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EPA Power Plant Standards: A Powerful Catalyst for Modernizing our Electric System A Union of Concerned Scientists Background Paper March 20, 2012 Rachel Cleetus, Senior Climate Economist, UCS

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Page 1: EPA Power Plant Standards: A Powerful Catalyst for Modernizing our

EPA Power Plant Standards:

A Powerful Catalyst for Modernizing our Electric System

A Union of Concerned Scientists Background Paper

March 20, 2012

Rachel Cleetus, Senior Climate Economist, UCS

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EPA Power Plant Standards: A Powerful Catalyst for Modernizing our Electric System

1. Introduction

Clean Air Act standards, being issued by the Environmental Protection Agency (EPA) to reduce pollution

from coal-fired power plants, provide a tremendous opportunity to clean up and modernize our electric

system. Collectively, these standards will require many conventional coal plants to install pollution

control technology that would significantly reduce their environmental and public health impacts, or

shut down. Numerous studies show that, in the current economic context, the oldest, dirtiest and least

efficient plants will likely be forced into retirement. There are many cleaner, low-cost alternatives – like

natural gas, renewable energy and efficiency – that can replace these plants in a manner that preserves

the reliability and affordability of our electricity system. Shifting to these resources could begin a

transition to a cleaner and more sustainable electricity system and all its associated health and

economic benefits.

2. Clean Air Act Standards and Public Health

Coal is one of the most polluting sources of energy. Carbon emissions from coal-fired power plants

contribute significantly to the risks of climate change. Harmful pollutants released by burning coal have

also been linked to an increase in asthma attacks, heart disease, neurological problems, and premature

deaths. These significant pollution costs are not currently captured in the price of electricity generated

from coal and instead fall broadly on the American public in the form of health and environmental

impacts.

A recent economic study evaluated the costs of pollution from different industries in the U.S. and found

coal-fired electricity to be the biggest culprit in terms of human health costs (Muller et al., 2011).

Increased deaths and harmful health impacts caused by emissions of sulfur dioxide (SO2), particulate

matter (PM2.5) and nitrogen oxides (NOx) were found to be the major contributors to the external costs

of coal-fired electricity generation, which added up to $53.4 billion a year. When the costs of climate

change caused by carbon dioxide (CO2) emissions from power plants were also included, the external

damage costs went up by 30 to 40 percent. Similarly, a study by prominent public health experts found

that the total cost of the damages caused by coal—from mining to burning to waste disposal— amount

to $345.3 billion per year, which would add 17.8 cents per kilowatt-hour (kWh) to the cost of electricity

generated from coal.1 Accounting for these costs would make coal-fired power more expensive than

many cleaner alternatives, including investments in wind energy and energy efficiency (Epstein et al.

2011).

To address some of these health concerns, EPA has recently finalized some key standards for coal-fired

power plants. These include the Cross State Air Pollution Rule (CSAPR), which will reduce their emissions

of NOx and SOx, and the Mercury and Air Toxics Standard (MATS) which will reduce their emissions of

mercury, lead, arsenic, acid gases and other hazardous pollutants. New Source Performance Standards

1 According to the study, the range for the externality costs of coal is $175.2 billion to $523.3 billion. On a per-kWh basis, this

ranges from 9.42 ¢/kWh to 26.89 ¢/kWh.

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for greenhouse gases (GHGs) from new and existing power plants (hereafter called Power Plant Carbon

Standards), which will reduce emissions of GHGs including CO2 from power plants, are also expected to

be issued this year. Other standards of importance include those establishing guidelines for coal ash

disposal and cooling water intake structures.2 Many of these standards have been years, even decades,

in the making, and were mandated by Congress and the court system. Taken together, they will provide

significant economic benefit in terms of reduced health and environmental impacts and costs. Together,

the MATS and the CSAPR are estimated to provide annual benefits of $150 to $380 billion and prevent

18,000 to 46,000 premature deaths, 540,000 asthma attacks, 13,000 emergency room visits and 2

million missed work or school days each year (EPA, 2011a).

In addition, state climate and energy programs like renewable electricity standards (RES)3, energy

efficiency resource standards (EERS)4, the Regional Greenhouse Gas Initiative (RGGI)5 and California’s

Global warming Solutions Act (Assembly Bill 32)6 will continue to play an important role in reducing

harmful emissions from the power sector and encouraging cleaner sources of generation.

3. Coal Retirements and the EPA Standards

The current suite of EPA standards is being implemented in the context of an ongoing, steady erosion of

the economic viability of coal-fired power plants (Freese et al., 2011). There are many reasons coal-fired

power is becoming increasingly uneconomic, including an aging and inefficient generating fleet,

increasing competition from natural gas and renewables, pollution control costs, slowing growth in

electricity demand, rising construction costs of coal plants, and rising coal prices driven by increased

global demand and growing costs of coal mining. As a recent Credit Suisse report states: ‘… we think a

large chunk of the US coal fleet is vulnerable to closure simply due to crummy economics… Awful energy

margins suggest to us that owners should be reevaluating their coal fleets due to pure energy economics

before even taking on the burden of a capex7 for environmental control equipment.’

The Energy Information Administration (EIA) projects coal generation will decline from 45 percent of

total generation in 2010 to 39 percent in 2035, with 33 gigawatts (GW) of coal-fired capacity retiring

over that period (EIA 2012) due to multiple economic factors. It is also unlikely that much, if any, new

conventional coal capacity will come on line beyond a few plants already in the pipeline. In fact, in 2011

2 For further information about these standards, please refer to the EPA website: http://www.epa.gov/lawsregs/ .

3 An RES, also sometimes called a renewable portfolio standard, requires electric service providers to gradually increase the

amount of renewable energy resources—such as wind, solar, bioenergy, and geothermal—in their electricity supplies, until they reach a specified target by a specified date. Currently, twenty-eight states, plus Washington, DC, have adopted an RES. To learn more, please see UCS’ Renewable Electricity Standards Toolkit (UCS, 2011). 4 An EERS sets an electricity savings target for utilities, often with the flexibility of achieving the target through a market-based

trading system (Nadel, 2006). 5 RGGI is the first cap-and-trade program in the United States to reduce greenhouse gas emissions. It is a cooperative effort

among the states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont. To learn more, go to http://rggi.org/. 6 Assembly Bill 32 requires California to develop regulations that will reduce its greenhouse gas emissions to 1990 levels by

2020. To fulfill these requirements, the state is implementing several programs including an RES, a clean vehicle standard and a cap-and-trade-program. For more information go to: http://www.arb.ca.gov/cc/cc.htm 7 Capital expenditure

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the EIA projected only 2 GW (3 units) of new coal plants built through 2035, in addition to the 11.5 GW

of planned additions by 2015 (EIA 2011).

Against this backdrop, Clean Air Act standards will force coal-fired electricity generation to take into

account some of its considerable public health and environmental costs. Numerous studies show that

this could potentially force a significant amount of retirement of some of the oldest and dirtiest coal

plants over the next decade, as well as require retrofits to install pollution control equipment on many

of the plants that are not shut down. While the standards may be hastening and increasing the number

of coal plant retirements, it is clear that retirements have been and will continue to be driven by

multiple factors, as described in more detail below. Recent coal plant retirements are part of a long-

term trend that started well before EPA began to issue the latest pollution standards (Tierney, 2012).

The EPA’s Clean Air Act standards present us with an incredible opportunity to truly transform our

electric system. The question is whether we will seize the moment to make smart long-term

investments that clean up and diversify our generation mix and also help address the challenge of

climate change.

3.1 How much Coal Retirement?

A wave of coal retirements has been taking place in the last few years, some of it well ahead of the

announcement of recent pollution standards, and financial and industry experts expect this trend to

continue. As of December 2010, across the country 12 gigawatts (GW) of coal plant retirements had

already been announced (Salisbury et al. 2010), and this had grown to approximately 39 GW by the end

of 2011 (SNL data). Recent announcements include one by the Tennessee Valley Authority (TVA)8 in April

2011, saying that it would retire 18 aging coal units by 2020 (TVA, 2011). American Electric Power (AEP)9

announced a roster of planned closures in June 2011, and Duke Energy recently committed to retiring

about 1,667 MW of coal capacity by 2018 (SNL, 2011). In January 2012, FirstEnergy10 announced that it

would close six older coal-fired power plants, with a total capacity of 2,689 MW, located in Ohio,

Pennsylvania and Maryland by September 1, 2012 (FirstEnergy, 2012a). This was closely followed by

their announcement of the retirement of three additional plants, totaling 660 MW, in West Virginia in

the same time frame (FirstEnergy, 2012b). Although company press releases often cite EPA standards as

the sole reason for closures, this flies in the face of evidence that broader market conditions are also

adversely affecting coal.

Several recent studies have estimated how much coal-fired generation may be expected to retire within the next few years. A summary of some of these studies in Table 1 below shows a range of approximately 25 to 100 GW of retirement by 2020. However, it is important to note that the

8 TVA is a federally owned power corporation which serves electricity to approximately 9 million customers in southeastern

states. 9 AEP is one of the largest electricity generators in the country, with units in a number of states including Texas, Ohio, Virginia,

West Virginia, Tennessee, Michigan, Indiana, Kentucky, Oklahoma, Arkansas and Louisiana. It also owns the nation’s largest electricity transmission system. 10

FirstEnergy is one of the nation's largest investor-owned electric systems, serving 6 million customers in the Midwest and Mid-Atlantic regions

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assumptions used to derive these estimates differ considerably across the studies and thus they may not be directly comparable (see note below table for more details). Yet they encompass the views of a wide range of experts so provide a good indication of changes in store for the coal fleet.

Table 1: Recent Estimates of Coal Plant Retirements

Study Author/Date Projected Coal Plant Retirements

Bernstein Research (Wynne et al, 2010) 65 GW by 2015

Bipartisan Policy Center (2011) 35 GW (18GW attributable to EPA rules)

Black and Veatch (Griffith 2010) 54 GW (in response to “pending” environmental regulations)

Brattle Group (Celebi et al. 2010) 50–66 GW “vulnerable to retirement” by 2020

Charles River Associates (Shavel and Gibbs 2010)

39 GW retired by 2015

Clean Energy Group (2010) 25-40 GW by 2015

Credit Suisse (Eggers et al. 2010) 60 GW assumed retired in base case by 2017 35 GW and 103 GW retirements considered in other scenarios

Deutsche Bank Climate Change Advisors(Mellquist et al. 2010)

60 GW “expected” to retire by 2020 92 additional GW “inefficient and ripe for retirement”

FBR Capital Markets (Salisbury et al. 2010) 45 GW retired in base case by 2018 (30–70 GW range)

Goldman Sachs (Lapides et al., March 2011) 38-45 GWs – or 12%-14% of the existing coal fleet and 4%-5% of the total US installed generation capacity – will be retired

ICF International (Rose, Collison and Parmar, 2011)

30-50 GW, up to about 10-20 percent of the nation’s total coal-fired generation today

NERC, October 2010 46-76 GW by 2018 (total fossil fuel capacity, including oil and gas)

NESCAUM (Miller, 2011) 25-76 GW by 2020

MISO (October 2011) 2,919 to 12,652 MW at-risk for retirement (MISO says the upper end is more realistic)

PJM Interconnection (August 2011) In the PJM territory: 11,051 MW of coal-fired capacity “most at risk”, 14,147 “at some risk”

UBS Securities (December 2011) 30-40 GW (from MATS); ~15GW in the PJM territory

Wood Mackenzie (Snyder 2010) Nearly 50 GW by 2020 Note: These studies are not necessarily directly comparable because they differ in terms of what factors were considered apart from the EPA

standards (e.g. assumptions about natural gas prices, future prices for coal, costs for wind and other renewable energy alternatives, financing

costs etc.), which standards were included, and the level of stringency assumed for a given standard. Several studies were published prior to the

finalization of EPA standards and thus the authors had to make their best guess at what they would be. The studies done by MISO and PJM are

focused only on those regions and are not nationwide estimates.

3.2 Risk factors for Coal Retirement

The coal plants most likely to shut down because of pollution standards are old, dirty, and inefficient,

and account for a small fraction of total generating capacity in the U.S. For example, of the coal-fired

power plants that currently lack SOx and NOx pollution controls, 40 percent are over 50 years old, 80

percent are smaller than 200 MW, and 40 percent run less than half of the time (Wynn et al 2010).

Overall, 72 percent of current U.S. coal capacity is older than 30 years and 34 percent is more than 40

years old (Bradley et al. 2010). These plants face high maintenance and capital costs if they are to

continue operating, and that could prove economically prohibitive. Many plant owners have already

made the financial decision that these plants are too old and too expensive to retrofit, compared with

the alternatives. Some older plants may continue to operate if they are deemed critical or “must run”

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for reliability reasons but this should just be for a short time until better alternatives can be

implemented.11

Plants that currently lack pollution controls are vulnerable to retirement unless it is economic to retrofit

them. Approximately half (47 percent) of the 300+ GW of total installed U.S. coal generating capacity

lacks key pollution controls, much of that in the Midwest, MidAtlantic and Southern areas of the country

(Lapides et al, 2011). Small plants are particularly vulnerable because most of them currently do not

have scrubbers to reduce SO2 emissions. Because there are significant economies of scale in the costs of

scrubber retrofits, most operators have chosen not to install these controls on small plants. According to

recent financial industry estimates, the cost of installing an SO2 scrubber at a 200 MW unit is estimated

to be $607 per kW, roughly equivalent to the cost of a new natural gas combustion turbine peaking unit;

at a 100 MW unit, $784 per kW; and at a 50 MW unit, $1,137 per kW, equivalent to the cost of a new

natural gas combined cycle plant (Wynne et al, 2010). In general, plants with higher heat rates12 and

lower utilization rates13 can also be expected to be more vulnerable since they will become even less

economic to run. In some cases, plant owners may decide to install scrubbers and run plants at higher

utilization rates than before.

An analysis by Goldman Sachs & Co. shows that the retirement of older, smaller and less efficient coal

plants will be economically beneficial for the power sector because it will help reduce the current

significant surplus in generation capacity, especially in the Midwest, MidAtlantic and Southeast (Lapides

et al., 2011). And a recent Credit Suisse report proclaims ‘Upcoming EPA policy to limit coal plant

emissions is the best chance for a deregulated power market recovery’ (Eggers et al., 2010). In addition,

retrofitting old power plants with new pollution controls will benefit manufacturers and installers of

pollution control equipment and encourage further innovation in these industries. For example, EPA

estimates that implementing the MATS rule will provide 46,000 short‐term construction jobs and 8,000

long‐term utility jobs (EPA, 2011a).

This wave of retirements poses two critical questions: (1) What other resources could take the place of

the coal-fired generation in a way that maintains both grid reliability and the affordability of power?;

and (2) What policies are needed to ensure that this transition happens in a timely and orderly fashion?

4. Filling the Gap as Coal Plants Retire

As old coal plants retire, multiple affordable alternative resources are available to fill the gap. These

include natural gas, renewable energy, efficiency and demand-side management. It is likely that some

combination of these will play a role. Ultimately, policy drivers and market forces will determine the

11

Utilities may be issued “reliability must run” (RMR contracts) for keeping operational certain units that are critical to maintaining grid reliability, even if the units are otherwise uneconomic. However, RMRs are only intended to be a short-term solution until better alternative solutions such as new transmission or new energy resources can be installed. They should not function as a way to compensate a plant owner for installing pollution controls on a plant that would otherwise shut down for economic reasons. 12

The heat rate of a plant is a measure of its energy efficiency – how efficiently it coverts heat energy from a given fuel type into electricity. A higher heat rate implies lower efficiency. 13

The utilization rate of a plant measures how much electricity the plant actually generates compared with its maximum generation if operating at full capacity

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proportions of each resource in our energy mix. For that reason, this is a critical moment for national,

state and regional decision-makers to make policy and planning decisions that align with long term goals

for transforming the electricity sector to a cleaner, more sustainable one.

4.1 The Role of Natural Gas

In the near term, it is highly likely that increased coal plant retirements in the U.S. will result in more

natural gas generation because of the excess generating capacity currently available from existing

natural gas plants, coupled with the current abundant supply of natural gas and low natural gas prices.

This excess generating capacity results from an overbuild of natural gas plants constructed in the late

1990s and early 2000s, which was driven by favorable technological developments (natural gas

combined-cycle or NGCC technology) and market conditions (such as low natural gas prices) at the time.

One recent analysis found that the power sector is expected to have over 145 GW of surplus generating

capacity in 2014 (Bradley et al. 2011) – and much of this is natural gas-fired. The nation has more than

220 GW of efficient NGCC plants and these plants were operating at a mere 42 percent of capacity in

2007 (Kaplan 2010) and at only 33 percent in 2008 (Bradley et al. 2010), when they are designed to be

operated at capacity factors of up to about 85 percent (MIT, 2011a).

Ramping up the use of existing gas plants could allow the nation to substantially cut its coal-based

electricity generation (Kaplan 2010; Casten 2010; Bradley et al. 2010; CRA 2010b). In fact, a recent

analysis by the Congressional Research Service estimated that if the utilization rate of existing natural

gas plants could be doubled, to 85 percent, they would generate additional power equivalent to 32

percent of all coal-fired generation in 2007 (Kaplan, 2010). Another study estimated that increasing the

fleet-wide average capacity factor of the more efficient NGCC plants (those with heat rates lower than

9000 Btu/kWh) to 60 percent could replace 61.4 GW of coal-fired plants.14 In addition, the excess

natural gas capacity is relatively well-aligned geographically with where potential coal retirements are

expected to occur (Swisher, 2011)

Recent advances in extraction technology have also substantially increased natural gas reserves in North

America, which has put downward pressure on gas prices and made coal plants less competitive. So in

many instances, the switch to natural gas can be done cost-effectively. Moreover, new gas plants can be

built quickly and at a relatively low cost, while existing coal plants can be repowered to burn natural gas

and utilize existing transmission infrastructure.

However, it is important to diversify our generation base beyond just natural gas for a variety of

reasons. A huge rush to gas could itself trigger rising gas prices. Apart from electricity generation,

natural gas is also used as a heating fuel. A cold snap or an unusually cold winter can result in sharp

increases in natural gas prices and even lead to temporary shortages in gas availability. During an

intense cold snap in New England in January 2004, some operators of gas-fired power plants found it

14

This estimate assumes that the coal plants operate at 80 percent capacity factor.

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more profitable to sell their gas to local distribution companies than to run their power generators.15 A

shortage of power and gas also occurred in southwestern United States during a spell of cold weather in

February 2011 (FERC and NERC, 2011).

Furthermore, a future of cheap, abundant natural gas cannot be taken for granted. EIA’s 2012 estimate

of shale gas in the United States is more than 40 percent lower compared with its 2011 estimate -- 482

trillion cubic feet, down from the 827 trillion cubic feet (EIA, 2012). In particular, there was a significant

downward revision in the estimated amount of gas reserves in the Marcellus Shale based on updated

assessments by the U.S. Geological Survey (Coleman et al., 2011). Together with increasing concerns

around the environmental impact of extraction practices like hydraulic fracturing (“fracking”), this

suggests that future natural gas supplies could be more constrained than currently assumed.

Finally, natural gas should not be viewed as a long term energy solution given climate change concerns.

A recent analysis by the IEA (IEA, 2011) looked at a scenario where global use of gas rises by more than

50 percent from 2010 levels, accounting for more than 25 percent of global energy demand by 2035. It

showed that this fuel switch did not allow for reductions in global warming emissions that are sufficient

to respond to the risks of climate change.16 In addition to the emissions produced while burning natural

gas, natural gas extraction, processing, and transport also results in the release of methane, a far more

potent global warming gas than carbon dioxide.

4.2 Scaling up Renewable Energy

In many parts of the country, the retirement of coal will also mean drawing more on energy efficiency

and renewable energy resources. In its most recent Annual Energy Outlook, EIA projects that increases

in renewable energy generation (excluding hydropower) driven by existing state and federal policies will

account for 33 percent of the overall growth in electricity generation from 2010 to 2035. In addition, the

share of U.S. power coming from renewable sources (including conventional hydropower) will grow

from 10 percent in 2010 to 16 percent in 2035 (EIA, 2012).

Existing state policies have been instrumental in ramping up renewable energy resources. Twenty nine

states, plus the District of Columbia, now have an RES in place, while eight more states have goals.

California’s recent passage of a 33 percent RES, the most aggressive in the country, is expected to be an

important driver in the domestic market for renewables. Its climate change law, A.B. 32, will also

incentivize energy sources that reduce carbon emissions. At the national level, tax credits have been an

important driver for renewable energy development and attracting new domestic manufacturing

capacity.. However, several short-term extensions and lapses in these tax credits over the past decade

have created a boom-bust cycle and significant investment uncertainty for the renewable energy

industry.

15

Interruptible gas contracts for power producers can also mean that, when supplies are constrained, natural gas power plants may have to go offline if the gas is needed for residential heating which is not likely provided under interruptible contracts.

16 The scenario modeled looked at the emissions reductions necessary for a path consistent with a global temperature rise of no

more than 2°C.

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Even without sustained federal support, recent data show that in many parts of the country wind power

is cheaper than new coal plants. The costs of well situated wind facilities could even be economically

competitive with new natural gas plants (Wiser and Bolinger 2010). The costs of solar photovoltaics (PV)

have also been falling rapidly in large part because of a steep drop in manufacturing costs. Costs of both

wind and solar are predicted to fall even further in the next few years as additional economies of scale

and technology innovation are realized. Other resources, such as bioenergy and geothermal energy, are

also promising and can be run around-the-clock just like a coal or natural gas “baseload”17 plant. As a

recent IPCC special report on renewable energy points out: “Some RE [renewable energy] technologies

are broadly competitive with existing market energy prices. The cost of most RE technologies has

declined and additional expected technical advances would result in further cost reductions. Monetizing

the external costs of energy supply would improve the relative competitiveness of RE” (IPCC, 2011).

In fact, technological advances and growing economies of scale have driven down wind costs by about

80 percent over the last three decades. While there were significant price increases in the early-to-mid

2000s (mainly because of tight supplies of raw materials like steel and cement), prices of turbines are

once again falling. Crucially, the price of the “fuel” in the case of wind is not prone to the volatility that

natural gas (or any conventional fuel) prices are prone to. The U.S. wind industry added wind capacity at

an average growth rate of 35 percent per year from 2005 to 2010, installing five times as many

megawatts during this period as in the previous 25 years (AWEA, 2011; AWEA, 2010). At the end of 2010

this added up to more than 40,000 MW of capacity in operation.

According to the Department of Energy, nine U.S. utilities generated between 10 and 38 percent of their

power from wind in 2009 (Wiser and Bolinger, 2010). The largest U.S. user of wind power, Xcel Energy

(which serves nearly 3.5 million customers across eight Western and Midwestern states), obtains 13

percent of its electricity from wind and other renewable energy sources. Xcel is expecting that level to

increase to 19 percent in 2012 and 30 percent by 2020 to meet Minnesota’s and Colorado’s renewable

electricity standards. In 2011, wind power provided 8.5 percent of the electricity generated in Texas,

which leads the nation in installed wind power capacity (ERCOT, 2012a). On March 7, 2012, Texas set a

new record by producing 22 percent of the state’s electricity from wind (ERCOT, 2012b). Detailed

simulations by grid operators, utilities and other experts in the United States have found that the

Eastern and Western U.S. grids can accommodate up to 30 percent of total electricity from wind, and

another 5 percent from solar energy in the West (EnerNex, 2010; GE Energy, 2010). Clearly, there is

potential to achieve higher wind penetration rates18 in many areas of the country.

4.3 The Interplay between Natural Gas and Renewable Energy

Natural gas has been characterized as a bridge fuel between coal and renewable resources. There are

good reasons for this: natural gas produces lower GHG emissions than coal when burned, natural gas

17

Baseload plants typically run all the time except when they need to be taken down for repairs or maintenance. They form the backbone of the electric system and help meet an area’s basic electricity demand. They usually have low variable costs of operation and are most economical when run continuously. Peaking plants can then be added on to meet demand fluctuations beyond the normal levels. 18

The penetration rate for wind measures the percentage of an area’s energy supply that comes from wind energy.

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plants can provide baseload power, and most plants can be ramped up and down to complement

variable sources like wind and solar power. The day-to-day reliability of our electricity supply depends

on the operation of the interconnected electric system, not just on any one type of baseload resource.

Over time, the expectation is that, with better storage technologies and a more integrated grid, it would

be possible to have wind and other renewable resources essentially “mimic” most of the services that

baseload resources provide – which is to match demand and supply throughout the day and during

different seasons, and help maintain a reserve margin in case of unexpected surges in demand or

outages. This would make it possible to slowly replace much of the natural gas from the system though

some amount would still be needed to complement variable resources in a flexible way. The shift to a

steadily increasing share of energy coming from renewable sources would allow us to transition to a low

or even zero-carbon energy infrastructure.

However, with cheap natural gas prices and lack of sustained federal support for renewable energy,

there is a real danger that natural gas could crowd out renewable energy, especially over the next

decade. It is critical that we not lose this opportunity to scale up renewables alongside natural gas.

Diversifying our energy base will leave us less exposed to price volatility, less vulnerable to the

environmental costs of natural gas drilling and processing, and allow us to sharply lower GHG emissions

thereby reducing the risks from global warming. Experience has shown that as renewable resources

have been scaled up, their prices have fallen dramatically. Natural gas has a very important role to play

in enabling this transition, but that role must be appropriately contained if we are to avoid stifling the

necessary innovation and price declines needed to decarbonize our energy infrastructure over the next

few decades.

4.4 Other resources: Efficiency and Demand Side Management

Energy efficiency is one of the quickest and least costly ways of replacing existing generation capacity.

Investments in efficiency, whether they are made at the plants that produce power or by consumers

who are the end-users of electricity, mean that the economy overall produces fewer harmful emissions.

This means that, with such investments, some coal plants can be retired without a need to replace that

electricity capacity, while others could simply be run more cheaply – all of which could mean that

consumers could lower their electricity bills and save money. Research shows that it costs a utility an

average of 2.5 cents per kWh to invest in energy efficiency measures, as compared with 6 to 15 cents

per kWh for new generation sources (Elliott et al., 2011). Twenty four states have adopted EERS and

have already achieved significant energy savings. Recent data show that nine of these states have

achieved energy savings of over 1.5 percent of their electricity sales (Sciortino et al., 2011). Appliance

efficiency standards recently enacted by the Department of Energy will also help consumers save energy

and money on their electric bills. Technologies like combined-heat-and-power (CHP) and waste energy

recovery19 are typically less expensive than investing in pollution control retrofits or building new gas

plants. (Elliott et al., 2011).

19

CHP systems generate heat and electricity together. Heat is always generated as a by-product of electricity generation and these systems capture most of that heat for useful purposes such as heating or for use in industrial processes. Waste heat

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Because current state regulatory policies reward utilities with a return on their investments in new

generation and/or transmission facilities, utilities have historically focused on meeting demand by

building such facilities and selling more power. These incentives need to be changed by elevating the

importance of efficiency and demand-side management (DSM) programs in the resource planning done

by state and regional utility planners and by decoupling utility compensation from kWh sales. State

Implementation Plans (SIPs), which lay out the specifics of how states intend to comply with EPA

standards, should also explicitly include the option of ramping up efficiency and demand management

as one way to reduce pollution from electricity generation while reliably retiring old coal plants.

5. Retrofitting the Existing Coal Fleet with Pollution Controls

Apart from retiring the dirtiest plants, power plant owners will also make the decision to retrofit some

plants when it is economic to do so, especially those that are newer and larger. There are a range of

available pollution control technologies and practices that will help some plants cost-effectively comply

with pollution standards. These include switching to low sulfur coal, investing in plant efficiency

improvements, or installing pollution control technologies such as: combustion controls, wet and dry

scrubbers, selective non-catalytic reduction, selective catalytic reduction, baghouses, electrostatic

precipitators, dry sorbent injection and activated carbon injection (see NESCAUM, 2011 for an

explanation of how these controls work). Some of these controls can serve multiple purposes. For

example, scrubbers, which are often the most expensive kind of pollution control to install, not only

reduce SOx emissions but also help control mercury and particulate matter emissions. See table 2 below

for costs of selected controls.

Table 2: Costs of Selected Air Pollution Controls

Construction Cost ($/KW)

Fixed O&M Cost ($/KW-Yr)

Variable O&M Cost ($/MWH)

Incremental Levelized Cost

($/MWH)

Flue gas desulfurization (FGD or scrubbers)(1)

500 MW plant 100 MW plant (2,3)

282–508 432–790

8.27 23.55

1.84 9.13

7.39–10.9 19.01–24.7

Selective catalytic reduction (SCR)(4)

500 MW plant 100 MW plant (2,5)

133–390 168–550

1.39 1.96

0.54 0.76

2.83–6.85 3.66–9.67

Activated-carbon injection (ACI)(6)

7-10 0.29 0.37 0.52-0.57

ACI and baghouse (7) 150-161 0.74 0.37 2.83-3.00 Source: Freese et al., 2011

O&M = Operations and maintenance All values are in 2010 dollars. (1) Lower scrubber cost from EIA 2010; higher scrubber cost from CRA International 2010. (2) Used linear regression on EIA data to estimate the 100 MW FGD and SCR construction-cost range (low value). Used EPA-IPM model of wet FGD to estimate capital costs for 100 MW (high value) (Sargent and Lundy 2010).

recovery uses a similar rationale to repurpose heat generated as a by-product from a variety of productions processes, e.g. “waste” heat from the process of making steel can be captured and turned into electricity.

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(3) Used EPA-IPM model of wet FGD to estimate O&M costs for 100 MW unit. (4) Lower SCR cost from EIA 2010g; higher SCR cost from NERC 2010. (5) Used CRA International MRN-NEEM equations to estimate construction costs and fixed O&M. Variable O&M costs for 100 MW unit were proportionally adjusted with installed 500 MW capacity (CRA International 2010). (6) Lower ACI cost from CRA International 2010; higher ACI cost from UBS 2010. (7) Lower ACI/baghouse cost from Eggers et al. 2010; higher ACI/baghouse cost from CRA International 2010a. (8) Assumes fixed-charge rate of 11.7 percent consistent with the EIA-NEMS model (personal communication); assumes a capacity factor of 85

percent.

Estimates for the total cost of retrofitting the coal fleet vary depending on assumptions about the

economics of retrofitting versus choosing other alternatives, as well as assumptions about which

pollution standards are included and their level of stringency. One study estimates $30-40 billion to

install scrubbers and SCR on 104 GW of coal (Lapides et al., 2011). A study from the Bipartisan Policy

Center concludes that $14.5 billion will be spent on retrofits in 2015 and $18.1 billion in 2025 to comply

with a suite of air, water and waste standards (Macedonia et al., 2011). Given the significant price tag

for retrofits, and the reality that coal-fired power will continue to face multiple economic challenges

including competition from low cost alternatives and the need to reduce global warming emissions, it

will be important for power plant owners to take a long-term view on whether it makes sense to keep

making these costly investments or instead consider alternatives.

Any rate impacts from the cost of retrofits will depend on whether plants are in regulated or

deregulated states, while any necessary modifications to the transmission system, and their associated

costs, will have to be reviewed and approved by the affected states and by FERC. In general, utilities in

regulated states can claim the capital expenditures from plant retrofits and retirements required for

compliance as recoverable costs; assuming approval by state regulatory commissions, these costs would

be added to the rate base. State PUCs who review and make decisions about these rate increases should

recognize the broader context of the long-term adverse outlook on coal and the availability of other

low-cost alternatives before saddling ratepayers with long-term costs.

Generators in unregulated states would not be able to recover these costs through rate increases (Wynn

et al., 2010). Rather, they would have to raise the capital for retrofits from private financiers – which

would mean convincing those investors that they could recoup the costs by charging higher prices in the

competitive wholesale markets where they sell their electricity. Current indications from Wall Street

make it clear that this is by no means a sure bet. For example, recently Edison Mission Energy

announced that it was unable to raise the financing necessary for pollution control upgrades at its

Homer City plant in Indiana County, PA, a 43-year old facility that is considered one of the dirtiest coal-

fired plants in the nation (Pittsburgh Tribune-Review, 2012). Regardless of the regulatory structure

generators operate under, changes in the composition of the generation fleet could provide an

important way to minimize rate impacts, both through coordinated regional planning and by turning to

options like natural gas, efficiency and low-cost renewables.

The decision to retrofit a plant also has implications for reliability, since plants must often be taken off-

line for several months to complete these retrofits, depending on the number of controls that have to

be installed and other plant-specific considerations. Because a large number of plants across the country

will have to be retro-fitted within the next 5 years, bottlenecks in the supply and installation of pollution

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controls and a shortage of skilled labor required to install these controls could occur. To address any

concerns about the supply of reliable electricity, plant owners, Independent System Operators (ISOs)

and Regional Transmission Operators (RTOs)20, working together with the EPA, the Federal Energy

Regulatory Commission (FERC), the North American Electric Reliability Corporation (NERC) and Regional

Reliability Organizations, need to develop appropriate plans and schedules for taking plants off-line for

retrofits and also coordinate that with planned retirements. This coordination and planning is already

underway in some regions, and all regions should follow EPA’s recommendation to develop these plans

as early as possible.

Of course, the pollution standards have been anticipated for a long time. Forward-thinking companies

already have taken steps to clean up their power plants and prepare for these rules. According to a

recent MJ Bradley report, “Companies representing half of the nation’s coal-fired generating capacity—

11 out of the top 15 largest coal fleet owners in the United States—have indicated that they are well

positioned to comply with EPA’s clean air rules because of early investments in their generating fleets.”

CEOs of companies including Exelon, PSEG, Calpine and Constellation Energy have been outspoken in

their support of the Clean Air Act standards and their ability to comply with them (Wall Street Journal,

2011; Washington Post, 2011).

6. Ensuring Electric System Reliability

There are two broad reasons we can retire coal plants while preserving the reliability of the electric

system: we have a number of low-cost alternatives readily available and we have institutions, systems

and processes in place to handle isolated cases where reliability may be a concern. A number of

independent studies confirm that the impacts of the EPA standards on reliability will be entirely

manageable. According to studies by the U.S. Department of Energy (U.S. DOE, 2011), the Congressional

Research Service (McCarthy and Copeland, 2011), and the Bipartisan Policy Center (Macedonia et al.,

2011), along with leading industry experts, such as MJ Bradley & Associates and the Analysis Group (M.J.

Bradley et al., 2011), and the country’s largest regional transmission organization, PJM Interconnection

(PJM, 2011), the EPA standards will not threaten overall system reliability, and existing planning and

coordination procedures can handle any localized concerns.

In addition, changes to the generating fleet driven in part by EPA standards will take place over a period

of years, thus giving the industry ample time to plan for retirements and retrofits in a manner that

preserves reliability reserve margins (i.e., ensuring that adequate extra generation capacity is standing

ready to meet unexpected or unusual conditions, as per NERC’s reliability rules). A timely, independent

system-by-system analysis can help identify and address any reliability impacts that may occur.

All of this, of course, is on top of the fact that companies have known for years or even decades that

these standards were coming, and many of the best performing power plants are already meeting the 20

ISOs help coordinate and monitor the flow of power so as to balance demand and supply in an electric transmission grid, usually within a state or a few neighboring states. RTOs perform similar functions but across a much larger region. They also operate wholesale electricity markets and ensure that there is back-up generation available at all times to meet demand fluctuations. There are 10 ISOs/RTOs across North America (some operating across international boundaries with Canada and Mexico.

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emissions limits established by the standards. Those “good actor” utilities will benefit when the EPA

standards are fully implemented and they can finally enjoy a level playing field. Moreover, utilities and

investors need the certainty provided by these standards in order to make the long-term investments

necessary for an orderly transition to a cleaner, more efficient electric system

6.1 Coordinated Actions by EPA and Electric Reliability Authorities

The EPA has taken several precautions to ensure that reliability is maintained as the Clean Air Act

standards are implemented. Compliance periods for the standards are reasonable and take full

advantage of existing flexibilities in the Clean Air Act. This allows the industry ample time to comply by

installing existing, cost-effective pollution controls and—as with other EPA rules—allow for case-by-case

extensions where necessary to ensure that reliability is maintained. The regulatory impact analyses

conducted as part of the rulemaking process include detailed modeling of impacts on the electricity

sector and were required to take into account reliability requirements. Along with its release of MATS,

EPA took the additional step of issuing a detailed memo regarding extensions to the compliance period

that will be available, if needed, to maintain reliability (EPA, 2011b). Companies subject to MATS have a

standard three-year compliance period (2012-2015), with a one-year extension (until 2016) that will be

made broadly available. An additional year (until 2017) could be possible, on a case-by-case basis,

through an Administrative Order.

FERC has initiated a process to elicit views from power companies, NERC, ISOs, RTOs, state public utility

commissions (PUCs)21, and others to identify any areas of specific concern related to the impact of the

standards and develop a plan to address them. In early 2012, FERC issued a draft white paper laying out

how it expects to give advice to the EPA on requests for extensions related to maintaining reliability

(FERC, 2012), and launched a joint forum with the National Association of Regulatory Utility

Commissioners (NARUC) to explore reliability issues stemming from the standards. As FERC

Commissioner Philip D. Moeller said in his testimony to the House Committee on Energy and Commerce

on September 14, 2011, “The electric industry can plan to meet whatever EPA regulations become final.

This nation has complied with EPA regulations in the past, and we can do it in the future, given enough

time and information” (Moeller, 2011).

6.2 Ample Reserve Margins

As mentioned previously, current reserve margins in the electric system are high, signaling that the

system has sufficient capacity to handle expected retirements in most areas of the country. A recent

analysis by MJ Bradley & Associates compares NERC’s target reserve margins for different regions of the

country (which range from 12.5 percent to 15 percent) with the projected reserve margins in 2014

(which range from 28 percent to over 40 percent). The comparison shows that the nation has a large

amount of excess generating capacity (over 145 GW nationwide) above the target reserve margins (see

Table 3), and that there is a projected excess in every region of the country as well (M.J. Bradley, 2011).

Of course, individual plant retirements may have localized reliability impacts that will have to be

21

PUCs have oversight over and regulate the prices (rates) of utility services in their states, such as electric power utilities, telecommunications, water etc.

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addressed before those plants can be taken off-line, but the EPA standards provide sufficient flexibility

to avoid negative system impacts.

Table 3: Reserve Margins in the Electric System

NERC Electric Reliability Region Projected Reserve Margin

(1) in 2014

NERC Target Reserve Margin

Cushion Above NERC Target Reserve Margin

(2) in 2014

Texas Reliability Entity (TRE)

31.0%

12.5%

12.5 GW

Florida Reliability Coordinating Council (FRCC)

31.7% 15.0% 7.4 GW

Midwest Reliability Organization (MRO)

28.3% 15.0% 5.5 GW

Northwest Power Coordinating Council (NPCC)

30.1% 15.0% 9.5 GW

Reliability First Council (RFC)

34.0% 15.0% 34.8 GW

SERC Reliability Corporation (SERC)

29.4% 15.0% 30.4 GW

Southwest Power Pool (SPP)

40.3% 13.6% 12.3 GW

Western Electricity Coordinating Council (WECC)

40.2% 14.7% 33.2 GW

Total 145.7 GW 1Includes capacity defined by NERC as Adjusted Potential Reserve Margin, which is the sum of deliverable capacity resources, existing resources,

confidence factor adjusted future resources and conceptual resources, and net provisional transactions minus all derates and net internal

demand expressed as a percent of net internal demand. Source: NERC, 2010 Long-Term Reliability Assessment, October 2010, p. 32 (Summer

Demand).

2Capacity in excess of what is required to maintain NERC Reference Margin or the regional target reserve levels.

Source: MJ Bradley, 2011.

6.3 Planning for a Ramp- Up in Renewable Energy and Efficiency

Renewable energy and energy efficiency can play an important role in helping maintain reliability as coal

plants are retired. While there are considerable challenges in the near-term policy landscape at the

federal and state levels, future success in ramping up the share of renewable energy depends critically

on enabling policies such as a national RES, tax credits, investments in research and development, and

improved processes for planning and siting of transmission projects and paying for them. Carbon pricing

would also provide utilities with an incentive to shift to lower carbon resources like renewables. And, as

noted earlier, SIPs for complying with EPA standards that explicitly include a role for efficiency and

renewable energy could provide further support for these resources.

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In addition, investments in transmission are especially critical for helping to reliably integrate power

from the best-situated wind resources into the grid. Over time, as the penetration rates of variable

renewable resources like wind and solar become much higher, there will be some challenges in

integrating them onto the electric grid, but there are already a number of technological advances that

can help overcome these hurdles. Key solutions include the integration of complementary, flexible

resources and advanced technologies into a transmission system that is robust enough to reliably

balance demand and supply across a wide range of resources. Other solutions include a geographically-

dispersed distribution of wind and solar facilities, larger power market balancing areas, better

meteorological forecasting and improved scheduling of wind and solar power, development of energy

storage technologies, and demand-response measures (MIT, 2011b).

FERC’s recently issued Order 1000 and its other ongoing initiatives provide a potentially important

framework to reliably integrate renewables and demand-side options into the electric system. Order

1000 requires transmission planners to consider state and federal public policies, such as state RES and

EERS, as drivers for transmission development and it requires regions to develop more coordinated

plans for building and allocating costs for new transmission projects. It also requires planners to provide

comparable treatment to alternatives to traditional generation, like efficiency and demand-response

measures, throughout the transmission planning process (FERC, 2011).

State PUCs, ISOs and RTOs should ensure that their planning decisions and deliberations over pollution

control-related rate increases incorporate the new realities about the diminishing role of coal and the

need to ramp up alternatives. In many parts of the country including the Midwest, Texas, the southern

plains, California and the West, there is growing recognition of the benefits of diversifying the

predominantly-coal based electric generating system and investing in natural gas and renewable energy.

For example, the Midwest Independent Transmission System Operator (MISO) is working to promote

the development of a significant amount of new transmission lines that will enable large amounts of

wind generation to access the grid. MISO’s 2011 Transmission Expansion Plan includes sixteen new

“multivalue projects”, or MVPs, which will provide regional reliability, public policy and economic

benefits. These projects will enable the delivery of 41 million MWh of renewable energy, while providing

economic benefits of 1.6 to 2.8 times their costs (MISO 2011b).

7. Conclusion

The long-awaited Clean Air Act power plant standards now being promulgated and implemented by the

EPA can bring tremendous public health, environmental and economic benefits by lessening our

dependence on coal, one of the most polluting sources of energy. Carbon emissions from coal-fired

power plants contribute significantly to the risks of climate change. Harmful pollutants released by

burning coal have been linked to an increase in asthma attacks, heart disease, neurological problems,

and premature deaths. Some industry representatives and members of Congress have greatly

exaggerated the potential reliability and economic concerns related to this positive transformation of

our electric system. The reality is that, for the most part, the standards are expected to have minimal

impact on reliability. Over the next few years, many coal plants will be updated with modern pollution

controls that will reduce their harmful emissions. Those that do retire can be replaced by a number of

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economically competitive, readily available alternatives like natural gas, renewable energy and

efficiency. There are also well-defined processes and procedures in place to identify and respond to the

isolated instances where reliability may be an issue. However, additional policies that explicitly support

the deployment of renewable energy and increased energy efficiency are needed, so that those

resources can complement the role played by natural gas as part of a diversified and affordable clean

energy resource base. Putting such policies in place will help ensure that the full benefit of this

opportunity to modernize and clean up our electric system is realized.

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MIT, 2011 b. The Future of the Electric Grid. An Interdisciplinary MIT Study from the MIT Energy Initiative. Available online at: http://web.mit.edu/mitei/research/studies/the-electric-grid-2011.shtml Moeller, Phillip D. 2011. Testimony before the U.S. House of Representatives Committee on Energy and Commerce Subcommittee on Energy and Power Regarding the Impact of Regulations Proposed by the Environmental Protection Agency (EPA). September 14, 2011. Available online at: http://republicans.energycommerce.house.gov/Media/file/Hearings/Energy/091411/Moeller.pdf Muller, Nicholas Z., Robert Mendelsohn, and William Nordhaus. 2011. "Environmental Accounting for Pollution in the United States Economy." American Economic Review, 101(5): 1649–75. Nadel, Steven. 2006. Energy Efficiency Resource Standards: Experience and Recommendations. ACEEE Report E063. Available online at: http://epa.gov/statelocalclimate/documents/pdf/5_16_06_ACEEE-EEPS.pdf North American Electric Reliability Corporation (NERC). 2010. Special reliability scenario assessment: Resource adequacy impacts of potential U.S. environmental regulations. Princeton, NJ: NERC. Available online at: http://www.nerc.com/files/EPA_Scenario_Final.pdf . Pittsburgh Tribune-Review. 2012. 3 More Power Plants Set to Close in W. Pa. March 1, 2012. Available online at: http://www.pittsburghlive.com/x/pittsburghtrib/business/s_784221.html PJM Interconnection. 2011. Coal Capacity at Risk for Retirement in PJM: Potential Impacts of the Finalized EPA Cross State Air Pollution Rule and Proposed National Emissions Standards for Hazardous Air Pollutants. Available online at: http://www.pjm.com/documents/~/media/documents/reports/20110826-coal-capacity-at-risk-for-retirement.ashx Sargent & Lundy. 2010. IPM model—revisions to cost and performance for APC technologies: Wet FGD cost development methodology. Chicago, IL: Sargent & Lundy, LLC. Available online at http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v410/Appendix51A.pdf . Sciortino, Michael, Seth Nowak, Patti Witte, Dan York and Martin Kushler. 2011. Energy Efficiency Resources Standards: A Progress Report on State Experience. ACEEE. Available online at: http://www.aceee.org/sites/default/files/publications/researchreports/u112.pdf SNL. 2011. Upcoming, recent coal-fired power unit retirements. Available online at: http://www.snl.com/InteractiveX/article.aspx?Id=13340423&KPLT=2 Swisher, Joel N. 2011. The Business Case for Integrating Clean Energy Resources to Replace Coal. A report of the American Clean Skies Foundation. Available online at: http://www.cleanskies.org/wp-content/uploads/2011/06/Swisher-final.pdf Tennessee Valley Authority. 2011. TVA Board Sets Path for Environmental Future. News release. Available online at: http://www.tva.com/news/releases/aprjun11/board_meeting_0414.htm

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Tierney, Sue. 2012. Why Coal Plants Retire: Power Market Fundamentals as of 2012. Analysis Group Inc. Available online at: http://www.analysisgroup.com/uploadedFiles/News_and_Events/News/2012_Tierney_WhyCoalPlantsRetire.pdf UBS. 2010. Clean air regulations: Impact of proposed EPA rules. Scheduled investors’ phone call with ICF International, September 16. U.S. Department of Energy. 2011. Resource Adequacy Implications of Forthcoming EPA Air Quality Regulations. Available online at: http://energy.gov/sites/prod/files/2011%20Air%20Quality%20Regulations%20Report_120111.pdf

Wall Street Journal. 2011. Utilities Have Planned for Years for the 'New' EPA Rule. Letters to the Editor. Available online at: http://online.wsj.com/article/SB10001424052970203501304577084573119094642.html

Washington Post. 2011. EPA finalizes tough new rules on emissions by power plants. Available online at: http://www.washingtonpost.com/national/health-science/epa-finalizes-tough-new-rules-on-emissions-by-power-plants/2011/12/16/gIQAc2WTzO_story.html

Wiser, R. and Bolinger, M. 2011. 2010 Wind Technologies Market Report. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. Available online at: http://www1.eere.energy.gov/wind/pdfs/51783.pdf Wynne, Hugh, Francois D. Broquin and Saurabh Singh. 2010. U.S. Utilities: Coal-Fired Generation Is Squeezed in the Vice of EPA Regulation; Who Wins and Who Loses? Bernstein Research. Available online at: http://207.114.134.6/coal/oh/downloads/bernstein-report.pdf