The Changing Landscape
of the U.S. Energy Market
U.S. Shale Gas Developments: Investment opportunities
from the wellhead to the burner tip – Summer 2011
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U.S. Shale Gas Developments: Investement opportunities from the wellhead to the burner tip
U.S. Shale Gas Developments:
Investment opportunities
from the wellhead to
the burner tip
Mitchell Silk, Paul Mohler, Gary Lazarus
and Rebecca Perkins – U.S. Projects Group
1. Introduction and Summary
With recent advents in the production of shale gas reservoirs, technically recoverable natural gas
reserves in the U.S. are now estimated to be 827 trillion cubic feet (Tcf ) – roughly equivalent on a Btu
basis to Iran’s oil reserves – and sufficient to meet domestic energy needs for many decades.1 U.S. shale
gas has several attributes that make it a particularly attractive energy investment – namely, it is clean,
contributes to domestic energy security and economic development and benefits from an existing
transport infrastructure.
Gas is the cleanest burning of the fossil fuels, emitting 60 percent less carbon dioxide than coal to
produce a similar amount of energy.2 With the development of shale gas reserves, natural gas is now
produced domestically in abundance, and thus contributes to U.S. energy security. The risk of drilling
a non-productive shale gas well is relatively low. Importantly, there is also an established infrastructure
that can be used, with planned additions and modifications, to move the gas to markets within the
U.S. and very interesting possibilities for exports. Potential investment opportunities range from
upstream leasehold acquisitions and drilling, to mid-stream production, gathering and processing, to
development of new or expanded pipeline infrastructure, and to downstream uses, including LNG
exports, feedstock uses by chemical and industrial users, and natural gas-fired electric generation.
1 Department of Energy , Office of Fossil Energ,. “Modern Shale Gas Development in the United States: A Primer”, April 2009. p. ES-1.
2 Navigant, “Market Notes”, July 2010. p. 3.
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This note addresses the range of opportunities for shale gas-related investments in the U.S. and
Canada. The Shale Gas Overview provides a concise description of the geology, technology, and
economics of shale gas development. The Investment Opportunities section identifies some of the
recently-completed or pending deals, and highlights other potential investment opportunities.
2. Shale Gas: An Overview of the Geology, Technology and Economics
The production of “shale gas” reservoirs is the most noteworthy energy development in the United
States in the past decade. Initially the development occurred relatively quietly, heralded largely by
natural gas industry professionals and out of the eye of the greater public. In the past year, however,
the development of this resource has been recognized as a key part of the U.S. energy future. Estimates
suggest that recoverable shale gas reserves in the U.S. alone could provide over 100 years of gas supply.
The total recoverable reserves in just four of the leading shale gas plays, the Haynesville, Fayetteville,
Marcellus, and Woodford, are over 550 trillion cubic feet, enough to supply close to 25 years of
U.S. gas consumption.3
2.1 The Geology of Shale Gas
Traditionally, shale gas was inaccessible due to the rock formations that contain it. Natural gas was
produced from rock formations, often sandstones, with high porosity, providing space for the gas
within the rock, and high permeability, allowing the gas to flow through the rock to a well and then to
the surface. Shale formations, which hold considerable gas, lacked the permeability that would let the
gas flow directly to the well, and thus were largely undeveloped.
3 Production volumes and reserves of gas in the U.S. are typically measured in cubic feet (e.g., Mcf = 1,000 cf, or Bcf = one million Mcf,
or Tcf = one trillion cf). At a typical heating value of about 1000 Btu per cf, 1 Mcf of gas = 1MMbtu. Converted to joules,
1 MMbtu = 1.055 GJ.
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U.S. Shale Gas Developments: Investement opportunities from the wellhead to the burner tip
The combination of two technologies – horizontal drilling and the hydraulic fracturing of low
permeability formations – now permit on a commercially viable basis a single well to access
underground areas comprising significant acreage, thereby allowing the production of gas from layers
of shale that were previously neither accessible nor economic. In addition to natural gas, natural gas
liquids (NGLs), are often produced from shale gas wells.
Table 2.1 details selected parameters of the leading U.S. shale gas plays, including the basin acreage (in
square miles), formation depths (including distance below aquifers) and thickness (both in feet), gas in
place (tcf ) and estimated technically recoverable resources (tcf ).
Table 2.14
Comparison of Data for Selected US Gas Shale Formations (estimated)
Basin
Barnett
Fayetteville
Haynesville
Marcellus
Woodford
Antrim
New Albany
Basin
5,000
9,000
9,000
95,000
11,000
12,000
43,500
Depth
6,500 – 8,500
1,000 – 7,000
10,500 – 13,500
4,000 – 8,500
6,000 – 11,000
600 – 2,200
500 – 2,000
Thickness
100 – 600
20 – 200
200 – 300
50 – 200
120 – 220
70 – 120
50 – 100
Gas in Place
327
52
717
1,500
23
76
160
Reserves
44
41.6
251
262
11.4
20
19.2
2.2 The Geography of Shale Gas Reservoirs
Shale gas plays exist throughout the U.S. and Canada, with many reservoirs located in areas where there
has been substantial historic oil and gas development. As a result, much of the production will occur
close to an already established transportation infrastructure that, with appropriate investment, can be
adapted to this new source of gas supply.
Figure 2.1 shows the major active shale gas plays in the U.S. Given that much of this development is
occurring within or near established gas and oil producing areas, or near market destinations, most
shale gas developments have ready access to the natural gas pipeline grid and thereby to natural gas
end users or distribution systems. To the extent this development occurs in parts of the country that
are closer to markets, the transportation costs may ultimately be lower than they have been for other
energy sources as the existing gas pipeline infrastructure is tailored to this new energy source.
4 DOE , supra note 1.
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Figure 2.1
2.3 T
he Economics of Shale Gas
The initial costs of horizontal drilling and hydrofracing to obtain gas from shale formations are
considerably higher than traditional vertical wells. These costs are offset by a very high success rate
and a front-loaded production curve. NGLs produced in conjunction with shale gas have additional
independent value, further offsetting the costs of production.
During the recent U.S. recession, traditional vertical drilling rig counts declined as they usually do
when gas demand and prices fall. Horizontal rig counts, however, stayed relatively level, thus resulting
in increased gas supply even as prices decreased. Figure 2.2 shows the projected change in gas supply
resulting from the development of shale gas reserves, and, in particular, how shale gas production is
projected to surpass all other forms of gas production by a not insignificant margin. While the full
impact of this fundamental supply shift has yet to unfold, there can no longer be any doubt that it will
substantially change the U.S. energy equation for decades to come.5
5 Navigant, supra note 2, October 2010 at 6.
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U.S. Shale Gas Developments: Investement opportunities from the wellhead to the burner tip
Figure 2.2: Projected U.S. Natural Gas Production6
U.S. dry gas production (trillion cubic feet per year)
30
25
History
Projections
Net Imports
15
11%
14%
20%
10
9%
20
Shale gas
8%
9%
2%
2000
45%
Non-associated onshore 8%
Non-associated offshore 8%
Tight gas 22%
28%
5
0
1990
1%
Alaska
2009
Coalbed methane 7%
1%
Associated with oil 7%
2020
2035
2.4 Regulation of Shale Gas
Most regulation of shale gas drilling, like other regulation of onshore oil and gas production, takes
place at the state level. For states that are traditional oil and gas producers, the parameters of this
regulation are well understood. For states where drilling has historically been less common, the
regulatory requirements are less clear, and will evolve, likely becoming more restrictive (and thus more
costly) as drilling increases.7
While there has been little direct federal oversight of drilling, recent interest in shale gas developments,
and particularly hydraulic fracturing, by both Congress and the EPA has led to speculation that
there could be future federal regulation over hydraulic fracturing or other aspects of the drilling and
production process. 8 For the moment, however, whether there ultimately will be any direct federal
regulation of drilling or hydraulic fracturing and the scope of regulation remain uncertain.9
Wellhead sales of gas in the U.S. are largely unregulated as such commodity markets provide significant
price transparency. As shown in Figure 2.3, since shale gas has started flowing into the U.S. gas market,
the price of natural gas has shown a steady overall decline. While price levels may also be lower due to
6 Source: U.S. Energy Information Administration.
7 “Utica Shale”, Oil & Gas Investor, February 2009; “Total Enters US Gas Shale Through Chesapeake JV”, BMI Americas Oil and Gas
Insights, January 1, 2010.
8 DOE , supra note 1, at ES-5.
9 U.S. Environmental Protection Agency, “Science in Action: Hydraulic Fracturing Research Study”, June 2010. pp. 1-2; Dlouhy, Jennifer,
“Execs Defend Shale Gas”, The Houston Chronicle, January 21, 2010.
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decreased demand over the past several years, in at least the short to medium term, increased levels of
supply from shale gas, as supplemented by traditional supplies and LNG imports, should continue to
moderate natural gas prices and volatility.
Figure 2.3
Daily Natural Gas Futures Contract 1
16
14
12
10
8
6
4
2
0
1994
1996
1998
2000
2002
2004
2006
2008
2010
Source: U.S. Energy Information Administration
2.5 Hydraulic Fracturing
Hydraulic fracturing, or “hydrofracing” is the process of using a fracing fluid, or water mixed with
different sets of proprietary chemicals, in conjunction with horizontal drilling, to create and hold open
fissures, often only millimeters wide, to permit the gas to flow to the drill hole and then to the surface.
In addition to the gas, a portion of the fracing fluid also returns up the well to create “produced water,”
which can contain contaminants from the fracing fluid, or from the formation itself. Produced water is
treated, contained, and in some cases injected into approved disposal wells.10
10 D
OE, supra note 1.
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U.S. Shale Gas Developments: Investement opportunities from the wellhead to the burner tip
3. Investment Opportunities
The advent of commercially viable shale gas exploitation provides a number of investment
opportunities at all levels of the economic supply chain. There is still considerable room for further
development of efficient upstream exploration and extraction methods. Another area that provides
a major pool of opportunity is in the development of and investment in mid-stream gathering,
processing, and pipeline infrastructure. These developments also give rise to interesting opportunities
in terminals and other facilities that will be required in order to seize opportunities in exporting gas
from the U.S. Finally, the new gas supply presents considerable downstream power generation and
industrial application opportunities.
3.1 Leasehold Acquisitions; A Consolidating Market
The most active part of the shale gas value chain over the past year has been in upstream leasehold
and production acquisitions. Opportunities in the area continue to be available, with, for example,
Chesapeake recently announcing it was seeking to reduce debt by selling significant gas reserves.
These sales would be in addition to the already substantial reserve sales that it has made to, among
others, Total SA of France and the China National Offshore Oil Corporation.
As shown in Tables 3.1 and 3.2 located at the back of this report, there has been considerable activity
involving international companies in U.S. and Canadian shale gas resource/reserves acquisitions over
the past two years, activity that will continue in 2011. Many of the transactions have involved foreign
acquirors purchasing or joint venturing for an interest in upstream assets. These transactions have
allowed U.S. and Canadian sellers to raise funds to finance continued development and production of
their assets, or, in some cases, to pay down existing debt.
Foreign participation has afforded major foreign energy companies an opportunity to learn the new
technology, in order to deploy that technology in the shale reserves now being discovered around the
world. Some, such as Royal Dutch Shell, have announced intentions to continue to invest significantly
in the industry. This is an important element of foreign strategic acquisitions in the U.S. since interest
in shale gas is growing internationally as the technology develops. By way of example, China projects
up to a quarter of its energy to come from shale gas by 2030 and will no doubt benefit from the
acquisitions already completed by CNOOC and CNPC. In addition, Polish and German shale
resources, among others, attract interest, as parties look to lessen dependence on pipeline gas from
points east and north. Global activity in the industry recently topped $85 billion as of October 2010
with the announcement of a $42.5 billion deal between Petrobras and the Government of Brazil.
In addition to the activity by international firms, there also has been considerable domestic acquisition
and joint venture activity as firms seek to obtain and develop reserves in new shale gas developments.
Smaller firms have in many cases required new capital, and the deals are an opportunity to monetize
their reserves while gas prices are low, allowing them to save drilling profits for when prices rise. There
are estimates in the market now that even at $4 per MMBtu, the internal rate of return (IRR) on natural
gas is approximately 40%, and that it may rise to close to 100% if gas prices return to their 2008
levels of $13 per MMBtu. Due to these price factors, it is expected that this domestic activity will also
continue in 2011-2012.
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The Canadian market has developed more slowly than the domestic market, but is picking up pace. As
seen from Table 3.2 attached at the back of this report, Canadian deals are following the same general
patterns as those in the U.S. market.
3.2 Mid-stream Investments
(a) Drilling Services and Operations, Production, and Processing
As the techniques associated with horizontal drilling and hydrofracing continue to be improved and
refined, and as new techniques are developed to address the production and post production issues
that have been raised by criticisms of the current process, there will likely be additional opportunities in
bringing the technologies to market and acquisitions and consolidation.
One example of such an advance is FracPure Mobile Water Treatment Systems development of a
process that it asserts can remove all contaminants from produced water and return 80% of flowback
to clean water. The remaining 20% of flowback water is a concentrated salt brine, than can be
further treated by FracPure to become salt products and distilled water. This system was approved by
Pennsylvania regulators for direct treatment of produced water, and to the extent it is successful will
likely create a new market niche that would be an important component of the shale gas drilling and
production process not only domestically, but internationally as well.11
(b) Pipeline Infrastructure
Most of the shale gas development is taking place in areas with existing infrastructure. However,
additional gathering lines and processing facilities, new pipelines, and a rationalized use of existing
infrastructure will be required to move the new supplies to existing or new markets. In addition, gas
storage may become even more important as a means of levelizing production with annual demand
cycles or to provide parking services for electric generation. Opportunities for investments in
gathering and mainline pipeline facilities, including storage, will be needed to accommodate shale gas
development, and has already begun with projects such as TransCanada’s Horn River pipeline.
In a report sponsored by the American Public Power Association, the Aspen Environmental Group
estimated that investment in pipeline capacity expansion alone could require as much as $348 billion
should all coal-fired plants be replaced with gas-fired plants.12 This would be in addition to the costs
associated with replacing coal-fired power generation. A more conservative estimate comes from the
INGAA Foundation, Inc., an affiliate of the Interstate Natural Gas Association of America (INGAA).
It projects a range of investment from $133 to $210 billion in natural gas pipeline infrastructure over
the next 20 years (from $6-10 billion per year), primarily related to the increase in domestic natural gas
production from unconventional shale basins and tight sands.13
11 W
orld Oil News Center, “First Pennsylvania DEP-approved mobile frac water treatment system launched”, November 9, 2010.
12 T
he Aspen Environmental Group, “Implications of Greater Reliance on Natural Gas for Electricity Generation”, July 2010. p. 89.
13 T
he INGAA Foundation, Inc., “Natural Gas Pipeline and Storage Infrastructure Projections Through 2030”, October 20, 2009. p. 1.
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U.S. Shale Gas Developments: Investement opportunities from the wellhead to the burner tip
Figure 3.1 details a number of pending or proposed projects identified by the Federal Energy
Regulatory Commission (FERC), the federal agency responsible for authorizing interstate gas pipelines.
Figure 3.1
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If even a portion of these facilities are built, there will be demand for substantial capital to finance
this infrastructure. While there have been project-financed pipelines built in the U.S. in the past
(for example, the Iroquois Gas Transmission System), most pipelines are planned, financed, and
constructed by existing pipeline companies or partnerships through a combination of equity and
debt, including non-recourse construction financing and bond issuances. Several pipeline companies
have adopted a master-limited partnership form as the result of favourable tax rulings by U.S. Courts.
Because of the location of shale gas production, and the variety of financing forms that can potentially
be used, evaluation of the return on investments in existing or new pipelines or storage requires caseby-case evaluation. With their typically strong cash flows, gas pipeline projects that bring shale gas
supplies to markets with growing demand should in particular provide sponsors with a reliable return
on investment.
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U.S. Shale Gas Developments: Investement opportunities from the wellhead to the burner tip
3.3 Downstream Opportunities
(a) LNG Exports
The dramatic increase in U.S. gas production will encourage proposals to expand or modify existing
LNG import facilities to also provide export capabilities. This will offer a unique set of opportunities
for equity investors and project finance lenders to be involved in these expanded projects, often times
at lower risk than if they were lending to greenfield projects.
The opportunities will primarily fall into one of four categories: (i) developers or infrastructure
investors (including investment funds) could invest in existing or expansion projects; (ii) existing
lenders can upsize their loans in order to finance the expansion; (iii) a new group of lenders could
take part in financing the expansion, alongside the existing lenders to the original project; or (iv) a new
syndicate of lenders can come in to refinance the existing project plus fund the additional costs of
expansion. From the debt finance structuring perspective, option (ii) above likely presents the most
difficult issues from various perspectives, including, intercreditor rights, new construction impact on
the original facility and its cash flow stream, and third party issues to the extent different construction
and offtake parties are involved in the pre- and post-expansion project. Options (i) and (iii) also present
issues of diligence and risk exposure to a single asset, but are more likely in any facility upsizing that
may occur simply because they involve fewer potential complications between various lender groups,
and are likely to be seen as more efficient from the sponsor’s perspective.
The potential for investment in this area is not just hypothetical. Two proposed U.S. export projects,
Sabine Pass Liquefaction LLC in Louisiana and Freeport LNG Development L.P. in Texas, are
currently pending U.S. regulatory approvals, and could be online by 2015. In March 2011, Encana
announced the acquisition of a 30 percent interest in the producer-sponsored Kitimat LNG
liquefaction and export terminal in British Columbia, Canada, a facility that could export as much as
700 MMcf/d to Asian markets when it is completed in 2015.
(b) Electric Generation
When burned, natural gas produces less than half the carbon of coal used to produce the same amount
of electricity. The combination of higher regulatory costs imposed on coal-fired generation, together
with gas’s decreased cost and relatively clean burning attributes, may give it a competitive advantage
over existing or new coal-fired electric generation. Combined combustion electric generation plants
can be built relatively quickly, and located to take advantage of both supply sources and markets. While
unsettled U.S. energy regulatory policies appear to be inhibiting this development at the moment, we
expect that gas-fired generation will be a key investment opportunity going forward, particularly as
electricity demand increases with increased U.S. economic growth.14
14 P
lease see our other note, entitled “Natural Gas-Fired Electric Power Plants: A Key Element for Future U.S. Energy Policy” for a more
detailed discussion of gas-fired electricity generation in the U.S., including potential financing opportunities.
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(c) Feedstock and Industrial Uses
A recent report by a task force sponsored by the Bipartisan Policy Center and the American Clean
Skies Foundation highlighted how a robust supply horizon for natural gas, the development of new
tools for managing price uncertainty, and unprecedented levels of available storage and import capacity,
would allow natural gas markets to function more efficiently and fluidly in the future. The report
concluded that dampening the potential for destructive cycles of price volatility and market instability,
would in turn create a more favorable investment environment for a range of gas uses. Bipartisan
Policy Center and the American Clean Skies Foundation, Report of the Task Force on Ensuring Stable
Natural Gas Markets (March 22, 2011) (“Stable Gas Markets Report”).
In addition to helping fuel the growth of gas-fired electric generation, a moderate and relatively stable
price for natural gas in the future will contribute to the use of natural gas for industrial feedstock
(fertilizer and chemicals) and industrial boiler fuel uses within the U.S. The U.S. is experiencing renewed
interest in development of greenfield and brownfield petrochemical projects, in large part due to the
continued expansion of shale gas plays, the liquids associated with them, and a belief among some
project sponsors that natural gas prices will remain relatively stable for a number of years. There may
be current and future investment opportunities in these areas that would require evaluation on a caseby-case basis.
In addition to the above examples, other midstream infrastructure buildout, primarily processing and
gathering facilities, also continues to pick up in order to keep pace with shale development, despite
potential challenges that exist in the U.S., such as the produced water issue. Overall, various market
participants appear ready to commit resources and financing to not only extraction and production of
shale gas, but also to various other downstream applications in anticipation of the impact shale gas will
have on the domestic market.
4. Risks: Factors to Consider as Part of Investment and
Lending Decisions
Shale gas reservoirs hold the promise of many years of natural gas reserves and the opportunities for
profitable investment. That said, there are risks associated with the development of these reserves. As
with any economic analysis, supply and price will be key drivers of investment. Expectations of lower
prices may make, for example, investment in production less attractive, while at the same time making
investment in end uses, such as fertilizer or electric generation, more attractive. Controversy over the
environmental impacts of drilling and producing shale gas may slow development in some regions or
result in increased levels of regulation or legislation, both of which could increase the costs of drilling,
fracturing, and production.
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U.S. Shale Gas Developments: Investement opportunities from the wellhead to the burner tip
4.1 Price Risk
Perhaps the most basic risk faced by investors in natural gas leases or production interests is that
natural gas prices may remain at depressed levels for a significant period, thus depressing returns and
future investment.15 While it may be expected that gas prices would eventually rise with increased
demand, as shown in Figure 1.2, it appears that long term U.S. gas supplies may remain abundant. This
may result in marginal producers deciding to delay production or to exit the market. For example, the
only currently operational U.S. LNG exporting facility in Kenai, Alaska recently announced that the
facility would be mothballed in 2011 because it could not renegotiate a new contract with its long-time
utility purchaser, Tokyo Electric Power Company in Japan, at a commercially viable price.
Another potential risk factor is the development of LNG supplies worldwide, which could further
constrain U.S. prices if the U.S. becomes a swing market for spot gas sales. This may also limit the
prices that U.S. suppliers can charge for natural gas exports. This will ultimately affect the contracting
strategies of equity investors in shale gas projects and will no doubt attract closer financier scrutiny on
offtake contracting strategies.
4.2 Market Risk
U.S. demand for natural gas during the past decade has been constrained by high and volatile prices
during the early and middle part of the decade, followed by the U.S. recession in the latter part of the
decade. While price volatility remains a concern for businesses dependent on gas, the trend towards
lower prices coupled with what appears to be abundant supply should help increase demand over
the coming years, expected to increase by 50% by 2020. Expanded natural gas-fired generation, in
particular, may help drive this increased demand. Again, this risk will impact on marketing and sales
strategies and will attract purchaser and financier interest in the due diligence phase of any transaction
or financing.
4.3 Regulatory Risks: General
Regulatory risks can arise in various contexts in transactions involving natural gas, from the transaction
itself, to post-transaction regulatory issues that must be confronted when developing new resources.
Many of the latter issues will involve permitting and land use issues at the local and state levels;
however, others can arise as part of the transaction itself at both federal and local levels. Given
the wide range of potential investments and vehicles for those investments, regulatory risks must
be assessed on a case-by-case basis as part of the ex ante or due diligence review of any proposed
investment.
Antitrust issues can arise in any acquisition, merger, or joint venture and must be considered as part
of the assessment of a transaction. Transactions involving mergers or significant acquisitions will most
likely require either Federal Trade Commission and/or Department of Justice clearances, and in some
cases filings with, or approvals by, other agencies such as the Department of Energy (DOE), FERC, or
state public utility commissions.
15 C
ox, Rob, “Shale Gas Success Drives Down Prices”, New York Times, December 21, 2010.
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Where the acquisition of U.S. assets or companies is by a foreign entity, advance review by the
Committee for Foreign Investment in the United States (CFIUS) may also be advisable. CFIUS is
chaired by the Treasury Department and includes members from U.S. agencies such as Homeland
Security, Justice, and Defense, and focuses its review on the implications of the transaction on U.S.
national security interests. While not mandatory, working through the CFIUS review process can avoid
complications that otherwise could arise from an after-the-fact review of a transaction that potentially
impacts U.S. security interests. Large energy deals, particularly those involving strategic resources or
technologies, will almost certainly raise such concerns. Similar concerns have been raised in Ontario
that have led it to impose a moratorium while it evaluates those concerns.
There remains a potential for new or strengthened regulation of natural gas drilling and production.
The Republican control of the House of Representatives, however, makes it less likely that new federal
regulations significantly restricting the drilling industry, with its attendant economic consequences,
would pass Congress.16 Moreover, the Obama administration has indicated numerous times that it
expects shale gas to be part of the U.S.’s energy future. On the state level, Gov. Corbett of Pennsylvania
recently lifted a short-term moratorium on future leasing of state forest land, thus opening the
potential for new development in that state.
4.4 Regulatory and Public Relations Risks: Hydraulic Fracturing
Despite being decades-old technology, hydraulic fracturing is facing increased, and often emotionallycharged criticism.17 These concerns have been highlighted by media reports and a recent movie,
Gasland, alleging industry malfeasance and the cover up of water and environmental contamination as
the result of hydrofracing and shale gas development.
Regulators or legislators in several states and the U.S. Environmental Production Agency (EPA) are
studying how hydrofracing techniques will impact groundwater and whether and how to regulate
the process, including the contents of the chemicals and components used in hydrofracing, often
proprietary mixtures that service companies are reluctant to disclose. 18 The EPA, which had previously
studied the issue and concluded that hydrofracing did not raise safety issues,19 is due out with a new
report later this year.20 The potential for new state regulation of shale gas development was further
highlighted by a moratorium imposed by Governor Patterson of New York, banning hydrofracing in
New York State until July 1, 2011.21
16 D
OE , supra note 1, at ES-4.
17 D
elaware River Basin Commission, “Natural Gas Development Regulations: Proposed Article 7 of Part III”, December 9, 2010.
18 The EPA issued voluntary requests for information on the content of the hydraulic fluid, to which Halliburton was the only company out
of nine not to respond. The EPA then subpoenaed Halliburton for the information, which the company complied with, but it remains to
be seen whether that information will become public. Environmental Protection Agency, “Hydraulic Fracturing: Hydraulic Fracturing
Information Request”, April 28, 2010; Clanton, Brett, “Chevron Joining Shale Spree Pennsylvania Holdings Key Asset in $4.3 billion Deal
to Acquire Atlas”, The Houston Chronicle, November 10, 2010.
19 T
he 2005 Energy Policy Act exempted hydrofracing from regulation under the Safe Drinking Water Act following a 2004 EPA study that
concluded the technique was safe. See http://www.epa.gov/ogwdw000/uic/wells_coalbedmethanestudy.html.
20 E
PA Study, supra note 9, at 2.
21 E
xecutive Order No. 41: Requiring Further Environmental Review, December 13, 2010.
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U.S. Shale Gas Developments: Investement opportunities from the wellhead to the burner tip
Other environmental impacts allegedly have been associated with the hydrofracing process, including
small earthquakes. The town of Guy, Arkansas has experienced 487 earthquakes between September
20, 2010 and January 14, 2011. Though the cause of these quakes is officially unknown, it is believed
by some scientists to be caused by the salt water disposal wells, approved by the state, for injecting
produced water from fracing into the ground at high speeds.22 Recently, Chesapeake shut down two
saltwater disposal wells in the Dallas-Ft. Worth area in response to a series of earthquakes near the
airport.23 The concerns with disposal wells should have little impact on overall shale gas development,
though the inability to use such wells may increase costs as alternative disposal methods are used.
On all regulations the U.S. is being used as a testing ground so once regulations are passed here they
are likely to be emulated elsewhere.
4.5 Environmental Risk: Clear Air and Clean Water Acts
Natural gas offers a number of environmental benefits over other sources of energy, particularly other
fossil fuels. However, regulated air emissions commonly occur during gas exploration and production
activities. Emissions may include NOx, volatile organic compounds, particulate matter, SO2, and
methane. EPA sets standards, monitors the ambient air across the U.S., and has an active enforcement
program to control air emissions from all sources, including the gas industry. Recent reports that diesel
fuel may have been used to frac wells in some areas may invite further investigation by the EPA and
potential assertions of jurisdiction that may not have otherwise existed. In this vein, the U.S. Geological
survey recently announced that it will heighten drilling scrutiny as it affects drinking water in the
Fayetteville Shale. Finally, because hydofracing requires substantial water resources, it competes with
other uses for water in areas where water supplies may be restricted, thus slowing development in some
regions, and potentially leading to additional local or state oversight.24 Many of these concerns can,
however, be addressed through existing or anticipated regulations, such as rules for capping
wells, protecting areas that are more sensitive to drilling, or banning some of the most harmful
fracing ingredients.
In addition to increased environmental regulation there have been civil lawsuits relating to claims of
environmental damage from drilling activities. Some examples include:
– Two environmental groups in New Jersey filed a law suit in the District Court in Trenton to stop
even exploratory drilling of natural gas wells in the Delaware River Basin.
– In October 2010, thirteen Pennsylvania families filed a complaint alleging that a Southwest Energy
Co. well contaminated the surrounding area’s groundwater due to a defective cement casing, and
alleged findings of chemicals in the local wells.
22 A
slup, Dave, “Earthquake ‘swarm’ rattles Arkansas town and its residents”, CNN.com. January 14, 2011.
23 S
haleblog.com, “Chesapeake Energy News”, August 21, 2009.
24 S
now, Nick, “Salazar Announces Oil Shale Lease Round, Addenda Inquiry”, Oil & Gas Journal, October 26, 2009; Cart, Julie, “Water, Oil
Don’t Mix in the Rockies”, Los Angeles Times, December 28, 2008.
© Allen & Overy LLP 2011
16
– A Texas family filed suit in 2007 over health concerns against Atmos Energy Corporation, Energy
Transfer Partners, L.P., Enbridge Inc., and later added Chesapeake Energy and Crosstex Energy
Services, leading to a settlement in October 2010.
4.6 Litigation Risks
In addition to the potential for increased local, state, or federal regulation, there is the potential for
lawsuits relating to leasing, drilling, or post-production activities or payments.25 Examples of lawsuits
include efforts to quiet title to mineral rights by landowners and leaseholders and to obtain higher
signing bonus or royalty payments, and claims of property damage from drilling activities. Some
examples include:
–– A surface landowner brought suit to quiet title to the mineral rights of the land. The court found
in favor of a natural gas production company that had bought the mineral rights, despite the
landowner’s leasing the mineral rights to another party.26
–– Oil and gas well lease holder in Oklahoma brought action against competing lease holder, claiming
he did not lose his mineral rights and his lease was still valid. The first lease remained effective so
long as oil and gas was produced from the well and the lease holder used reasonable efforts to
market the gas.27
There may also be demands, similar to those made recently in Pennsylvania, that developers pay for
improvements or repairs for the use of existing state-owned infrastructure, such as roads damaged by
heavy trucks used during drilling and hydro activity. Currently, drilling companies are required to post
a bond of $12,500 for each mile of paved road and $6,000 for each mile of unpaved road that they will
use. Chesapeake Energy spent over $15 million in road maintenance in Pennsylvania alone in 2010.28
4.7 Contractual Risks: Revenue and Cost Certainty
As with any transaction involving oil and gas extraction, the specific terms and conditions of the lease
or production agreements will require close scrutiny. For example, some leases contain a drill-it-or-loseit provision that requires reserves to be produced within a specified term, often three to five years. This
type of lease agreement may force development to avoid loss of the lease, where a well might otherwise
be delayed for commercial reasons. Gas is often sold by the producer at the wellhead at a net-back
price from an established index to gas gathering companies who then process the gas and deliver it to
competitive gas markets. These include active forward contract and derivatives markets to manage risk.
25 B
MI Americas Oil and Gas Insights, supra note 7.
26 H
ernandez v. El Paso Production Co., 2011 WL 1442991 (Tx. App. 2011).
27 C
oncorde Resources Corp. v. Kepco Energy, Inc., 2011 WL 1570335 (Okla. Civ. App. Div. 2011).
29 Bumsted, Brad and Conte, Andrew, “Natural Gas Drillers’ Damage to Roads Debated”, Pittsburgh Tribune-Review, December 29, 2010. pp. 2.
www.allenovery.com
www.allenovery.com
17
U.S. Shale Gas Developments: Investement opportunities from the wellhead to the burner tip
Gas purchase contracts generally contain provisions specifying term, volume, price, and delivery
location. Prices in natural gas contracts are often indexed to market prices. A substantial part of
the natural gas supply is purchased by distribution companies that can pass prices, with regulatory
approval, to their customers. Sales of natural gas also take place in spot or futures markets, using
standardized industry contracts.
As the use of natural gas grows, long-term purchase contracts may well become more common as
overall price levels and volatility moderate, particularly for new electric generation or feedstock uses.
This sentiment was recently echoed in the Stable Gas Markets Report, which viewed long-term
contracts as an important (if not the only) tool for promoting greater stability in gas markets. These
longer term deals would likely be tied to long-term transportation and storage arrangements on gas
pipelines, thus reducing overall gas supply risk. However, to the extent gas supplies may be needed
to ramp up or ramp down electric generation that is, for example, backing up intermittent generation
sources, new pipeline services also may be required to ensure the availability of supplies on short
notice. These contractual supply and transportation risks would need to be evaluated in the context of
a specific proposal.
The structure of deals may create additional contractual risks that would require consideration in the
context of a particular deal. Joint ventures, in particular, can be complicated to form and may raise
difficult issues during both negotiation and operation. It is important to select a corporate structure that
will achieve both parties' goals, with a fair allocation of risks. A feature of some new JVs, and one that
can be the subject of intense negotiation, is for the incoming investor to simply assume drilling costs
going forward, as opposed to participating in the operation of the venture. Confidentiality and disclosure
provisions are sensitive areas, especially with larger investors participating in more than one JV.
For deals involving the construction or modification of downstream facilities, additional contractual
risks may arise as part of material project contracts such as construction, fuel supply, and offtake
agreements. Negotiations of any such agreements must carefully weigh the expected return on
investment (ROI) of the transaction or project against the potential risks, including regulatory market
and commodity price risks, of the project or transaction.
4.8 Federal Lands Issues
The first round of federal leases of land for shale development, administered during the Bush
administration, were investigated by new Secretary of the Interior Ken Salazar due to terms that
allegedly favored the oil and gas industry. Specifically, concerns were expressed that royalty rates of
about 5 percent on shale gas leases were much lower than the average rates closer to 12-15 percent for
projects in other industries on federal lands.29 With significant reserves under federal lands, particularly
in the Western part of the U.S., the policies under which these reserves may be developed remain
uncertain, and a point of political contention.30 Recent efforts to lease lands at higher royalty payments
have met with only limited success. The extent to which these lands will be developed in the future
remains uncertain.
29 T
ankersley, Jim and Meyer, Josh, “Probe of Bush-era Leases for Oil Shale is Expanded”, Chicago Tribune, October 21, 2009.
30 E
xxon-Mobil Corp. (TX), Natural Soda Inc. (CO), AuraSource Inc. (AZ) bid for the new leases. Kohler, Judith, “Feds’ Offer of New Oil
Shale Leases Nets 3 Takers”, Forbes.com, January 27, 2010. p. 2.
© Allen & Overy LLP 2011
18
5. Conclusion
The ability to explore and produce shale gas in the U.S. on an economic and commercially viable basis
is having a profound impact on the U.S. energy landscape, particularly gas development and potential
gas uses. In addition to the race for reserves, there are numerous other investment opportunities
along the shale gas value chain, including industrial applications for natural gas, and gas-fired electric
generation. As with any investment, these risks require thorough evaluation, particularly where there
is significant potential for, or actual regulatory oversight of, the acquired entity or activity. Risks
notwithstanding, the immense market opportunities that advents in technology are ushering in promise
fertile activity in this area both domestically and abroad. In addition to the shale gas “revolution”
that is well underway in the U.S., shale gas developments are unfolding in a number of countries with
shale gas reservoirs. No doubt, experience gained by early investments in the U.S. will pay significant
dividends as these world-wide supplies are developed.
This note is generally high-level in nature and is intended to provide a broad summary of the issues relevant to shale gas.
To the extent there are specific transactions under consideration, we would need to review and analyze the particular facts
of any such transactions, including laws applicable to such transaction and the structure of the deal under consideration,
in order to advise on such transactions. Nothing contained in this note is intended to be, or should be construed as,
investment advice.
www.allenovery.com
19
U.S. Shale Gas Developments: Investement opportunities from the wellhead to the burner tip
Table 3.1 Selected International Transactions Involving U.S. Shale Gas Resources31
Date of Deal
Parties Involved
Type of Transaction
Shale Formation
April 2011
Marubeni Corp
Marathon Oil Corp.
Acquisition ($270 M)
Niobrara
February 2011
BHP Billiton Ltd
Chesapeake Energy
Acquisition ($4.75B)
Fayetteville
February 2011
Crestwood Midstream
Partners
Frontier Gas Services LLC
Pipeline development
Granite Wash
February 2011
Heckmann
Construction of Disposal
Wells
Fayetteville, Haynes
February 2011
Eagle Ford Gathering, LLC
Anadarko E&P Co. L.P.
Acquisition
Eagle Ford
January 2011
CNOOC Ltd.
Chesapeake Energy Corp.
Acquisition ($1.27B)
Colorado, Wyoming
January 2011
Samson Oil & Gas Ltd.
Halliburton
Acquisition
Niobrara
January 2011
MarkWest Energy Partners
EQT Corporation
Acquisition
Huron/Berea
November 2010
ENN Energy Trading
Cheniere Energy
LNG Processing Agreement
Sabine Pass Processing
Facility
November 2010
Royal Dutch Shell
East Resources
Acquisition ($4.7B)
Appalachian Basin
November 2010
StatoilHydro
Talisman, Enduring
Resources
Acquisition ($1.3B)
Eagle Ford
November 2010
StatoilHydro
Talisman
Acquisition ($180M)
Eagle Ford
November 2010
Flint Energy Services Ltd.
Acquisition ($36M)
Haynes, Eagle Ford
September 2010
Reliance
Carrizo Oil & Gas
Joint Venture
Marcellus
September 2010
Enerplus Resources Fund
Acquisition ($1.3B)
Kirby; Bakken Marcellus
August 2010
Reliance
Atlas Energy
Joint Venture ($1.7B)
Marcellus
June 2010
Barclays Capital
Chesapeake Energy
Production Agreement
Barnett
31 S
ources: industry and news reports.
© Allen & Overy LLP 2011
20
Date of Deal
Parties Involved
Type of Transaction
Shale Formation
June 2010
Reliance
Pioneer Natural Resources
Joint Venture ($1.36B)
Eagle Ford
June 2010
BG Group
EXCO
Acquisition ($950M)
Appalachian Basin
May 2010
StatoilHydro
Chesapeake
Acquisition ($3.4B)
Marcellus
May 2010
Williams Cos.
Alta Resources LLC
Acquisition ($500M)
Marcellus
May 2010
StatoilHydro
Chesapeake
Lease ($253M)
Marcellus
March 2010
BP Plc.
Lewis Energy
Joint Venture
Eagle Ford
February 2010
Avere Energy Inc.
American Exploration Corp.
Joint Venture ($2.85M)
Haynesville
February 2010
Mitsui & Co.
Anadarko Petroleum
Joint Venture ($1.4B)
Marcellus
January 2010
Total SA
Chesapeake
Acquisition ($2.25B)
Barnett
June 2009
BG Group
EXCO
Joint Venture ($1.3B)
Haynesville
May 2009
Eni
Quicksilver Resources
Joint Venture ($280M)
Barnett
January 2009
Total SA
American Shale Oil
Acquisition
Barnett Shale
2008
BP Plc.
Chesapeake
Acquisition ($1.75B)
Fayetteville shale
www.allenovery.com
21
U.S. Shale Gas Developments: Investement opportunities from the wellhead to the burner tip
Table 3.2 Selected International Transactions Involving U.S. Shale Gas Resources32
Date of Deal
Parties Involved
Type of Transaction
Shale Formation
March 2011
Sasol
Cypress A
Acquisition (C$1.05B)
Montney Basin
March 2011
Molopo Energy, Spearfish
Legacy Oil & Gas
Acquisition (C$188M)
Williston
February 2011
PetroChina
Encana Corp.
Joint Venture (C$5.4B)
Cutbank Ridge
January 2011
Apache Corporation
Early Exploration
New Brunswick
January 2011
Southwestern Energy
Company
Early Exploration
New Brunswick
December 2010
Sasol
Talisman
Acquisition (C$1.05B)
Farrell Creek, Montney
October 2010
RBC Rundle
Acquisition
Horn River
August 2010
Mitsubishi Corporation
PennWest Energy Trust
Acquisition
British Columbia
July 2010
Reliance
Quicksilver
Joint Venture
Horn River Basin
June 2010
China National Petroleum
Encana
Joint Venture
Horn River, Montney
June 2010
ARC Energy Trust
Storm Exploration Inc.
Acquisition (C$680M)
Montney
May 2010
EOG Resources Canada Inc.
Galveston LNG Inc.
Acquisition
Kitimat Processing Facility
May 2010
Encana
Acquisition (C$37.5M)
Collingwood
May 2010
Canadian Natural Resources
Acquisition (C$1B)
Alberta, British Columbia
April 2010
Encana
Korea Gas
Acquisition (C$1B)
Horn River, Montney
April 2010
Talisman
Acquisition (C$1.9B)
Western Canada, Alberta
March 2010
LNG Energy Ltd.
Kunagu Real Estate S.A.
BWB Exploration LLC
Acquisition (C$9M)
Ardmere/Black Warrior
March 2010
TransAmerican Energy Inc.
Acquisition (C$225K)
Quebec
February 2010
Dejour Enterprises Ltd.
Acquisition
Montney
Mid 2009
ExxonMobil
Acquisition (C$106.3M)
Horn River
2004-2010
Canadian Government
Auctioned Leases (C$6.3B)
British Columbia
32 S
ources: industry and news reports.
© Allen & Overy LLP 2011
22
Allen & Overy LLP
Mitchell Silk is a projects Partner in the Banking Department and head
of the U.S. China Group in the New York office. He advised on many of
China’s landmark project financings, and has considerable experience in
the energy sector, including upstream and midstream oil and gas matters,
cross-border pipelines and LNG receiving terminals in Greater China
(including Mainland China, Hong Kong and Taiwan), Indonesia, Russia,
Korea, Brazil, Colombia and the United States.
Mitchell Silk
Paul Mohler is a Senior Consultant in the U.S. Energy Practice. He served
in a number of senior capacities at the U.S. Federal Energy Regulatory
Commission, and has considerable experience in oil and gas matters.
Paul Mohler
Gary Lazarus is Senior Counsel in the Projects Group of the Banking
department and has substantial experience in both domestic and
international power projects, including gas and coal-fired facilities, wind
and solar farms.
Gary Lazarus
Rebecca Perkins is an Associate in the Banking department.
Rebecca Perkins
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