OIL AND GAS BUSINESS OPPORTUNITY IN EASTERN SIBERIA
(Updated March 5, 2014)
EXECUTIVE SUMMARY
Joint-Stock Company «Angara Petroleum» (Moscow) (hereinafter «AP») is the 100% Russian
shareholder of 5 Licenses (each valid until 2032) for development and extraction of hydrocarbons
in 1 gas condensate and 4 gas Licenses in the Irkutsk Oblast, Russia.
The current registered (mid-2013) capital of AP is 4.2 billion rubles (~US$140m) (excluding
reserves and the purchase cost of rights to the Licences). An IPO/private sale is planned for 2017
(London/Asia) with at an estimated price of ~$3-5m (/share (1,000 share issue) with a x0.1-0.5
Russian market multiple.
The Irkutsk region had large static proven recoverable reserves (2004 State booked) of gas (287
trillion ft3) and condensate/light oil (15.2 billion bbls) which had not been exploited because of the
lack of export infrastructure. However, due to the completion of the ESPO (Transneft's «East
Siberian – Pacific Ocean») export pipeline (~3.5m tons/year capacity, includes complex uploading
facilities for oil storage, pumping equipment, laboratories and a quality control centre) to
China/Asia markets, and competitor access in 2015 to Gasprom's European pipelines, the Russian
government has recently allocated up to $100b for the development of these assets through JSC
Vnesheconombank (VEB).
AP's business plan is to grow the company into a mid/large-cap by monetizing its State Booked
(2012) recoverable reserves of ~2.1 billion oil equilivent bbls (63m bbl oil + 12.3b ft3 gas) by sales
of oil and gas, and converting gas into value added products initially as energy and methanol. The
150mWh Energy Plant (AP 100%) and the 2m ton/year Methanol/heavy plastics Plant will be
located in a petrochemical complex to be built in License 4 by AP's (51%) subsidary ZAO
“Priangarskaya Gazchemical Company” (PGC).
AP's Licences (1-5)
(Licence 4 – Location of Petrochemical Complex; purple line, ESPO pipeline)
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AP will also supply gas to a local factory of JSC Sayanhimplast (SAP) to produce plastics. SAP
produces 60% of Russia's plastics and plans to increase market share to 70% by investing in PGC.
SAP will provide the land for the petrochemical complex and investment for a 26% interest. VEB
will provide a $2.5b credit line (at 16% compound) to finance 80% (for 20% PGC) of the
petrochemical projects. The intent is that PGC will cash-out VEB's methanol plant debt in 2017.
Current project funding is summarized below. Note that all funds will be held in the EU, and only
paid into Russia on invoice:
The light oil and associated gas from License 1 (which also holds an oil separation facility) and gas
from License 2 will be sold domestically and exported in 2015. However, rather than sell the oil at a
debased Ural price, AP will investigate refining it into value added products at Rosneft's Angarsk
refinery in Irkutsk. Note that both Licenses 1&2 are adjacent to the ESRO pipeline (purple on map).
AP's oil and gas production costs are low (oil average and *gas mean over the period 2014-2023)
and will sustain AP's cash flow in the event of lower prices long term:
Project IBTIDA are summarized below:
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Angara Petroleum LLC (Excel Tab 3): The company is considered a medium risk – high return
enterprise with a 106% IRR, profit/investment (P/I) of 8, a NPV (12%) of $4,234m, and breakeven
in 2016, contributing a dividend flow of $478 - $5,933m/year (2014-2023), a total of ~$27b:
ILF Beratende Ing. GmbH (Germany) has been contracted as the independent Project Manager and
consultant to implementate the Development Plan. Geological expertise and preliminary
evaluations will be provided, and conducted by leading Russian and Western experts from the SRC
and the EBRD. Negotiations are currently underway with the insurance company JSC Allianz against
possible project risks, with an insured premium of $50m. AP will operate under western standards
of accounting (Ernst & Young, London) and HC asset reserve evaluations (Miller & Lents, Houston).
AP Project Update (2013-14):
 Wells: 4 new appraisal wells have been completed and succesfully tested for oil and gas. 2
wells were completed on Kirensky oil field (License 1), 1 gas well on Antonovsky (License
2) and 1 gas well on Verkhnelensky (License 5). The field reserves are currently being
recalculated.
 Seismic: No seismic was aquired in 2013. Both 2D and 3D will be aquired in 2014 in
accordance with the 2013-14 License obligations and AP's enlarged seismic program.
 Energy Plant (100% AP): A turnkey contract is available with «Teknonet AG» (Switzerland)
to provide a 150mWh open cycle gas turbine station for a capex of $70m. The build time is 6
months and we plan full power output of ~0.4GWh/year by January 2015. AP will provide
an infrastructure capex loan of $35m (+$10m contingency) at 6% simple interest for 5
years. A new AP daughter company will be formed.
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



Methanol/Plastics Plant (51% AP): The technology has been aquired by AP in terms of
rights, license and capital rights.
Relationship with JSC Sayanhimplast (SAP): In progress concerning their equity and
investment in PGC. SAP operates a plastics plant ~20km SE of License 4, and it has been
agreed that AP will supply their gas feedstock, with SAP providing the cost of the pipeline.
Additional funding: AP will continue to find funding for AP and PGC projects.
AP Profit: Profit will be made from the projects, which together with investor financing, will
be used to fund field development, energy plant purchase, PGC investment and future
projects:
o Sale of oil and gas (domestic/export, project gas feedstocks), NGL and Helium.
o Dividends from AP Energy.
o Dividends from PGC.
AP Budget (2014-2016):
The budget can be found on Tab 1 of the attached Excel speadsheet, and at the bottom of this report.
RESERVES, G&G, WORK PROGRAM
Hydrocarbon Reserves:
Based on available geologic, well and geophysical analysis, AP's 5 Licences contain the following
hydrocarbon reserves booked in 2012 on the State Reserves Balance Sheet. Kirensky's ~300m oeb
recoverable reserves (see Tab 3a, and below) under the Russian system are the development
planning reserves based on the number of wells, well test results using minimum reservoir volume
parameters (porosity, saturation, etc) and recovery efficency.
These reserves are progessively updated by additional drilling during the field appraisal phase. If
judged economic, the field then moves into the development and production phase. Note that AP's
5 fields have a combined 2.127b oeb recoverable reserves under this classification:
Licence
Ref No
Licence
Number
1
2
3
14515 HP
02349 HP
02348 HP
4
02372 HP
5
Field
Kirensky
Antonovsky
SredneOkinsky
Zaslavsky
Verkhnelensky
21047 HP
Total
Million bbl oil equivalent
Type
In place
Oil
Million
bbls
210
Gas
Gas
Gas
Gas
Recoverable
Billion
ft3
1,767
9,895
1,307
Million
Bbls
63
1,201
Gas
210
2,790
1,307
15,477
Billion
ft3
1,414
7,916
1,046
961
63
2,127
1,046
12,383
Classified Reserves:
The Russian classification of C1,C2,C3 is statistically equivilent to the western probabilistic P90,
P50, P10 reserves classification (see Kirensky below):
1. Kirensky (IP oil):
a. C1 = 418, 000 tons = 3.09mbbls
b. C2 = 6.319m tons = 46.8mbbls
c. C3 = 13.062m tons = 96.66mbbls
d. C1 = 3.1mbbs IP = P90; C1+C2 = 40mbbls IP = P50; C1+C2+C3 = 137mbbls IP = P10.
The mean ~P40 reserves = ~60mbbls IP.
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2. Antonovsky (IP gas):
a. C1 = 42bm3 = 1,554bft3
b. C2 = 93bm3 = 3,290bft3
c. C3 = 196bm3 = 6,930bft3
3. Sredni-Orinsky (IP gas):
a. C1 = 2bm3 = 70bft3
b. C2 = 8bm3 = 282.7bft3
c. C3 = 196bm3 = 6,926bft3
4. Zaslavsky (IP gas):
a. C1 = 16bm3 = 564bft3
b. C2 = 28bm3 = 989bft3
c. C3 = 33bm3 = 1,166bft3
5. Verkhnelensky (IP gas):
a. C1 = 27bm3 = 954bft3
b. C2 = 61bm3 = 2,155bft3
c. C3 = 134bm3 = 4,735bft3
The following abbreviations and conversions are used in context: in place = oip or gip (oil/gas) =
«resources» (Russian); k = thousand; m = million; b = billion; t = trillion; bbl = barrels of oil = m3
oil*7.4; ft3 gas = cubic feet gas = m3 gas*35.34; recoverable = at surface = recoverable oil = 30% oip,
recoverable gas = 80% gip; gor = gas/oil ratio; mboe = mbbl oil equilivent = bft3 gas/6; mt = million
metric tons; $ = US$, and expressed as $m in this report; Rb = rubles.
License work program:
The Licencing Agreements require the following work programs in 2013-2014:
Licence
Number
Reference
1
2
3
4
5
Total
2013
Exploration
Wells
2
1
1
2
0
6
2D Seismic
(km)
150
200
100
300
0
750
2014
Exploration
Wells
1
1
1
1
4
2D Seismic
(km)
1850/450**
100
200
0
2150/750*
* Drilling locations have been selected. With success, 4 month exploration wells will be
converted to 6 monthly production wells.
** Reduced Licence area, and the net line km of seismic required.
AP's Planned G&G Program:
Licence
No
2013
Exploration 2D Seismic
Wells
Reference
(km)
1
2
1,000
2
1
200
3
1
300
4
2
300
5
0
0
Total
6
1,800
3D Seismic
2014
Exploration
(km2)
200
150
0
0
300
650
Wells
1
1
1
1
1
6
5
2D
Seismic
(km)
850
100
950
3D
Seismic
(km2)
0
200
160
230
590
All the major works (design, seismic, geophysical interpretation, drilling, etc) are contracted out.
Works will be carried out in 2013-2014 in accordance with the Licencing Agreements. Any works
not fullfilled in 2013 will be carried out in 2014.
AP will endevor to employ the latest drilling and seismic technology (as horizontal production wells
and 3D seismic, processing and interpretation) to increase production, reduce well costs, and to
fully evaluate reserves and monitor field production. As such, additional 2D and 3D seismic surveys
will be aquired on all the Licences.
Geology:
1. Structure and Trap Syle: From ~40-35 million years ago, India began to collide from the
south with the Lena-Siberian craton, closing the ancient Tethysis seaway, to eventually
forming the Mongolian plateau and Pymara Mountain chain. In the Urkutsk region, strong
wrench tectonics structured a Paleozoic basement block faulted inerior sag basin into
structures developed along the crests of a series of enechelon NE-SW trending wrench
anticlines, dipping depositionally basinward from to the SW. The developed hydrocarbon
traps in general are combination structural-stratigraphic-erosional pinchout.
2. Reservoir: Reservoirs are at a depth of ~2,100-3,600m deepening from the NE to the SW,
from License 1 to License 5, and consists of 2-4 intervals: a basal continental-lacustrine
sequence overlying granitic Precambrian basement, overlain by marine sandstone and
argillacous limestones. The basal reservoir clastics consitist of a granite wash, alluvial –
fluvial sandstones, capped with sealing (and hydrocarbon sourcing) lacustrine shales. The
reservoir/seal is analogous to that in the Bo Hai giant oil field offshore Vietnam.
3. Field Characteristics (2013):
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1. In Soviet times (~1945-1980) many wells were drilled in the region defining the observed
fields. Sixteen were drilled on the AP's Licences of which 10 were productive, but owing to
the technology at the time are not useable for current production. Four productive wells
(shutin) were drilled 1997-1998, 2 wells on Kirensky (Licence 1) and 2 on Zaslavasky
(Licence 4). These wells are potential producers requiring workovers, and are included in
the field Development Plan.
2. The fields are generally moderately to highly overpressured and are likely not to require
pressure maintenance during production.
DEVELOPMENT PLAN
The work is divided into 3 phases: Phase 1 (2013-2014), Phase 2 (2015-2017) and Phase 3 (20182023). In Phase 1, AP expects to fully comply with all the Licence Agreements requirements on its 5
Licences, and deliver reserves to the SRC (State Reserves Commission) balance sheet.
In parallel with the execution of the Licence Agreements, AP will provide oil and gas to the
commercial projects and for export. Implementation of AP's conceptual Development Plan through
2023, will create a significant number of new jobs in the region.
Financial Caveates:
1. This is a conservative evaluation of the AP's asset potential. It is not a cash flow model
which is planned for 2014.
2. The time frame could be delayed due to operational considerations.
3. Costs are assumed paid and accruded in the same year. However, oil & gas sales are
adjusted for delayed payments by carrying forward 50% as revenues
4. Exploration/production wells are assumed to be 6 month wells, such that 2 wells spudded
and drilled in a year will provide a conservative net 0.5/year productive well.
5. O&G sales and other prices used in this report are reasonably conconservative:
Currently (February 2014) the Irkutsk oil price is $98/bbl, gas $150/1,000m3, and
methanol $340/ton.
BUSINESS PLAN
1. Kirensky gas/condensate (g/c) field (License 1) (Tab 3a): Revenues from the sale of oil and
associated gas will be used to support AP's cash flow and investment in gas production for
petrochemicals and other projects. Oil and gas will be sold domestically in 2014 and then
exported from 2015.
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2. Antonovsky Field (License 2): Gas from this large (~8b ft3 recoverable) field will be sold
domestically in 2014, and exported from 2015. Peak production from 18 wells in 2020 can
be increased by a more aggressive well program
3. Three gas fields (Licenses 3-5) (Tab 3b) will supply the Petrochemical Complex located in
Licence 4. Surplus gas will be sold domestically:
4. AP plans to drill 26 field appraisal wells by 2016 and have 100 wells in production by 2019.
5. Based on this scheme, AP's budget and financial metrics are shown below:
Oil Sales (Kirensky Field, Licence 1) (Tab 3a):
AP will focus on producing early oil in 2014 from current wells, and then selling it for export
through the 'ESPO' pipeline in 2015. There is a tentative agreement with «GUNVOR Spa»
(Switzerland) to sell crude oil to its subsidiary «Strukturevsey» at Dubai/Oman - $3.8/bbl terminal
port Kozmino terms. Subject to a stable 3-6 month crude delivery, there is the possibilty of
additional funds (up to $150m) from GUNVOR. AP would use this for capital projects as opporunites
occur.
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Peak oil production of ~16,000 bopd is expected in 2017-2021 with the field near depletion by
2023 with 30% remaining field reserves. Accordingly, AP recommends purchase another field in
the Kirensky region in 2014 such that it can be brought on stream by 2015/16. Purchase of a new
field ($40m capex) is currently being negotiated with the Ministry of Natural Resources of Russia
and the Irkutsk Oblast Administration.
Gas Utilization Projects (Licenses 3-5)
License 4 has been selected for the location of a Gas Processing Facility, as it has a widely developed
infrastructure, an extensive transportation network, as well as skilled human resource. AP expects
to begin gas production in 2014 from fields 3-5 to supply up to 10.6 bft3/year to SAP. The other gas
fields will be brought progessively onstream in 2014/15 to supply the PGC and Energy Plant.
Surplus gas will be sold domestically:
AP 100% NGL & Helium Sales (Tab 3b): Verkhnelensky (License 5) gas is rich in NGL (52 bbls/mft3
gas) and Helium (5%) (as well as brines rich in Na, K, and Li etc – assets not considered in this
report). The field will produce 0.13 mbbls/year NGL in 2014 increasing to 2.4m bbls in 2019 and
there-after, providing up to $60m/year to AP's bottom line. The NGL will be sold domestically.
Similarly, the field will produce 0.13 to 2.4b ft3/year of Helium in the same time frame, providing
up to $145m/year to AP's bottom line. The Helium will be compressed and sold domestically.
AP 100% gas sales (Tab 3b): After meeting feedstock demand from projects, surplus produced gas
from the 3 gas fields will be sold domestically with sales of 1b ft3 in 2014 rising to 33 bft3 in 2019
and there-after, will provide up to $116m/year to AP's bottom line.
AP 100% SAP Gas Sales (Tab 3c): A preliminary agreement has been signed to provide up to 300m
m3/year (10.6b ft3/year) of gas from 2014/15 to process into plastics. SAP is willing to finance the
construction of the pipeline from the point of delivery to the enterprise. The project will yield up to
AP ~$38m/year cash in 2015-2023.
AP 100% Energy Plant (Tab 4)
(new company to be formed/registered)
AP has a contract to purchase a 2nd hand 150mW gas power plant for $70m from «Teknonet AG»
inclusive of transportation and rebuild in 6 months in the petrochemical complex. AP will provide
$45m as a loan for the infrastructure ($35m) + a $10m contingency and will be the sole supplier of
gas (~3.4b ft3/year) at commercial rates. The energy plant metrics are summarized below:
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AP energy sales to the projects, and any surplus sold locally, will provide a net profit of $134m over
the period. Gas sales will provide $467m over the period with $52m in 2015 and $52m/year thereafter. Similarly, AP dividends will provide $544m cash over the period, with $34m in 2015 rising to
$147m/year in 2023.
PGC (petrochemical complex) (Tab 5)
AP's subsidary company PGC will have an intital capitilization of $795m 2014-2016 to produce 2mt
methanol at full production (Tab 5a) from a $540m build cost plant, as feedstock for heavy plastics
production. Other products as fertilizer, ethanol etc, will be entertained at a later date.
PGC's financials and metrics are summarized as follows:
Methanol production is capex and feedstock intensive business. The project has a capex+opex =
$2,728m, booked revenues of $5,543m and an EBTIDA of $2,815m, and breakeven in 2017.
AP should add a total of $2,509m in cash dividends to its bottom line over the 10 year period, with
$8m in 2014 rising to $546m in 2023. Plus, a total of $2,099m over the period from the sale of gas
($37m-$502/year from 2014 to 2023).
Methanol/Plastics Plant (Tab 5a): Methanol/plastics production is planned to start in 2014 with
~0.2mt CH4 from 1 unit, producing up to 2mt methanol/year in 2017 from a total of 4 units, which
can be increased by adding additional units
The build time for 1 unit is 4 months. The first unit will be build and producing in 2014, 2 in 2015
and 1 in 2016 with full production of 2m tons in 2017. German companies «Ferrostaal GmbH» will
provide the plant and «Helm AG» the build and management. AP will hold a 51% share in the
project. The chosen technology allows modular build capacity. AP will be the supplier of gas to the
Plant.
Methanol will be used onsite to produce initially heavy plastics. 2m tons CH4 will produce 2.34m
tons plastics at full production at a sales price of $351/ton based on a methanol price of $300/ton.
0.26m tons plastics will be produced in 2014 rising to 2.34m tons in 2017 and there-after.
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AP Gas Sales (Tab 3b): Gas sales will return a total $9,730m cash over the period, with sales of
$150m in 2014 rising to a peak $1,250m/year in 2019 then declining to ~$1,000 in 2023. Domestic
sales will return $856m over the period and export sales of $4,660m.
Gas Export (Gasprom) (Tab 3b: Gasprom's pipeline monoply ends in 2014 providing export access
in 2015. After the construction of local gas infrastructure, a tie-in pipeline, and supplies of gas to the
above projects, the residual (~1,320 bft3) over the period will be sold to Gazprom. Gas sales will
contribute a total of $4,660m cash, with $288m in 2015 rising to a peak of $629m reducing to
$376m in 2023 due to declining Kirensky production.
Estimated AP IPO/Sale Price (2017) (Tab 3)
The intent is to cash-out by bringing AP to the Asian/London market or private sale as soon as
conditions permit, possibly in 2017. An attempt is made to give some idea of the AP's market value
by using, for example, BASF AG which has a market cap of x2.2 valuing the company at ~$22b.
Assuming an AP capitilization of ~$4b and as such 1/5th the size of BASF in 2017 then AP's x
market =~x0.4 x 50% country risk = ~x0.2 = $3.91m/share/1,000 shares. Hence the price range
could be in the order of $4-5m/share. An abitory $4.18/share at a x0.3 is used in this report. Note
that under this scenario, the recoverable assset of ~2b oeb is valued at $800m or ~$0.40/oeb.
AP Structure, Founders/Investors:
1. The registered Founders capitilization is 4.2b rubles or ~$140m at 30Rb/$.
2. New investor: will provide €1.05b as loan (@8%)/equity in 2014 converted to 25% equity
share end 2014 subject to business performance. Funds will be used to increase the
capitilization of ZAO Angara Petroleum by acquisition of additional hydrocarbon and other
assets in the region.
3. All funds will be held outside Russia and paid into Russia on invoice. Accounting and
reserve calculations will be carried out by independent western companies.
Attachment:
A 10 year (2013-2023) printable (by each Tab) Excel financial spreadsheet with Tabs:
1
2
AP Budget (2014-2016)
Stratigraphic column
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3
3a
3b
3c
4
5
5a
AP Company
AP oil fields
AP gas fields
AP SAP gas sales
AP Energy plant
PGC Company
PGC CH4/plastics plant
CONTACT
Dr. Vladimir Sokolov
+7 926 887 9616 or +49 176 95401286
dr.v.a.sokolov@gmail.com or vs1307@mail.ru
Dr Godfrey Butler
+44 77 634 58 32 41
gpbconsulting@gmail.com
APPOVED BY «ERNST & YOUNG»: __________________________________________ Sergey Kachalov
09-03-2014, Moscow
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