The Changing Landscape of the U.S. Energy Market - Allen & Overy

www.allenovery.com

The Changing Landscape of the U.S. Energy MarketU.S. Shale Gas Developments: Investment opportunities from the wellhead to the burner tip – Summer 2011

Mitchell Silk, Paul Mohler, Gary Lazarus and Rebecca Perkins – U.S. Projects Group1. Introduction and SummaryWith 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.

U.S. Shale Gas Developments: Investment opportunities from the wellhead to the burner tip

© Allen & Overy LLP 2011

U.S. Shale Gas Developments: Investement opportunities from the wellhead to the burner tip1

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 GasTraditionally, 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.

www.allenovery.com

2

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 ReservoirsShale 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.



Figure 2.1

2.3 The Economics of Shale GasThe 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.

www.allenovery.com

4

Figure 2.2: Projected U.S. Natural Gas Production6

30

25

20

15

10

5

01990 2000

History

U.S. dry gas production (trillion cubic feet per year)

Projections

2009 2020 2035

1%

45%

8%8%

1%

Net Imports11%14%20%

9%

Shale gas

Tight gas

Coalbed methane

22%

7%7%

Non-associated onshore

Non-associated offshore

Associated with oilAlaska

28%

8%2% 9%

2.4 Regulation of Shale GasMost 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.



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

12

10

8

6

4

2

01994 1996 1998 2000 2002 2004 2006 20102008

16

Daily Natural Gas Futures Contract 1

14

Source: U.S. Energy Information Administration

2.5 Hydraulic FracturingHydraulic 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 DOE, supra note 1.

www.allenovery.com

6

3. Investment OpportunitiesThe 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 MarketThe 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.



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 World Oil News Center, “First Pennsylvania DEP-approved mobile frac water treatment system launched”, November 9, 2010.

12 The Aspen Environmental Group, “Implications of Greater Reliance on Natural Gas for Electricity Generation”, July 2010. p. 89.

13 The INGAA Foundation, Inc., “Natural Gas Pipeline and Storage Infrastructure Projections Through 2030”, October 20, 2009. p. 1.

www.allenovery.com

8

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



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 case-by-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.

www.allenovery.com

10

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 Please 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.



(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 case-by-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.

www.allenovery.com

12

4.1 Price RiskPerhaps 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 RiskU.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 Cox, Rob, “Shale Gas Success Drives Down Prices”, New York Times, December 21, 2010.



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 FracturingDespite being decades-old technology, hydraulic fracturing is facing increased, and often emotionally-charged 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 DOE , supra note 1, at ES-4.

17 Delaware 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 The 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 EPA Study, supra note 9, at 2.

21 Executive Order No. 41: Requiring Further Environmental Review, December 13, 2010.

www.allenovery.com

14

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 ActsNatural 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 Aslup, Dave, “Earthquake ‘swarm’ rattles Arkansas town and its residents”, CNN.com. January 14, 2011.

23 Shaleblog.com, “Chesapeake Energy News”, August 21, 2009.

24 Snow, 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.



– 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 RisksIn 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 CertaintyAs 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-lose-it 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 BMI Americas Oil and Gas Insights, supra note 7.

26 Hernandez v. El Paso Production Co., 2011 WL 1442991 (Tx. App. 2011).

27 Concorde 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

16

www.allenovery.com

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 IssuesThe 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 Tankersley, Jim and Meyer, Josh, “Probe of Bush-era Leases for Oil Shale is Expanded”, Chicago Tribune, October 21, 2009.

30 Exxon-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.



5. ConclusionThe 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

18

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 CorpMarathon 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 TradingCheniere Energy

LNG Processing Agreement Sabine Pass Processing Facility

November 2010 Royal Dutch ShellEast Resources

Acquisition ($4.7B) Appalachian Basin

November 2010 StatoilHydroTalisman, Enduring Resources

Acquisition ($1.3B) Eagle Ford

November 2010 StatoilHydroTalisman

Acquisition ($180M) Eagle Ford

November 2010 Flint Energy Services Ltd. Acquisition ($36M) Haynes, Eagle Ford

September 2010 RelianceCarrizo Oil & Gas

Joint Venture Marcellus

September 2010 Enerplus Resources Fund Acquisition ($1.3B) Kirby; Bakken Marcellus

August 2010 RelianceAtlas Energy

Joint Venture ($1.7B) Marcellus

June 2010 Barclays CapitalChesapeake Energy

Production Agreement Barnett

31 Sources: industry and news reports.




June 2010 ReliancePioneer Natural Resources

Joint Venture ($1.36B) Eagle Ford

June 2010 BG GroupEXCO

Acquisition ($950M) Appalachian Basin

May 2010 StatoilHydroChesapeake

Acquisition ($3.4B) Marcellus

May 2010 Williams Cos.Alta Resources LLC

Acquisition ($500M) Marcellus

May 2010 StatoilHydroChesapeake

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 SAChesapeake

Acquisition ($2.25B) Barnett

June 2009 BG GroupEXCO

Joint Venture ($1.3B) Haynesville

May 2009 Eni Quicksilver Resources

Joint Venture ($280M) Barnett

January 2009 Total SAAmerican Shale Oil

Acquisition Barnett Shale

2008 BP Plc.Chesapeake

Acquisition ($1.75B) Fayetteville shale

www.allenovery.com

20

Table 3.2 Selected International Transactions Involving U.S. Shale Gas Resources32


March 2011 SasolCypress A

Acquisition (C$1.05B) Montney Basin

March 2011 Molopo Energy, Spearfish Legacy Oil & Gas

Acquisition (C$188M) Williston

February 2011 PetroChinaEncana 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 SasolTalisman

Acquisition (C$1.05B) Farrell Creek, Montney

October 2010 RBC Rundle Acquisition Horn River

August 2010 Mitsubishi CorporationPennWest Energy Trust

Acquisition British Columbia

July 2010 RelianceQuicksilver

Joint Venture Horn River Basin

June 2010 China National PetroleumEncana

Joint Venture Horn River, Montney

June 2010 ARC Energy TrustStorm 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 EncanaKorea 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 Sources: industry and news reports.



Mitchell Silk

Paul Mohler

Gary Lazarus

Rebecca Perkins

Allen & Overy LLPMitchell 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.

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.

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.

Rebecca Perkins is an Associate in the Banking department.

www.allenovery.com

22

www.allenovery.com

Allen & Overy means Allen & Overy LLP and/or its affiliated undertakings. The term partner is

used to refer to a member of Allen & Overy LLP or an employee or consultant with equivalent

standing and qualifications or an individual with equivalent status in one of Allen & Overy LLP’s

affiliated undertakings.

© Allen & Overy LLP 2011 I CM1105024

Allen & Overy is an international legal practice with approximately 5,000 staff, including some 470 partners, working in 36 major centres worldwide. Allen & Overy LLP or an affiliated undertaking has an office in each of:

Abu DhabiAmsterdamAntwerpAthens (representative office)BangkokBeijingBratislavaBrusselsBucharest (associated office)BudapestDohaDubai

DüsseldorfFrankfurtHamburgHong KongJakarta (associated office)LondonLuxembourgMadridMannheimMilanMoscowMunich

New YorkParisPerthPragueRiyadh (associated office)RomeSão PauloShanghaiSingaporeSydneyTokyoWarsaw

GLOBAL PRESENCE

Date post:	04-Feb-2022
Category:	Documents
Upload:	others
View:	3 times
Download:	0 times

The Changing Landscape of the U.S. Energy Market - Allen & Overy

Documents