the changing landscape of the u.s. energy market

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The Changing Landscape of the U.S. Energy MarketNatural gas-fired electric power plants: A key element for future U.S. energy policy – Summer 2011

Natural gas-fired electric power plants: A key element for future U.S. energy policy

© Allen & Overy LLP 2011

Natural gas-fired electric power plants: A key element for future U.S. energy policy2

Mitchell Silk, Paul Mohler, Gary Lazarus and Noah Baer – U.S. Projects Group1. Introduction and SummaryIn his January 25, 2011, State of the Union Address, President Barack Obama challenged the U.S. Congress to join him in “setting a new goal: by 2035, 80% of America’s electricity will come from clean energy sources” as a means of reducing greenhouse gas emissions. Unlike many U.S. states with renewable mandates that exclude natural gas, clean coal and nuclear, the President observed that “we will need them all”. This goal was echoed when President Obama introduced his March 30, 2011, “Blueprint for a Secure Energy Future,” during a major policy speech focused on U.S. energy issues.

Whether Congress will take up the President’s challenge, and the ultimate form and effectiveness of any clean energy standard (CES) mandate that comes out of the legislative process, is unclear at this time. It is foreseeable, however, than any formulation of this goal, or any regulatory regime that imposes costs, directly or indirectly, on greenhouse gas emissions, will lead to an increase in the development and utilization of new and existing combined-cycle, gas-fired electric generation plants. The key underlying factor that will make this development possible is the expected contemporaneous development of U.S. shale gas resources.1

This note explores the continued role of natural gas in the U.S. electric power generation mix at this critical juncture. The note first provides an overview of the current and projected sources of electric generation in the U.S. It then examines the relative capital costs of new generation sources. It goes on to review the “economic” dispatch process and how natural gas-fired generation is likely to fare where additional costs are imposed on generation sources due to greenhouse gas or carbon emissions.

1. See the Allen & Overy LLP companion piece, U.S. Shale Gas Developments: Investment Opportunities from the Wellhead to the Burner Tip, by Mitchell Silk, Paul Mohler, Gary Lazarus and Rebecca Perkins.

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After considering potential competitors to natural-gas fired generation, the note concludes that natural gas-fired generation is the power source most likely to fill the gap between the renewable generation sources that will come online over the next several decades and total electricity demand–a gap that will grow as existing coal-fired plants are retired and electric demand grows. Additionally, gas-fired generation may be the most cost-effective resource for providing the back-up necessary for intermittent generation sources as wind and solar resources become an increasing part of the U.S.’s electricity generation profile.

2. Overview of U.S. Electricity GenerationAs shown in Figure 1.1, the U.S. currently gets about 45% of its electricity from coal-fired electric generation plants. By 2035, the U.S. Energy Information Administration (the EIA) estimates that coal-fired generation would still account for 43% of electricity generated, a relatively modest decrease from current generation levels.

Figure 1.1: Electricity generation by fuel, 1990-2035

6

5

4

3

2

1

01990 2000

History Projections

2009 2020 2035

43%

14%

25%

17%1%

Coal45%

10%23%

20%1%Oil and other liquids

Renewables

Natural gas

Nuclear

Net electricity generation (trillion kilowatthours per year)



During this same period, renewable sources of energy, including hydroelectric, are projected to increase from 10% to 14% of total generation. Nuclear is expected to decrease slightly, from 20% to 17%. Natural gas, the focus of this note, increases from 23% to 25%, matching the percentage decrease in coal generation. Under these projections, just 57% of electric generation would come from the types of generation included in President Obama’s proposed 80% CES goal.

Even using a generous definition of “clean coal,” the current and projected share of traditional coal-fired generation would need to decrease substantially more than under current projections. While planning and building solar and wind-powered projects continues, these sources alone will not be sufficient to meet future electric demand, at least not at any reasonable cost. Some new nuclear plants may come on line, but they too will likely not be sufficient to close the gap, and with the expense, risk, and long lead times of new plants, may not even be sufficient to retain their current percentage of electric generation as demand grows over the next decades. The only currently viable candidate to fill the gap is natural gas-fired generation.

Natural gas will fill the gap in three different ways. First, existing natural gas-fired plants will become more economic on the margin vis-à-vis existing coal-fired generation. Second, more new, high-efficiency, gas-fired generation plants will be built. Third, natural gas-fired generation will be the generation of choice to back up intermittent generation resources.

Because a substantial part of the U.S.’s generation resources are bid into electricity markets subject to federal regulation (or state regulation in the case of Texas), these markets will be critical in determining the extent to which natural-gas fired generation will be used in major U.S. electricity markets. The next several sections provide a review of the dispatch mechanisms generally used in these markets, followed by the likely impact on dispatch decisions of lower gas prices coupled with higher direct or indirect costs faced by coal-fired generation.

2.1 Economic Dispatch(a) Introduction

In its simplest form, “economic dispatch” is the process of dispatching lower-cost generation before higher-cost generation to meet a given level of demand. The result is that generation with the lowest marginal costs is utilized at the highest capacities, while generation with incrementally higher marginal costs is used only during peak load periods and thus operates at a lower capacity factor. In practice, economic dispatch is more complicated, as some units must be dispatched for reliability, operational, or contractual reasons, even where those units may not be the most economic. Figure 1.2 illustrates a typical daily dispatch stack. Understanding the dispatch process is critical to making investment decisions.

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All major U.S. electricity markets use a form of economic dispatch to manage and operate their electricity distribution systems.2 Economic dispatch should result in the lowest marginal electricity generation costs for a given dispatch zone, subject to the operational constraints of the generation fleet and the transmission system.3 Improvements in economic dispatch, and thus lower electricity costs, are generally driven by: (i) substituting generation with lower marginal costs for generation with higher marginal costs; (ii) substituting more efficient power generation (e.g., low heat-rate sources) for less efficient power generation (e.g., high heat-rate sources), and (iii) reducing trading costs between electrically connected regions (e.g., through development of new transmission).4

Figure 1.2: Typical Dispatch Stack

Generation Competing for Economic Dispatch in Merit Order (IPPs, utility-owned, out-of-area purchases)

Reliability Must-Run Generation

Bilateral Contracts & Self-Scheduled Generation

Must-Take Native Load Generation (run-of-river hydro, wind, QFs)

Minimum-Run Generation (nuclear, coal, natural gas steam turbine)

100% of Available On-line

Resources

Committed Generation CapacityNot Dispatched

Demand

midnight noon midnight

Source: Massachusetts Institute of Technology

2. United States Department of Energy, The Value of Economic Dispatch: A Report to Congress Pursuant to Section 1234 of the Energy Policy Act of 2005 at 12 (Nov. 7, 2005).

3. Id. at 10.4. Id. at 33.



(b) The Impact of Price on Dispatch Curves

After reliability and must-take obligations, the most important factor in determining which resources are utilized under an Economic Dispatch regime is the marginal price of available generation. Historically, the dispatch of natural gas-fired generation has been limited by natural gas prices that were higher and more volatile than the price of coal used to generate a similar amount of electricity. Weather-related spikes in demand, or supply constraints caused by damage from hurricanes or unexpected freezes, have contributed to natural gas price swings.5 Natural gas prices ranged from as high as USD13.98 per million British thermal units (MMBtu) in July 2008 to as low as USD1.98 per MMBtu in September 2009.6 This price volatility made utilities and generators reluctant to make new long-term commitments to natural gas, especially given coal’s lower and more stable price history.7 A historical comparison of gas versus coal prices is illustrated in Figure 1.3.

Figure 1.3: U.S. Natural Gas and Bituminous Coal Spot Prices from 1970 to 2009

Source: Energy Information Administration

5. United States Government Accountability Office, GAO-08-610R Implications of Switching from Coal to Natural Gas at 12 (May 1, 2008), available at http://www.gao.gov/new.items/d08601r.pdf (hereinafter, GAO Report).

6. Aspen Environmental Group, Implications of Greater Reliance on Natural Gas for Electricity Generation at 27 (Jul. 2010) (hereinafter, Aspen Report).

7. Clifford Krauss, Breaking Away from Coal, The New York Times, Nov. 30, 2010, at B1, available at http://www.nytimes.com/2010/11/30/business/energy-environment/30utilities.html?_r=1.

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This historic relationship is, however, changing. Technological advancements in shale gas drilling and production have increased the current and projected supply of natural gas in the U.S., resulting in lower and more stable prices.8 The current projection of recoverable shale gas resources is over 900 trillion cubic feet, and could account for 50% or more of total U.S. gas supply by 2035, compared with only 20% currently.9 At the same time, the greater development of on-shore natural gas resources has lessened the impact of extreme weather-related events on natural gas supply.10 Shale gas resources are being developed rapidly and, as can be seen in Figure 1.4, production levels have reached heights in the last year that the EIA forecasted in its 2010 Annual Energy Outlook would not be met for another 10 years.

Figure 1.4: Energy Information Administration Forecast of Shale Production (per Annual Energy Outlook) vs. Actual Production

Bcf

per

Day

(Dry

)

16.0

14.0

12.0

10.0

8.0

6.0

4.0

2.0

0.0

1990

1995

2000

2005

2010

2015

2020

2025

2030

Actuals to 2010

AEO 2010 Forecast

AEO 2008 Forecast

Source: Energy Information Administration

8. Richard G. Smead, APPA Report Does Not Underline Shift to Gas Generation, Natural Gas & Electricity, Sep. 2010, at 31.9. Chua Baizhen and Dinakar Sethuraman, Utilities May Build Gas-Fired Plants, Duke Says, Bloomberg, Sep. 13, 2010,

http://www.bloomberg.com/news/2010-09-13/utilities-may-build-u-s-gas-fired-plants-duke-says-update1-.html.10. Smead, supra note 8, at 29.



In less than two years, the production of shale gas resources has fundamentally transformed the U.S. natural gas market, reducing both volatility and price levels from those experienced just a few years ago. The impact this price moderation will have on dispatch curves will be amplified by the additional costs likely to be imposed on coal-fired generation through additional environmental restrictions imposed on coal plants, or indirect restrictions imposed by state renewable energy standards or federal clean energy standards. That is, as gas prices moderate and coal-fired generation costs increase, there will be a greater incursion of gas-fired generation vis-à-vis coal-fired generation in the dispatch stack. The next section explores the competition between coal and gas as a fuel for electric generation in more detail.

2.2 Will Natural Gas Displace Coal-Fired Generation?Increased environmental regulation or the imposition of carbon pricing on electric generation would make coal-fired generation more expensive. While costs for both coal-fired and natural gas-fired power plants increase with carbon pricing, the costs for coal-fired generation increases at a faster rate due to the greater inefficiencies in the coal-burning process as well as the greater carbon content in coal. While it varies by the type of coal, in general coal releases more than twice the carbon into the atmosphere as natural gas. Burning coal also produces sulfur dioxides, nitrogen oxides, and particulates not produced by natural gas.

According to a study by the Energy Information Administration, assuming gas prices are in the USD5 to USD7 MMBtu range, carbon pricing between USD15 and USD30 per ton would make natural gas significantly cheaper than coal.11 However, coal would not be “thoroughly displaced” by natural gas until carbon prices are between USD50 and USD100 per ton.12 It appears at this time that the type of “cap and trade” or “carbon tax” schemes that would directly assess these costs to electric generators are unlikely to be implemented in the U.S. However, this does not mean that there will not be either direct or indirect regulation that would result in higher costs to coal-fired generation relative to gas.

While comprehensive climate legislation does not appear forthcoming in the near-term and the impact of regulation is uncertain, the Environmental Protection Agency (EPA) has taken steps to issue new rules and regulations regarding carbon emissions, with new standards to be proposed for utilities by July 2011 and for oil refineries by December 2011. These rules are to be made final in May 2012 and November 2012, respectively.13 On March 16, 2011, the EPA issued proposed regulations, often referred to as the “Utility MACT Rulemaking”14 that would require coal and oil-fired power plants to reduce mercury and a variety of other emissions.15 A final rule is due November 16, 2011. More stringent emissions standards in the future could make early adoption of cleaner sources of energy economically beneficial, especially considering that 70% of the United States’ coal-fired power plant fleet is over 30 years old, with limited capabilities for economic emissions reductions.16 The EIA itself

11. Sean Casten, Fuel Swap, Recycled Energy Newsroom, Apr. 1, 2010, available at http://www.recycled-energy.com/newsroom/publication/fuel_swap/.

12. Steven H. Levine et al., Prospects for Natural Gas Under Climate Policy Legislation, The Brattle Group at 3 (Mar. 2010).13. Kim Chipman, EPA to Impose Its Rules, Philly.com, Dec. 24, 2010, http://www.philly.com/inquirer/health_science/daily/20101224_EPA_

to_impose_its_rules.html14. MACT refers to Maximum Achievable Control Technology. 15. The text of the proposed rule and related fact sheet are available on the EPA website at www.epa.gov.16. Krauss, supra note 7. It is estimated that 30% of the fleet has no emissions control at all, while another 33% lack either a scrubber for

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estimates that 10 gigawatts of generation will retire as a result of the MACT rule; industry estimates are even higher. Compliance costs over the next decade for replacing or retrofitting the coal power fleet are estimated to be as high as USD70 billion and many utilities may be hesitant to make such substantial investments in older, largely depreciated assets.17

In contrast, existing gas-fired generation will require little of the retrofitting required by coal-fired plants. New high-efficiency gas plants can be built with a shorter lead time and have smaller footprints than coal-burning facilities. Also, since natural gas is delivered by pipelines thoughout the continental United States, there is more flexibility to locate gas-fired generation near demand or existing transmission infrastructure.

It is unlikely that existing coal plants can be economically converted to use natural gas. The U.S. Government Accountability Office concluded that “it would be more feasible and cost-effective to construct new natural gas units or to dispatch excess capacity at existing natural gas units than to convert a coal plant because of technical and economic factors.”18 Supporting this conclusion, there have not been any instances to date of operational coal-fired plants being retrofitted and converted to gas-fired plants in the United States. 19 Indeed, in almost all cases, proposals to “convert” are actually proposals to replace the coal-fired plants with newly constructed gas-fired plants at the same location.20

The conclusion that there will be a significant shift from coal to natural gas as a preferred fuel is not just theoretical, but is reinforced by recent events, announcements, and analyses from major energy utilities and utility executives. Over the last 18 months, at least ten power companies have announced plans to close more than three dozen of their oldest and least efficient coal-fired power plants within the next decade.21 Since then, the move away from coal to natural gas has accelerated. Thus, Jim Rogers, CEO of Duke Energy, recently stated, “[g]as-fired power plants will be built in lieu of coal plants because of uncertainty in the regulation of coal, on sulfur oxides and nitrogen oxides, as well as carbon.”22 Similarly, Bill Johnson, president and CEO of Progress Energy, observed that Progress is planning to retire a third of its coal-fired units, mostly smaller ones, and replacing some of them with natural gas-fired units.23 John Rowe, chairman and CEO of Exelon, which manages the U.S.’s largest fleet of nuclear generation plants, has similarly endorsed natural gas over other generation sources for the next several decades or more, largely on the basis of inter-fuel economics.24 Finally, in April 2011, the Tennessee Valley Authority announced that it planned to retire 18 of its 59 coal-fired power plants by 2017, replacing the energy with combined cycle (natural gas) and nuclear power plants.25

removal of sulfur dioxide or other controls for nitrogen oxides. Id.17. Id.18. GAO Report, supra note 5, at 5-6.19. Aspen Report, supra note 6, at 87. Several proposed coal-fired plants have, however, been converted to natural gas.20. Id. For example, in Minnesota, Xcel Energy proposed spending USD1 billion to "convert" some coal plants to gas. However, what Xcel

Energy actually did was build 1100 MW of new combined cycle gas-fired generation at the sites of existing coal-fired plants. Id.21. Krauss, supra note 7.22. James Rogers, CEO of Duke Energy Corp., as reported by Bloomberg News, Sep. 13, 2010.23. Inside Energy, Feb. 28, 2011, at 8.24. John Rowe, Speech to the American Enterprise Institute, Mar. 3, 2011. Transcript available.25. See TVA Fact Sheet, Apr. 14, 2011, available at http://www.tva.gov/news/releases/aprjun11/pdf/plans_for_coal_fired_generation_

spring_2011_fact_sheet.pdf.



While the trend towards increased use of natural gas in electric generation is clear, there are still major economic and structural impediments to a complete switch from coal-fired to gas-fired power plants. Since most power plants are routinely financed over 20-year or 30-year periods and 30% of the existing coal-powered fleet is 30 years old or less, the cost of paying off this outstanding debt and its impact on future cash flows from the project must also be recognized as part of the replacement cost.26 These tend to be the more efficient plants to operate, especially when base-loaded in the dispatch queue. There would also be substantial new infrastructure costs from a rapid coal-to-gas conversion. The American Public Power Association estimates that new pipeline capacity alone could require USD348 billion27 should all coal-fired plants be replaced with gas-fired plants, in addition to the USD335 billion cost of replacing the 335,000 MW of coal-fired power generation.28

While costs and infrastructure limitations will inhibit a complete displacement by natural gas of all coal-fired plants, certain areas of the country are better suited to making such a transition than others. Figure 2.1 is a map of the United States showing where opportunities for displacement of coal by natural gas are greatest, based on the amount of coal used to make electricity in that state compared with the amount of excess capacity of gas-fired power plants. Where there are relatively matching amounts of coal and excess natural gas capacity, there is a greater potential for resource switching. Certain states like California and New Jersey, which are already heavily gas dependant with limited coal-fired capacity, and Midwestern states that are heavily coal dependent with limited gas-fired capacity, will have only limited fuel switching opportunities. However, many South eastern states, including Texas, Louisiana, Mississippi, Alabama and Florida, appear to have relatively greater potential given the match between coal usage and excess natural gas capacity in those States.29

26. Aspen Report, supra note 6, at 89.27. Id. at 92.28. Id. at 89. The installed cost for a new combined-cycle gas-fired unit of 1000 MG is about USD1 billion, or roughly USD1 million per MW.

Id.29. Massachusetts Institute of Technology, The Future of Natural Gas at 47 (2010).

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Figure 2.1: Scale and Location of Fully Dispatchable Natural Gas Combined-Cycle and Coal Generation (MWh, 2008)

Scale: 100,000,000 MWh

MWh coal generation, heat rate <10,000 Btu/kWh

MWh coal generation, pre-1987 plants with heat rate <10,000 Btu/kWh

Existing NGCC capacity operating at 85% capacity factor minus 2008 actual MWh generation (FDNP)

WA

MT ND

MNWI

IA

MO

AROK

KS

COUT

SD

NE

ID

WY

OR

CA

NV

AZ NM

TX LA

MS AL

FL

GA

SC

NCTN

KY

VAWV

ME

VT

NY

PA

MDDE

NJ

OH

MI

INIL

NH

MA

CTRI

Source: Massachusetts Institute of Technology



2.3 Development of New Gas-Fired PlantsThe current U.S. fleet of gas-fired power plants consists of three different technologies: gas-fired steam boilers, simple-cycle turbine plants, and combined-cycle turbine plants that include secondary heat recovery steam generators and steam turbines on the back end.30 The last is by far the most efficient of the three; earlier generations of the combined-cycle plants were heavily developed in the gas-fired plant fleet build-out in the late 1990s.31 These combined-cycle turbine plants average a thermal efficiency (i.e., they burn natural gas more efficiently at a lower heat) of almost 46%. This is 39% higher than the efficiency of the average coal plant.32 The reason these combined-cycle turbine plants are so efficient is that they are designed to first burn the natural gas through a turbine to generate power and then use the waste heat from the turbine combustion to make steam in a boiler, which in turn is used to generate additional electricity.33 Combined-cycle plants do, however, present challenges of heat rate efficiency management when operating at partial loads, which is a particular concern for facilities subject to economic dispatch.

2.4 Growth PotentialThe industry has been optimistic about the “attractive economics of new natural gas-fired power plants relative to the building of other types of power plants.”34 Furthermore, gas-fired power plants are relatively easy to site and thus can be constructed close to load centers.35 As evidenced in Figure 3.1, when factoring a variety of costs, including the likely costs associated with greenhouse gas emissions, gas-fired power plants are the most economic choice for power generation with prices of natural gas between USD5 and USD7 per MMBtu.36

30. Casten, supra note 11.31. Id.32. Richard G. Smead, Better Use of Gas-Fired Generation Damps Volatility, Cuts Back CO2, Natural Gas & Electricity, May 2010, at 30.33. Id.34. Levine et al., supra note 12, at 6.35. Smead, supra note 32, at 29.36. Levine et al., supra note 12, at 6.

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Figure 3.1: Level Real New Generation All-In Cost Estimates

350

Baseload Renewable300

250

200

150

2008

$/M

Wh

100

50

SC C

oal @

$2/M

MB

tu

SC C

oal @

$4/M

MB

tuG

as C

C @

$5/M

MB

tu

Gas

CC

@$7

/MM

Btu

IGC

C w

/ Seq

@$2

/MM

Btu

IGC

C w

/ Seq

@$4

/MM

Btu

Nuc

lear

@ $

4,00

0/KW

Nuc

lear

@ $

7,00

0/KW

Ons

hore

Win

d @

25%

Ons

hore

Win

d @

35%

Sola

r PT@

34%

Sola

r PT@

45%

+ S

tora

geSo

lar P

V @

21%

0

CO2 at $100/ton

CO2 at $30/ton

CO2 at $10/ton

CO2 Trans & Storage

Fuel

Capital

O&M

6785

5468

112

112101133

151

217

298

73 72

Source: The Brattle Group

In a recent EIA report on electric generation capital costs, the advantage of natural gas was similarly evident, with increases in overnight capital costs estimated for coal and nuclear units of 25% and 37%, while natural gas combined combustion decreased by 3%. While photovoltaic and thermal solar also decreased on a percentage basis, even the least expensive option had overnight capital costs that were five times the cost of a natural gas combined combustion unit.37

37. Updated Capital Cost Estimates for Electricity Generation Plants, EIA, Nov. 2010.



2.5 FinancingAs discussed above, due to historical pricing in favor of coal, few gas-fired generating facilities have come to market in the last ten to fifteen years. This means that there is scant guidance in the market as to how new-build gas-fired facilities will be structured and financed. However, looking back at the last boom of combined-cycle gas-fired plants in the late 1990’s, we can garner some insight into how new-build in this sector will likely be financed. Generally, the gas-fired facilities that came to market during the last wave of construction were financed in one of three ways: on balance sheet; with project financing; or packaged together in a bond or other debt offering.

The first two methods were used for greenfield projects, to get them through construction to commercial operation and revenue producing status. Project financing is often preferred by sponsors if available in the market. Whether or not lenders will have appetite for financing a domestic power project will depend on various key factors, including:

the quality of the offtaker, – EPC contractor and O&M provider;

the term of the – PPA relative to the proposed tenor of debt; and

whether there is a take-or-pay PPA or the plant will be selling in the merchant market. –

All of these factors, including others relating to energy needs and fuel cost projections (as discussed herein), will be critical for lenders in determining the bankability of any given new project.

Once a sponsor has constructed a portfolio of proven revenue producing facilities, it might look to bundle those together in a bond or other debt offering to refinance existing project debt and/or the sponsor’s equity investment. These portfolio refinancings were typically structured as note or bond offerings at a holding company level, but might also be done through a larger syndicate of banks. Although diligence is still required on all of the items set out above for a greenfield project, these refinancings are usually at lower financing costs than the original financing because the projects have completed construction and have a history of producing revenue.

In general, once the market for new gas-fired generating facilities begins to grow (as is expected over the next few years), there will be a concurrent need for additional financing to complete the required new build in this sector, which will create many opportunities for debt and equity financing providers.

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3. Potential Competition to Gas-Fired Power Plants is Unlikely to Materialize

3.1 CoalAs discussed above in Section 2.2, natural gas is becoming increasingly competitive with existing coal-fired generation in areas where both compete in the same markets, and is likely to make inroads in the future in those areas where coal currently has a capacity advantage. There was no new construction of coal-fired power plants in the United States in 2010—the second straight year without any new deals breaking ground.38 “[A] combination of low natural gas prices, shale gas discoveries, the economic slowdown and litigation by environmental groups” has effectively stopped the development of most new coal-fired power plants. The uncertainty of how or when additional costs would be imposed on existing or new coal plants is creating an environment where investment in both existing and new coal projects is increasingly in doubt. In 2010, utilities and power-generating companies halted plans to build 38 coal-fired plants, and bank financing and insurance for new construction has increasingly become more difficult to obtain.39 On the other hand, projects that were commenced in earlier years are likely to still come on line over the next few years. As of October 2009, roughly 15,000 MW of coal-fired generation capacity was under construction in the United States, with the majority of this capacity to come online between 2010 and 2012.40

“Clean coal” technologies are not competitive with natural-gas fired generation. While basic elements of these technologies are in limited use in the coal industry—usually as part of projects that have received governmental grants or other public financial support—a broader and rapid adoption of such technologies is unlikely absent a technological break through that substantially reduces their costs.41

Ultimately, the market for new coal-fired power plants appears weak, with new technologies not economically viable and higher expected costs from EPA regulations or climate change legislation. The greater threat to the higher load factor use of existing and new natural gas-fired plants in the short and medium term comes not from development of new coal-fired plants, but rather by the continued operation of existing plants, if clean energy mandates are not implemented or if new EPA regulations are legislatively or judicially delayed.

3.2 Renewables and Demand-Side ManagementTax incentives and political mandates for renewable resources may make new renewable power plants a preferred investment choice in some regions of the U.S. Figure 1.7 provides a state-by-state view of the renewable portfolio standards (some mandatory and some voluntary) that have been enacted to date.

38. Steven Mufson, Coal’s Burnout, The Washington Post, Jan. 2, 2011, http://www.washingtonpost.com/wp-dyn/content/arti-cle/2010/12/31/AR2010123104110.html. Kevin Parker, global head of asset management of Deutche Bank has called coal “a dead man walkin’” and predicted coal’s share of electric power generation would tumble from 47% in 2009 to 34% in 2020 and 22% in 2030. Id.

39. Id.40. Levine et al., supra note 12, at 8.41. Jeffrey Ball, Coal Hard Facts: Cleaning it Won’t Be Dirt Cheap, The Wall Street Journal, at A12, Mar. 20, 2009, available at http://online.

wsj.com/article/SB123751110892790871.html.



Figure 4.1: Renewable Portfolio Standards by State

Renewable Power & Energy Efficiency Market: Renewable Portfolio Standards

Federal energy regulatory Commission • market oversight • www.FerC.gov/oversight

Renewables Portfolio Standards (RPS) and Goals 29 states and D.C. have an RPS; 7 States and 3 Power Authorities have Goals

Source: Federal Energy Regulatory Commission.

WA: 15% by 2020OR: 25% by 2025

5-10% – smaller utilitiesCA: 33% by 2020MT: 15% by 2015NV: 25% by 2025UT: 20% by 2025CO: 30% by 2020;

10% – co-ops, munisAZ: 15% by 2025NM: 20% by 2020 – IOUs

10% – co-opsTX: 5,880 MW by 2015;

500 MW non-wind goalHI: 40% by 2030

ND: 10% by 2010SD: 10% by 2015NE: Public Power Districts:

10% by 2020KS: 20% by 2020OK: 15% by 2015MN: 25% by 2025;

30% by 2020 – XcelIA: 105 MW; 1 GW wind

goal by 2010MO: 15% by 2021LA: 350 MW by 2012-13MI: 10% MWh and 1,100

MW by 2015WI: 10% by 2015I

IL: 25% by 2025; wind 75% of RPS

OH: 12.5% by 2025WV: 25% by 2025ME: 30% by 2010; 10% new

by 2017; 8 GW wind goal by 2030

VT: 20% by 2017; all growth to 2012 from RE and EE

MA: 15% new by 2020, then 1% annually; 2 GW wind goal by 2020

RI: 16% by end 2019CT: 27% by 2020NY: 30% by 2015

NJ: 22.5% by 2020PA: 18% by 2020DE: 25% by 2025DC: 20% by 2020MD: 20% by 2022VA: 15% by 2025; goal with

production incentivesNH: 23.8% by 2025NC: 12.5% by 2021 –

IOUs10% by 2018 – co-ops, munis

TVA: 50% by 2020

Updates at: http://www.ferc.gov/market-oversight/othr-mkts/renew.asp

Notes: An RPS requires a percent of an elevctric provider’s energy sales (MWh) or installed capacity (MW) to come from renewable resources. Most specify sales (MWh). Map percents are final year’s targets. Nebraska’s two largest public power districts, which serve close to two-thirds of Nebraska load, have renewable goals. The Tennessee Valley Authority’s (TVA) goal across its 7-state territory is 50% zero- or low-carbon generation by 2020.

Sources: Derived from data in: Lawrence Berkeley Labs, State Public Utility Commission (PUC) and legislative tracking services, Pew Center. Details, including timelines are in the Dataase of State Incentives for Renewables and Energy Efficiency: http://www.dsireusa.org

RPS

Accelerated or strengthened RPS

Voluntary State or Utility standards or goals

Strengthened voluntary standard

Pilot or study

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The potential build-out of substantial renewable resources, along with coal-fired plants that should come on line in the next few years, have led to predictions by one federal agency that the use of natural gas generation could decline in the near term.42

However, renewable resources are often constrained (e.g., hydro resources by water levels) or are intermittent (e.g., wind and solar), which requires adequate reserves for periods of time when those resources are not available. The growth of such constrained or intermittent resources will make the availability of natural gas-fired plants, with shorter start times and ramp rates than most coal-fired power plants—particularly important for reliability purposes. Also, for the reasons discussed above, we expect that natural gas will become increasingly competitive with coal.

Demand-side management uses a variety of technologies and techniques to reduce demand during peak periods, thus essentially providing the same service as adding new capacity. Indeed, in several RTOs, proposals to reduce demand on request have been determined to be eligible for capacity payments. Other proposals have focused on various metering strategies that allow users to evaluate their usage, sometimes coupled with time-of-day pricing that incentivizes demand to shift to lower demand periods. While it is expected that these programs will continue to grow, it is not expected that they will substantially reduce overall demand in the short term, and thus should not have a significant impact on the development of new natural gas-fired generation.

3.3 NuclearWhile there will be some continued development of nuclear power generation, the high capital costs, long lead times, siting and public relations issues, and potential risks make it unlikely to compete with natural gas in displacing coal-fired generation. The events in Japan following the recent earthquakes and tsunami make it likely that new nuclear projects will be even further delayed. It is possible that this could change in the future with the development of small-scale, modular nuclear units—an approach currently under consideration by the Tennessee Valley Authority. However, while these units have lower up-front capital requirements than larger nuclear projects, the operating costs may not have the same advantages as larger plants. As one executive opined, “it’s going to come down to costs.”43 Moreover, construction on any such units is unlikely to commence before 2020, at the earliest.

42. Levine et al., supra note 12, at 7.43. Bill Johnson, president and CEO of Progress Energy, as reported in Inside Energy, Feb. 28, 2011, at 8.



4. ConclusionNatural gas-fired generation will be a key and growing part of the U.S. electricity generation market for the foreseeable future. On the margin, gas-fired generation is already competitive with coal and is on a trajectory to become even more so in the future. Gas-fired generators produce up to 60% less carbon than coal-fired plants. Combined-cycle technology has dramatically improved the efficiency of new plants. Gas-fired generation can be strategically sited to take advantage of gas supply sources and electric markets. And, gas-fired generation is a leading candidate to provide back-up service for intermittent renewable generation sources such as wind and solar. While the pace of development of new gas-fired electric generation will vary by region and in part will be dependent on the retirement or economic displacement of existing coal units, the shale gas revolution has created a supply base that should provide both a reliable and a reasonably priced fuel for many years to come. Taken together, these factors will create a fertile environment for investment in strategicallylocated, gas-fired electric generation in the U.S., and, as shale and other gas resources are developed abroad, internationally as well.

This note is generally high-level in nature and is intended to provide a broad summary of the issues relevant to natural gas-fired generation. 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.

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19

Mitchell Silk

Paul Mohler

Gary Lazarus

Noah Baer

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 electric power sector, advising on the development and financing of facilities ranging in sizes from 24MW to 3,000MW and involving virtually every type of fuel/generating technology in China and elsewhere in Asia, the United States, India, Latin America and Africa.

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.

Noah Baer is an Associate in the Banking department.

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© Allen & Overy LLP 2011 I CM1105024

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