging efforts and
funding Tortue.
Qatar Petroleum rebrands as QatarEnergy
Norman Valentine, 14 October 2021
The facts: the world’s LNG largest supplier has changed its name to QatarEnergy. It becomes the latest large oil and gas
company to recast its public image as a broad energy provider and follows similar moves by Equinor, TotalEnergies and others.
Our take: this symbolic move highlights QatarEnergy’s ambitions in low carbon energy. The NOC is firmly focused on LNG
supply growth, aiming to increase production from 77 mmtpa to 126 mmpta by 2027, but it is also investing in a range of carbon
mitigation projects as demand for carbon neutral LNG grows. These include 2-4 GW of renewable power and 7-8 mmtpa of
CCUS capacity by 2030.
QatarEnergy’s goal is a net carbon intensity reduction of 15% from upstream and 25% from LNG facilities by 2030. Longer-term
decarbonisation targets are yet to be set. We think QatarEnergy will ultimately need to go much further on long-term
decarbonisation if it is to defend its LNG leadership role through the energy transition.
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Chevron sets net zero ambition
Tom Ellacott, 14 October 2021
The facts: Chevron has joined the net zero club, setting an aspiration to reach net zero from equity upstream Scope 1 and 2
emissions by 2050 in its new Climate Change Resilience report. Additional upstream targets include a 50% reduction in
methane relative to a 2016 baseline, to 2 kgCO2e/boe in 2028.
In Downstream, the company is targeting a 1% to 2% reduction in Scope 1 and 2 emissions intensity from 2016 to 2023 and 2%
to 3% between 2016 and 2028.
Chevron also set a target of reducing its Portfolio Carbon Intensity (PCI) more than 5% by 2028 related to the 2016 baseline.
The PCI covers the full value chain, including Scope 3 emissions from the use of end products.
Our take: the net zero ambition is a positive development. But it does not come as a surprise, coming hot on the heels of the
announcement that the Oil & Gas Climate Initiative (which includes Chevron) aim to reach net zero Scope 1 and 2 emissions
from operations under their control by 2050.
Chevron’s upstream ambition goes further, covering equity emissions. But the exclusion of downstream contrasts with the allinclusive net zero targets of the Euro Majors. Chevron’s refining emissions intensity also jumped 5.5% between 2016 and 2020.
The Supermajor will be under pressure to turn this around and eventually wind downstream into its net zero aspirations.
Chevron’s upstream methane intensity target for 2028 is flat relative to the 2020 reported actual of 2 kgCO2e/boe. But demand
destruction and other macro impacts were the main factors driving a 17% year-on-year reduction in upstream methane intensity
in 2020. Chevron still has work to do to ensure sustained reductions.
The target to reduce the PCI follows shareholders voting 61% in favour of a call for Chevron to “substantially reduce’ its Scope 3
emissions in the medium and long-term at the AGM earlier this year. The target is a starting point but is only 2.3% lower than
the 2019 actual PCI. Chevron may also be able to grow production through development of low emissions intensity assets such
as the Permian.
The deeper longer-term reductions in PCI required under a net zero scenario would have more far-reaching strategic
implications. Chevron outlined how growth in its low-carbon business would have to offset a shrinking legacy oil and gas
business, leaning heavily on its hydrogen, low-carbon fuels and CCUS focus areas. The company recently tripled its low carbon
investment to an average of US$1.25 billion pa through 2028.
ExxonMobil starts to scale up its advanced recycling operations
Tom Ellacott, 13 October 2021
The facts: ExxonMobil is planning the construction of its first large-scale advanced recycling facility at its Baytown industrial
hub. The company expects to bring the facility online by year-end 2022 with an initial capacity of 30 ktpa.
The move is part of a broader strategy to add up to 500 ktpa of advanced recycling capacity across multiple sites over the next
five years. ExxonMobil has also initiated a similar project at its Notre Dame Gravenchon steam cracker in France and is
evaluating potential facilities in the Netherlands, US Gulf Coast, Canada and Singapore.
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Our take: this is part of a bigger trend of the Majors establishing a foothold in the embryonic advanced chemicals recycling
sector. The general approach is to chemically recycle waste plastics into a synthetic “pyrolysis oil” feedstock, which is then run
through existing steam crackers to displace fossil-based feedstocks.
The volumes of waste plastics and circular feedstock processing are small currently. But we expect the market to grow over the
next 20-30 years as the technology evolves and more companies become active in the space. Downstream brand owners will
also drive demand for circular plastics to use in packaging.
We expect ExxonMobil will be looking to establish a position of peer leadership, leveraging its leading Chemicals business.
Commercial scale-up would also be an important step in driving the company’s sustainability agenda.
Repsol's Low Carbon Day
Tom Ellacott, 8 October 2021
The facts: increased investment and more ambitious targets dominated Repsol’s Low Carbon Day. The company raised its
budget for 2021 to 2025 by 5% in response to large upgrades to renewables capacity and renewable hydrogen targets. These
flowed through to another upgrade to interim decarbonisation ambitions, the second since Repsol announced its net zero
objective in 2019.
Our take: Repsol’s pivot to low carbon is gaining serious momentum. Low carbon investment will now account for 35% of
overall spend out to 2025 – higher than any oil and gas peer. The upgraded renewables capacity target of 20 GW in 2030 ranks
ahead of Equinor and Eni’s guidance. The result is a more rapid emissions reduction trajectory this decade than some peers.
The aggressive low carbon strategy is no surprise. Repsol is at the sharp end of the energy transition. Downstream accounts for
US$18 billion or 56% of our overall valuation – a far higher level of exposure than any other Major, including ExxonMobil. The
domestic-focused downstream business is exposed to an Iberian market in which we expect oil product demand to start falling
sharply from 2023.
But Repsol sees opportunity in transforming its legacy industrial sites to low carbon ‘energy parks’. The next few years are all
about laying the building blocks for the ‘refinery of the future’.
Biofuels, renewable hydrogen and e-fuels will, over time, displace hydrocarbon products. A growing renewables portfolio and
customer-centric business will provide integration opportunities. Repsol will also have flexibility to adapt its strategy, leaning on
the diversify of low-carbon options in this multi-energy platform.
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Repsol's upgraded low carbon ambitions
PETRONAS sells Shah Deniz stake to LUKOIL for US$2.25 billion
Andrew Harwood, 8 October 2021
The facts: Russian operator LUKOIL has upped its stake in Azerbaijan's Shah Deniz gas-condensate megaproject to 25.5%,
acquiring PETRONAS' 15.5% share. Effective 1 January 2022, the deal marks PETRONAS’ exit from Azerbaijan's upstream
sector. The transaction also includes PETRONAS' aligned 15.5% stake in the South Caucasus Pipeline export route to Georgia
and Turkey.
Our take: The largest M&A transaction in the Caspian region in more than 5 years, this is LUKOIL's second major growth move
in Azerbaijan in a week. The Russian player recently joined BP in the Shallow Water Absheron Peninsula (SWAP) exploration
block. LUKOIL has come to covet international expansion, with the Caspian a clear focus region. It is also in talks for discovered
resource opportunities in Kazakhstan and cross-border Azerbaijan/Turkmenistan.
Having acquired its stake from Equinor in 2015 – for a similar US$2.25 billion consideration – PETRONAS has grown frustrated
with its progress in the Caspian Sea, particularly across the border in Turkmenistan at its 100%-owned Block 1 development. As
Malaysia's NOC refocuses its upstream portfolio on high-margin positions or areas with major growth potential, the opportunity
to realise a sizeable consideration for its Shah Deniz interest may have been too good to pass up.
Eni launches renewables IPO process
Tom Ellacott, 8 October 2021
Our take: Eni has launched an IPO process for its integrated Gas&Power retail and renewables business. The company plans
to complete the transaction during 2022, subject to market conditions. Eni will retain a majority stake in the listed company.
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The facts: we outlined the strategic logic for spinning off a minority stake in renewables businesses in Should the Majors spin
off new energy? The primary objective is to access low-cost growth capital while also improving see-through valuation for the
entire group.
Capturing a ‘new energy’ valuation premium is the ultimate prize. EBITDA multiples for the Big Renewables names have
softened this year. But these companies are still, on average, trading at more than twice the multiple of the Majors. For context,
Eni is looking to double the EBITDA of the business unit over the next five years, hitting €1.2 billion in 2025.
Repsol will take note. The company was a first mover in declaring that it is evaluating either an IPO or trade sale of a minority
stake in its renewables power business. But the target date has slipped as Repsol has focused on scaling up its renewables
pipeline. The company will now return to evaluating options for a minority spin-off although, in contrast to Eni, it does not plan to
include its customer-facing business.
EV:trailing 12-month EBITDA multiple
ExxonMobil upgrades Guyana resources to 10 billion boe
Tom Ellacott, 8 October 2021
The facts: ExxonMobil has increased its estimate of recoverable resources for the Stabroek Block in Guyana from 9 to
approximately 10 billion boe. The updated resource estimate includes the Whiptail, Pinktail and Cataback discoveries and
recent appraisal results.
Our take: the upgrade does not come as a surprise given recent E&A results. Even so, the scale of this advantaged resource
for ExxonMobil (45%) and its partners Hess (30%) and CNOOC Ltd (25%) continues to impress. And we think the resource
estimate will continue to creep upwards.
Development of the asset will drive portfolio improvement for all three players. In Lens, the project delivers a return of 26%
under our base-case price (US$50/bbl). That jumps to 40% at US$80/bbl flat real. Emissions intensity of less than 10
tC02e/kboe at plateau production is also highly competitive – and more than two thirds lower than the average upstream
emissions intensity of each partner.
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Saudi Aramco puts timeline on oil capacity expansion
Norman Valentine, 8 October 2021
The facts: Saudi Aramco’s CEO has given an insight into the timing of the company’s oil production capacity expansion plans
for the first time. Amin Nasser indicated the increase in maximum sustainable crude production capacity from 12 million to 13
million b/d will be developed in phases and come fully onstream by 2027.
Our take: back in March 2020 when capacity expansion plans were first announced, we estimated project execution could take
4-5 years. Coronavirus related delays and pressure on Aramco’s finances following the oil price crash have pushed back
timescales.
Capacity expansion remains a multi-mega project, involving both new fields and expansions to a number of Aramco’s offshore
giants already in production. Aramco will need to balance its oil expansion commitments with its plans for large-scale
unconventional gas development in the Jafurah Basin.
Higher oil prices mean Aramco now has more money to throw at the challenge. Assuming oil prices average US$70/bbl in 2021,
we estimate the company will generate over US$30 billion in free cash flow this year, after dividends and including proceeds
from pipeline asset sales.
Excess cash will be used to delever the balance sheet and put Aramco in a solid position to meet the huge cost of oil capacity
expansion, which we estimate could be in the region of US$30 billion.
TotalEnergies an anchor investor in the world’s largest clean hydrogen
infrastructure fund
Tom Ellacott, 4 October 2021
The facts: TotalEnergies, Air Liquide, VINCI and a group of other large international companies have launched the world’s
largest clean hydrogen infrastructure fund.
The fund has secured €800 million of initial commitments and aims to reach €1.5 billion. TotalEnergies pledged €100 million as
an anchor partner alongside Air Liquide and VINCI.
The fund’s objective is to invest in large strategic projects and leverage the alliance to accelerate the growth of clean hydrogen.
It will be managed by Hy24, a new 50:50 JV between private investment house Ardian and FiveT Hydrogen, a clean hydrogen
enabling investment platform.
Our take: the move is another example of how TotalEnergies is getting creative in expanding into low-carbon, leveraging
partnerships and strategic relationships. The fund will invest in the entire value chain of renewable and low carbon hydrogen, in
the most promising regions in the Americas, Asia and Europe.
TotalEnergies’ portfolio is currently focused on relatively small pilot programmes, as outlined in our Majors’ hydrogen
benchmarking report. The company’s expansion across the value chain could pave the way for a more aggressive scale-up of
green and blue hydrogen, in line with its objective of being a pioneer in mass production. TotalEnergies will also look to capture
synergies with its growth in gas and future CCUS investments.
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TotalEnergies’ 2021 Strategy and Outlook
Tom Ellacott, 1 October 2021
The facts: TotalEnergies delivered another comprehensive strategy outlook. There was no big unveil. Rather, the update was
an opportunity to demonstrate that the strategy to transform into a broad energy company is on track.
Our take: TotalEnergies’ strategy to grow energy production while lowering emissions is unchanged. But the strategic
transformation to low-carbon is gaining pace. And the Supermajor is aiming high. TotalEnergies’ goal is to be a top-five global
renewable power producer by the end of the decade.
We welcomed the additional disclosure to underline strategic progress. Our analysis of both the Upstream and Renewables
portfolios also indicates the strategy is on track. But managing execution risk will be vital to avoid disappointment.
In a first for a Major, TotalEnergies included the Utilities in its ESG and financial benchmarking slides. The competition is
changing as portfolios pivot away from the Big Oil to the Big Energy business model. More Euro Majors will follow
TotalEnergies’ lead.
Soaring LNG prices and the resumption of dividend growth were hot topics. TotalEnergies stressed that capital allocation needs
to be sustainable at US$50/bbl. A structural upward shift in cash flow to support dividend growth is coming but is still a few years
out based on our analysis. We think that buybacks will be the favoured mechanism for re-deploying surplus cash flow in the
near-term.
TotalEnergies' Strategy Update
CNOOC doubles down on the world’s largest deepwater field
Raphael Portela and Kavita Jadhav, 1 October 2021
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The facts: CNOOC exercised the option to buy an additional 5% stake in the Buzios field for US$2.08 billion. The payment to
Petrobras includes US$1.45 billion as compensation for prior investments and loss in value (known as co-participation), and
US$630 million for the reimbursement of the signature bonus. Buzios is the largest deepwater field in the world, located in the
prolific Brazilian pre-salt. CNPC is yet to exercise an identical option.
Our take: in practice, the additional stake equates to about 3.7% of the field, given the complex nature of the contract split
between the original and surplus Transfer of Rights volumes. The payment implies an improved valuation (previously US$1.47
billion), though higher oil prices was likely a driver. In 2019, we noted that despite the enormous resource addition and almost
immediate access to production, the economics for the Transfer of Rights surplus volumes was challenging. The co-participation
is actually a net positive for Petrobras, guaranteeing and boosting returns.
Last week, CNOOC announced an equity raise of US$5.4 billion to fund material oil projects due to be commissioned in the
near-term. Additional interest in Buzios procures more oil from an already producing field. These are not the most cost
competitive barrels to procure, particularly at a time when the oil price is skirting US$80/bbl. The recent oil price spike has
potentially brought energy security into sharp focus.
CNOOC has previously cited a shift to more gas in its portfolio, targeting 50% by 2035 (currently 20%). This priority on gas will
also require effort especially with oil increasing in its portfolio.
Q3 2021
Rosneft to collaborate with Majors on carbon reduction
Scott Walker, 30 September 2021
The facts: Rosneft simultaneously announced two cooperation agreements with ExxonMobil and Equinor to collaborate on
carbon management. The companies will work together to develop low carbon solutions and reduce emissions. Focus areas will
include CCUS, hydrogen, development of low carbon fuels and the implementation of renewables in operations. The
cooperation agreements with ExxonMobil and Equinor follow similar announcements with BP in February and with the Ministry
of Economy, Trade and Industry of Japan earlier this month.
Our take: Rosneft’s latest cooperation agreements are positive steps towards a lower carbon intensity future. As we highlighted
in our recent Horizons note, collaboration is a key piece of the decarbonisation jigsaw. And the Sustainability Accounting
Standards Board rates Rosneft’s momentum towards ESG commitments as positive. Rosneft will look to harness shared ideas
from its partners to deliver carbon-efficient growth from new and existing projects.
With easily the strongest production CAGR outlook among the Majors and its Russian peers (4.1% vs a Majors+Gazprom
average of 0.7% out to 2030), Rosneft’s future remains centred on growth in oil and gas. However, Rosneft’s long-term carbon
management outlook, as yet, remains behind industry leaders. The company has yet to commit to achieving net zero, instead
opting to reduce upstream intensity by 30% out to 2035.
Shell sells ‘core’ Permian position to ConocoPhillips for US$9.5 billion
Luke Parker, 27 September 2021
The facts: ConocoPhillips is buying Shell's Delaware Basin assets for US$9.5 billion in cash. The assets include ~225,000 net
acres and producing properties located entirely in Texas, as well as over 600 miles of operated crude, gas and water pipelines
and infrastructure.
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Our take: You’ll find our initial reaction to the deal in the Inform we published on the day: ConocoPhillips channels Permania.
Look out for deeper analysis – a Deal Insight and Lens walk-through – in the coming days. Here we focus on Shell’s rationale
for the deal. Key questions:
Why sell (now)? Having designated the Permian one of nine core upstream positions just 12 months ago, Shell’s exit seems
incongruous. However, while the asset ticked many boxes – margin at low prices, leverage to upside, attractive returns on new
drilling, investment flexibility, efficiency gains over recent years – it didn’t offer the scale and longevity that Shell wanted. The
company had been looking for several years to grow in the Permian, exploring potential acquisitions, JVs and alternative
structures. But it simply wasn’t seeing the opportunities or the value. On the flip side, the Permian is one of the few bright spots
in global upstream M&A right now. Big deals can get done. Grinding consolidation dictates that you’re either a buyer or a seller,
and once Shell decided it wasn’t going to be a buyer, there was only one outcome. It makes sense to sell while the selling is
good.
Is carbon a factor? Yes and no. On the one hand, the Permian ranks favourably on Scope 1&2 emissions intensity and value
at risk. Indeed, it’s one of Shell’s flagship projects, with GHG and methane emissions down by over 80% since 2017 and routine
flaring eliminated since 2018. However, growing in the Permian would’ve been a hard sell in a broader net-zero Scope 3
context, irrespective of arguments around ‘advantaged barrels’. Exiting makes a big dent in Shell’s target to reduce liquids
production by 1-2 % pa to 2030, without making much of a dent in free cash flow over the period (a function of the tight oil
investment profile).
Why pass US$7 billion of proceeds directly to shareholders? Put simply, because it can. Shell didn’t need to do this deal
from a financial perspective. Net debt was already comfortable and falling (gearing of 23% ex-leases at mid-year), shareholder
distributions are rebounding, and Shell is able to fund its pivot to low carbon through organic cash flow. Assuming dividends and
buybacks at the high end of Shell’s guidance (30% of CFO) – equivalent to annual distributions of around US$17 billion – we
calculate a corporate cash flow breakeven of US$57/bbl over 2022/2023. That’s before this disposal. The US$7 billion being
passed on from this deal is a ‘bonus’. With it, Shell is sending a powerful message on its position of strength, and an implicit
message that it sees its shares as woefully undervalued right now (unlike its Permian assets).
CNOOC to raise capital in Mainland China
Kavita Jadhav, 27 September 2021
The facts: CNOOC has filed to list on the Shanghai stock exchange and raise RMB35 billion (US$5.4 billion), by issuing up to
2.6 billion new shares. The listing would represent approximately 5.8% of its share capital. CNOOC has indicated in its
application that it will use the proceeds largely on its oil projects in China and Guyana. Two developments in Guyana mentioned
in the proposal are Liza and Payara which are under development and due onstream in 2022 and 2023.
Our take: the NYSE delisted CNOOC’s shares in February 2021, after CNOOC was added to a blacklist by the Trump
administration. CNOOC has appealed the decision. The delisting forced many American investors to divest their holdings.
CNOOC’s shareholder base has largely become domestic, which does not place the same priority on ESG relative to investors
buying shares on the NYSE. Raising capital on the domestic bourse aligns CNOOC even more closely with China’s strategic
interests.
The Shanghai listing will provide liquidity for CNOOC to deliver on material oil projects due to be commissioned in the near-term.
The capital raising does not refer to CNOOC’s priority to raise the share of gas in its production mix or its intention to spend 510% of annual capital (of US$14-15 billion) on new energy.
OGCI group targets net zero
Tom Ellacott, 23 September 2021
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The facts: the companies in the Oil & Gas Climate Initiative (OGCI) have announced that they aim to reach net zero Scope 1
and 2 emissions from operations under their control. They will also leverage their influence to achieve net zero on non-operated
assets.
The updated emission reduction ambitions include reducing upstream methane emissions intensity to well below 0.2% by 2025
(previously 0.25%), reducing upstream carbon intensity to 17 kgCO2e/boe (previously 20 kgCO2e/boe) and zero routine flaring
by 2030.
Our take: OGCI is a CEO-led consortium of 12 of the largest oil and gas companies aimed at accelerating the industry’s
response to climate change. It includes the Euro Majors, US Majors, Saudi Aramco, CNPC, Petrobras and Occidental.
All the Euro Majors and Occidental already have net zero Scope 1 and 2 targets. Petrobras announced a net zero target on the
back of the OGCI pledge. But we were surprised that the US Majors have not yet gone public with their net zero ambition. They
may be waiting until their Q3 results for the big unveil, although Chevron did talk about its pathway to net zero in its recent
Energy Transition Spotlight.
The announcement is another indication that decarbonisation momentum is gaining pace. We think the OGCI is well placed to
outperform the methane and flaring targets: indeed, with the group reporting methane intensity of 0.2% in 2020 some may argue
whether the methane target is sufficiently 'stretched'. These industry big hitters will also play a vital role in leading the industry’s
response to climate change through more extensive, timely and creative collaboration.
Vattenfall boosts energy transition goals
Norman Valentine, 21 September 2021
The facts: the Swedish state-owned utility unveiled an ambitious path towards net zero carbon and an updated renewables
capacity growth target at its annual capital markets day. Vattenfall’s core aim is to be net zero through the value chain by 2040
which it sees as aligned with a 1.5 degree global warming scenario. As part of its mantra of fossil free living within a generation,
Vattenfall expects to quadruple installed renewable power capacity, currently 3.6 GW, by the end of this decade. It will also
phase out remaining coal-fired assets by 2030.
Our take: Vattenfall has raised the bar on corporate net zero targets. It joins Ørsted as one of the few large energy companies
to target carbon neutrality by 2040. A big expansion in renewables capacity is part of the plan but Vattenfall’s targets remain
modest compared to other companies such as BP, EDF, Ørsted and Total that are targeting big capacity growth in wind and
solar. Vattenfall’s CEO struck a note of caution on a headlong rush into renewables, emphasising the company’s focus will be
on value and not volume.
Vattenfall also sees integration from generation through to end-user as a key competitive advantage in renewables. This means
the strategic focus will remain primarily on Europe rather than large-scale expansion in other geographical markets.
CCS in the Houston Area gains early momentum
Tom Ellacott, 17 September 2021
The facts: eleven companies have agreed to begin discussing plans to support the large-scale deployment of CCS in Houston.
Nearly 75 MtCO2pa could be captured and stored by 2040 from the facilities operated by these players in the Houston Area.
Our take: this could be the start of large-scale CCS in the Houston Area gaining momentum. Discussions with other players
operating industrial facilities in the area are ongoing. The latest announcement also follows ExxonMobil’s proposal for a CCS
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hub along the Houston Ship Channel that was announced earlier in 2021. The concept has the potential to capture 100
MtCO2pa by 2040.
Our recent Horizon note highlighted the importance of collaboration in derisking decarbonisation projects. The planning phase
will involve 2 Majors (ExxonMobil and Chevron), 3 refiners (Marathon, Phillips 66 and Valero), 2 IPPs (Calper and NRG) and 4
chemical companies (DOW, Ineos, Linde and LyondellBassell). With such a diverse mix of big-hitters, the development of CCS
in the Houston Area sits firmly in the 'Collaborate' bucket.
Stakeholders lay out net zero standards for oil and gas
Tom Ellacott and Greig Aitken, 17 September
The facts: a new Net Zero Standard covering a 10-point action plan sets the minimum expectations for what must be included
in net zero transition roadmaps. The blueprint is the product of engagement between more than 20 investors managing over
US$10 trillion of assets, NGOs and oil and gas Majors.
The goal is to develop a set of consistent reporting standards to assess the credibility and adequacy of company transition
plans. Key aspects of the Net Zero Standards include:
•
Set an ambition to achieve net-zero emissions by 2050 (or sooner), including Scope 3 emissions for all products sold. Clearly
define short, medium and long-term targets
•
Outline a decarbonisation strategy to define the pathway to net zero and the contribution of each action to medium and longterm targets
•
Disclose future capital allocation plans for at least the next three years, breaking out upstream, exploration, CCUS and
‘green’ investment. Confirm that the investment strategy is aligned with net zero and set out key assumptions, including price
and carbon tax.
Our take: the standards in many ways mirror the blueprint outlined in our Commit and collaborate: squaring the circle for oil and
gas Horizons insight. Our note focused on the need for companies to commit to a more ambitious plan for Scope 1, 2 and 3
reductions, including bolder Scope 1 and 2 targets and a realistic Scope 3 reduction strategy. We also outlined the importance
of collaboration to achieve decarbonisation goals and how, to build credibility, companies should lay out a financial framework
for their energy transition.
The Net Zero Standard for Oil and Gas will help develop a standardised approach to assess climate risk and emissions
reduction performance. The plan emphasises the need to leverage existing disclosure frameworks, which will facilitate its
implementation. We also like the fact that it outlines the need for strategic diversity – we’d stressed that diversity of strategic
pathways should deliver more orderly decarbonisation in our Horizons note.
The Net Zero Standards will add further momentum to the decarbonisation agenda. The standards will now be piloted by a
group of leading oil and gas companies. These include BP, Eni, Repsol, Shell, TotalEnergies and, importantly as a leader in
carbon management in the US, Occidental. We expect this will pave the way for much wider implementation across the oil and
gas sector.
Tullow’s last hope in Kenya?
Scott Walker, 17 September 2021
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The facts: Tullow has submitted a draft field development plan to the Kenya authorities for an optimised design concept at its
South Lokichar project. Gross capital costs for the project are expected to increase by 20% to US$3.4 billion, which will facilitate
a proportionately larger increase in peak production, up around a third to 120 kboe/d. The company estimates it will reduce
overall project costs from US$31/bbl to US$22/bbl. The aim is to have a final field development plan submitted by year-end.
Tullow holds a 50% operated stake in South Lokichar, with field partners TotalEnergies and Africa Oil holding 25% each.
Our take: the revised field development plan could be Tullow’s final throw of the dice to secure a cost carry and progress South
Lokichar to FID. The company has allocated no capital to the project in its budget plan, freely acknowledging that its balance
sheet cannot support the development.
Tullow’s near-term financial constraints underscore the need to free up capital. Gearing is above 100% and we estimate the
company has an average breakeven of US$59/bbl out to 2023. Capital allocation is to be almost exclusively directed towards
extracting full value from its highest margin producing assets, Jubilee and TEN in Ghana.
Beyond this, the strategy is less clear. Finding a partner in Kenya would be material to Tullow, providing a route to accelerated
deleveraging and greater strategic flexibility. But first reports of an attempted farm-down go as far back as 2013, when the M&A
market was booming. In today’s environment, the odds don’t look good.
BP to partner ADNOC and Masdar on clean energy initiatives
Luke Parker, 16 September 2021
The facts: BP is to partner ADNOC (Abu Dhabi’s national oil company) and Masdar (the Abu Dhabi Future Energy Company –
wholly owned by the government’s Mubadala Investment Company) on clean energy initiatives in the UK and UAE. The
companies have signed agreements for future collaboration in three areas: 1) development of low carbon hydrogen across hubs
in the UK and UAE; 2) exploring sustainable energy and mobility solutions for cities; 3) deepening collaboration to decarbonise
oil and gas operations in Abu Dhabi, including CCUS.
Our take: Strategic partnerships – with countries, cities and industries – are core to BP’s IEC strategy. The announcements
have been coming thick and fast. But a strategic partnership with the UAE, albeit still early days, stands out as having the
potential to develop into something material. The agreements are broad in scope, spanning all three of BP’s strategic focus
areas. And the partnership appears to have the political backing that will be needed – UK Prime Minister Boris Johnson was
quoted in BP’s press release. See our recent Horizon – Commit and collaborate – for thoughts on the importance of
partnerships in decarbonisation.
BP brings in renewables big hitter to lead gas and low carbon energy
business
Luke Parker, 15 September 2021
The facts: BP has announced the appointment of Anja-Isabel Dotzenrath to EVP, gas and low carbon energy. Until recently she
was CEO of RWE Renewables – one of the world’s largest renewables players, second largest in offshore wind. Dotzenrath will
replace Dev Sanyal – a BP veteran of over 30 years.
Our take: We wouldn’t normally comment on HR matters, but this appointment is noteworthy for its broader resonance. It plays
to the question of how companies on a Big Energy pathway are evolving to align capability with strategy. A question that applies
at every level – from executive to coalface.
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Across the Euromajors, headcount is tilting – in parallel with investment – towards businesses in which these companies have
relatively little experience. Investors are rightly keen to understand more about how capability is being built, and risk managed.
Most of the Majors could do with being more transparent on this front.
BP’s appointment of Anja-Isabel Dotzenrath – a renewables big hitter from outside the business – sends a message. CEO
Bernard Looney has been candid in his assessment that Dotzenrath lends “enormous credibility” at executive level to the
company’s renewables growth strategy. That is particularly true of offshore wind – an important but relatively new area of growth
for BP, in which it has already looked externally to strengthen capability.
Meanwhile, the solar business – run under a very different, arms-length business model – is powering ahead. Lightsource BP
just announced a new target to develop 25 GW of solar by 2025 (50% net to BP) – an advance on its previous target of 10 GW
by 2023. That would take care of over half of BP’s Group target of 20 GW of renewables by 2025.
US Independents delivering on debt reduction
Robert Polk, 14 September 2021
The facts: Balance sheets for US Independents continue to improve on the strength of prices, commitments to capital
discipline, and focused debt reduction. The quarterly reduction in net debt in Q2 nearly equaled the prior three quarters
combined. The momentum continues in Q3 with known tenders or redemptions from ConocoPhillips, Occidental, APA, and
Marathon, among others.
Our take: With sustained capital discipline, US Independents are generating unprecedented free cash flow. While this windfall
allows producers to move past the distress of 2020 and deliver higher returns of capital to shareholders, the most consistent
priority across the peer group remains an ongoing commitment to reducing absolute debt.
Much stronger overall asset coverage ratios reflect this commitment. Average coverage, excluding restructurings, improved to
2.7x following Q2 2021 compared to 1.8x after Q2 2020. Higher valuations contribute, but the impact of targeted debt reduction
is apparent. Gearing ratios continue to fall in tandem, but accumulating hedge losses hinder additional improvements to
unadjusted capitalisation despite continued deleveraging.
Positive momentum is encouraging, but much of the peer group still has plenty of room for improvement to reach recommended
levels of resiliency. Recent commitments and accelerated targets from large and financially secure US Independents
underscore the strategic importance for the whole group. Wood Mackenzie’s updated Lower 48 Corporate Debt Monitor
assesses the progress made to date, the outlook for additional deleveraging, and the risks to continued balance sheet integrity.
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Chevron increases commitment to new energies
Alex Beeker, 16 September 2021
The facts: Chevron is accelerating its commitment to the energy transition. Cumulative capital investment is tripled from the
previous outlook to US$10 billion through 2028. That equates to more than US$1.0 billion per year. The Supermajor also raised
its overall annual budget by 7% through 2025 from US$14-16 billion to US$15-17 billion, reflective of higher new energies
spend.
The new energies guidance is well head of ExxonMobil’s planned US$3 billion spend over the next five years. But it still lags a
long way behind the Euro Majors.
Our take: By investing in CCUS, renewable fuels and hydrogen to service these customers, Chevron believes it can generate
double-digit returns and grow new energies operating cash flow to more than US$1.0 billion per year by 2030. But returns can
be heavily influenced by policy and not all jurisdictions are supportive at the moment.
Increased low carbon spend is certainly a positive step. It sends a strong signal of just how seriously oil and gas focused players
are taking decarbonisation. But has Chevron gone far enough?
Chevron will have to work hard to firm up visibility on its project pipeline. But the focus on longer-dated technologies may
constrain the pace of change – and risk coming under fire from stakeholders. Collaboration with other oil and gas players, other
industries and governments will be key to driving the decarbonisation strategy forwards.
Guyana resources edge closer to 10 billion boe with latest strike
Tom Ellacott and Alex Beeker, 13 September 2021
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Corporate week in brief
Our take: ExxonMobil and its partners have announced the Pinktail discovery on the Stabroek block, six kilometres to the
southeast of Yellowtail. The partners also completed the Turbot appraisal well, encountering 13 metres of net pay in a deeper
interval than in the original discovery well.
ExxonMobil operates the block with a 45% stake. Hess and CNOOC Ltd have 30% and 25% interests respectively.
The facts: Stabroek is a shining example of how exploration can drive portfolio improvement. Gross discovered resources are
now edging closer to 10 billion boe. The asset will have one of the lowest emissions intensities in ExxonMobil’s portfolio once at
plateau (9 tCO2e/kboe in our Emissions Benchmarking Tool). The asset also lies to the left of the global cost curve with an
NPV10 development breakeven of just US$28/bbl.
Pinktail and the 2021 Whiptail discovery add volumes to the Yellowtail-Redtail development cluster. The operator will target the
area with the fourth development module. A final investment decision is expected in 2022. We expect the area to turn into a
multi-FPSO development.
The Turbot-2 well has extended the string of success in stacked sands in separate, deeper intervals from the original
discoveries. The deeper intervals are likely to be Santonian – the same age as the key reservoir in Block 58 discoveries across
the border in Suriname. Deepening into these sands is a crucial part of the 2021 appraisal campaign.
The partners also announced a positive progress update on the Liza development with the conclusion of the FPSO Liza Unity
construction. The Phase 2 FPSO will arrive in time for installation and an early 2022 start-up.
See our Inform for more details.
Chevron makes multiple announcements ahead of energy transition call
Alex Beeker, 10 September 2021
The facts: last week, Chevron made multiple announcements related to its energy transition strategy. The company is hosting a
conference call this Tuesday, 14 September 2021 to discuss how it plans to reduce emissions intensity in current operations
and grow lower carbon businesses.
Last week’s announcements included:
•
An MOU with Google and Delta Airlines to track sustainable aviation fuel (SAF) emissions data using cloud-based
technology.
•
•
A letter of intent with Gevo, Inc. to jointly invest in a facility that would process inedible corn into SAF.
A collaboration agreement with Caterpillar to develop hydrogen demonstration projects in transportation and stationary power
applications. The aim is to create demand for hydrogen in the heavy-duty transportation and industrial sectors, which are
typically harder to decarbonise.
The announcements come just days after it was reported that Chevron executives met with representatives from Engine No. 1,
the investment firm that won three seats on ExxonMobil’s board earlier this year. The meetings are a sign Chevron is likely to
face mounting pressure over its energy transition strategy.
Our take: the announcements are a preview of what we anticipate from Tuesday’s call. Renewable fuels, hydrogen, and CCUS
remain at the centre of Chevron’s energy transition strategy. Capital committed to these areas is still dwarfed by upstream
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spend, but it’s trending upwards. Chevron has allocated US$300 million of its 2021 budget to the energy transition vs US$11.5
billion for upstream.
On the call, we expect Chevron to defend the Big Oil business model and justify why things like SAF and hydrogen are
necessary for a lower carbon future. A Scope 1 and 2 net zero target or a commitment to address Scope 3 emissions are
unlikely to be announced anytime soon. Chevron has continually said it needs a clear path to net zero before it makes a
commitment. Any change to this messaging would be a major shift in strategic stance.
ExxonMobil to certify Permian natural gas
Tom Ellacott, 9 September 2021
The facts: ExxonMobil has signed an agreement with MiQ, an independent validator, to certify around 200 mmcfd of gas from
the Poker Lake field in the Permian. The certified gas could be available for customers by Q4 2021.
Our take: this latest responsibly sourced gas (RSG) agreement follows a series of announcements by prominent US
independents such as Chesapeake and EQT also looking to certify production. The big difference here is that most wells
seeking or obtaining certification to date have been located in gas-weighted plays.
ExxonMobil looking to certify Permian associated gas is a positive sign for the RSG movement and could have an outsized
impact on Permian emissions if other producers follow suit. Keep in mind that Permian production features higher methane
intensity than gas plays.
MiQ’s certification framework assesses and grades methane intensity, enhanced monitoring technology deployment and
emissions reduction operating processes. It will provide a credible third-party validation of ExxonMobil’s efforts to reduce
methane emissions by 40% to 50% by 2025.
RSG can potentially fetch premium pricing of up to 10 cents/mcf. However, the market is still nascent. But the concept is
catching on so fast that it will likely be table stakes for every big producer before we know it. This initial agreement only covers a
fraction of ExxonMobil’s 2.5 bcfd of US gas production. We expect the SuperMajor to expand the certification process to other
Permian fields and shale plays, including Appalachia and the Haynesville.
TotalEnergies strikes major cross-commodity deal in Iraq
Tom Ellacott, 6 September 2021
The facts: TotalEnergies has signed major contracts covering the production and exploitation of oil, gas and solar energy in
Iraq. The agreements include:
•
The construction of a new gas gathering network and treatment units to supply local power stations. The project will recover
gas that is being flared on five oil fields providing feedstock for 1.5 GW of power generation capacity in a first phase, rising to
3 GW in phase two.
•
TotalEnergies will upgrade oil and gas production from the Ratawi field through drilling and building and operating new
capacities.
•
The construction of a large-scale seawater desalination unit to increase the water injection capability in southern Iraq fields.
The water injection is needed to maintain pressure in several fields.
•
The construction and operation of a solar PV power plant with a capacity of 1 GWp to supply electricity to the grid.
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TotalEnergies estimates the projects will need a total gross investment of around US$10 billion (100% share) over the first
decade. The Iraqi government estimate US$27 billion over the lifetime of the projects.
Our take: the agreements are evidence of TotalEnergies’ dual growth strategy in action. The company has signalled that largescale upstream business development is still on the agenda as it transitions to a broad energy company. But these landmark
cross-commodity agreements have a strong sustainability angle: reducing flaring, water resource management and developing
solar power generation.
TotalEnergies remains open to business in areas of high above-ground risk. The move is out of step with peers that are
reducing their exposure to Iraq. TotalEnergies will lean on its geographically diverse global portfolio to manage risk. The scale of
the investment also underscores that Iraq could play an important role in TotalEnergies’ long-term future, both in terms of lowcost upstream resources and a renewables market.
TotalEnergies already holds a deep global development pipeline. Overall investment increases in our base-case, driving cash
flow breakevens up. Large-scale investment in Iraq is now added to the mix. We expect TotalEnergies to seek financing and
additional partners to reduce its capital outlay. The company will also rely on rapidly bringing the Ratawi project online to selffinance future spend. Finally, the Supermajor may turn to asset sales to reduce its net investment and lower breakevens.
For more details, read our Inform.
Beneficiaries of gas price rally separated by hedge books
Alex Beeker & Matt Woodson, 3 September 2021
US natural gas prices surged +7.4% last week to US$4.71/mmbtu which is their highest level since November 2018. LNG prices
into Asia surpassed US$20/mmbtu and European gas prices also set record highs last week.
A combination of factors are playing into the price rally including hurricane-related production outages in the Gulf of Mexico,
hotter than average temperatures, less than expected gas injections into storage and upstream producer capital discipline. But
companies won’t benefit equally from the rally. Hedge books are a large differentiator.
Our recently updated hedging monitor shows 8.0 bcfd of gas hedges were added during the second quarter at a weighted
average hedge price of US$2.7/mmbtu (Henry Hub). But volumes and price vary widely among companies. The chart below
highlights some of the biggest gas producers covered in the insight.
CNX, EQT, Southwestern and Antero are more than 90% hedged this year. CNX and Southwestern are more than 80% hedged
next year. Weighted average hedge prices range from US$2.44/mmbtu (CNX) to US$2.85/mmbtu (Antero). But a notable
exception is Cabot which hedged just 24% of volumes this year and remains unhedged next year.
Although these companies and their investors would undoubtedly prefer to be benefiting from the price rally, it’s important to
remember these hedges were originally put in place to ensure positive free cash flow this year. Strategies that stick to capital
discipline, debt reduction and shareholder distributions will outlast any near term price volatility.
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CNOOC announces first offshore CCS project
Kavita Jadhav, 3 September 2021
The facts: CNOOC announced plans for China’s first offshore carbon capture and storage project. The project will sequester
300,000 tonnes of CO2 per year with ultimate capacity to sequester more than 1.46Mt of CO2 over its lifetime. CO2 associated
with development of the Enping 15-1 field located in the South China Sea will be injected into a saltwater layer in the field itself.
Our take: this would be China’s first offshore project and the first to permanently store CO2. Previously, there have been a small
number of demonstration projects onshore which have tested storage of up to 150,000 tonnes of CO2 per year. Peer Sinopec's,
recently announced onshore CCS project will utilise CO2 for EOR, but currently has no provision to permanently store CO2 that
returns to the surface.
CNOOC has not provided any details yet on dates for FID or start-up. The Enping 15-1 field is currently under development and
expected onstream in 2024. The CCS project will be an auxiliary facility at the Enping 15-1 field and could also potentially
commence in 2024.
The capacity of this project at 300,000 tonnes of CO2 per year is similar in size to Phase 1 of the Acorn CCS project in the UK.
However, Acorn plans to increase capacity in phases to 5-6mmtpa by 2030. CNOOC’s CCS project would be a small, project
specific development and could potentially be a precursor to larger scale hub type projects. For CCS to contribute to emission
reduction in China it would have to be implemented at scale.
CNOOC announced along with H1 2021 results that it intends to spend 5-10% of annual capex of US$14-15 billion on new
energy and emissions reduction, to reach its goal of net zero by 2050.
Eni discovers a whale offshore Cote d'Ivoire
Greig Aitken, 3 September 2021
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The facts: Eni has announced a giant deepwater Cretaceous light oil (40 °API) discovery in Cote d’Ivoire. Drilled on the edge of
the CI-101 licence in 1,210 metres of water, Baleine-1X encountered oil and gas in Santonian and Cenomanian/Albian
reservoirs. The well was successfully tested and drilled in just one month.
Eni estimates oil-in-place of 1.5 to 2 billion barrels and 1.8 to 2.4 tcf of gas. It is the largest discovery ever made in Cote d’Ivoire.
Eni (90%) and PETROCI (10%) will appraise Baleine and develop near-term development options.
Our take: We estimate recoverable oil and gas resources of 760 mmboe. There could be more upside with the structure thought
to extend into neighbouring CI-802, awarded to Eni earlier this year.
We expect Eni will look to farm down here in-line with its “dual exploration” model, which seeks to quickly monetise new
discoveries as it fast-tracks development. Assuming an initial phase starting-up in 2025, with a converted 100,000 b/d leased
FPSO, we value the project at US$1.9 billion (NPV10, Jan 2021, US$50/bbl long term), with an IRR of 24%.
Exploration is a core strength for Eni and remains central to its near-term strategy. It is targeting 2 billion boe of new resources
out to 2024 and already has a string of successes this year in Angola, and Mexico, while Baleine comes hot on the heels of the
Eban discovery in Ghana.
For more details, read our Inform.
Shell announces big expansion of ubitricity EV charging network
Luke Parker, 2 September 2021
Shell subsidiary ubitricity has announced plans to install 50,000 on-street EV charge points across the UK by the end of 2025,
from its current 3,600. Shell acquired ubitricity in Q1 of this year. The company’s USP is installing EV charging into existing
street infrastructure such as lamp posts. We took an in-depth look at the strategy at the time: Never mind the bollards?
50,000 charge points would make a big dent in the UK’s ambitions to grow EV charging capacity. The UK Committee for Climate
Change recently recommended that the country needed 150,000 public charge points by 2025 (vs 25,000 today), and between
280,000 and 480,000 by 2030. Shell itself is aiming to grow its global EV charging network to over 500,000 charge points by
2025 (from 60,000 today) and around 2.5 million by 2030.
Sinopec Corp’s first half profits soar, bets big on hydrogen
Kavita Jadhav, 30 August 2021
The facts: Sinopec Corp reported a profit of RMB40 billion (US$6 billion) for H1 2021, up from a loss of RMB22 billion in H1
2020. The company has declared an interim dividend of RMB0.16 per share, more than double the RMB0.07 per share in H1
2020. Oil and gas production increased 4.2% year-on-year.
Our take: Sinopec Corp had a strong set of financials in the first half due to a rebound in commodity prices and domestic
demand. The company went a step further from its previously set net zero goals to unveil an ambitious energy transition
strategy, hinged on hydrogen. Sinopec will spend RMB30 billion (US$4.6 billion) by 2025 to accelerate its hydrogen, wind and
solar business.
•
Financials: revenue jumped 22% to RMB1.26 trillion from higher gas production and an increase in refinery margins and
throughput as refineries were upgraded to produce more high-value products. Sinopec guided that second-half sales will
improve further relative to the first six months.
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•
Production: gas production increased 13.7% and Sinopec aims to raise natural gas production for 2021 by 10% from 2020.
Sinopec processed a total of 126 million tonnes of crude oil, up nearly 14% and Ethylene production also jumped 12%.
•
Capex: capital expenditure for the half-year came in at RMB58 billion (US$9 billion), about 35% of its full-year investment
plan of RMB167 billion. Like peer PetroChina, Sinopec will have to increase spend in the second half to meet its full year
budget.
•
New Energy: Sinopec aims to build China’s largest supply chain for automotive hydrogen by setting up 1,000 hydrogen
refuelling stations with 200,000 tonnes of annual refuelling capacity. Sinopec will leverage its current network of 30,000 fuel
stations, modifying them to provide hydrogen and solar power. The company also plans to upgrade its refineries and
petrochemical plants to use green hydrogen in its own operations. The goal is to avoid the emission of 10 million tonnes of
carbon per year by 2025.
PetroChina hits record earnings on price and demand recovery
Kavita Jadhav, 30 August 2021
The facts: PetroChina’s net profit rose to RMB53 billion (US$8 billion) from a loss of RMB30 billion in H1 2020. Higher profits
enabled the company to increase its dividend to RMB0.13 per share versus RMB0.09 per share in H1 2020. PetroChina’s oil
and gas production of 4.5 million boe/d declined by 1.7% y-o-y. Refinery throughput rose 6.7% to 3.35 million b/d. Capital
expenditure was similar to H1 2020 totaling RMB74 billion (US$11.5 billion).
Our take: PetroChina had a strong set of financials in the first half, triggering a 49% jump in the dividend. The company also
used the results to shed more light on its new energy strategy with a commitment to transitioning the portfolio to oil, gas and
green energies each accounting for a third by 2035.
PetroChina described H1 2021 as its highest half-year profit in 7 years. However, US$2 billion was attributable to one-off gains
as the company completed the disposal of Kunlun Energy pipeline. Higher oil and gas prices and downstream margins and
throughput also played an important role.
•
Financials: the company continued its focus on making the downstream more profitable with a reduction in refining and
increase in chemicals contributions. Chemical output was up 6.3% and profits nearly doubled year-on-year. Gearing at 21.6%
was marginally higher than 21.3% as of 31 December 2020.
•
Production: lower production was driven by a reduction in overseas oil production of nearly 34%. The company said that this
was due to lower output on PSCs due to higher oil prices and production restrictions in certain countries. PetroChina guided
to full-year output growth of 1.5% in 2021.
•
Capex: H1 2021 capital expenditures represents only 31% of PetroChina’s 2021 target. Mirroring the trend in 2020, the
company will increase spend in the second half as it maintains its 2021 outlook to spend RMB239 billion (US$37 billion).
•
Dividends: the cash dividend for H1 2021 is, in absolute terms, the highest since 2015.
•
New Energy: PetroChina plans for a net carbon emission peak in 2025 and to achieve near zero emissions by 2050. The
immediate focus is to raise the share of gas to 55% by 2030, up from about 46% in H1 2021 but achievable based on our
analysis. In addition to expanding natural gas production, PetroChina is zeroing in on geothermal, solar and wind power, by
adding renewable projects in 2021 with total capacity of 3.45 million tonnes of standard coal equivalent.
Heavy derivative losses continue for US producers
Matt Woodson, 27 August 2021
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We estimate the 52 operators included in Wood Mackenzie’s hedging model have realized a combined hedging loss of US$9.8
billion through July. US Permian producers have been especially hard hit and account for 35% of that total. Losses will continue
as the ten Permian-focused operators modeled have hedged between 20%-66% of crude production through the end of the
year at an average strike price of US$46/bbl (Brent).
Despite this hit to cash flows, hedging activity remained elevated and the peer group managed to layer on 2022 and 2023
protections at more favorable pricing. A net 475 kb/d in post-2021 oil hedges was added during the quarter at an average strike
price of US$58/bbl. EOG, Ovintiv and Whiting added over 50 kb/d each. To date, the group has hedged a combined 13% of
projected 2022 oil production.
Our peer group also added over 8 bcf/d in new gas protections – beating the record set during Q3 2020. The average strike
price was US$2.70/mcf (Henry Hub). Appalachian gas producers EQT, Southwestern and Range led this surge in gas hedging
activity. EQT alone added over 2 bcf/d in protections, including hedge volumes acquired through its purchase of Alta Resources.
Read our soon to be published hedging update Insight for more detail.
Unrealized hedge valuations based on US$65.50/bbl Brent price
Chevron, BP and Imperial Oil accelerate renewable fuels investments
Alex Beeker, 27 August 2021
The facts: all three companies made investments in renewable natural gas (RNG), renewable diesel and energy storage last
week. Highlights include:
•
BP announced a 15-year agreement with CleanBay Renewables to purchase renewable natural gas (RNG) for use in
California’s transportation sector. The RNG is processed from poultry litter.
•
Chevron, which initially produced and sold dairy biomethane (also known as RNG) in Q3 2020, announced an extension of
its partnership with Brightmark RNG Holdings and reinforced its commitment to grow RNG volumes 10x by 2025. Chevron
also made an investment in Malta Inc., a company focused on utility-scale, long-duration electro-thermal energy storage.
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•
Imperial Oil outlined a plan to produce renewable diesel from the Strathcona refinery located in Alberta, Canada.
ExxonMobil, which owns a 69.6% stake in Imperial, has set a target of producing 40 kb/d of low-emissions fuels by 2025.
Our take: individually, the announcements may seem small but collectively they’re part of a growing trend of increasing
renewables investments, even among the US Majors. The majority of new energy spend still goes toward utility-scale wind and
solar projects. But technologies like CCUS, renewable fuels, geothermal, hydrogen and energy storage will also play an
important role in energy transition strategies.
Canada and California have low carbon fuel standards (LCFS) in place that incentivize the production of renewable fuels to help
decarbonize the transportation sector. Demand for renewable fuels could continue to grow as more countries and US states
adopt clean fuel standards. These investments are about laying a foundation for longer-term expansion. Chevron’s investment
in long-duration energy storage is also a step in positioning the company to help resolve the intermittency challenge created by
a growing share of renewable energy on the grid.
We calculate the Majors' new energies M&A investments have exceeded US$8.0 billion this year, already more than doubling
last year’s total. The direction of travel is clear: US$7.0 billion of net upstream divestments from the Majors in the year to date
roughly offsets the new energy M&A spend.
CNOOC Ltd’s profits soar on higher oil price
Kavita Jadhav, 19 August 2021
The facts: CNOOC Ltd’s half-year profits increased 221% year-on-year. Output increased 7.9% y-o-y to reach an average of
1.5 million boe/d in H1 2021, with six new projects online and improved recovery from existing fields.
CNOOC shared the upside with shareholders and increased its dividend by 50% y-o-y to HK$0.3 per share. Gearing reduced
from 24.9% to 23% and management reaffirmed its full-year investment guidance of RMB90-100 billion (US$14-15 billion).
Our take: The profit increase was largely fueled by higher oil prices with some contribution from higher production. The record
increases were against H1 2020 which was unusually suppressed from the pandemic and oil price crash. Unit operating costs
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increased albeit from a 13-year low in 2020, but managing emerging cost inflation is an area of management focus. Analyst
questions focused on CNOOC’s investment in new energy. CNOOC expounded a strategy which would focus on increasing
share of gas and building an offshore wind business. This strategy has been tested successfully by Equinor with its' combination
of a largely upstream business and a leading position in offshore wind.
Financials: Net profit of RMB33 billion (US$5 billion) trebled y-o-y. Free cashflow of RMB38 billion (US$6 billion) was available
after capex of RMB31 billion and dividends of RMB9.3 billion. CNOOC’s dividend yield of over 7% is comparable to the top
international oil majors.
Production: Share of gas remained unchanged at 20% and overseas production proportionately fell again, with domestic
production increasing from 67% to 69%. CNOOC is following an exploration led strategy, with plans to achieve a Reserve
Replacement ratio of 120%. In the first half CNOOC made discoveries in China and Guyana. Wood Mackenzie’s view is that to
raise gas to 50% of its 2035 output, the company will need to deliver exploration success and selective acquisitions.
Capex: Six out of nineteen new projects planned for the year commenced production and management indicated some delays
in overseas projects due to the pandemic. Most of the projects coming onstream in 2021 are oil fields. Management reaffirmed
guidance for capex of RMB90-100 billion (US$14-15 billion), similar to BP and Chevron and higher than Equinor (US$9-10
billion).
New energy: CNOOC’s pivot to low carbon will initially focus on increasing share of gas from 20% now to 35% in 2025 and
50% by 2035. Start-up of Lingshui, CNOOC’s first offshore large-sized independent deepwater gas field was testament to this
strategy. CNOOC intends to spend 5-10% of annual capex on new energy with a focus on offshore wind to leverage offshore
upstream expertise. CNOOC has signed a strategic cooperation agreement with domestic offshore wind specialist China Three
Gorges to collaborate in developing offshore wind projects.
Alaska court blocks ConocoPhillips' Willow project
David Clark and Rowena Gunn, 19 August 2021
The facts: The US District Court in Anchorage has blocked ConocoPhillips’ Willow project on Alaska’s National Petroleum
Reserve, vacating permits granted last fall by the Bureau of Land Management and the US Fish and Wildlife Service. The ruling
on the BLM permit found that the agency’s exclusion of foreign greenhouse gas emissions in its analysis was “arbitrary and
capricious.” The judge vacated the USFWS permit due to insufficient specifics regarding polar bear impact mitigation. The
permits had been granted under the Trump administration in October, but the Biden administration had filed a brief in support of
the approval in May. The project had also been held up in February after the 9th Circuit Court of Appeals issued an injunction,
affirming an earlier District Court emergency order, stopping ConocoPhillips from opening a gravel mine site in order to build
roads to support the project. Hearings were held in late April, then the case was sent back to the District Court to hear the
broader case. Following this new ruling, ConocoPhillips says they are considering their available options.
Our take: The US$8 billion Willow project, which ConocoPhillips called “The Next Great Alaska Hub” in its June investor
meeting, was expected to start up in late 2027, with development work commencing in 2022. Initial development was to include
three drill-sites and a central processing facility (with 180 Kb/d oil and 250 mmcf/d gas capacity) and would produce a peak of
about 150 Kboe/d later in the decade. North Slope construction is limited to the winter, so whether an appeal is made, or is
successful, this delay will likely at minimum push the project back by a year. We model a one year delay to the Willow project
would reduce the project NPV by over 7%.
The project would allow ConocoPhillips to leverage existing infrastructure capacity. The company own 29% of the TAPS pipeline
system, other North Slope production hubs, and a wholly owned and operated fleet of five double-hulled tankers, Polar Tankers,
that delivers oil from the TAPS terminus in Valdez to the US West Coast. That infrastructure advantage is an important driver of
Willow’s potential low cost of supply (mid-$30’s/bbl), which is a central feature of ConocoPhillips’ development decision-making.
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Longer-term, the Willow project could potentially expand to include other nearby discoveries, as exploration both west and south
of Willow show promise.
Due to project uncertainties, ConocoPhillips has left Willow out of its ten-year development plan. A positive FID would allow the
company to exceed its moderate company-level growth plan (~3% per annum) for the next decade. The project would also
provide an important long-cycle diversification counter-weight to the short-cycle Permian.
ConocoPhillips has announced its intention to farm-down some of its Alaska business to achieve its broader US$2-3 billion by
2022 year-end disposal target. The delays and risks around Willow may influence the decision to move forward with farm-outs.
On the one hand, it may lose some appeal, as the assets support portfolio diversification, which is framed as a unique
advantage by the company. On the other, Alaska is arguably becoming a riskier place to operate – though existing projects
outside of the NPR-A aren’t impacted by the current court case or new project permitting.
Woodside and BHP agree to merge oil and gas businesses
Andrew Harwood, 18 August 2021
The facts: Woodside and BHP have agreed to combine their respective oil and gas businesses to create a new international
‘super independent’. It's the second massive Australian merger this month, hot on the heels of Santos-Oil Search. Under the
terms of the all-stock merger, Woodside will issue new shares to BHP shareholders in return for BHP’s entire Petroleum
division, debt free. Ownership of the merged portfolio will be split between Woodside and BHP shareholders on a fixed 52:48
ratio, based on the respective net values of the underlying assets.
Our take: This is a deal of the times, with energy transition writ large in the rationale of both companies. For Woodside, the
combination is about creating an oil and gas business better equipped to deal with the uncertainty and upheaval of the next few
decades. For BHP, this is about getting out of oil and gas altogether and leaning into ‘future facing’ commodities that will support
its energy transition strategy.
https://my.woodmac.com/web/woodmac/document?contentId=519278&source=30&isVideo=0&isPresentation=0For more on
what the merger means for Woodside and BHP, including analysis of the combined portfolio through LENS, take a look at our
Inform.
For thought leadership on the bigger issues at play, read our latest Horizons note: Commit and collaborate – squaring the
carbon circle for oil and gas.
Ecopetrol buys stake in ISA for US$3.6 billion
Raphael Portela, 12 August 2021
The facts: The deal signed with Colombia's Finance Ministry is for a 51.4% stake in the electricity transmission company
Interconexion Electrica SA (ISA). ISA owns energy, transportation, and telecommunications operations in Colombia, Brazil,
Chile, Peru, Bolivia, Argentina, and Central America.
Our take: Admittedly, the potential ISA acquisition announcement back in January caught us by surprise. And scepticism from
investors is warranted. First, the sale would unlock funds for the cash-strapped Colombian government without much loss in
ownership – the state has an ~89% stake in Ecopetrol. Second, the argument for counteracting crude price volatility with a
steady, predictable cash flow stream is also weak. Ecopetrol's midstream unit already fulfils that role, as evidenced during the
pandemic.
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The deal's merit boils down to Ecopetrol's strong views on the energy transition. The company sees this megatrend as an
opportunity to establish leadership in Latin America. Integrating ISA would deliver benefits like lower carbon risk and access to
other Latin American markets for future business, aligning well with upstream 's internationalisation ambitions.
Still, transmission has even less skill overlap with oil and gas than renewables. And its place in Ecopetrol's energy transition
strategy is unknown – short-term plans tout increasing renewables output for self-consumption while the long-term aim is to
evaluate full-scale opportunities in renewables, hydrogen, CCUS, and so on. Regulatory restrictions further complicate matters,
with entry into Colombia's transmission market precluding Ecopetrol from generating electricity for sale in the country.
Financially, the valuation is reasonable, representing a 16% premium to ISA share price and a multiple of 4-5x EBITDA (using
2017-2020 reported numbers). But the deal will put a considerable strain on Ecopetrol's balance sheet. The NOC is relying on
debt to fund the transaction, despite not trimming its net debt in 2021 like many other E&Ps and maintaining pre-deal gearing
(47%) above pre-pandemic levels.
Source: Ecopetrol
Chesapeake acquires Vine Energy
Adela Kim and Mike Stinebaugh, 12 August 2021
The facts: Chesapeake Energy announced it will acquire Vine Energy for US$2.2 billion in stock (92%) and cash (8%). Vine
Energy holds 123,000 net acres in the Haynesville and Bossier Shale with net production of 1,050 mmcfd as of Q2 2021. Vine
shareholders will receive 0.2486 Chesapeake shares of common stock and US$1.20 cash for each share. This equates to
US$15 per share and represents zero premium to Vine's stock price. The deal is expected to close in Q4 2021.
Our take: The Haynesville became a core part of Chesapeake’s portfolio as the company focused on developing its gassy
assets after emerging from bankruptcy earlier this year. We’re not surprised to see Chesapeake doubling down on one of its
best gas assets, as we expected the company to get aggressive under new leadership.
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This acquisition brings Chesapeake back to its former leading position in the Haynesville; pro-forma production will be 1.6 bfcd.
The deal is another example of the leading US M&A trend - companies striving for a ‘basin dominance’ growth strategy.
Having completed an IPO in Q1 2021, Vine is exiting during a time period when Henry Hub prices are at a premium. The sale
allows Blackstone, Vine’s private equity sponsor, to exit into a larger multi-basin upstream natural gas company with many more
years of drilling inventory.
Saudi Aramco profits surge
Norman Valentine, 9 August 2021
The facts: Saudi Aramco’s quarterly net income nearly trebled year-on-year as rebounding oil prices and improved downstream
margins offset lower oil output (-9% y-o-y to 11.6 million b/d). Half year net profit of US$47.2 billion doubled compared to 2020
and was broadly in line with the pre-crisis figure for 2019.
Higher quarterly cash flow from operations (+243% y-o-y to US$30 billion) supported dividend commitments and higher
quarterly capital expenditure (+20% to US$7.5 billion) with excess cash flowing through to the balance sheet. Gearing fell from
23% to 19% over the quarter. Deleveraging was also helped by the US$12.4 billion sale of a 49% stake in Aramco’s crude oil
pipeline business. Aramco’s dividend proposal for Q2 was maintained at US$18.8 billion.
Our take: higher oil prices and proceeds from the crude pipeline sell-down boosted Aramco’s balance sheet in Q2. Based on
our US$63/bbl Brent oil price assumption for 2021, Aramco reaches its 5-15% gearing target by year-end using our models.
This would put Aramco in a strong position to increase its investment budget and dividends in 2022. Additional asset sales could
further boost financial firepower and management confirmed that negotiations on asset monetisation continue.
Analysts repeatedly questioned Aramco’s CEO and CFO on the company’s capital allocation priorities and its appetite to invest
in new growth opportunities. Responses gave a broadly positive outlook on: i) expansion in maximum sustainable oil production
capacity to 13 million b/d, ii) potential investment in new energy (renewables, hydrogen and CCUS) and iii) possible projects
within the Saudi government’s Shareek (partnership) programme. Optionality and sustainability were common themes while
Aramco also aims for double digit returns on new growth initiatives.
Santos and Oil Search merge to create Australia's new leading E&P
Scott Walker and Andrew Harwood, 6 August 2021
The facts: Santos and Oil Search announced agreement on a revised all-scrip merger proposal on 2 August 2021, after merger
discussions were first disclosed on 20 July 2021. The revised proposal will see Oil Search shareholders receive 0.6275 new
Santos shares for each Oil Search share held. This equates to an offer of A$4.29/share – a 16.8% premium to the Oil Search
closing price on 19 July 2021, the day prior to disclosure of the initial proposal. Under the latest proposal, Santos and Oil Search
shareholders will own 61.5% and 38.5% equity in the combined entity, respectively.
Oil Search had rejected a previous offer of 0.589 Santos shares per Oil Search share as undervaluing the company. The initial
approach made on 25 June 2021 equated to a bid price of A$4.25/share – a 12.5% premium to Oil Search's share price a day
prior to the offer. Under this initial merger proposal, the combined group would have been owned 63% by Santos shareholders
and 37% by Oil Search shareholders.
Oil Search's board intends to unanimously recommend the revised merger proposal to its shareholders, subject to completing
the necessary due diligence, which is expected to take four weeks.
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Our take: we believe there is a compelling case for a merger of Santos and Oil Search, creating an operator with the requisite
scale, thematic focus and financial footing to remain resilient through the energy transition.
With a combined market capitalisation of over US$16 billion, the company will surpass that of local rival Woodside Petroleum.
The merged portfolio will consist of Santos' Australian operations, overlapping LNG interests in Papua New Guinea and Oil
Search's operations in Alaska, United States. The complementary nature of Santos and Oil Search's interests in Papua New
Guinea will increase the combined entity's LNG-focus, a strategically important resource theme for the transition to lower-carbon
sources of energy.
We model production rising from 314 kboe/d in 2021 to nearly 450 kboe/d by 2030. As one of the top 20 largest international,
publicly listed, independent E&Ps, the combined entity will be well placed to weather demand uncertainty and price fluctuations.
Look out for our upcoming Deal Insight for a more detailed view.
US independents Q2 results, week 2: hedging headwinds, but cash still
delivered
David Clark, 5 August 2021
The facts: a compact schedule of 22 US independents reported Q2 earnings this week. On top of the ten that reported last
week, we now have 32 data points on how the Lower 48-focused E&Ps are doing through the first half of the year in terms of
capital discipline, deleveraging, and cash return to shareholders.
Our take: as a group, the US independents had headline earnings of US$1.63 billion in Q2. But ConocoPhillips (US$2.09
billion) and EOG (US$907 million) accounted for ~US$3 billion of positive net income, while the other 30 companies had an
aggregate (unadjusted) loss in the quarter of ~US$1.37 billion. Seventeen of those thirty were “in the red”, mostly driven by
hedging losses.
Overall, the group reported Q2 derivative losses of US$10.4 billion, including US$2.8 billion of cash settlement payments.
The nine gas-focused E&Ps, in particular, were hard-hit, reporting a collective net loss of US$2.8 billion due to US$4.3 billion in
derivative losses. ConocoPhillips was the only US independent that was hedge-free in the quarter. Occidental had modest
hedging losses, and would have reported a slim profit - but for the ~US$200 million quarterly preferred dividend payment to
Berkshire Hathaway. We expect Q2 to be the nadir for derivative losses, though they will likely continue to be a feature of 2021
updates.
But the sector bottom-line was misleading - operating cash flow (ex-working capital) rose from $17 billion in Q1 to US$20.5
billion in Q2, and free cash flow climbed from US$8.8 billion to a robust US$11.4 billion. Cash returned to shareholders
(dividends + buybacks) rose from US$2.1 billion in Q1 to US$2.5 billion in Q2 – and that does not include the EOG US$1/sh
special dividend declared in May, paid on July 30. Several companies “upped” their return of cash plans – e.g., Pioneer pulling
its initial variable dividend forward from 2022 to Q3 and increasing payout to 75% of FCF (post-base dividend), Marathon
moving its minimum dividend + buyback target from 30% to 40% of OCF.
Importantly, the US E&Ps continued to maintain capital discipline. There were no meaningful increases to 2021 budgets, despite
the US$20+/bbl rise in oil since the beginning of the year. The group-wide reinvestment rate was ~45% in Q2 (42% among
the oil-focused) with WTI averaging about US$66/bbl, a bit below the ~48% in Q1 when WTI averaged US$57/bbl. Certainly
aided by DUCs, but a reinvestment rate of 46% through H1 augurs well for cash return to shareholders, even if moderate growth
returns in 2022.
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As a group, the over-levered E&Ps reduced net debt by US$8.1 billion in Q2 (versus US$2.6 billion in Q1, though US$2.2
billion of incremental debt from four closed deals distorted that total). Aggregate book gearing fell from 40.8% to 38.9% in the
quarter. The year started at ~43%.
Cost inflation worked its way onto almost every conference call. Few hard numbers, but a general view that inflation is shifting
from steel, diesel and chemicals in H1, to include labor, trucking and services in H2.
Record Q2 profitability for Latam NOCs
Raphael Portela, 5 August 2021
The facts: Petrobras and Ecopetrol reported earnings this week. And in theme with the Olympics, results were record-breaking.
Petrobras’ EBITDA margin came in at 54%, thanks to 20%+ uplifts in its three business lines. Free cash flow surged to US$9.3
billion, a company best. For Ecopetrol, highlights included a 49% EBITDA margin versus 24% in Q2 2020 and net income of
US$1 billion.
Our take: profitability in oil and gas is coming back with a vengeance. And it’s no different for the Latin American NOCs.
Petrobras and Ecopetrol represent the cream of the crop, with Q2 results reflecting that leadership.
Petrobras stood out, delivering on all fronts. The company accelerated its debt payment, surpassing the US$67 billion gross
debt target for 2021 (US$64 billion in Q2). The Brazilian NOC thinks it can reach US$60 billion by Q4, meeting its 2022 target a
full year ahead of schedule.
Achieving that indebtedness would kickstart higher shareholder distributions, computed as 60% of operating cash flow minus
capex*. The fast-tracking of dividends, together with the announced US$6 billion disbursement for 2021 – well above the
mandatory minimum and three times the 2018-2020 average – is likely the cause behind its share price closing 8% higher on
the day.
*Capex used in the dividend formula excludes bid rounds and acquisitions.
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Raízen IPO puts a US$6 billion value on Shell’s Brazilian biofuels business
Luke Parker, 5 August 2021
The facts: shares in Raízen – the Brazilian biofuels JV between Shell and Cosan – saw their first day of trading Thursday on
the São Paulo Stock Exchange, following the IPO of ~9% of the company. The listing price of R$7.40 per share raised US$1.15
billion, putting a value of around US$13 billion on Raízen. That marks Shell’s 43.5% equity stake in the company (down from
48.25% pre-IPO) at around US$5.6 billion. Post-IPO, Shell and Cosan will each retain 50% of the voting rights in Raízen, and
Shell will continue to account for Raízen as a consolidated subsidiary.
Our take: Shell has big ambitions for growth in low carbon fuels. The company aims to produce 8 times more in 2030 than it did
in 2020. Through its stake in Raízen, Shell already ranks as one of the world’s largest blenders and distributers of biofuels. The
February 2021 acquisition of Biosev took Raízen’s production capacity to 3.75 billion litres of bioethanol and 4.4 million tonnes
of sugar. By way of comparison, BPBunge – BP’s 50:50 Brazilian biofuels JV – has production capacity of 1.5 billion litres of
bioethanol and 1.1 million tons of sugar.
The primary driver for the IPO is access to capital, as Raízen looks to fund its aggressive growth strategy. As well as the Biosev
deal, Raízen recently announced the acquisition of Shell’s Brazilian lubricants business (both yet to complete) and is pushing to
expand second-generation biofuels production capacity. The IPO also puts a number on the value of Shell’s holding – improving
see-through valuation for the entire group. See our recent note – Should the Majors spin off new energy? – for detailed analysis
of the pros and cons of equity carve out structures.
ConocoPhillips Q2 results: post-Concho earnings soar
Matt Woodson, David Clark, 3 August
The facts: with all Concho acquisition expenses in the rearview, ConocoPhillips’ cash flow from operations more than doubled
from Q1, to US$4.25 billion. Adjusted earnings came in at US$ 1.7 billion, with US$1.2 billion attributed to Lower 48. No
changes were announced to the outlook provided in the company’s Market Outlook presentation in June. ConocoPhillips
provided Q3 volume guidance of 1,480-1,520 kboe/d (down from 1,547 kboe/d in Q2), with seasonal maintenance in Alaska and
Asia.
Our take: the company emphasized its lack of hedges and diversified portfolio as advantages for the quarter and in the nearterm future. While its US tight oil peers are seeing outsized hedging losses this year (Hess and Oxy being notable exceptions),
ConocoPhillips is taking full advantage of price upside. Realized crude pricing averaged US$65.51/bbl for the quarter, a 10%
improvement over Q1.
During Q&A, COP avoided a question on large-scale acquisitions (the company is rumoured to be a potential buyer for Shell’s
Permian assets) and rejected a potential acceleration of its debt repayment plan. Its current plan is to pay down US$5 billion by
2026, reaching a gearing ratio of 12.2%. During Q3, the company lowered gearing from 23.3% to 20.1%.
Discipline and a dedication to returning value to shareholders remain a constant theme for the company. Reinvestment rate for
the quarter was just 31% (~40% year-to-date). During Q2, return of cash to shareholders was US$1.19 billion or 30% of FCF,
split roughly evenly between dividends and buybacks.
BP rounds out positive Q2 earnings season for the Majors
Luke Parker, 3 August 2021
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Corporate week in brief
BP reported underlying earnings of US$2.8 billion – well ahead of sell side consensus forecasts for a second successive
quarter. Net debt nudged lower, leaving gearing at 26% (excluding leases). But it was growing shareholder distributions that
grabbed the headlines.
As trailed last quarter, BP initiated its ‘surplus buyback’ programme. But the company also surprised the market by announcing
a 4% dividend increase, pointing to growing confidence in three areas: 1) strong underlying performance, feeding through to 2)
a healthier balance sheet, supported by 3) a much-improved macro outlook. Messaging is important: increasing shareholder
distributions through the dividend (rather than discretionary buybacks) plays to BP’s “performing while transforming” narrative.
See our reported results write-up for our take on BP’s financial outlook, its revised oil price assumption and the
operational/strategic highlights arising from the analyst call.
Majors’ Q2 results
Tom Ellacott, Greig Aitken, Norman Valentine and Luke Parker, 2 August 2021
The facts: The Majors’ earnings and cash flow surged in Q2. Oil prices jumped more than 130% year-on-year, blowing
comparisons with Q2 2020 – the low point of the crisis last year – out of the water. It was also a stellar quarter for
petrochemicals, and fuels retail staged a comeback as Covid-related mobility restrictions started to ease.
More impressive was the uplift relative to pre-pandemic levels in Q2 2019, when oil prices were broadly similar. Lower
underlying costs and investment rates are the primary factors underpinning the financial reset.
Adjusted earnings Q2 2021 versus Q2 2020 and Q2 2019
Eni reported in Euros. All other Majors report in US$.
Net debt reduction is now well ahead of expectations at the beginning of the year. New buyback programmes and dividend
increases sent a strong signal of rising confidence in the financial outlook. But the Majors acknowledged the still substantial
risks on the horizon and the need for prudent capital allocation. Investment budgets were largely unchanged.
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TotalEnergies’ net debt fell 7% quarter-on-quarter to reduce gearing to 18.5% and well below its target of less than 20%. The
company agreed to allocate up to 40% of additional cash flow generated above US$60/bbl to share buybacks. Renewables
business development slowed but TotalEnergies struck some material business-to-business renewable power supply deals
during the quarter (Amazon, Air Liquide and Merck & Co).
Equinor directed higher cash flow towards the balance sheet. Net debt and adjusted gearing fell by over a third over the
quarter. Gearing is now close to the bottom end of the company's 15-30% target range. Equinor initiated the share buyback
programme and 20% dividend increase that it announced at last month's Capital Markets Day. Equinor also reaffirmed its aim to
be a leader in the energy transition while sustaining its oil and gas business through this decade.
Shell reported underlying earnings of US$5.5 billion (up 60% on Q2 2019) and cash flow from operations of US$14.2 billion –
one of the company’s best quarters on record. A previously trailed increase in shareholder distributions was the main story.
Having all but met its US$65 billion net debt target, Shell signalled its confidence in the outlook by raising the dividend by 38%
and initiating a US$2 billion share buyback for H2.
Continued high oil prices saw Eni bounce back to 2019 levels of income. Cash generation will reach US$10 billion if oil prices
remain strong through the year. Shareholders were the winner - the elevated oil price has sent the variable dividend back to prepandemic heights and triggered a US$400 million buy back. The Italian Major also completed the integration of its renewables
and retail divisions and boosted near-term renewables targets by 1 GW, following recent acquisitions.
Chevron reinstated a buyback program of US$2-3 billion per year, vs US$5 billion per year pre-pandemic. The company
created a New Energies unit reporting directly to the CEO. But rumours also circulated last Friday that Chevron, in addition to
ConocoPhillips and Devon Energy, is evaluating Shell’s Permian position. With gearing at the low end of its target range (2025%) and more than US$7 billion of cash on the balance sheet, Chevron has the financial strength to do a deal.
ExxonMobil’s earnings also surged and net debt reduction continued. But, in contrast to peers, the Supermajor didn't announce
any buybacks or dividend increases. Deleveraging remains a priority for surplus cash. Analysts had their first opportunity to
probe ExxonMobil on how its strategy is evolving following the recent changes to the board. Management doesn't expect a huge
strategic shift, but it will accelerate activity in some areas. CCUS business development picked up in Q2. Expect it to increase in
coming quarters.
US Independents Q2 results, week 1
David Clark, Mike Stinebaugh, Alex Beeker and Robert Polk, 30 July
The facts: Week one of US Independent Q1 earnings included ten companies in our coverage, six of which were Appalachian
gas producers. Hess and Ovintiv were the large caps among the few oil-focused producers that reported.
Our take: The dominant theme of the week was hedging losses – the six Appalachian names had a total mark-to-market
derivative loss of US$3.76 billion, and cash settlement losses of US$291 million.
The fair value hedging losses drove large income statement losses, which in turn lowered aggregate shareholders’ equity by
US$2.6 billion. Coupled with a net debt increase of US$110 million across the group (granted, with EQT paying US$1 billion in
cash in the Alta deal), the group’s book gearing rose from 40.4% to 43.3%. The gas producers came into 2021 quite overleveraged, at 42.1% (and that includes Cabot, which has among the better balance sheets in US E&P), and paid down US$863
million in Q1. These Q2 hedging losses have thrown a wrench in the works for deleveraging, which is the group’s top priority.
Despite the near-term gas strip trading above $4/mcf, the entire Appalachian peer group signaled they will continue to operate in
maintenance mode, due to a large local basis differential and backwardation hitting the forward curve in 2023.
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Among the few oil-focused companies that reported in week one, debt reduction was more substantial. Ovintiv delivered strong
free cash flow, and reduced net debt by ~US$1.2 billion, aided by asset sales. They are on pace to meet accelerated 2021
targets, and set a new net debt target of US$3 billion by year-end 2023. Hess knocked US$627 million off of net debt in the
quarter. Gearing is still at 46%, but deleveraging will accelerate once Liza Phase 2 comes onstream in early 2022.
With about 20 US E&Ps reporting next week, we will get a clearer picture on Q2 tight oil capital discipline, de-leveraging and
cash return to shareholders.
Oil Search accepts Santos' revised merger proposal
Luke Parker, 2 August
The facts: As anticipated, Santos has returned to Oil Search with a revised merger proposal, less than a fortnight after its initial
approach was disclosed. Under the revised terms, Oil Search shareholders will receive 0.6275 new Santos shares for every Oil
Search share held. That equates to an offer of A$4.29/share – a 16.8% premium to the Oil Search closing price on 19 July
2021, the day prior to disclosure of the initial proposal. The Oil Search board has signalled its intention to unanimously
recommend the new proposal. Santos' initial offer (rejected by Oil Search) was 0.589 shares for each Oil Search share –
equivalent to A$4.25/share (a 12.5% premium).
Our take: The revised terms sweeten the deal for Oil Search shareholders, but it remains compelling from a Santos
perspective: complementary portfolios, a stronger financial footing from which to grow, and the likelihood of further synergies
and optimisation. See our Deal Inform – Santos proposes Oil Search merger – for further analysis, and look out for an in-depth
Deal Insight later this week.
TotalEnergies and Equinor withdraw from Venezuelan extra-heavy oil project
Tom Ellacott and Norman Valentine, 30 July
The facts: TotalEnergies has transferred its non-operated 30.32% stake in the Petrocedeño asset in Venezuela to the state oil
company PDVSA. The transaction was carried out for a symbolic amount in exchange for a broad indemnity related to the past
and future participation of TotalEnergies’ in the asset. TotalEnergies recorded a loss of US$1.38 billion on the deal in its Q2
results.
Equinor has also opted to transfer its 9.67% in the asset to PDVSA, which will own all the equity in the project upon completion
of the transactions.
Our take: the withdrawal from the asset does not come as a surprise. The Euro Majors’ upstream strategies are increasingly
focused on low cost, low carbon assets. In TotalEnergies’ case, new E&P investment has to have a lower carbon intensity than
the average of the existing upstream portfolio.
The Petrocedeño extra heavy oil asset requires a material capital injection to restore production. But the project ranks as
TotalEnergies and Equinor’s most carbon-intensive asset in our Emissions Benchmarking Tool and will not have satisfied the
emissions screening process. High above ground risk will also have been a factor in the decision to exit.
Pemex’s improved earnings still far from ideal
Raphael Portela, 28 July 2021
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Corporate week in brief
The facts: Pemex kicked off earnings season for the Latin American NOCs on Wednesday. Crude production continues to
show signs of improvement, now registering three consecutive quarters of growth (1.76 million bbl/d for Q2). Financial KPIs
remain strong, with gross and net income above pre-pandemic levels and EBITDA margin at 36%, some 3% higher than in Q1.
There was no change to strategy or guidance on this call.
Our take: Despite a strong recovery, Pemex’s financial health remains challenged. This year, the Mexican government is
injecting Pemex with US$3.7 billion and will be absorbing an additional US$6.4 billion in debt maturities. Even Shell’s Deer Park
refinery acquisition is being carried out thanks to state funding. Still, the sizable support is not enough to reduce Pemex's debt
load – we estimate its corporate breakeven at US$75/bbl Brent. To complicate matters, the L48-centric theme of hedging losses
is also impacting Pemex – its hedging program cost the company US$160 million in H1 2021 alone.
US Independents' Q2 2021 results preview
David Clark, Alex Beeker, Robert Polk, Matt Woodson, Adela Kim, Anuj Goyal, 22 July
The facts: US Independent Q2 earnings begin next week. The big six Appalachian gas operators, along with Ovintiv and Hess,
kick things off in Week 1, followed by a dense Week 2 with at least 19 E&Ps on the schedule.
Our take: here are the five key things we will be watching for:
US Independents continue to show strong capital discipline, for the most part maintaining initial 2021 budgets despite a
US$20/bbl+ rise in WTI since the beginning of the year. The Q1 aggregate reinvestment rate across the 32 US E&Ps we track
was 48%, with WTI averaging US$57/bbl for the quarter. With WTI about $9/bbl higher in Q2, we would expect aggregate
reinvestment rate to be in the 40-45% range for the quarter. It is probably too early for 2022 budgets, but there will be earnings
call questions about initial plans.
Low reinvestment rates dovetail with ongoing commitments to strengthening balance sheets. Debt reduction remains a top
priority for most of the peer group. Strong expected cash flow likely accelerated paydowns in the quarter. We expect further
deleveraging to remain a priority, but better than anticipated progress frees up capital for incremental shareholder returns.
White-hot high-yield markets also enabled more stressed producers to refinance upcoming maturities and improve near-term
flexibility.
Hedging losses will be one of the few blemishes in Q2. WTI averaged US$66/bbl during the quarter while our analysis shows
many companies have hedges in the US$40-55/bbl range. We estimate that the 32 US-focused operators included in Wood
Mackenzie’s hedging model realised a combined hedging loss of -US$3.37 billion during Q2, up from a -US$2.82 billion loss the
previous quarter. Given the recent price rally, we’re expecting many companies to have added 2022 hedges at prices above
US$60/bbl.
US drilling activity has risen much less than oil prices would normally suggest, which has dampened cost inflation, though
there has been meaningful upward pressure on some cost categories. Wood Mackenzie’s Cost Center of Excellence estimates
the combined cost of a basket of diesel, steel and chemicals was up ~34% from 3Q20 to 2Q21, while all other inputs were up
~3% over that period. Anecdotally, labor costs are rising, as tangential industries (e.g., logistics) are attracting away drivers.
On the ESG front, expect to see more disclosures on operational plans and costs associated with emissions reductions. Lower
48 companies, previously laggards on energy transition plans, unveiled relatively ambitious emissions reduction targets over the
past few quarters. Now the focus shifts to execution. Greater details on long-term action plans are necessary for operators
looking to establish themselves as leaders in this space.
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For more on US E&P reinvestment rates, de-leveraging and cash generation, see Wood Mackenzie Corporate Research’s “US
Independents: Stay-flat cash flow framework”, and “Financing US Independent producers through the energy
transition”, both published this week.
Motiva suspends US$6.6 billion petrochemical expansion
Mike Stinebaugh, 22 July 2021
The facts: Motiva Enterprises LLC, owned by Saudi Aramco, planned to create the largest petrochemical/refining complex in
the US at its Port Arthur, TX facility. The expansion plan dates back to 2019, when Motiva initially sought approval to build two
petrochemical plants at the 630 kbbl/d Port Arthur refinery. The expansion is now on hold.
Our Take: we view the strategic decision as a market signal Aramco will seek to bolster its core upstream operations. We don't
view the Port Arthur expansion project as necessarily dead, and still believe it will be revisited in the future. The recent uptick in
crude prices has likely made other projects in the Aramco portfolio more appealing.
Santos proposes Oil Search merger
Scott Walker, 20 July 2021
The facts: Santos has made an all-share takeover approach to acquire PNG-focused competitor Oil Search. Santos announced
it made its initial approach to Oil Search on 25 June 2021, offering 0.589 of its shares for each Oil Search share. This equates to
a bid price of A$4.25/share – a 12.5% premium to Oil Search’s share price a day prior to the offer. The merged group would be
owned 63% by Santos shareholders and 37% by Oil Search shareholders. Oil Search rejected the initial bid as undervaluing the
company but has indicated it is open to further discussions, if an increased offer is forthcoming.
The takeover approach was confirmed a day after the departure of its CEO, Keiran Wulff. At today's share price, the Santos
offer equates to A$4.02/share and an enterprise value of US$8.8 billion – a reduced premium of 9.5%. If Santos is successful, a
combined market capitalisation of US$16.5 billion would surpass Woodside's US$15.4 billion to become the largest Australianlisted E&P.
Our take: with overlapping LNG assets in Papua New Guinea, there has long been speculative merger rumours between the
companies. PNG LNG is the largest single asset by NPV10 in each respective portfolio. A combination would see Santos
increase its interest in PNG LNG from 13.5% to 42.5% and add a 17.7% interest in the pre-FID Papua LNG project. A deal
would also include Oil Search’s Alaska position – not an obvious fit for Santos and an area we suspect would be a divestiture
candidate.
Consolidation among E&Ps is something we’ve been expecting. To-date, this has yet to play out in any meaningful way outside
of North America. But with scale and resilience set to be a crucial differentiator in the years ahead, we think there is logic to this
tie-up. As discussed in our a recent Horizon note, the potential for combinations in resource theme niches could feature as the
energy transition continues to unfold.
See our Inform for a more comprehensive view.
The Majors’ Q2 2021 results preview
Tom Ellacott, Luke Parker, Greig Aitken, 20 July
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Corporate week in brief
The facts: all the Majors bar BP report their Q2 results next week. The focus will be on capital allocation plans as the group
delivers a strong set of financial results.
Our take: high prices and disciplined investment will combine to deliver stellar quarterly free cash flow in Q2. Some players may
even notch up a record quarter. The resultant rapid deleveraging will trigger questions about capital allocation plans at higher
prices. Buybacks could be the big winner this quarter.
Shell has already trailed that it is moving early to the next phase of its capital allocation framework – scrapping its US$65 billion
net debt target and bumping total shareholder distributions to 20-30% of CFFO. BP will announce its H1 ‘surplus cashflow’
buyback, with expectations high on the back of two strong quarters. The numbers will be closely compared. Eni should provide
an update on its distribution framework while surging surplus cash flow may see Chevron launch a fresh buyback programme.
Future investment plans will also be under the spotlight. We’ll be watching for any indication of accelerated low-carbon growth
and decarbonisation. Increased capital allocation into low-breakeven Permian tight oil could also be a theme for the US Majors.
But capital discipline and portfolio management (including new upstream JVs) will again be dominant themes. The Majors may
need at least another quarter of high prices before raising budgets.
The Q2 results will be the first opportunity for analysts to ask questions on the Hague ruling against Shell and proxy votes
against the US Majors. All the companies will want to be on the front foot.
Shell might take the opportunity to be more definitive about its response. ExxonMobil’s recruitment of Diageo’s CFO Kathryn
Mikells to be its next CFO is another indicator of an accelerating pace of change. Whisky and Guinness are very different
commodities from oil and gas. But analysts will note that Diageo is targeting net zero Scope 1 and 2 emissions, a 50% reduction
in Scope 3 emissions and 100% renewable energy for its own operations by 2030. Expect a lively Q&A session.
Summary of quarterly prices and refining margins
Average prices
2020
2019
Q2 2021
Q2 2020
Q1 2021
Q-o-Q
Brent FOB SVT (US$/bbl)
41.9
64.4
68.9
29.6
60.9
13%
WTI Houston FOB (US$/bbl)
40.8
61.9
66.8
29.6
59.2
13%
Henry Hub (US$/mmbtu)
2.00
2.52
2.67
1.66
3.42
-22%
1.8
3.5
1.8
1.3
1.3
41%
Global composite refining margin (US$/bbl)
Source: Refining margin - Wood Mackenzie,
Prices - the Argus Media group
Majors submit bids for Scottish offshore wind leases
Luke Parker, 19 July 2021
The facts: BP, Eni, Equinor, Shell and Total are among companies to submit bids to ScotWind – Scotland’s first offshore
leasing round in more than a decade. The leasing round, held by Crown Estate Scotland, includes up to 15 areas with potential
generation capacity of 10 GW, floating and fixed. The process closed for submissions on Friday (16 July), with results expected
to be announced in early 2022.
BP joined forces with German utility EnBW in bidding for a lease area that could support up to 2.9 GW of generation capacity.
Shell partnered Iberdrola-owned ScottishPower to submit several proposals for floating offshore wind. Equinor also submitted a
proposal for a floating offshore wind project. Eni partnered UK offshore wind developer Red Rock Power, while TotalEnergies
joined forces with Macquarie’s Green Investment Group and Renewable Infrastructure Development Group.
ScotWind is expected to say more about the bids this week. Look out for analysis from WoodMac’s Energy Transition Practice.
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ExxonMobil and Shell sign CCUS MoUs in the UK
Tom Ellacott, 19 July 2021
The facts: the owners of the SEGAL and FUKA gas terminals have signed MoUs with the partners in the Acorn transportation
and storage cluster (Shell, Harbour Energy and Storegga) to formally become customers of the scheme. ExxonMobil and Shell
jointly own the SEGAL gas terminal. The FUKA gas plant is owned by North Sea Midstream Partners.
The Acorn CCUS development aims to capture around 5-6 MtpaCO2 by 2030 from gas terminals at the St. Fergus complex.
Future expansion could boost storage capacity to more than 20 MtpaCO2 by the mid-2030s.
ExxonMobil has also joined NECCUS, a carbon capture alliance that includes industry, government and academic experts
committed to reducing carbon emissions from industrial facilities in Scotland.
Our take: we outlined how ExxonMobil has a leading market share in existing CCUS capacity in our Majors' CCUS
benchmarking report. The commercial scale-up of this technology lies at the heart of the company’s low-carbon strategy. This
latest move is another indication that business development is accelerating. It also underscores the importance of CCUS in
Shell’s strategy.
Acorn is the lynchpin of the so-called Scottish Cluster, one of the CCUS projects currently bidding for UK government support. It
has a good chance of being one of the clusters selected, due to the relative readiness of the existing infrastructure. The 5 – 6
Mtpa of projected carbon captured by 2030 is equivalent to c. 2% of our forecast global capacity. We would expect ExxonMobil
to seek an equity stake in any development.
ExxonMobil and Shell will have to take a lead role in driving engagement within the oil and gas sector, across other industries
and with governments to derisk their early-stage CCUS pipelines. The development of supportive regulation and policy will be
an especially important success factor underpinning the large-scale commercial scale-up.
First term contract for carbon-neutral LNG signed by PetroChina and Shell
Kavita Jadhav and Akif Chaudhry, 19 July 2021
The facts: on 12 July, PetroChina and Shell took a major step forward in signing the industry’s first 5 year term-contract
forcarbon-neutral LNG. No details were given on price or volumes. For every cargo delivered, CO2 emissions (Scope 1, 2 and 3)
will be offset using third-party verified carbon credits from Shell’s portfolio of nature-based projects. Shell will continue to use UK
government department DEFRA's methodology to calculate emissions. Shell has said that offset costs will be shared across the
chain.
Our take: this is the first term deal for carbon-neutral LNG and is a step towards formalizing this nascent market. The
agreement covers well-to-wheel emissions, and so includes end-use combustion of gas, which is the biggest contributor to LNG
life cycle emissions.
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LNG carbon intensity and emissions per cargo (example cargo delivered to Japan)
Source: Wood Mackenzie LNG Emissions Tool
For PetroChina, carbon-neutral LNG is important for its own corporate target of net zero by 2050. China has become the world’s
largest LNG importer in 2021, fueled by economic growth and its policy of coal-to-gas switching. China’s power sector could be
incentivized to pay the premium associated with carbon-neutral LNG, in part due to the recent launch of China’s emissions
trading scheme. This scheme will for the first time set pollution caps for power companies.
For Shell, this is another carbon-neutral LNG milestone. Shell’s transition strategy sees oil production declining by 1-2% per
annum while growing gas as a share of hydrocarbons to 55% by 2030. Thus, decarbonizing the LNG value chain will be key for
Shell and carbon-neutral LNG could play a role, if the market can be scaled up. Shell has been a pioneer in the carbon-neutral
LNG space, trading the first cargoes to Tokyo Gas and GS Energy in 2019 and since then the company has participated in
around half of all carbon-neutral LNG cargoes to date, as both a seller and a buyer.
Scaling up the market will depend on the additional cost of carbon-neutral LNG and the volume of high quality offsets that will be
required. Companies have so far kept quiet about the cost or “green premium” associated with these trades. For now this
premium is likely to be a small percentage of the overall LNG price but would increase with higher carbon prices. Wood
Mackenzie estimates that in most cases to date, the cost of offsets has not added more than US$0.40/mmbtu to the total cargo
cost, assuming an average carbon price of US$5/t CO2e. However, as carbon costs continue to rise towards current EU ETS
prices of over US$60/tCO2e or US$110/t CO2e1 this premium would rise considerably.
1. Wood Mackenzie estimates that a carbon price of US$110/t CO2e is needed under an accelerated energy transition scenario to reach net zero globally
by 2050.
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New large scale carbon capture facility announced by Shell
Scott Norlin, 15 July 2021
The facts: Shell Canada announced plans for a new CCUS project at the Scotford complex in Alberta called Polaris. The
project is set to be developed in phases, with phase 1 sequestering 750,000 tonnes of CO2 per year with ultimate capacity to
sequester up to 300Mt of CO2 over its lifetime. CO2 would be injected into the Basal Cambrian Sands 2 kilometres below the
surface. Shell's final investment decision is scheduled for 2023 with operations beginning in the mid 2020's. One key note is that
due to the carbon tax and clean fuel standard, Shell expects the facility will require no government funding.
Our take: Shell already designed, built and operates the Quest facility at the Scotford complex. The experience and expertise
that Shell brings in operating large scale CCUS facilities in Alberta and globally will certainly help with the Polaris project. As
discussed in our recent insight Canadian carbon capture credentials, Quest cost nearly C$1.3 billion to build. However, Shell
has since stated that they "gold-plated" the project and could deliver a similar scale project for 30% less cost.
Polaris has a significant impact on Shell’s aim to increase its CCS capacity by 25 million tonnes per year by 2035. This is
another major announcement by Shell on the CCS front, also taking FID on Northern Lights in Norway and participating the
Porthos CCS project in the Netherlands.
TotalEnergies signs US$750m GLNG infrastructure agreement with GIP
Andrew Harwood, 14 July 2021
The facts: Global Infrastructure Partners Australia (GIP), has entered into a US$750 million agreement with TotalEnergies for
its GLNG infrastructure assets.
TotalEnergies retains full control and ownership of its 27.5% stake in the GLNG downstream Joint Venture. GIP will receive a
tolling fee based on TotalEnergies’ share of GLNG production over the next 15 years.
Our take: The deal allows TotalEnergies to monetize its investment in the GLNG infrastructure, freeing up capital for
deployment into priority investments aligned with its corporate stategy. Its also an example of the evolution of deal structures in
an environment rich with opportunity, but light on buyers.
This transaction is GIP’s second major investment in Australian LNG infrastructure, following its US$2.5 billlion acquisition of a
26.25% stake in Shell’s Queensland Curtis LNG (QCLNG) common facilities in December 2020. Long life spans and stable cash
flows make LNG infrastructure attractive for players that can leverage lower costs of capital. We expect infrastructure funds to
be one of the buyer types that will drive future Australian M&A activity.
Woodside’s Pluto Train 2 expansion project and Santos’ infrastructure business headline similar assets gaining attention; could
this deal also be a blueprint for Chevron's eventual exit from the North West Shelf?
TotalEnergies and ExxonMobil join forces with industry to evaluate a French
decarbonisation project
Tom Ellacott, 12 July 2021
The facts: TotalEnergies, ExxonMobil, Air Liquids, Borealis and Yara International have signed a Memorandum of
Understanding to help decarbonize the industrial basin of Normandy.
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The partnership will explore the development of CO2 infrastructure, including evaluating carbon capture and storage to capture
CO2 from industrial facilities for storage in reservoirs in the North Sea. The aim is to reduce CO2 emissions by up to 3 million
tons per year by 2030.
Our take: the MoU is another example of how collaboration across the oil and gas sector and other industries will play a key
role in driving decarbonisation. This partnership brings together a broad group of companies with distinctive capabilities. These
include industry-leading CCUS experience (ExxonMobil), proprietary CO2 capture and liquefaction technology (Air Liquide) and
strong regional industrial footprints (all the players).
More exploration success in Ghana for Eni
Greig Aitken, 9 July 2021
The facts: Eni has announced a discovery on Cape Three Points Block 4 in Ghana. The Eban-1x was drilled in 545 metres of
water and encountered an 80-metre light oil column in a Cenomanian-aged sandstone reservoir. The discovery is close to the
2019 Akoma gas/condensate find, suggesting a single structure could exist.
The Eban-Akoma complex is estimated to hold 500 to 700 mmboe of in-place oil and gas, which Eni plans to appraise before
licence expiry in April 2022.
Our take: Eban is Eni’s fifth success in the Cape Three Point area from eight wells. Over 1.1 billion boe has been discovered in
total. We estimate Eban’s recoverable volumes will be around 130 mmboe. We value Eban’s oil and gas at US$378 million
(NPV10, January 2021, US$50/bbl long term oil price) with an IRR of 16.6%. This assumes start-up in 2024 with six subsea
development wells tied back to the John Agyekum Kufour FPSO on Sankofa located eight kilometres away.
Though Eni has a detailed and comprehensive energy transition strategy, exploration remains core to Eni, at least in the near
term. The Italian Major is targeting 2 billion boe of resources in its current four-year plan. Eban aligns perfectly with one of Eni’s
key strategic themes – lower-risk, infrastructure-led exploration with quick pay-back and high returns.
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Eban oil field location map
For further details, see our Inform.
Eni continues new energies diversification
Greig Aitken, 9 July 2021
The facts: Eni is acquiring a portfolio of 13 onshore wind farms in Italy, with a total capacity of 315 MW already in operation,
from Glennmont Partners and PGGM Infrastructure Fund. No financial terms were disclosed. The deal takes Eni’s installed and
under construction renewables capacity to 1.3 GW.
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Separately, Eni has signed an agreement with the EEHC and EGAS to assess the technical and commercial feasibility of
projects for the production of hydrogen in the Egypt.
Our take: Bringing in operational assets will boost the renewable division’s operating cash flow though net cash will remain
negative as Eni continues to invest in growing its capacity base. Eni’s first interim target is 4 GW of installed capacity by 2024. It
already had line of site on that number, with around 1 GW operational or under construction (prior to this deal) and a further
3GW accessed and under study. Eni remains well behind leading peers TotalEnergies and BP, which each have over 20 GW of
capacity. That is, however, reflective of Eni’s transition strategy, which takes a measured approach to growing renewables
capacity. For more on Eni’s renewables portfolio, see Eni Corporate New Energy Profile.
Eni does not currently have any operational hydrogen assets. But like the rest of the EuroMajors, Eni expects hydrogen will play
a big role in the energy transition and is looking at looking at various ways to develop a hydrogen business. Currently, Eni has
has green and blue hydrogen projects underway in Italy and the UK. For more details on the Majors’ hydrogen strategies and
assets, see our Majors’ hydrogen benchmarking report.
Sinopec announces first Carbon Capture and Utilisation project
Kavita Jadhav, 9 July 2021
The facts: Sinopec has announced that it is building a CCUS project as part of the company’s goal to be carbon neutral by
2050. The project in eastern China’s Shandong province will capture CO2 from coal-based hydrogen production at Sinopec’s
Qilu refinery.
The CO2 will be injected for enhanced oil recovery at the Shengli oil fields, also located in Shandong. According to Sinopec, the
project will complete by year-end 2021 and will cut emissions by 1 million tonnes per annum. Sinopec expects to inject 10.68
million tonnes of CO2 over the next 15 years in order to increase oil production by 22 million barrels.
Our take: Shengli is China's second-largest oil field complex and contains a number of mature fields, originally developed in the
early 1960s. Sinopec already conducts extensive EOR at Shengli, including water and chemical injection, to maintain oil output.
The investment in anthropogenic CO2 capture for EOR is an interesting step that could act as a catalyst for future
commercialization of CCUS in China. Globally a majority of CO2 EOR projects use naturally occurring CO2, which does not
provide any net emissions reduction.
This project will provide Sinopec with proof of concept for separating CO2 from an industrial process at scale. Additionally,
increased oil recovery will provide revenue to set off against the costs of carbon capture. While CO2-EOR is therefore a
potentially lower-cost opportunity for CCUS, its economics also rely on the proximity of industrial sources of CO2 to appropriate
mature oil fields, or the pipeline infrastructure to move the CO2 to the fields. Sinopec hasn’t yet provided any financial details on
the project, or the broader potential opportunity if this project is successful.
A question remains around whether Sinopec will conclude with the final step of storing all the CO2. While a portion of the
CO2 injected for EOR, will remain below the ground, some will return to the surface. For permanent storage, this portion of
CO2 that returns to the surface would have to be separated and reinjected.
LUKOIL acquires in Mexico in the country’s largest upstream deal
Scott Walker, 6 July 2021
The facts: LUKOIL has acquired a 50% operated stake in Area 4 (Ichalkil-Pokoch discoveries) from Fieldwood Energy for
US$435 million, effective 1 January 2021. Located in shallow-water off the coast of Tabasco in the Southwest Marine region, the
fields were awarded to Fieldwood and Petrobal in September 2015, with development approved in January 2019. Phase 1
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development is nearing completion – start-up expected in late 2021 – and will be one of the few private-operated fields in
Mexico to utilise Pemex's existing infrastructure. Development of Phase 2 – expected between 2022 and 2025 – will require
LUKOIL to build out additional infrastructure, which will see gross working interest production peak at around 130 kboe/d in
2029.
Our take: the lack of visibility on long-term growth is one of LUKOIL’s key challenges and its acquisition in Mexico goes
someway to addressing this. Currently, the company’s operational focus is primarily centred on organic growth at its legacy
domestic assets, targeting hard-to-recover reserves in Timan Pechora and West Siberia through advanced technologies and
efficiencies. But following the announcement that the Russian state is to eliminate tax incentives for high viscosity fields from
January 2021, LUKOIL could find a key growth area is subjected to diminishing returns.
The acquisition of Area 4 will see Mexico become LUKOIL’s largest producing country outside its core Russia and Caspian
region by the middle of the decade. However, even following its Mexico acquisition, its production CAGR from 2020 to 2030
remains negative (reducing only slightly from -0.8% to -0.6%).
But with one of the strongest balance sheets in the sector and gearing of only 4%, the company is well positioned to leverage its
financial strength to pursue opportunities in what is currently an attractive M&A market for buyers. There will be plenty of
opportunities ahead with the Majors’ running sizeable rationalisation programmes as they look to decarbonise and reshape their
portfolios. And with most of the best domestic opportunities reserved for its larger peers Rosneft and Gazprom, we expect
LUKOIL could increasingly look overseas for its next phase of growth.
Global M&A: H1 2021 highlights
Scott Walker, 2 July 2021
Half-year M&A activity has recovered to pre-pandemic levels. There were 115 deals announced, matching the 2019 half-year
average (115). Disclosed spend reached US$52 billion, down from US$84 billion in Q4 2020 but slightly above the five-year
average pre-2020 of US$49 billion (excluding +US$50 billion deals).
Increased deal count has been a global story. But the above average spend is largely being driven by a wave of corporate
consolidation in North America, continuing the trend from H2 2020.
Highlights included:
•
Deal count in both North America (67) and Rest of World (48) more than doubled on H1 2020 (27 and 22 respectively). Rest
of World deal count showed a more robust recovery against the pre-2020 five-year average: down only 14% (56 deals)
versus North America, which was down 43% (117 deals).
•
At US$42 billion, North America contributed 80% of global M&A spend – the region’s highest proportional share since H1
2004.
•
Corporate-level deals increased in prominence, accounting for 24% of all deals announced (versus a pre-2020 five-year
average of 14%) and 65% of total disclosed spend (versus a pre-2020 five-year average of 34%).
•
The Majors recorded only US$30 million disclosed spend, the lowest half-year period in over a decade. As sellers, the peer
group announced disposals totalling US$7.1 billion, the highest half-year disclosed total since H2 2019 (US$15.3 billion).
•
Our Implied Long-Term Oil Price (ILTOP) for H1 2021 was US$50/bbl, up from an average of US$47/bbl in 2020. In 2021, the
quarterly average increased from US$46/bbl in Q1 to US$52/bbl in Q2.
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M&A H1 2021 deal count by region
For a much deeper dive into recent and expected deal activity and trends, look out for our Global upstream M&A: H1 2021
review and outlook, to be published to M&A Service subscribers soon. In the meantime, all data is available in our M&A Tool.
Equinor signs blue hydrogen MoU with US Steel
Norman Valentine, 2 July 2021
The facts: US Steel and Equinor have announced a non-exclusive memorandum of understanding (MoU) to study carbon
capture and storage and hydrogen development in Ohio, Pennsylvania, and West Virginia. The MoU includes assessments of
regional hydrogen and CCS potential, customer and supplier screenings, blue hydrogen advocacy, CCS, and renewable energy
synergies.
Our take: Equinor is extending its blue hydrogen push beyond Europe. The company has a material, mainly non-operated gas
portfolio in the US Northeast. This MoU will look to leverage that position through the supply of blue hydrogen to the steel
sector. Longer-term green hydrogen synergies could come from Equinor’s US East coast wind business.
For further analysis of the Majors' ambitions in the hydrogen sector, please see our recent Majors’ hydrogen benchmarking
report.
Shell, EDF and Ørsted awarded New Jersey wind contracts
Norman Valentine, 2 July 2021
The facts: the New Jersey Board of Public Utilities has awarded Ørsted and the Atlantic Shores joint venture the rights to
provide a total of 2.6 GW of offshore wind power.
Atlantic Shores, owned 50:50 by Shell and EDF Renewables, will provide 1.5 GW and Ørsted’s Ocean Wind 2 project will
deliver 1.15 GW. Atlantic Shores is expected to be operational in 2027-28 with Ocean Wind 2 in 2028-2029.
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Ørsted’s 1.1 GW capacity Ocean Wind 1 project won the first New Jersey offshore wind tender in 2019.
Our take: these are some of the largest offshore wind developments in the US and the awards pave the way for the project
sanction. For Ørsted, Ocean Winds 1 and 2 are important elements in its plans to increase installed offshore wind capacity to 30
GW by the end of the decade.
It is also a positive result for Shell and EDF’s offshore wind ambitions in the US. It will be EDF’s first offshore wind development
in the country. Shell is also a partner in the Mayflower project offshore Massachusetts which was awarded an 804 MW supply
contract in 2020.
Sinopec divests mature, non-core Argentine assets
Kavita Jadhav, 2 July
The facts: Sinopec Group has sold its interests in the Golfo San Jorge and Cuyo Basins to Argentine energy firm Compañía
General de Combustibles. Sinopec paid US$2.5 billion to buy these assets from Occidental Petroleum in 2011, one of the
biggest deals in the Argentine oil sector. Sinopec has been trying to sell them since 2017.
The terms of the transaction were not disclosed. Wood Mackenzie estimates the NPV10 of the assets to be approximately
US$40 million using a US$50/bbl long-term real Brent assumption.
Our take: Sinopec has finally sold a particularly challenging and non-core set of assets. These concessions contain mature
black and light oil fields, which require extensive infill drilling and water flooding to mitigate decline rates. Sinopec has also faced
challenges from inflation issues prevalent in Argentina and difficult labour relations. Additionally, the authorities from the
province of Santa Cruz launched an investigation in 2020 to audit the accomplishment of Sinopec's investment commitments.
The sale may also be the starting gun for much needed rationalisation of Sinopec’s international portfolio. From 2008-2013,
Sinopec followed a predominantly M&A-led approach to international portfolio development. The range of acquisitions means
Sinopec has one of the most diverse international upstream portfolios of any Asian NOC. But with many assets in mid-life, the
international portfolio lacks long-term growth potential. It is also overly scattered across many countries. There is a strong case
for further rationalisation.
CNOOC Ltd’s deepwater gas drive
Kavita Jadhav, 2 July 2021
The facts: CNOOC Ltd has announced first gas from the US$3.1 billion Lingshui deepwater field development in the South
China Sea. This is CNOOC’s first fully-operated and 100%-owned deepwater project, without any IOC involvement. CNOOC
partnered with Husky on its first deepwater project in 2014. CNOOC accelerated the Lingshui development in 2020, despite the
Covid-19 pandemic, in order to help meet China’s growing gas demand.
Our take: in support of China’s push for gas, CNOOC Ltd is aiming to rebalance its traditionally oil-weighted portfolio. It aims to
deliver a 70:30 oil:gas production mix by 2025, up from an 80:20 split in 2020. Wood Mackenzie estimates initial production from
Lingshui will peak at around 340 mmcfd in 2024. This will account for about half of CNOOC Ltd's net increase in gas output over
the next five years.
Developing Lingshui is also proof that CNOOC Ltd can go it alone in developing complex projects and grow gas production from
frontier domestic fields. CNOOC will continue to explore for gas resources in the Lingshui area to increase its gas reserves and
future gas production from this new core area.
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Petrobras exits Brazilian retail for US$2.3 billion
Raphael Portela, 2 July 2021
The facts: Petrobras will sell its remaining 37.5% stake in Petrobras Distribuidora (BR Distribuidora) through a secondary public
offering. The Board of Directors approved the sale, valuing the stake at approximately US$2.3 billion. The shares will start
trading on the São Paulo Stock Exchange on July 2.
Our take: the move does not come as a surprise. Petrobras announced it would sell its stake back in December 2019, five
months after trimming its 71% controlling interest by 33.5%.
With the sale, Petrobras will essentially have exited the retail space. If the NOC successfully sells its stake in the Colombian
retailer PECOCO (123 service stations) – currently in binding negotiations – its retail portfolio will consist solely of
trademark/brand licence agreements in Brazil, Chile and Paraguay. BR Distribuidora itself has a 10-year licence agreement with
Petrobras, signed in 2019, and renewable for another 10 years.
The transaction is part of Petrobras’ broader divestment programme, started back in 2015. Petrobras sees itself as an even
more focused E&P, concentrated on upstream, particularly on the Brazilian pre-salt. Other big-ticket items in its disposal
programme also target non-upstream assets – for example, half of its refining capacity and all of its gas pipeline network.
With over 120 assets sold or currently on sale, Petrobras does not make it easy to keep track of its every move. To address
that, we have published a tracker with detailed metrics of every open or closed transaction.
ExxonMobil rationalises its petrochemicals business
Tom Ellacott, 1 July 2021
The facts: ExxonMobil has signed an agreement to sell its Santoprene business to Celanese for US$1.15 billion. The portfolio
includes two manufacturing sites in the UK and the US.
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The Supermajor expects the transaction to close in Q4 2021.
Our take: ExxonMobil is focusing on higher volume markets, scale and technology in the petrochemicals sector e.g. olefins and
polyolefins. Santoprene is an elastomer/rubber type speciality chemical with a smaller market and therefore strategically noncore. ExxonMobil has found a buyer that is more speciality focused and can leverage synergies with its existing products and
customer base.
The deal is another indication that ExxonMobil’s high-grading programme is gathering some momentum. Portfolio rationalisation
is under way across all business segments. We discuss the drivers for a more aggressive campaign in our ExxonMobil
corporate report.
EQT raises the bar on ESG strategy
Mike Stinebaugh, 1 July 2021
Yesterday on an investor call focused solely on ESG, EQT established bold new plans going forward. It included a target goal of
net zero GHG emissions by 2025. The company disclosed the goal would not be completed organically, however it would be
achieved through the use of carbon offsets. It also announced the company will be allotting US$75 million over the next five
years to a "New Ventures" division of the company. New Ventures will be focused on finding sustainable practices to aid EQT in
reaching its net zero goal by 2025 and beyond.
Q2 2021
ConocoPhillips lays out updated ten-year plan
Matt Woodson and Dave Clark, 30 June 2021
The facts: ConocoPhillips rolled forward its ten-year plan at a scheduled “Market Update” on Wednesday, its first investor day
since 2019. At a US$50/bbl planning assumption, the company projects US$145 billion of operating cash flow from 2022
through 2031, with US$70 billion of free cash flow (a 40% improvement over the 2019 outlook), and a reinvestment rate of just
over 50%.
Our take: COP has been the US independent industry leader with regards to shareholder-friendly capital restraint and return of
cash since 2017. This plan update reinforces that leadership.
Near-term, the company increased its 2021 buyback plans, adding an incremental US$1 billion to reach an expected US$6
billion of shareholder distributions this year. The company also increased its estimate of annual cost/capital synergies from the
Concho deal by another US$250 million to US$1 billion (they had raised it by US$250 million in February as well). As a result,
ConocoPhillips lowered the 2021 capital plan from US$5.5 billion to US$5.3 billion.
ConocoPhillips continues to position itself as a producer of advantaged barrels for the long-term. The company has 20 bnboe of
resource with a cost of supply below US$40/bbl (average cost of supply around US$30/bbl), and has reduced its company-level
free cash flow breakeven by US$5/bbl since the 2019 investor day, to US$30/bbl.
The ~US$75 billion of planned capital investment over the ten-year period is expected to drive production growth of about 3%
per year, largely from the Permian. While the company intends to reduce debt (already relatively low at 23% gearing at Q1) by
another US$5 billion, the rest of the free cash flow is likely to flow to shareholders. Furthermore, there is meaningful leverage to
higher oil prices – each US$1/bbl in price improvement is worth ~US$300 million of operating cash flow. US$60/bbl WTI
therefore points to US$175 billion of operating cash flow (OCF) through 2031, and about US$100 billion of free cash flow.
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COP is committed to a minimum of 30% of OCF returned to shareholders. But the company is likely to deliver the balance of
OCF after its capex plan and modest debt reduction to shareholders. That means ~US$65 billion at US$50/bbl WTI real, and
US$95 billion at US$60/bbl WTI real. Thus COP could deliver more than the company’s current market cap of ~US$81 billion
back to shareholders by 2031.
ConocoPhillips reaffirmed its ESG ambitions in terms of its “triple mandate” to (1) meet hydrocarbon demand during the energy
transition while (2) delivering peer-leading returns and (3) achieving its net zero emissions goal. The company reported 2020
emissions roughly on par with the previous three years. New near-term milestones on the path to zero emissions include
elimination of routine flaring and a 10% improvement in methane intensity by 2025. Management continues to advocate for an
economy-wide price on carbon.
CNPC swaps drilling for Turkmen gas, looks to broader gas push
Kavita Jadhav, 25 June 2021
The facts: CNPC has won a drilling contract at Turkmenistan’s super-giant Galkynysh (South Iolotan) development, the world’s
second-largest gas field. Notably, CNPC will be paid for its services in kind, with 17 bcm of gas delivered over the next three
years under its long-term contract with the cash-constrained Central Asian producer. Gas exports to China from Turkmenistan
began in 2009 and were 2.7 bcfd in 2020, almost 10% of China’s total supply.
Our take: Galkynysh is vital to the Turkmen economy and China’s gas supply. The megaproject has relied on strategic Chinese
financing and service sector support. CNPC does not have an equity stake, but has served as construction and drilling
contractor: for Phase One (commissioned) and a delayed Phase Two (under execution). Turkmen gas deliveries to China have
disappointed in recent years, especially during peak winter demand. For CNPC, this deal should boost near-term import
reliability and the delivery of the first stage of its own energy transition plan.
CNPC, which supplies 50% of China’s crude oil and 70% of China’s gas demand, has committed to net zero emissions by 2050
— 10 years ahead of China’s national target. CNPC has said that it will take a three-stage approach to achieve its target for a
carbon emission peak in 2025 and net-zero emissions in 2050. Natural gas is expected to be a key bridge fuel over the next two
decades.
In the first stage, CNPC will maximise its gas operations by raising the proportion of gas in its energy supply mix to 55% by
2025. CNPC expects China to cut its coal use to 44% of energy consumption by 2030 and 8% by 2060 as the country aims to
use more natural gas. The company expects China, the world's biggest coal consumer, to increase the use of natural gas in its
primary energy mix to 12% in 2030 from 8.7% in 2020.
Chevron, TotalEnergies and Qatar Petroleum win offshore bids in Suriname
Alex Beeker, 25 June 2021
The facts: Suriname’s state oil company announced Chevron, TotalEnergies and Qatar Petroleum won bids in a recent offshore
licensing round. Chevron was awarded Block 5 and a consortium of TotalEnergies and Qatar Petroleum won Blocks 6 and 8.
Production sharing contracts are in the process of negotiation.
Our take: Chevron’s move might signal a more active stance to acreage reloading as many peers lean away from exploration.
Broadening out the exploration portfolio makes sense. Chevron has a lighter portfolio of pre-FID projects relative to peers. With
near-term caps on investment, adding exploration is a sensible strategy to diversify the opportunity set so long as the company
sticks with the Big Oil business model.
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The federal leasing ban in the US may also have motivated Chevron to expand internationally. The award marks Chevron’s
entry into the exploration sector in Suriname. But the acreage acquired is located in shallow water. Moves into the deeper
exploration sector could be on the cards in the future.
Blocks 6 and 8 were natural expansion opportunities for TotalEnergies, which operates the adjacent Block 58.
Devon Energy sets net-zero ambitions
Robert Polk, 23 June 2021
The facts: Devon Energy has established targets to reach net-zero GHG emissions for Scope 1 and 2 by 2050. The target
includes additional interim 2030 goals related to lowering overall emission intensity by 50% and methane emission intensity by
65%.
Our take: Devon previously lagged its large-cap peers in terms of emission ambitions, but the new goal reflects a growing
standard and requirement for low carbon strategies. Devon’s previous targets were limited to methane emission intensity only
and did not contemplate all GHG emissions or absolute emission levels. The notable step-up in measurable targets underscores
rapid evolutions in corporate mindsets.
As more US independents adopt net-zero goals, the pressure only grows on other producers to establish their own goals.
Pioneer Natural Resources already publicly commented about ongoing internal discussions about setting a net-zero target. It is
a safe bet to expect additional announcements soon across the peer group, possibly alongside Q2 earnings.
Devon possesses the highest flaring intensity amongst the largest US independents. Improving those metrics is critical for
accomplishing interim targets. Devon pledged to eliminate routine flaring by 2030. Previous flaring commitments were focused
on core operations in the Delaware Basin, not the entire asset base. There is a cost associated with more ambitious targets, but
it is apparent that the cost of standing idle is greater.
Chevron, TotalEnergies and Qatar Petroleum win offshore bids in Suriname
Alex Beeker, 22 June 2021
The facts: Suriname’s state oil company announced Chevron, TotalEnergies and Qatar Petroleum won bids in a recent offshore
licensing round. Chevron was awarded Block 5 and a consortium of TotalEnergies and Qatar Petroleum won Blocks 6 and 8.
Production sharing contracts are in the process of negotiation.
Our take: Chevron’s move might signal a more active stance to acreage reloading as many peers lean away from exploration.
Broadening out the exploration portfolio makes sense. Chevron has a lighter portfolio of pre-FID projects relative to peers. With
near-term caps on investment, adding exploration is a sensible strategy to diversify the opportunity set so long as the company
sticks with the Big Oil business model.
The federal leasing ban in the US may also have motivated Chevron to expand internationally. The award marks Chevron’s
entry into the exploration sector in Suriname. But the acreage acquired is located in shallow water. Moves into the deeper
exploration sector could be on the cards in the future.
Blocks 6 and 8 were natural expansion opportunities for TotalEnergies, which operates the adjacent Block 58.
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BP reportedly looking at another upstream spin-off – this time Iraq
Luke Parker, 18 June 2021
The 'facts': The Wall Street Journal has reported that BP is looking to spin off its operations in Iraq – the Rumaila oil field – into
a standalone company jointly owned with PetroChina. This is the latest in a growing list of potential spin-offs. BP last month
signed an MoU with Eni to explore merging their Angolan businesses (see CWiB story from 20 May). And there were reports a
few weeks ago that BP is looking to spin-off its interests in Algeria, again in partnership with Eni.
Our take: Exiting Iraq would make sense for BP, in the context of its broader upstream wind-down. Rumaila is among the least
resilient assets in the portfolio, from a cash flow and emissions perspective. It’s high on our list of BP's most likely disposal
candidates, along with Angola and Algeria (among others). But exiting Iraq would not be easy – the list of potential buyers is
very short and the Iraqi authorities have recent form for making life difficult for would-be sellers.
So it seems that BP is instead looking to retain its interests in Iraq through an associate. That’s the structure through which BP
already holds its upstream interests in Norway (via Aker BP, in partnership with Aker) and Argentina (Pan American, in
partnership with Bridas). It’s a structure that BP and Eni are exploring in Angola. Generally speaking, the idea is to give
otherwise tired businesses a new lease of life, with the autonomy to be more dynamic, efficient and effective. Perhaps with an
eye to wholesale exit longer-term. But that doesn’t really apply with a single asset JV holding in Iraq.
So maybe this is about energy transition? From a structural and accounting perspective, Iraq would become a standalone
business – self-funded with its own balance sheet, falling outside BP Group level cash capex guidance. The owners – BP and
PetroChina – would be paid an annual dividend. That might tick a box with some investors. But Iraq would still be included in
Group level guidance and targets for production and greenhouse gas emissions, as is the case with Pan American and Aker BP.
Unless, that its, BP decided to treat Iraq as it does its equity holding in Rosneft: although Rosneft is accounted for as an
associate, BP chooses to ignore its equity production and emissions.
How likely is a Shell Permian sale?
Raphael Portela, 17 June 2021
The rumour: Shell could be looking to divest its Permian acreage. According to Reuters, the sale could be for part or all of
Shell's position, valued at more than US$10 billion.
Our take: Shell exiting the Permian would surprise us. The company has indeed been active on the M&A front, especially in the
US, where it exited the Haynesville, Appalachia, and Deer Park refinery in just the past year and a half. However, the Permian is
one of its nine core positions and the only shale asset in that group. Therefore, divesting more peripheral unconventional
projects – Montney in Canada or Vaca Muerta in Argentina – would be more likely in our view.
Our valuation of US$9.7 billion (NPV10) makes an outright sale nearly prohibitive in size, requiring appetite from Big Oil players.
Unfortunately, the list of capable buyers is short, and many of those won't be willing. Financially healthy E&Ps such as Chevron
and ConocoPhillips could execute, but recent chunky acquisitions (i.e. Noble Energy, Concho) lower the likelihood. Its Permian
JV with Shell makes Oxy an intriguing buyer, but factors such as high leverage and the ongoing Anadarko integration will be
hard to overcome.
Then there are smaller players like Diamondback, who have offset acreage and could stand to gain from more scale, but the
biggest hurdle would be the transaction's size.
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Should a deal materialize, we suspect dealmakers will have to be creative. For example, the transaction could involve cash and
stock, similar to what Shell pulled off with its Canadian Duvernay assets. A three-way deal is another avenue, allowing the buyer
to negotiate a side deal, like the Occidental-Anadarko-Total transaction.
We do not think carbon footprint is a consideration. The Permian's carbon intensity ranks low among Shell's portfolio, and it's a
flagship asset when it comes to proactive stewardship. Shell has reduced GHG and methane emissions in the Permian by over
80% since 2017. Flaring is also down by a similar amount, with no routine flaring since 2018.
Equinor accelerates shift towards new energy
Norman Valentine, 16 June 2021
The facts: Equinor’s 2021 Capital Markets Day saw it outline an accelerated shift towards new energy. The company’s 12-16
GW net renewables capacity target was brought forward by five years to 2030. It also unveiled ambitions to develop 15-30
mmtpa of CO2 storage capacity and 3-5 hydrogen projects over the next 15 years. To fund these goals, investment in
renewables and low carbon will rise to 50% of gross investment (before project financing) by the end of this decade.
Other highlights from the strategy update included: i) new intermediate targets for carbon intensity reduction, ii) increased focus
on value over volume in upstream with high-grading of the international portfolio, and iii) a commitment to increase shareholder
distributions comprising a 20% increase in the quarterly dividend in Q2 2021 and the reintroduction of share buybacks this year.
Our take: Equinor’s strategy update clearly articulated its ambition to accelerate along the road to net zero. Equinor’s plans to
advance renewables investment could see its net spend in new energy (post project finance) exceed BP by mid-decade. While
Equinor has undoubtedly increased its low carbon ambitions, the accelerator hasn’t been pushed to the floor. We see its
strategy as remaining balanced, aimed at maximising value from the legacy oil and gas business while positioning to be among
the leaders in renewables, CCUS and hydrogen.
•
Creating value in renewables: amongst the growth plans there was an acknowledgement that competition in established
renewables markets is pushing down project returns. Equinor reduced its renewables target return to 6-10% nominal
unleveraged, down two percentage points compared to its target from early 2020.
Equinor’s return target remains at the high end of our estimates for established markets. The company will look to enhance
returns by capturing large-scale entry positions in early-stage markets, with only selective engagement in auctions to avoid
competition-driven return erosion. It will also look to invest in onshore wind and solar as part of a diversified approach to
growth.
•
Refocusing in oil and gas: upstream will continue to be the cash engine that funds the business over the near to medium
term. There will be an increased focus on value and near-term cash payback. Equinor dropped its 3% annual production
growth target but still expects output to rise over the next five years. It aims to limit decline thereafter so that 2030 output is
similar to today.
Our base case production projections remain more conservative than the company’s guidance. But additional capacity
upgrades at Johan Sverdrup, positive newsflow from East Coast Canada, recent exploration success in Norway and progress
on improved recovery mean Equinor’s medium-term output goals are within reach.
The outlook for upstream beyond 2030 looks to be one of managed decline. Equinor has pulled back from frontier exploration
and early stage unconventionals in Australia, Argentina, Mexico, Nicaragua and the US. The focus will be about maximising
value from core assets and countries. Upstream cash flow will be increasingly harvested for reinvestment in new energies or
returned to shareholders rather than invested in long-dated upstream portfolio renewal.
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•
Financial framework: Equinor was pressed on how increasing new energy investments will impact the financial outlook and
dividend sustainability. The commitment to increase shareholder distributions this year looks easily affordable given current
oil prices. Equinor’s aim to raise annual buybacks to US$1.2 billion from 2022 pushes our corporate cashflow breakeven
estimate up from an average of US$45/bbl to US$50/bbl from 2022 to 2024 inclusive.
The reintroduction of buybacks rather than a full restoration of dividends to pre-crisis levels provides Equinor with financial
flexibility should oil prices fall below the US$50-60/bbl range that it plans to use as a buyback criteria. At US$1.2 billion per
year, buybacks will also be lower than the US$5 billion 3-year programme Equinor had in place before the oil price crash.
Shell plans “bold steps” to reduce emissions in response to legal ruling
Luke Parker, 14 June 2021
Shell last week offered its first meaningful response to a landmark legal ruling ordering the company to dramatically cut carbon
emissions. Investor Relations issued an FAQ on the case, and Ben van Beurden set out his thoughts on how Shell will “rise to
the challenge” (earning praise from BP counterpart Bernard Looney – see Comments).
To recap: on 26 May, the District Court in The Hague ruled that Shell must cut absolute Scope 1, 2 and 3 emissions from all
energy products sold by 45% before the end of 2030 (vs 2019 levels). The ruling came into effect immediately and cannot be
suspended pending an appeal.
Our take: While the legal ruling may be black-and-white, the issues it seeks to address and the challenges they pose for all oil
and gas companies are hugely complex.
It’s easy to suggest that the ruling – viewed in isolation – doesn’t make much sense. Targeting one company on the supply side
does nothing to ‘solve’ climate change. The arguments are well-rehearsed and some of Shell’s largest institutional investors
seemingly agree. The company’s climate strategy was approved by 89% of shareholders at its 18 May AGM. No surprise that
Shell intends to appeal.
But the message that the ruling sends and the apprehension of what comes next cannot be ignored. And Ben van Beurden was
clear that Shell will not ignore it. Rather, the company “will seek ways to reduce emissions even further in a way that remains
purposeful and profitable. That is likely to mean taking some bold but measured steps over the coming years.” We don’t know
what “bold” entails (rumour abounds), but it certainly means change.
Prior to the ruling, Shell’s Powering Progress strategy was targeting a 20% reduction in emissions intensity by 2030, with oil and
gas production flat to rising over the period. The 45% reduction in absolute emissions mandated by the Dutch court is a
completely different proposition, effectively requiring the company to cut supply by a similar quantum. Shell will presumably now
set a new trajectory that falls somewhere between those two very wide extremes. It may not go full BP (yet), but it will edge in
that direction.
In short, this ruling seems set to change Shell, irrespective of where the legal interpretation lands and how the appeal process
plays out. But the details will be hugely important – for Shell and the wider oil and gas industry – in resolving some of those
complex challenges and defining the trajectory.
Oxy divests non-core Permian acreage for US$508 million
Anuj Goyal, 11 June 2021
The facts: Oxy has announced the sale of 25,000 acres of its Southern Delaware basin acreage in Reeves and Ward counties
to Colgate Energy Partners III, LLC for US$508 million. The sale includes 10,000 boed/d of production from 360 active wells.
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The company plans to use the proceeds of the sale for debt reduction. This transaction brings Oxy’s total divestitures for the
year to US$1.3 billion, roughly halfway to its target of US$2 to US$3 billion.
Our take: Oxy has one of the highest gearing ratios in its peer group and has highlighted asset sales as a core part of its
deleveraging strategy. This transaction lowers gearing from 65.4% to 65.0%, which is still uncomfortably high.
To meet its asset sales goals, the company must divest between US$700 million and US$1.7 billion of additional assets. Its
Permian basin acreage provides some of the best opportunities for the company to do so. By our models, Oxy has over 25
years of inventory in the Permian, even with a modest activity increase. Divesting some of its non-core acreage could bring
value forward.
Additionally, private operators such as Colgate Energy Partners (which purchased the majority of Luxe Energy LLC’s assets just
two weeks ago) have been active buyers in the US Lower 48. The region has accounted for over 67% of global upstream deal
spend in 2021 so far, improving the chances that the company can continue to close deals here.
Rosneft sells a further 5% in Vostok Oil
Scott Walker, 11 June 2021
The facts: the Russian NOC has enticed two more foreign investors to take a stake in its massive Vostok Oil Project, which has
a reported estimated resource of 44 billion barrels. Commodity traders Vitol and Mercantile & Maritime are to acquire a
combined 5% stake for an (as yet) undisclosed sum. The sale to Vitol and Mercantile & Maritime follows fellow commodity trader
Trafigura joining the project in December last year, acquiring a 10% stake for a reported fee of around US$8.5 billion, implying a
value of US$85 billion for the project.
Our take: another major boost for Vostok Oil, Rosneft’s flagship project on the Taimyr Peninsula that is expected to maintain
Russia's oil production above 10 million b/d post-2030. Rosneft has been actively transacting of late as it looks to build out the
project, notably divesting multiple assets to NNK as part swap for the multi-billion-barrel Paiyakhskoye oil field, which is to be
incorporated into Vostok.
The addition of two more investors along side Trafigura is another show of confidence in the project, builds momentum, and –
with capital expenditure expected to exceed US$130 billion – brings in crucial extra funding. Similar to Trafigura, we think Vitol
and Mercantile & Maritime will have been swayed by the prospect of a long-term strategic relationship with the second largest oil
producer in the world and the guaranteed future trading volumes this could bring. We expect Rosneft will continue to look for
external investment, potentially diluting its interest by up to 49%.
A new Alliance: The Oil Sands Pathways to Net Zero Initiative
Rowena Gunn and Tom Ellacott, 11 June 2021
The facts: the five biggest oil sands operators announced the formation of a new alliance focused on reducing oil sands
emissions. The Oil Sands Pathways to Net Zero initiative aims to achieve net zero greenhouse gas (GHG) emissions from oil
sands operations by 2050. The alliance comprises CNRL, Cenovus, Imperial Oil, Suncor and MEG Energy. ExxonMobil has a
69.6% stake in Imperial Oil.
Our take: this is a big target covering Scope 1 and 2 emissions that’s backed by the oil sands’ leading players. Together, the
companies in the alliance are responsible for 91% of oil sands production. The alliance will only be able to achieve net zero
through employing several initiatives, building on current technologies and piloting emerging ones.
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The game changing idea is a proposed carbon capture, utilisation and storage (CCUS) scheme. A carbon sequestration hub
near Cold Lake, Alberta, will create an infrastructure corridor tying in multiple projects. The scheme will be among the largest
proposed yet. We forecast oil sands emissions of 75 Mt of CO2e for 2021 in our Emissions Benchmarking Tool. Current
global CCUS capacity is just 41 MtCO2e per year.
ExxonMobil will welcome the announcement, which comes just a few weeks after its shareholder proxy defeat. The proposed
scheme is a template that the Supermajor could deploy elsewhere in its portfolio. ExxonMobil had already proposed the 100
MtCO2e per year Houston Hub CCUS concept.
Moving these proposals to commercial reality will be an important step in convincing stakeholders that it can scale-up CCUS.
The big question is whether the pace will be sufficient to keep on a Paris glidepath.
Scope 1 and 2 oil sands emissions
Equinor sells Danish refinery
Norman Valentine, 11 June 2021
The facts: Equinor has agreed to sell its Danish refining business to the Klesch Group for an undisclosed consideration. The
principal asset in the sale is the 107,000 b/d capacity Kalundborg refinery, the largest in Denmark.
Our take: this sale sees Equinor dispose of one of only two refineries in its portfolio. We expected Kalundborg to provide limited
profitability over the medium term given the refinery’s low complexity and lack of petrochemicals integration, as well as a
maturing outlook for the European refining sector. New owner Klesch Group will look to create value through synergies with its
Heide refinery in northern Germany.
Equinor’s only remaining refining asset is the Mongstad refinery in Norway which is highly integrated with it upstream oil and gas
operations. We expect Equinor to retain Mongstad as its sole exposure point to the downstream sector. For detailed analysis of
European refinery net cash margins, please see the recent report from our downstream colleagues.
Hess announces new discovery and appraisal results in Guyana
Alex Beeker, 8 June 2021
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The facts: on 6 June 2021, Hess announced a new discovery at the Longtail-3 well. The well encountered 230 feet of net pay,
including new oil-bearing reservoirs below the Longtail-1 discovery, which was drilled in 2018. The discovery adds to the
previously announced estimate of 9.0 billion boe of gross discovered recoverable resource at the Stabroek block.
Additionally, the Mako-2 appraisal well confirmed the quality, thickness and areal extent of the reservoir. When combined with
data from the Uaru-2 discovery, there is line of sight to a fifth FPSO in the area. Lastly, the Koebi-1 exploration well discovered
non-commercial hydrocarbons. This well was located outside of the northwest-southeast fairway of discoveries, so its miss was
not too surprising.
Our take: this is the first time a potential location for FPSO #5 at the Stabroek block has been discussed. Given Uaru-Mako has
jumped ahead of prior discoveries like Hammerhead in the development queue, it speaks to the economic potential of the area.
The current plan is to FID one development per year. FID of the fourth development at Yellowtail is anticipated for early 2022
but the timeline could be accelerated if the government moves quickly. We value the Stabroek block in Guyana at US$31.9
billion, NPV10 (30% net to Hess). We model 9 FPSOs and peak oil production of 1,188 kboe/d in 2030.
Suncor commits to a 2050 net-zero Scope 1 & 2 emissions target
April Read, 8 June 2021
The facts: Suncor Energy has joined the net-zero club. The company also set an intermediate emissions target, bucking the
trend of using intensity targets and instead setting an absolute emissions target for Scope 1 & 2. On its way to net-zero, Suncor
will reduce emissions from 29MT/year in 2019 to 19MT/year by 2030. Other major oil sands producers Cenovus and Husky
(now part of Cenovus) earlier made declarations of net-zero (for Scope 1 & 2 emissions) by 2050, while CNRL has net-zero
targets for oil sands operations and Imperial Oil supports the Canadian federal government’s ambition to be net-zero by 2050.
Our take: this announcement is a significant change in messaging for Suncor. Earlier this year, the company appeared reluctant
to commit to net-zero targets, as it viewed the technology needed to achieve net-zero in oil sands as unproven or not yet
developed. The Investor Day presentation, however, laid out where both Suncor’s upstream and downstream emissions come
from and what technological opportunities it sees to reduce them.
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Suncor emissions
Source: Suncor 2021 Investor Day presentation
Suncor’s plan is the clearest mapping of where a Canadian company produces emissions from today and how it plans to
achieve emissions reductions in each of its business verticals. Developing CCUS options will be critical to meet corporate goals.
Also notable is Suncor’s decision to consider emissions not only from a base business perspective, but also from the view of
how it can help reduce emissions externally. For example, producing power with natural gas to help reduce Alberta’s
dependence on coal-fired electricity generation. We also see a bit of European flavor in Suncor’s plan, with investments into
wind power and renewables, albeit not at the same scale or business model disruption as some of the European majors.
BP boosts solar project pipeline with flurry of deals
Luke Parker, 7 June 2021
The facts: BP has acquired 9 GW of undeveloped solar projects from 7X Energy for US$220 million. The projects are spread
across 12 US states. Assets with a combined generating capacity of 2.2 GW are expected to reach FID by 2025, with the rest
progressing by 2030. The projects will be developed through Lightsource bp (BP’s 50-50 solar JV).
Our take: According to BP, the deal takes the company’s renewables development pipeline from 14 GW to 23 GW, implying
that BP will own 100% of the assets, with development effectively subcontracted to Lightsource bp. Assuming that BP can meet
its ambitious development timeframe, this deal marks a big stride towards its target to develop 50 GW (net) of renewables
capacity to FID by 2030. And at an apparently modest entry cost of US$220 million. BP expects the deal to meet its 8-10%
returns threshold for renewables.
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Over the past few weeks, Lightsource bp has also announced “co -development” partnerships in Greece (with Kiefer TEK) and
Portugal (with INSUN) that could eventually lead to the development of up to 2 GW (gross) of solar projects.
Please see our BP corporate new energy profile for in-depth analysis of BP’s strategy and portfolio.
Ørsted scales-up and broadens green ambitions
Norman Valentine, 4 June 2021
The facts: Ørsted’s capital markets day saw it set out an ambition to be the “world’s leading green energy major” by 2030. The
company’s headline growth target is to increase installed capacity to 50 GW by 2030, up from its previous target of 30 GW and
quadrupling current installed capacity of 12 GW.
To realise its vision, Ørsted expects to invest DKK 350 billion (US$57 billion) out to 2027, increasing annual spend by 50%
compared to figures set out at its last strategy update in 2018.
Leadership in offshore wind will remain core and Ørsted plans to increase installed offshore capacity to 30 GW, up from 7.6 GW
today. Ørsted also expects to grow strongly in onshore wind and solar and also plans to build global leadership in renewable
hydrogen and green fuels
Our take: Ørsted’s strategic vision provides a glimpse into how the world’s leading offshore wind player sees its future in a
rapidly evolving sector. We highlight three main takeaways:
•
Diversification: Ørsted is going global, extending its onshore footprint and seeking to leverage its scale and development
experience. It expects to maintain leadership in offshore wind in Europe, the US and Asia through the development of its
existing project pipeline. In onshore wind and solar, Ørsted will extend its footprint from the US across Europe and Asia.
•
Integration with emerging technologies: integration of renewables and hydrogen, growth in floating offshore wind and
positioning for a role in Denmark’s offshore energy islands are all elements in Ørsted’s plan to be a leader in the energy
transition.
•
Elevating environmental credentials: Ørsted is seeking to differentiate itself as the greenest of the green. Ørsted has made
commitments to be carbon neutral on Scope 1 and 2 carbon emissions by 2025 and be totally carbon neutral (including the
carbon impact of its supply chain) by 2040. It has also committed to recycle all its turbine blades from now onwards and
increase biodiversity in all commissioned projects by 2030.
For a more comprehensive viewpoint on Ørsted’s strategy, please read our Inform.
Repsol high-grades in South-Eastern Asia
Tom Ellacott, Andrew Harwood, 4 June 2021
The facts: Repsol has agreed to sell a package of Malaysian and Vietnamese assets to KLSE-listed player Hibiscus Petroleum
for an upfront cash consideration of US$212 million. The transaction marks the company’s exit from the Malaysian upstream
sector.
Our take: we’d previously touted Vietnam and Malaysia as prime divestment candidates. Both countries lack critical mass.
Repsol has also taken an important step in reducing its global carbon footprint. The asset package includes PM3 CAA, the
company’s fourth-largest emitter of Scope 1 and 2 emissions despite producing only 19 kboe/d net (2% of the total). Repsol
retains minor interests in Vietnam, but will look to tidy these up swiftly.
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Repsol’s rationalisation programme is gathering momentum. This transaction follows the sale of producing assets in Russia, the
cessation of production in Spain and streamlining of exploration portfolio. But more country exits will be on the table as the
company shrinks its geographical footprint from 25 to 14 countries. Russia and Ecuador are among the more obvious
candidates.
Look to our Asia Pacific upstream in-brief for further discussion of the deal details and the outlook for further M&A in SouthEastern Asia.
Oil-hedging activity steady in Q1 as losses grow
Matt Woodson, 3 June 2021
The facts: Our 53-operator hedge benchmarking peer group saw a combined hedging loss of $3.2 billion in Q1. The quarter
remained active for new crude-hedging with 649,000 b/d of new volumes, down just 7% from the previous quarter. North
American producers Cenovus and Pioneer led the peer group with over 100,000 b/d of new contracts each.
Our take: Hedge contracts entered into during the downturn will continue to limit upside. We estimate that the peer group would
see a combined further hedging loss of US$13.0 billion in our high price scenario ($77.50/bbl Brent, $3.23/mcf Henry Hub). The
peer group has hedged 32% of expected 2021 oil production at an average floor Brent price of US$48.02/bbl.
Most US Permian-focused operators have hedged a higher percentage of 2021 crude volumes, at between 43%-73%. APA
Corporation is an outlier at 19%. Devon, Pioneer and Diamondback have all absorbed the hedge portfolios of the companies
they have acquired over the past year (WPX, Parsley and QEP, respectively) leaving them possibly more hedged than they
would prefer to be. Q1 was a welcome return to profitability for many in the tight oil space, but hedge obligations will be a drag
on future returns for the remainder of the year.
For more detail, see our hedging update insight.
Monthly summary of oil hedge volumes and price
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Corporate week in brief
More L48 shale gas consolidation
Mike Stinebaugh, 2 June 2021
The facts: Southwestern Energy announced today that it is acquiring Indigo Natural Resources, a large private gas producer,
for US$2.7 billion. The transaction consideration is a combination of stock (~US$1.6 billion), cash (US$400 million) and
assumed debt (US$700 million of 5.375% senior notes due 2029). The deal is expected to close in Q4 2021. The acquisition
adds about 1 bcfe/d of production, bringing combined company volumes to about 4 bcfe/d, 85% gas.
Our take: Southwestern is stepping out from its pure-play Marcellus position to add Haynesville growth options to its portfolio.
As you’d expect from a non-overlapping acquisition of a private, synergy savings are low, with G&A reductions targeted at
US$20 million. Despite the move into another basin, Southwestern is sticking to its core principles of achieving competitive scale
in low-cost gas basins – they began as a dominate producer in the Fayetteville before heading to the Northeast.
While not a complementary in-basin deal, this acquisition still fits the 2021 consolidation playbook. Activity on the new acreage
will be limited to four rigs/US$ 500 million, and projected incremental cash flow will increase Southwestern’s cash flow by over
50%. This is the third large deal this year in the shale gas peer group, following EQT-Alta Resources and the Cimarex-Cabot
merger-of-equals. In the coming days we will follow-up with a full-length deal insight.
Big Oil gets (another) wake up call
Luke Parker, Tom Ellacott, 31 May 2021
The facts: Three Majors suffered landmark defeats last week to stakeholders pushing for change on climate related risk.
ExxonMobil and Chevron shareholders voted, against Board recommendations, in favour of proposals that effectively push them
toward Euromajor-style transition strategies and carbon commitments. But the Euromajors themselves are not unimpeachable.
On the same day, a Dutch district court ruled that Shell must adopt more aggressive emissions reduction targets, to cut absolute
Scope 1, 2 and 3 emissions by 45% to 2030.
Our take: Each verdict is meaningful in its own right. That they came on the same day adds to the sense that this is a
watershed moment. But, despite the headlines (and the timing), this turn of events shouldn’t come as a surprise. The direction of
travel for the Majors is clear. Wednesday's proceedings mark the latest signposts on the journey. We've also suggested that the
perceived ‘split’ between the Euro and US Majors reflects a time-lag in shifting stakeholder sentiment on either side of the
Atlantic, rather than anything more fundamental. The gap is closing fast. The fact that all three companies’ share prices barely
moved on the news speaks volumes (it’s not that there isn’t a problem – it’s that the problem is already priced in).
The specific implications of each ruling for the companies concerned are impossible to know at this stage. The resolutions are
vague, and the court ruling will be challenged. No matter, the broader message is clear. As far as signposts go, these were big,
neon and flashing, and will rightly draw the attention of the entire oil and gas industry.
Read more in our Inform: Challenging verdicts for Big Oil.
Total gets shareholder approval for rebranding and transition strategy
Tom Ellacott, 31 May 2021
The facts: Total’s shareholders voted in favour of the resolutions proposed by the Board of Directors at its Annual General
Meeting. Total’s name change to TotalEnergies was almost unanimously approved. More than 90% of shareholders also
approved the resolution on Total’s sustainable development and transition towards carbon neutrality and related 2030 targets.
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Our take: the seal of approval was in contrast to the stakeholder defeats suffered by peers (see above). But 90% of Shell’s
shareholders also approved its transition strategy at the AGM a few weeks ago, yet 30% voted for the Follow This resolution.
Total didn’t face any special resolutions (Follow This or other) in its AGM because these groups fall short of the holding required
to table one.
The rebranding to TotalEnergies is nevertheless highly symbolic. Total has built up a range of low-carbon growth platforms
including a peer-leading position in renewable power. The company also has leading hydrocarbon growth prospects. This
differentiated dual growth strategy provides optionality on a range of energy transition scenarios.
Total’s goal is to reduce emissions while growing total energy production out to 2030. The company reduced Scope 1, 2 and 3
emissions intensity by 8% between 2015 and 2020 and has set interim targets for 2030. Shareholders will also have taken note
of Total’s financial performance. Total was the only Euro Major not to cut its dividend in 2020 but still has one of the strongest
balance sheets in the peer group.
Shell continues refining purge, sells Deer Park to Pemex
Luke Parker, Raphael Portela, 27 May 2021
The facts: Shell announced two more downstream disposals this week. The larger of the two will see it sell its 50% stake in the
340,000 b/d capacity Deer Park refinery (Texas) to Pemex, its partner in the JV. The consideration is US$596 million, plus the
value of any inventory at close. Shell will also sell its 100% stake in the 90,000 b/d Mobile refinery (Alabama) to pure-play refiner
Vertex for US$75 million, plus inventory value.
Our take: Shell is on a roll. In May alone it has announced US$1.2 billion of downstream disposals. The company is in the
process of cutting the number of refineries in its portfolio from fourteen to six, retaining sites integrated with petrochemicals to
create six “energy and chemicals parks”. Curiously, however, Deer Park was supposed to be one of those six. By our analysis,
the refinery ranks among the best in Shell’s global portfolio. The company will retain its 100% stake in the adjacent chemicals
facility, but it seems that Pemex’s unsolicited offer for the refinery was just too good to refuse.
Pemex, for its part, believes the purchase will help Mexico reach self-sufficiency in gasoline production. Reducing dependence
on imports is high on the Mexican President’s agenda, as typified by the ongoing construction of the 340,000 b/d Dos Bocas
refinery (Tabasco). And relative to the US$10 billion price-tag on that greenfield project, the Deer Park acquisition undoubtedly
offers bang for buck. Our view, however, is that Pemex would be best served by focusing on the low-hanging fruit – revamping
its Mexican assets, most of which are operating under 50% utilizations today.
Look out for detailed analysis - portfolio, valuation and strategic rationale - in our forthcoming Deal Insight.
Cimarex and Cabot combine in merger of equals
Mike Stinebaugh, 25 May
The facts: on 24 May 2021, Cabot Oil & Gas and Cimarex Energy Company agreed to merge in a stock-for-stock transaction
with a combined enterprise value of ~US$17 billion. Cimarex shareholders will receive 4.0146 shares of Cabot per share of
Cimarex, equivalent to 49.5% of the company. The new entity is yet to be named but will produce over 600 kboe/d across the
Permian, Mid-Continent and Appalachian Basin. The market's initial verdict on the deal was negative, with the share price of
each company falling 7% on the day of the announcement.
Our take: this deal surprised us and many observers. It is differentiated in several ways, none more than the unique
combination of assets. While Cimarex holds interests across the Permian and Mid-Continent, Cabot is a pure-play Marcellus
shale gas operator.
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But there's a lot for investors to like about the merged entity - both operators hold low-cost assets in major basins and have
strong balance sheets. Cabot's strong PDP cash flow profile will support organic development of Cimarex' considerable
Delaware Basin acreage, in turn boosting cash flow and dividends.
The merger will put to rest rumours of either company being acquired but raises questions about deal valuation and the outlook
for the new entity. We addressed these questions in an inform on the match-up, and covered the deal details in our deal insight.
Shell exits Philippines with sale of Malampaya gas fields
Greig Aitken, 21 May 2021
The facts: Shell Petroleum N.V has signed an agreement with Udenna Corporation to sell its 45% stake in the Malampaya
Service Contract 38 (SC38), offshore Philippines. Udenna will pay a base consideration of US$380 million, plus up to a further
US$80 million contingent on achieving license extension and certain commodity prices.
Our take: Malampaya is the Phillipines' sole producing gas field, servicing approximately 30% of Luzon’s power generation and
nearly a quarter of the country’s power needs. We expect the field to continue producing 300-360 mmcfd of gas until license
expiry in February 2024. Post-expiry, we estimate Malampaya will have an additional resource of 300 bcf.
Shell’s decision to sell its stake is consistent with efforts to streamline its global upstream portfolio and focus on core positions.
A successful sales process of Shell’s interest in the Masela block (Abadi) in Indonesia would leave the company's southeast
Asian focus squarely on Malaysia and Brunei.
The acquisition takes Udenna’s interest in Malampaya to 90%, having bought Chevron's 45% stake in March 2020. Udenna will
face the challenging task of managing a mature and depleting deepwater gas asset without the expertise of a major upstream
player. In addition, a contract extension is necessary for Udenna to sustain cash flow from the asset beyond 2024.
Eni and BP consider merging their Angolan portfolios
Greig Aitken, 20 May 2021
The facts: Eni and BP have entered a non-binding memorandum of understanding (MoU) to progress detailed discussions on
combining their oil, gas and LNG assets in Angola under a new joint venture (JV).
Our take: BP plans a 40% reduction in global production by 2030. Its Angolan portfolio is non-core, accounting for just 2.9% of
the group's total projected volumes in 2021 following a 60% decline in liquids production since 2015. A country exit was, and
still is, an option to help achieve its target.
Angola is more core to Eni. The company has enjoyed great success with exploration and reserves growth, particularly in Block
15/06. Eni might have simply acquired BP's portfolio. But the proposed joint venture makes a lot of sense.
A JV would give each company's oil-weighted Angolan operations a well-defined and self-funded structure in which to operate.
Both parents would still benefit from cash distributions, without having to allocate future capital. We envisaged exactly this type
of structure being utilised by IOCs in our latest Horizons insight "Swimming upstream - a survivor's guide". It is not a surprise to
see BP and Eni specifically involved in leading the charge. Both players have had success with similar structures - BP with its
minority stake in AkerBP and Eni with its majority holding in Var Energi.
The Angolan portfolios are well-matched resource-wise. Each company contributes around half of the combined reserves of 2.3
billion barrels and both portfolios have similar 75/25 oil to gas splits. However, Eni’s portfolio carries a value of US$5.5 billion
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compared to BP’s US$3.2 billion. BP’s Block 31 holds over one billion barrels of undeveloped resources and offers synergies
with neighbouring 15/06. The JV could also undertake portfolio rationalisation, with BP’s high-cost Block 18 Greater Plutonio a
divestment candidate. It may also consider acquiring blocks 16 and 31 in the 2021 licence round.
See our Lens video for further analysis of this proposed venture.
BP, Eni combined entitlement production, Angola
Source: Wood Mackenzie Lens
Total gets renewables boost in India
Tom Ellacott, 19 May 2021
The facts: Adani Green Energy Limited (AGEL) has announced the acquisition of SB Energy for an enterprise value of US$3.5
billion. The transaction is the largest renewables acquisition to date in India.
SB Energy holds 4,954 MW of renewables capacity, split 84% solar, 9% wind-solar hybrid and 7% wind. Operational solar
capacity amounts to 1,400 MW with the remaining 3,554 MW under construction. All projects are contracted under 25-year
power purchase agreements.
Total acquired a 20% minority interest in AGEL in January 2021.
Our take: AGEL is proving an effective expansion vehicle for Total in India. AGEL will achieve its renewables growth target of
25 GW in 2025 four years ahead of guidance through this deal. The US$705/KW price tag also compares favourably with our
estimate of regional average solar capex in the Asia Pacific region this year (c. US$945/KW).
The transaction adds 991 MW of net capacity to strengthen Total’s peer leadership in wind and solar. The long-dated PPA
coverage with sovereign counter parties will also have been attractive for AGEL and Total.
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AGEL will continue to push growth hard. The company has ambitions to become the world’s largest solar player by 2025 and
the global renewables leader by the end of the decade. This transaction will also provide the building blocks for expanding into
hydrogen and storage. Total will have material exposure to any upside through its 20% interest in the company.
Wood Mackenzie estimate of wind, solar and hydro power capacity
Proxy season for Big Oil – investor pressure on carbon continues to ratchet
Luke Parker, 17 May 2021
May is AGM season for Big Oil – when shareholders get to sign off on such matters as executive pay, nominations to the Board,
buyback programmes, approval of auditors and so forth. But it’s also the one chance that shareholders get each year to submit
proposals of their own.
For a while now, these ‘special resolutions’ have been dominated by carbon and climate-related proposals, with companies
varyingly urged to adopt net zero emissions targets, cease exploration, disclose lobbying activity, stop producing oil and gas,
etc. These proposals are, almost universally, opposed by the Board and overwhelmingly voted down. Exceptions can be
counted on one hand.
The 2021 proxy season has added a few more examples to the list. Last week, 58% of ConocoPhillips shareholders voted,
against the Board’s recommendation, in favour of a Follow This proposal that the company adopt Scope 3 emissions reduction
targets. A few days later, an undisclosed majority of Phillips66 shareholders did the same. Both companies have, to date,
focussed targets on Scope 1 & 2 emissions, arguing that end-use (Scope 3) emissions are not their responsibility. Effectively the
same argument that BP made for a long time, until it didn’t.
Elsewhere, however, it seems like business as usual. Equinor last week faced seven climate-related proposals from various
shareholder groups, all of which the Board opposed, all of which were rejected by at least 94% of shareholders. BP faced its
own Follow This resolution, which was opposed by the Board and rejected by 79% of shareholders.
But these resolutions are never the whole story. It’s the engagement behind the scenes, of which they are emblematic, that
really matters. None of the climate strategies and carbon targets that the Euromajors have adopted over recent years were
‘forced’ by one-off activist investor proxy votes. But they were all a direct result of broader engagement with big institutional
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shareholders. So don’t be surprised to see Equinor, for example, set interim targets for global Scope 3 emissions on the route to
net zero – the kind of targets that Follow This was calling for.
There are more votes, and more headlines, to come. Shell holds its AGM tomorrow; ExxonMobil and Chevron later this month.
Each face similar motions. ExxonMobil is under additional pressure from hedge fund Engine No.1, which is citing a lack of
preparedness for energy transition in its move to shake up the Board of Directors. For all the large oil companies, climate
and carbon related pressure – from investors and beyond – continues to ratchet, and will only increase from here.
Investor motions on climate-related risk and carbon emissions targets, 2017-2020
Source: Wood Mackenzie analysis of company statements. Majors only. Not exhaustive – only notable investor motions. Individual motions
represented by individual pins. Does not include investor motions concerning climate related lobbying or Board representation.
Petrobras Q1 results: staying the course
Raphael Portela, 14 May 2021
The facts: recurring adjusted EBITDA (ex-impairments) came in at US$8.7 billion versus US$6.5 billion in Q4 2020, aided by
higher oil prices and lower operational expenses. Gross and net debt both fell by US$5 billion to US$71 billion and US$58
billion, respectively. Operating results continued their positive trajectory, with production up 3.1% and lifting costs down 13%
(US$4.9/boe) quarter-on-quarter. Shares were up 4.3% immediately after the call.
Our take: The new CEO was absent from the call. Instead, Petrobras played a short clip of him with prepared remarks. The
move does affirm his initial stance – a hands-off start to his stewardship. Analysts attempted to extract any indication of a
change in plans from those present but were ultimately unsuccessful. Even when discussing Petrobras’ update to its business
plan (usually released in December), leadership revealed their expectation of little change. Priorities for 2021-2022 remain to
deliver on its operational strategy and to delever.
Repsol retreats from Russia
Tom Ellacott and Michael Moynihan, 14 May 2021
The Facts: Repsol is reported to have agreed to divest its 49% stake in AR Oil & Gas to majority shareholder Neftegazholding
(NNK). The subsidiary produces around 9 kboe/d net to Repsol in West Siberia.
Our Take: Repsol outlined a goal to shrink its upstream geographical footprint from 20 to 14 countries in its five-year strategic
plan last December. The company will still retain its stake in Eurotek-Yugra and exploration opportunities with Gazpromneft in
Russia after this deal closes. But the transaction could signal the start of the portfolio streamlining process.
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Russia is an obvious country exit option given its lack of materiality to Repsol. Ecuador, Malaysia and Vietnam are also small
producing regions that the company could look to divest. The pace of disposals will be dependent upon the return of more
supportive upstream asset market dynamics.
Repsol enters the US renewables sector
Tom Ellacott, 13 May 2021
The facts: Repsol has announced that it will acquire a 40% interest in Hecate Energy to enter the US renewables market.
Hecate Energy has a portfolio of more than 40 GW of renewable and energy storage projects. This includes 16.8 GW of solar
projects at advanced stages of development. The company also participates in Hecate Grid, a battery platform for energy
storage with a capacity of 4.3 GW.
No consideration was announced for the transaction. But Repsol has the option to acquire all the outstanding shares three
years after the deal has closed.
Our take: Repsol has taken an important step in diversifying its portfolio with this deal. The company entered the Chilean
renewables sector in 2020 in its first internationalisation move. Repsol subsequently guided that it would enter another two to
three countries. The US was top of our target list given its scale and rapid growth potential.
Repsol will gain exposure to a geographically diverse portfolio. Hecate has a strong presence in the PJM regional market but
has also expanded into other states from Northeast to Northwest and California to the Carolinas, and even internationally in
Canada. Hecate is also a nimble developer that partners with other renewable financiers.
Hecate operates a business model in which early stage projects are captured, de-risked then sold. It doesn’t have any capacity
in operation or under development. The deal provides Repsol with a platform to buy into projects that hit its investment and
strategic criteria for power generation. Exercising the option to acquire all the equity in the company could also result in
additional opportunities for portfolio development.
US Independents Q1: week two earnings recap
Dave Clark, 7 May 2021
Last week, US E&P earnings were dominated by a theme of laser-focused deleveraging. In a very busy Week 2 (20+
companies), with most of the elite independents reporting, the narrative shifted in the direction of cash return to
shareholders.
EOG announced an attention-grabbing ~US$580 million special dividend (US$1/sh) after a record quarter for free cash flow of
US$1.1 billion. Devon made its second consecutive quarterly variable dividend payment, US$0.23/sh, up ~20% Q/Q. Combined
with its regular dividend, the implied annualized dividend yield is almost 6%. Pioneer reiterated its plan to start a robust variable
dividend (~75% of trailing FCF, after the regular dividend) in 2022. Assuming 60% reinvestment, they expect about US$23
billion of free cash flow from 2021 to 2026 at current strip prices – more than half the current ~US$41 billion enterprise value.
ConocoPhillips returned nearly US$1 billion to shareholders in the quarter, including US$375 million of share repurchase
under its annual US$1.5 billion plan, and outlined an intention to sell down its 10% Cenovus stake to fund incremental
buybacks. A half dozen companies increased their base dividend, including Marathon Oil who boosted it by 33%. Numerous
others outlined plans for dividends and buybacks once they reach leverage thresholds.
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Capital discipline remained strong across the group – no one raised 2021 capex guidance, despite rising oil prices and cash
flow. The 30 US independents in our coverage that have reported (Occidental and Chesapeake report next week) generated
US$13.6 billion of operating cash flow (US$14.8 billion ex-working capital), and had capex of US$7.6 billion, a reinvestment
rate of just 56%.
Excluding companies involved in major deals (who saw combined-company debt rise), the US Independents paid down about
US$4.3 billion in net debt. Aggregate gearing for the whole group fell from 38.1% to 36.4% in the quarter. The US E&Ps still
have a ways to go to mend balance sheets, but as we highlighted in our “Stay-Flat Cash Flow” analysis in November, the
duration of required deleveraging is much shorter above US$60/bbl WTI.
One thing we were watching for this quarter was indications of service cost inflation. While there was some mention of higher
steel, chemical and diesel costs, overall the issue was quite muted. Inflation is likely coming, but hasn’t had much impact on the
sector yet.
Shell sells Puget Sound, shrinks downstream further
Luke Parker, 7 May 2021
Shell is selling its Puget Sound refinery (Washington State) to independent US refiner HollyFrontier for around US$500 million
(including US$150-180 million of inventory). It’s the latest move in a high-grading programme that will see Shell cut the number
of refineries in its portfolio from fourteen to six. Shell will keep hold of those that are integrated with chemicals sites to create six
“energy and chemicals parks”, spread across North America, Europe and South East Asia. The consideration reflects the very
different strategies and outlooks of the respective parties, and highlights that there is a market for assets that might no longer fit
within a net-zero Big Energy portfolio. See our Inform for analysis.
EQT Corp to acquire Alta Resources
Mike Stinebaugh, 6 May 2021
On its earnings call this morning, EQT announced it will be acquiring Alta Resources, a Marcellus pure-play private operator, for
US$2.925 billion. The transaction will be financed through US$1 billion of cash and the remaining portion met with EQT common
stock, subject to customary closing adjustments. We have a valuation of US$2.948 billion on Alta Resources, with US$400
million attributed to its midstream assets.
The largest US natural gas producer is becoming larger. Upon close of the deal in Q3 2021, EQT will be producing 5.6 Bcf/d.
Although EQT's share price suffered a 8.6% loss today, we view the transaction positively. Its importance will grow as time goes
on. Acquiring Alta Resources allows for EQT to enter the NE Marcellus, gaining pricing hub diversification; and more
importantly, now holds over two decades of double-digit positive IRR undrilled inventory in its portfolio.
Equinor enters Polish solar sector
Norman Valentine, 6 May 2021
The facts: Equinor has completed the acquisition of Polish onshore renewables developer Wento from the private equity firm
Enterprise Investors for an enterprise value of EUR91 million (US$110 million) before adjustments. Wento aims to
commercialise a portfolio of small and large (25 MW+) solar projects in Poland with a total potential net capacity of around 1.6
GW.
Our take: this deal provides Equinor with an early-stage solar portfolio adding to its directly owned solar assets in Brazil and
Argentina and its equity stake in the Norwegian solar developer SCATEC Solar. The acquisition of Wento is consistent with
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Equinor’s strategy of building early-life renewables positions across technologies in core target countries. Combined with its
offshore wind portfolio, Equinor now holds a renewables pipeline in Poland with a potential total net capacity of up to 3.1 GW.
Equinor secures price support for Polish wind projects
Norman Valentine, 5 May 2021
The facts: Equinor and Polenergia’s Bałtyk II and Bałtyk III offshore wind projects have been awarded contracts for difference
(CfD) under the first phase of Poland’s offshore wind development scheme.
The projects, with a combined potential capacity of 1,440 MW, were awarded CfDs at PLN319.6/MWh (approximately
EUR70/MWh) for up to 25 years, subject to adjustments and final approval from Polish authorities and the European
Commission.
The CfD mechanism will guarantee a fixed price for future power generation. Equinor anticipates the projects could begin
construction in 2024.
Our take: this is another big win for Equinor as it develops its offshore wind business. Two of the company’s largest wind
assets, equivalent to around 10% of the total net potential capacity of its global wind portfolio, have taken a sizable step towards
project sanction within the next few years. For further views on Equinor and the other Majors ambitions in the offshore wind
sector, please watch our recent webinar.
Saudi Aramco Q1 results rebound
Norman Valentine, 4 May 2021
The facts: Saudi Aramco reported a 30% year-on-year increase in quarterly net income as higher average realised oil prices
(+16% year-on-year to US$60/bbl in Q1 2021) and improved downstream margins offset lower oil output (-12% y-o-y to 8.6
million b/d).
Higher quarterly cash flow from operations (+18% y-o-y to US$26 billion) supported dividend commitments from Q4 2020
(US$18.75 billion) and higher capital expenditure (+11% to US$8.2 billion), especially in upstream (+19% to US$6.5 billion).
Gearing remained flat at 23% over the quarter. Based on this quarter’s performance, Aramco maintained its quarterly dividend
at US$18.75 billion.
Our take: higher oil prices helped Aramco to balance the books this quarter. But unlike its capital discipline focused
international peers, Aramco is eschewing deleveraging for now and is hiking investment instead. A near 20% jump in upstream
investment this quarter highlights Aramco plan to increase capital spend by close to 30% this year, mostly in upstream.
With spending up and Aramco’s huge dividend maintained, asset sales will boost Aramco’s finances. The recently announced
sale of a 49% stake in Aramco’s crude oil pipeline network for US$12.4 billion could nudge reported gearing down by a couple
of percentage points in Q2 (see Corporate Week in Brief 9 April 2021).
Further asset sales could also be on the horizon. Aramco indicated Saudi Arabia’s newly launched Shareek program could
present new partnership opportunities. A monetisation of Aramco’s gas pipeline could be one option and there has also been
speculation that divestments could extend to upstream. Recent reports also indicate a stake in Aramco could also be for sale to
a strategic partner.
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Majors’ Q1 results round-up: corner turned?
Tom Ellacott, Luke Parker, Norman Valentine, 3 May 2021
All seven Majors reported Q1 2021 results last week – the most upbeat set of earnings calls since the coronavirus pandemic hit.
Most reported soaring earnings and cash generation, beating market expectations and sending a strong message on the
performance of ‘re-set’ businesses at current oil prices.
However, all were keen to emphasise discipline and prudence in the face of continued risk and uncertainty. Investment
guidance for 2021 remains tight across the board and plans for growth in shareholder distributions are cautious.
With six of the seven having recently presented strategy updates (and the seventh – Equinor – due to do the same mid-June),
there were no major announcements. But all seven devoted airtime to reaffirming big strategic messages, with a focus on
energy transition.
BP’s numbers were buoyed by an “exceptional” quarter for gas trading and US$4.8 billion of disposal proceeds. The company
hit its US$35 billion net debt target ahead of schedule, triggering a share buyback programme that could amount to tens of $
billions over the next few years. BP shares were up 3.7% for the week.
Shell (up 0.3% for the week) and Equinor (up 2.7%) also strengthened the balance sheet on the back of strong cash
generation and material disposal proceeds. Equinor signalled its confidence in a sustained recovery with another quarterly
dividend increase. Shell, meanwhile, is closing in on its net debt target of US$65 billion – the threshold at which growth in
shareholder distributions kicks in.
Total – the only Euromajor that didn’t cut its dividend last year – beat market expectations and ended the quarter with gearing
below its 20% target. However, the declaration of force majeure on the flagship Mozambique LNG project (story below) cast a
shadow. Shares ended the week flat.
Eni’s performance in Q1 2021 was a mixed bag, with European refining exposure and thin gas spreads dragging on solid
upstream performance. Separately, Eni announced a project to spin off its gas and power retail and renewables business – the
first such move among the Majors. Shares ended the week down 1.7%.
ExxonMobil’s earnings surged to its first profit in five quarters, beating market expectations. Net debt reduction turned the tide
on two years of quarterly increases. Upstream and chemicals had strong quarters, but weak margins once again buffeted
downstream results. The strategy for transition and the focus on CCUS took up a lot of airtime. Shares ended the week up
3.0%.
Chevron reported its best quarterly profit since the pandemic yet fell short of the performance of some peers. A 4% dividend
increase was a signal of confidence in its financial strength. But Chevron is not yet ready to commit to a fresh buyback
programme given the uncertain macro outlook. Shares ended the week up 1.5%.
US Independents Q1: week one earnings recap
Dave Clark, 30 April 2021
The Facts: US Independents kicked off earnings this week. Ten companies in our coverage reported, five of which were
Appalachian gas producers. The oil-focused operators included Hess, Continental and Ovintiv. While the Week 1 group is
gassier, and more heavily levered, than the 20+ companies that report next week, we see some clear themes emerging this
earnings season.
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Our Take: Capital discipline remains strong, thus far no increases to 2021 budgets, despite WTI sustaining US$60+/bbl, robust
NGL prices, and NYMEX just shy of US$3/mmbtu. Aggregate reinvestment rate for the ten companies this week was just 50%
of operating cash flow. The bigger test will come on Q2 in July after another quarter of meaningful FCF.
As expected, debt reduction has been paramount, with nearly all free cash flow going to clean up balance sheets. FCF (after
dividend) for this group of ten was US$1.99 billion in Q1, with net debt reduction of US$1.94 billion - nearly 100%. The paydown took aggregate book gearing for this over-levered sample of E&Ps down from ~50% at year-end to about 48% - still a long
way to go to resilient balance sheets.
With commodity strips all at healthy levels by late in the quarter, the companies as a group hedged much of the balance of
2021, after entering the year less hedged than four of the last five years. Hess has covered 85% of its oil production at
US$55/bbl WTI and US$60/bbl Brent. Antero has locked in US$36/bbl for almost half of its C3+ NGLs (65%+ of WTI). We
expect many operators next week to reveal a step-up in hedging as well.
On 4Q reporting in late February/early March, we had three companies initiate new dividends, and several discuss plans for a
variable dividend. This quarter Continental has re-started its suspended quarterly dividend at $0.11/sh (last dividend was Q1
2020 at $0.05/sh), and Cabot boosted its quarterly dividend 10% to $0.11/sh. Several of the companies outlined plans for
buybacks or variable dividends once they have reach leverage targets. For now though, cash return to shareholders is
secondary to mending balance sheets. Just 4% of operating cash flow in Q1 went to dividend or buyback from these ten
companies.
Total enters offshore wind project in Taiwan
Tom Ellacott, 29 April 2021
The facts: Total has signed an agreement to acquire a 23% stake in Yunlin Holding, the owner of the Yunlin offshore wind
development in Taiwan. The 640 MW project is under construction and due online in 2022. A 20-year PPA contract has been
signed with state-owned Taipower for US$250/MWh for the first 10 years, falling to US$125/MWh over the following 10 years.
Total will pay a consideration based on its share of past costs.
Our take: Total has made a good start in expanding into the Asia Pacific offshore wind sector. Taiwan has led the charge to
develop offshore wind capacity (outside China) and is open to foreign investors (excluding Chinese companies). Total will
secure a high fixed PPA price through its early entry. Future projects will be awarded via tenders for which competition will place
downward pressure on price.
The move continues Total’s intense business renewables development since 2020. The company added 10 GW of gross wind
and solar capacity in Q1 alone. Offshore wind will be a core focus for future growth given its scale and higher capacity factors.
We expect Total to be on the prowl for opportunities in other East Asian markets with ambitions in offshore wind, building on the
5.5 GW of cumulative capacity secured since its entry into the sector in 2020.
Progress towards net zero goal is highlight of Lundin results call
Zoe Sutherland, 29 April 2021
The facts: Lundin has taken another important step towards its goal of reaching net zero from its Scope 1&2 emissions by
2025. This month it acquired a 100% interest in the Karskruv onshore wind farm in Sweden. The farm is due onstream in 2023
and will produce 290 GWh per annum.
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Our take: reaching net zero is now in clear sight for Lundin, which is on track to be the first Upstream company to reach this
goal. Combined with its other renewables projects, Lundin now expects all of its net electricity usage will be powered by
renewables by the end of 2023, and 95% of its oil production will be powered by its own generated renewable energy. Any
residual emissions will be offset through natural carbon sinks.
Lundin’s impressive progress on reducing carbon emissions has allowed it to trade the world’s first certified carbon neutral crude
cargo. This means any emissions associated with production of the crude have been avoided or offset. Its worth noting that the
crude is not net zero from Scope 3 emissions - those that occur when the crude is burned by the end user. Lundin is setting
itself up to benefit from the growing market for low carbon fuel. At present, low carbon crude does not command a premium, but
this could change as carbon taxes increase and the pressure to de-carbonise mounts. Vitol recently launched a similar initiative
- a green LNG product where cargos will be issued a certificate, verifying that emissions have been offset.
Total declares force majeure on Mozambique LNG project
Tom Ellacott, 26 April 2021
The facts: Total has confirmed the withdrawal of all personnel working on the Mozambique LNG project. As a result, the
company has declared force majeure.
The development follows an attack in March by Islamist militia on Palma, six kilometres from Mozambique LNG project, which
forced Total to suspend construction.
The partners in the project are Total (26.5%, operator), Mitsui & Co (20.0%), ENH (15.0%), Beas Rovuma Energy Mozambique
(10.0%), Bharat Petroleum (10%), ONGC (10.0%) and PTTEP (8.5%).
Our take: Mozambique LNG is one of Total’s flagship growth projects. We had already assumed that production would start-up
in 2025 compared to Total’s 2024 guidance after the site was shut down to only essential work. This translates into a production
plateau of 320 kboe/d from 2027 (85 kboe/d net to Total).
The decision to declare force majeure will not have been taken lightly. There is a risk that personnel and contractors don’t return
to the site this year. Whilst the project is 21% complete, we think production is now likely to slip into 2026.
Most of the work to date has been engineering-related and done off-site. The development had been entering the construction
phase: we assume US$13 billion of gross investment between 2021 and 2025 in our base case. Any delays and associated cost
increases risk eroding our base-case project IRR of 10%. The Rovuma Area 4 partnership will also be monitoring the security
situation closely and what it means for the timing of FID.
Majors’ Q1 results preview
Tom Ellacott and Luke Parker, 21 April 2021
The facts: the Majors report their Q1 results next week. With big strategy updates behind them, the focus of this reporting
season will shift to financial performance, particularly after prices surprised on the upside in Q1.
Most of the Majors are prioritising debt repayment, with commitments to increase shareholder distributions once deleveraging
targets are achieved. The Q1 results will offer a feel for how ‘reset’ businesses are performing, and a barometer of what to
expect in the year ahead.
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Our take: free cash flow will have surged during Q1. We calculate the Majors need an average US$35/bbl to achieve cash flow
neutrality in 2021, far lower than the actual price year-to-date. North American refining profitability should be back to pre-Covid
levels, though potentially punctured by the ‘Big Freeze’. Companies with European-weighted downstream portfolios could lack
lustre.
BP has already signalled that it achieved its US$35 billion net debt target during Q1, up to a year ahead of guidance. But we
expect all the Majors will deliver material deleveraging, supported by portfolio rationalisation in both upstream and refining.
The spotlight will be on capital allocation plans. Some players may choose to nudge up their dividend (Equinor, Chevron). Q1
prices were at a level that could trigger Eni’s buyback programme. BP will also shed light on its buyback strategy. Yet it may be
too early for the majority to throw caution to the wind and start repurchasing shares. The Majors will also stand firm on capital
discipline. We don’t expect budgets to increase quite yet.
CCUS and hydrogen will be hot topics. We’ll be looking for more colour on planned industrial decarbonisation hubs following an
active quarter of business development. More proof points that wind and solar investments are achieving double-digit returns
would also help reinforce the value proposition in new energy strategic pivots.
Summary of quarterly prices and refining margins
Average prices
2020
2019
Q1 2021
Q1 2020
Q4 2020
Q-o-Q
Brent FOB SVT (US$/bbl)
41.9
64.4
60.9
50.7
44.2
38%
WTI Houston FOB (US$/bbl)
40.8
61.9
59.2
48.3
43.6
36%
Henry Hub (US$/mmbtu)
2.00
2.52
3.49
1.87
2.49
40%
1.8
3.5
2.3
2.7
1.7
36%
Global composite refining margin (US$/bbl)
Source: Refining margin - Wood Mackenzie,
Prices - t
US Independents' Q1 results preview
Dave Clark, Alex Beeker and Robert Polk, 23 April 2021
The facts: US Independents' Q1 earnings reporting begins next week. Most of the Appalachian gas operators and Hess kick
things off, followed by at least 19 US E&Ps the subsequent week. The Q1 results will have a lot of moving parts, with the rise in
oil prices and the winter storm in February.
Our take: Here are the five key things we will be watching for:
How high did natural gas realizations go? Gas-focused operators like Comstock and EQT discussed captured upside in the
immediate aftermath of Winter Storm Uri. Marathon Oil released preliminary results and disclosed pre-hedge gas realizations
of US$6.30/mcf. Event driven realization uplift won’t roll forward, but upside benefit in Q1 for gas-producers will help jump-start
compliance with full-year goals. On the flip-side, oil production was temporarily undermined, and may partly offset the rise in
price.
For much of the group, deleveraging was the priority coming into 2021. With prices throughout the quarter exceeding budgeted
levels, we expect excess cash flow to have facilitated meaningful debt pay down. With greater-than-anticipated cash flow, will
operators remain committed to the balance sheet and accelerate debt reduction? Or will incremental proceeds flow
through to dividend or buybacks?
Hedging proved to be a life saver for many US Independents in 2020 but it’s expected to negatively impact earnings in Q1. Our
hedging tracker published last month shows many companies are hedged at prices below US$50/bbl WTI. Prices rallied from
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US$48/bbl at year-end to more than US$60/bbl during Q1, which will push the fair value of some hedge books negative.
Volumes hedged by operator vary from 0% to more than 70%. The companies with less volumes hedged were in a better
position, everything else held equal. We will be looking to see how many producers added hedges at US$60+/bbl in the
quarter.
Despite the rise in oil, there were few changes to initial 2021 budgets when companies reported Q4 2020 earnings in late
February/early March. Will that capital discipline persist as WTI remains at US$60+/bbl? Most of the group is well within the
investor imperative of 70-80% reinvestment rate, with perhaps some room to increase budgets and stay within that constraint.
Our hunch is that budgets will be maintained until at least July (Q2), but temptation to increase 2021 spending will build.
There will be a lot for E&P leadership to talk about on the regulatory impact front. The focus this quarter will likely be on the
sector implications of the Biden administration’s aggressive US GHG emission targets for 2030. While that
announcement was short on policy detail, it clearly ratchets the pressure up on US independent emissions-reduction plans.
EOG steps even further away from the US
Alex Beeker, Rob Clarke, Andrew Harwood, 23 April 2021
The facts: ASX-listed Melbana Energy announced an agreement to sell its 100% interest in an Australian offshore permit (WA488-P) to EOG for an upfront US$7.5 million. A further payment of US$5 million is contingent on extension of the permit by a
year to allow drilling of the Beehive prospect, and the subsequent award of a production permit. An exploration well is expected
in 2022. Melbana will retain two permits adjacent to the prospect.
In the event of a commercial discovery, EOG will pay Melbana US$10 million for every 25 million boe produced. Santos and
Total previously opted out of farming into the licence having acquired seismic on behalf of Melbana.
Our take: EOG’s business development activities abroad are picking up pace. Recall the company’s two deals in Oman last
year and its large gas discovery offshore Trinidad and Tobago. But this move is quite different and Australia was not high on the
list of regions we expected EOG to enter.
The Omani moves are for onshore unconventional plays, square in EOG’s wheelhouse. They also align with EOG’s ongoing US
new ventures in the San Juan Basin and South Texas (Dorado). Trinidad and Tobago is a region the company has operated in
for over a decade and progress there fits with the company’s traditional strategy of generating its own exploration prospects. But
the Beehive project is almost like a farm-in, reliant on another company’s G&G work.
Melbana has previously pegged the prospect as oil, targeting a deeper carbonate play, "analogous to the giant Tengiz field". An
oil discovery would certainly be easier to develop than gas, with the Northern Territory gas markets virtually saturated and
nearby LNG infrastructure running at full capacity.
EOG’s US peers must be paying close attention to these moves, even if they’re just a small part of the company’s US$140-180
million exploration budget. The entry price tag for Beehive is about the same as a single Permian well.
ExxonMobil unveils giant Houston CCUS hub concept
Tom Ellacott and Zoe Sutherland, 20 April 2021
The facts: ExxonMobil has announced a plan to develop a giant CCUS hub for the Houston Ship Channel. The Supermajor's
goal is to create a CCUS Innovation Zone to dramatically accelerate CCUS deployment.
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The proposed concept could potentially capture and store 50 Mtpa of CO2 by 2030, rising to 100 Mtpa by 2040. This would be
sufficient to capture the emissions from all the manufacturing, refining, petrochemical and power generation facilities located
along the Houston Ship Channel.
The pitch comes ahead of the US climate summit that kicks off on Thursday.
Our take: the proposed scheme indicates ExxonMobil’s ambitions in CCUS. The Houston concept dwarfs the current global
operating CCUS capacity of 41 Mtpa (ExxonMobil has a leading 20% market share). The hub would account for 4% of our
forecast of the global CCUS capacity needed in 2040 in our AET-2 scenario.
Combined estimated investment of over US$100 billion is equivalent to more than five times ExxonMobil's 2021 capital budget.
The project would be a collaborative effort, requiring government and private-sector funding.
ExxonMobil’s ambitions extend well beyond this scale-leading project. The company will look to replicate the concept in other
areas of the US with large industrial concentrations located near potential CO2 storage sites, such as the Midwest or along the
US Gulf Coast. ExxonMobil’s Low Carbon Solutions business unit has a global pipeline of over twenty potential CCUS projects.
A market price for carbon and supportive government policies will be critical for these concepts to become a commercial reality.
Working with governments to develop the commercial and regulatory framework to support the scaling up of CCUS will be an
important focus for ExxonMobil. Success would allow the Supermajor to build a material new profit centre in a decarbonisation
theme in which it already has a competitive advantage.
Shell publishes Energy Transition Strategy
Luke Parker, 15 April 2021
The facts: Shell has published its inaugural Energy Transition Strategy, summarising its climate targets, decarbonisation
strategy, capital allocation and approach to climate-relate policy and advocacy. The strategy will be put to shareholders for an
advisory vote at the 2022 AGM. The strategy will be updated, and voted upon by shareholders, every three years.
Our take: There’s nothing new in this publication (Shell detailed its strategy and targets earlier this year) but it provides a clear,
comprehensive and digestible summary. Perhaps more importantly, it is the basis on which shareholders get an advisory vote –
a first for the industry. That move will have been motivated, in part, by a desire to ward-off potential activist investor motions. As
has been the case for a while, Shell remains on the front foot when it comes to transition strategy. Other companies are likely to
follow its lead.
On that theme, readers will be interested in our latest analysis of the NOCs’ strategies for transition – The role of NOCs on the
road to net zero. They may not be at the leading edge, but national oil companies face the same fundamental questions around
long-term resilience as the IOCs.
Shell and CNOOC start new petrochemicals units
Luke Parker, 14 April 2021
The facts: CNOOC and Shell Petrochemicals Company Limited (CSPC – the 50:50 JV between Shell and CNOOC established
in 2000), has started up new units at its petrochemicals complex in Huizhou, Guangdong Province, China. One unit produces up
to 630,000 tonnes per year of styrene monomer and 300,000 tonnes per year of propylene oxide. A further three units process
propylene oxide into up to 600,000 tonnes per year of polyols.
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Start-up marks the completion of phase two expansion of the CSPC complex, which now supplies up to 6 million tonnes (gross)
per year of product, including polyols, ethylene glycol, polyethylene and polypropylene. A third phase of expansion is in the
planning.
Our take: Chemicals is an important strategic growth area for Shell, framed as part of the decarbonisation story – products will
replace more carbon intensive materials. Shell is investing to grow capacity, and China is a key target area. The CSPC complex
is a chemicals-only site – not one of Shell’s six integrated Energy and Chemicals Parks. However, as an advantaged asset –
producing performance chemicals into a high growth market – CSPC is core.
Shell’s other key focus for growth is the US. The company’s flagship project – a 1.6 million tonne capacity greenfield complex in
Pennsylvania – is expected onstream in 2022 at a reported cost of US$6 billion. With that, Shell’s global petrochemical capacity
will rise to 16 million tonnes (net).
Chevron backs Ocergy’s floating wind technology
Alex Beeker, 14 April 2021
The facts: Ocergy Inc announced that it has secured investments from Moreld Ocean Wind and Chevron Technology Ventures
to fund growth and commercialization of its sustainable offshore solutions. Ocergy expects to deploy a 10 MW prototype of its
new, low-cost floating wind concept in the Atlantic by 2025. Ocergy has also developed an environmental monitoring buoy which
collects wind and metocean data.
Chevron has allocated US$300 million to its Future Energy fund this year, which will be the source of the investment.
Our take: This investment marks Chevron’s move into offshore wind. Chevron has been actively investing in advanced
geothermal, renewable fuels, and carbon capture but has been noticeably absent from wind and solar development.
It’s important to note Chevron has a partnership with Algonquin Power & Utilities to supply 500 MW of renewable power to
support its upstream operations. But this is the first example of Chevron partnering with a wind developer to sell electricity into
the grid. Chevron also acknowledged the possibility of producing green hydrogen from the offshore wind project.
This investment is closely aligned with Chevron’s broader energy transition strategy of seeding private companies with
innovative technology. Rather than going all-in on one sector or building a business unit from the ground up, Chevron is casting
a wide net by diversifying through start-ups tackling the energy transition. Undoubtedly some of these investments will fail, but
we think it’s a defensible strategy in a world that needs an all-of-the-above approach to combat climate change.
Despite the investment in Ocergy, Chevron Technology Ventures president, Barbara Burger, admitted the company does not
have a defined aspiration for a large-scale offshore wind business. Even so, floating offshore wind could eventually play an
important role in Chevron’s decarbonization strategy if it can establish competitive advantage.
Aramco strikes US$12.4 billion midstream deal
Norman Valentine, 09 April 2021
The facts: Aramco will receive upfront proceeds of around US$12.4 billion in a deal signed with a consortium led by EIG Global
Energy Partners (EIG).
The consortium will acquire a 49% stake in a newly formed Aramco subsidiary, Aramco Oil Pipelines Company, that will lease
usage rights in Aramco’s stabilised crude oil pipeline networks for a 25-year period. Aramco will retain a 51% majority stake.
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Aramco Oil Pipelines Company will earn a tariff from Aramco for flows through the network, backed by minimum volume
commitments.
Our take: the transaction is one of the largest energy infrastructure deals globally and will allow Aramco to accelerate
deleveraging.
We highlighted the impact of low prices and the US$69 billion SABIC acquisition on Aramco’s balance sheet in 2020 in our
Saudi Aramco corporate report. Aramco’s gearing had risen to 25% by the end of the year, up from -5% at the end of 2019.
We calculate Aramco’s gearing will fall to 22% assuming US$12.4 billion of asset sales proceeds. Sustained prices at
US$65/bbl will result in additional free cash flow generation, supporting deleveraging towards Aramco’s target of 5-15% across
the cycle. But this is not a hard target and Aramco has not ruled out increases in shareholder distributions if circumstances
allow.
Equinor partners with SSE in UK low-carbon power proposals
Norman Valentine, 9 April 2021
The facts: Equinor and SSE have announced plans to develop two low-carbon power stations in the Humber region of the UK.
The proposals include the world’s first hydrogen-fuelled power station.
The first project, Keadby 3, is a 900 MW capacity gas-fired facility fitted with carbon capture and storage (CCS). CO2 would be
transported using shared pipelines for storage in the Southern North Sea. Equinor and SSE envisage Keadby 3 could come
online by 2027.
The Keadby Hydrogen power station would have a peak demand of 1,800 MW of hydrogen, generate 900 MW of electricity and
produce zero emissions at the point of combustion. Equinor and SSE think Keadby Hydrogen could come online before 2030.
Equinor and SSE are also developing options for hydrogen blending at SSE’s under-construction Keadby 2 project.
Our take: these plans add to the string of low-carbon project proposals for the industrial Humber region, using infrastructure to
be developed by Zero Carbon Humber (ZCH) and Northern Endurance Partnership (NEP) (see Corporate Week in Brief 19
March for further details).
The agreement also builds on the growing partnership between Equinor and SSE which already includes the 3.6 GW Dogger
Bank wind farm. The Keadby power projects could see Equinor move down the power value chain to support the commercial
case for its blue hydrogen and CCS businesses. For further Insight into the Majors’ approach to CCS look out for our
forthcoming Insight, part of our Corporate New Energy Series.
ExxonMobil mulls the closure of its Slagen refinery in Norway
Gerrit Venter and Tom Ellacott, 09 April 2021
The facts: ExxonMobil plans to cease crude oil processing at its 122 kb/sd Slagen refinery and convert it into an oil product
import terminal. This follows the company’s Altona refinery closure announcement in February.
Our take: ExxonMobil’s second refinery closure announcement this year has not come as a surprise. In fact, Slagen has been
high on our list of refineries at risk of closure for some time.
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Its persistently negative margins have placed the asset firmly in the bottom quartile of ExxonMobil’s portfolio for many years.
Slagen’s prospects of a recovery to profitability post pandemic were severely dampened by Norway’s plan to phase out the sale
of new fossil fuel cars by 2025. The policy will accelerate the decline of domestic liquid fuel demand and force refiners to export
more. Due to its negative cash margins, we expect Slagen’s closure to give cash back to ExxonMobil’s refining business.
We expect more refinery closure announcements from the Majors and other downstream players in the near term. ExxonMobil
is taking tough, necessary action to trim the tail of weaker assets and strengthen its refining portfolio. But we believe there is
more scope to rationalise – keep an eye on standalone assets with low margins and no chemical integration. We have identified
the Trecate refinery in Italy as vulnerable.
BP hits deleveraging target ahead of plan, trails share buybacks
Luke Parker, 8 April 2021
The facts: BP achieved its US$35 billion net debt (excluding leases) target during Q1 2021 (the figure stood at US$38.9 billion
at end 2020). This is well ahead of February guidance that the target would be met in Q4 2021 or Q1 2022 (under a US$4550/bbl Brent planning price). A higher realised oil price (Brent averaged US$61/bbl in Q1) and timely receipt of disposal
proceeds – the Khazzan farm-down in particular – made the difference.
BP also took the opportunity to remind readers that net debt of US$35 billion (excluding leases) is the threshold at which share
buybacks come into play: BP is committed to returning at least 60% of surplus cash flow as share buybacks.
Our take: hitting its net debt target early is light relief for BP – no surprise that it wanted to share the news ahead of its 27 April
Q1 results call. BP shares jumped 3.5% on the day, outperforming Shell (+1.5%) and ExxonMobil (-0.3%).
Still, the share price remains at levels last seen in the 1990s. And despite a 24% uplift since “bp week” in mid-September,
performance has lagged Shell (+36%) and ExxonMobil (+51%) over the same period. Having halved the dividend last year,
fixing it at a level approximately two thirds below its pre-Macondo high, BP is understandably keen to initiate share buybacks.
Our analysis highlights the strength of BP’s cashflow outlook. We estimate the company’s 2021 corporate cashflow breakeven
at US$13/bbl pre-dividend, or US$25/bbl post-dividend. Under a US$50/bbl Brent assumption, we project 2021 “surplus cash”
(as defined by BP) of US$7 billion, rising to US$13 billion at US$70/bbl. The figures for 2022 and 2023 are broadly comparable,
once anticipated disposals are factored in.
In short, BP is well placed to initiate and sustain a material buyback programme at current prices. The announcement is due on
27 April. As ever, BP has set expectations high.
Hess trims Bakken position with non-core disposal
Alex Beeker, 8 April 2021
The facts: Hess announced a sale of Bakken assets in Dunn County (4,500 boe/d and 78,700 net acres) for a total cash
consideration of US$312 million. The company was last active here back in 2015 and was not planning to develop this acreage
before 2026. The acreage is also not connected to Hess Midstream infrastructure. Enerplus expects to realize value through
accelerating development on the land.
Our take: this is Hess’ third asset sale in the last six months. The company sold assets in Denmark for US$150 million in March
2021 and sold its interest in the Shenzi field in Deepwater GoM for US$505 million in October 2020.
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The company did not disclose its intended use of proceeds but debt reduction and Guyana development are most likely. The
2020 downturn weighed heavily on Hess’ balance sheet. Gearing surpassed 50% at year-end 2020, up from 15% at the end of
2017. With debt levels already elevated, asset sales help Hess financially bridge the gap over the next two years until Guyana
turns cash flow positive in 2023.
Higher oil prices have opened the doors to the M&A market with deals transacting above PDP-only value. We estimate 150
remaining wells on the divested acreage, which will extend Enerplus’ runway in the basin to 2030. But prices must remain high
enough for Enerplus to justify development.
Wells in the area have an average breakeven price of US$54/bbl WTI, which is are higher than our long-term planning price of
US$50/bbl Brent. For this reason, we do not currently assume any future development on this acreage. We value the flowing
production on the acreage at US$190 million (NPV10).
Hess operated production on the divested acreage
Source: Wood Mackenzie Lens
Eni maintains outstanding exploration on Angola’s Block 15/06
Greig Aitken, 06 April 2021
The facts: Eni announced a new light oil discovery in Block 15/06, in Angola’s deep offshore, estimated at 250 mmbbls of oil-inplace. The well was drilled on the Cuica exploration project and reserves are likely to be in the region of 80-100 mmbls.
Eni operates the licence ((36.84%) with partners Sonangol P&P (36.84%) and Sonangol Sinopec International (26.32%).
Our take: after the enforced break in 2020, exploration is back in full swing with Cuica adding to a string of five discoveries
since 2018 which together have yielded two billion barrels of oil-in-place. And there is more to come.
However, the real value-add is monetising these finds quickly. Agogo, with reserves of 430 mmbbls, is a phased development
that was brought onstream just nine months after discovery. The first phase alone delivers an IRR of 67% and a payback period
of just under three years.
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Eni will deploy a similar strategy on Cuica, but on a smaller scale and faster. The company is targeting first oil in October 2021.
Up to 10,000 b/d from the side-tracked exploration well will tie back to the nearby Olombendo FPSO with additional wells in
future phases.
The discovery will help Eni achieve its target of discovering 2 billion boe of resources out to 2024. Eni’s strategy is now more
focused on lower-risk infrastructure-led exploration with short lead-times offering quick pay-back and high returns. The Cuica
discovery underscores that exploration will remain a core value growth driver for Eni despite its pivot to new energy.
Pioneer doubles down on the Permian
Anuj Goyal, 5 April 2020
The facts: on 1 April 2021, Pioneer Natural Resources announced the acquisition of DoublePoint Energy for US$6.4 billion. The
consideration consists of 27.2 million shares of Pioneer’s common stock worth approximately US$4.5 billion, US$1 billion in
cash and the assumption of US$0.9 billion of debt and liabilities.
The acquired company has approximately 90 kboed of flowing production and 100,000 net acres in the Midland Basin. Pioneer
will target US$175 million of synergies to realise further value from the acquisition.
Our Take: Pioneer has been vocal about the need for scale in the Permian to remain “investible”. The company’s production
jumps to around 620 kboe/d with this deal, catapulting it to the leading Permian producer ahead of Occidental and Chevron.
Plans to reduce the number of rigs on DoublePoint’s assets and the realisation of synergies will enhance cash flow. Pioneer will
also still have one of the strongest balance sheets in the sector even when the deal closes.
The transaction is the largest since oil prices rose above US$60/bbl earlier this year. Pioneer is one of only a handful of US
companies in a position to make large acquisitions, as most of the sector focuses on de-leveraging. The company’s share price
has nearly doubled since the Parsley acquisition last October, providing more valuable equity currency to target additional bolton deals. Will this deal also trigger more financially-strong players to snap up rivals in a fresh drive to scale-up?
Refer to Pioneer double dips - second big Permian acquisition in six months for more details.
Oxy to construct and operate CO2 capture facility at Rio Grande LNG
Zoe Sutherland, 1 April 2021
The facts: Occidental’s subsidiary Oxy Low Carbon Ventures (OLCV) and NextDecade have signed a term sheet for the offtake
and permanent geologic storage of CO2 captured from NextDecade’s planned Rio Grande LNG project on the Texas coast.
OLCV will construct and operate the CO2 pipeline and storage facility.
The Carbon Capture and Storage (CCS) project will be one of the largest in North America, with a capacity of 5 Mtpa. Project
sanction on a minimum of two trains at Rio Grande LNG is expected in 2021. FID on the CCS project is expected soon after. If
the LNG facility receives sanction, it could start-up in 2028.
Our take: Oxy has taken another important step towards building its CCS business. This project could be the first of several
similar hubs that the company is planning to set up across the US. Last year, Oxy announced its intention to be carbon neutral
from its Scope 1,2 and 3 emissions by 2050. It will achieve this entirely through using CCS to offset its emissions.
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The high costs associated with CCS facilities mean there are currently few in operation – total global capacity is only 41 Mtpa.
The Rio Grande LNG and CCS facility will benefit from being an integrated project. NextDecade claims that building both at the
same time will lower the costs by 60-80% when compared to retrofitting an operating LNG facility. It will also benefit from the
45Q tax credit which allows US$50/ton for CO2 stored in saline formations. This will reduce the cost per MT of CO2 from
US$63-74 to US$13-24.
The CCS project at Rio Grande is expected to reduce CO2 emissions from the facility by more than 90%. NextDecade is also
looking into options to reduce emissions to zero. The growing market for green LNG, combined with a more supportive
regulatory environment under the Biden Administration, could pave the way for more projects of this kind being proposed.
Sinopec Corp sets net zero ambition, looks to hydrogen leadership
Norman Valentine, 1 April 2021
The facts: China’s largest oil refiner used its 2020 results to communicate a new goal on carbon neutrality. Sinopec Corp aims
to achieve peak carbon emissions before 2030 and carbon neutrality before 2050.
Sinopec Corp also plans to become China’s leading hydrogen supplier. The company will develop 1,000 hydrogen fuel stations
over the next five years as part of an energy marketing plan covering oil products, gas, hydrogen, power and non-fuel services.
A one million tonne per year carbon capture demonstration project is also included in Sinopec’s plans.
Our take: Sinopec Corp follows PetroChina in aligning itself with Chinese government plans for a greener future. China’s two
largest NOCs have set out broad carbon reduction aspirations. Political imperatives means action and investment will follow. But
the roadmap towards net zero for both companies is far from clear, lacking detail on both scope and intermediate goals.
Whatever the route towards net zero, Sinopec Corp’s position as Asia’s largest refiner means its path will be unique. It has
highlighted hydrogen as one area where it will pursue leadership. This will build initially on the company’s huge refining and
marketing network.
Sinopec Corp will also continue its push on natural gas development, aiming to increase production by an average of 10% over
the next three years. Upstream capital investment will rebound in 2021 as a result. The company’s budget sees upstream spend
reach RMB 67 billion (US$9.8 billion) in 2021, a 9% increase on its pre-crisis 2020 budget and 18% up compared to realised
spend last year.
Chemicals, including coal and oil to chemicals technologies, are also a key part of Sinopec Corp’s strategic vision. The
company’s chemicals budget will rise to RMB 49 billion (US$7.1 billion) in 2021, up 46% on 2020.
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