1 

To: Docket ID EPA-HQ-OAR-2013-0495 

Date: October 31, 2013 

Title: Trends in Structure of Electric Power Sector Limiting Amount of New Coal 

The purpose of this document is to provide additional historical and empirical support for EPA’s 

observations, stated in the proposed rulemaking, “Standards of Performance for Greenhouse Gas 

Emissions from New Stationary Sources: Electric Utility Generating Units” (also referred to as the 

reproposal) that no more than a small amount of new coal-fired electric generation is expected to be 

built, and, in particular, for EPA’s reliance on modeling projections of limited or no construction of such 

generation during certain periods in the future. In particular, this discussion addresses three concerns 

expressed by commenters on the original proposal, 77 Fed. Reg. 22,392 (April 13, 2012) that, in the view 

of the commenters, pointed towards additional construction of new coal-fired electric capacity, – 

through at least 2030: 

• Natural gas prices are extremely volatile and can be expected to remain volatile 

• Forecasts of coal and natural gas prices and coal plant construction have always been proven 

wrong 

• History shows that current market conditions of low gas prices and little or no coal plant 

construction will be followed by high gas prices and renewed construction of coal plants 

In the original proposal and reproposal, EPA addressed the comment in the first bullet by modeling a 

low natural gas supply scenario that failed to show new coal plant construction in the foreseeable future 

even if an unexpected and large upswing occurs in natural gas prices. As noted in the reproposal, 

multiple EPA and non-EPA modeling exercises project that no new coal plants are likely to be built , and 

that these projections are robust against a large range of potential future natural gas prices. 

The comment in the second bullet lacks any compelling evidence to suggest that an alternative forecast

including new coal-fired facilities would somehow be more accurate than the plethora of currently 

informed modeling scenarios that project no new coal-fired facilities being built. Such general criticism 

about the inherent limitations to modeling cuts both ways: for example, forecasts of significant coal 

plant construction in the 1990s were followed by little or no coal plant construction. The discussion in 

this paper illustrates why those prior projections of a coal plant “boom” in the 1990s were mistaken and 

why, in contrast, current projections are more in accord with the structure and trends in the industry

through 2020. 

The comment in the third bullet is the focus of this document. This comment depends on there being a 

sufficient analogy between present market conditions and historical conditions to support the claim that 

a pattern of recurring coal plant construction following periods of low natural gas prices will repeat in 

the near future. EPA believes that a closer examination of historical and current conditions shows that 

there is no basis in history for this comment. This document discusses the historical conditions used to 
2 

support claims of the recurrence of coal plant construction, followed by a discussion of reasons why 

present market conditions differ from the historical market experiences cited by commenters in ways 

that support EPA’s finding that no more than a small amount of new coal-fired generation is likely to be 

built in the foreseeable future. The document also discusses claims that future market conditions, such 

as increased demand for natural gas exports, will cause the construction of new coal plants, and 

demonstrates why these claims are unwarranted.1

A. The Historical Basis for Future Coal Plant Construction Claims 

Commenters frequently cite the volatility of gas prices in criticizing the EPA projections of no new coal 

plants through 2020. These commenters provide data to demonstrate the historical variability of 

natural gas prices. They then argue that the current dearth of new coal plant activity cannot be 

assumed to last through 2020. The argument is based on historical data that show natural gas prices 

were very low during the mid-1990s and led to substantial construction of new natural gas plants and 

historically low levels of new coal plants, only to be followed by dramatic increases in natural gas prices 

and renewed construction of coal plants. The historical coal and gas prices behind these claims are 

shown in Figure 1; the historical pattern of plant capacity construction is shown in Figure 2. 

 

1

 This document presents analysis of the industry and economic trends that underlie the model projections of no 

new coal, but EPA recognizes there remain a limited number of factors outside the scope of these trends that 

could point to a small amount of new coal. Those factors include the desire for fuel diversification and the ability of 

some sources to link electricity generation from coal with the manufacture and sale of coal-derived commodities. 

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

1976 1981 1986 1991 1996 2001 2006 2011

Price in 2012$ / MMBtu

Figure 1. Coal and Natural Gas Prices

1976 - 2012

NG2012$

Coal2012$

Source: Energy Information Administration, Annual Energy Review 2012
3 

As discussed below, the analogy between low natural gas prices in the 1990s and the current natural gas 

market is misleading with respect to conclusions about new coal plant capacity. These historical 

circumstances do not support the return of coal capacity construction in the near term through 2020. 

The period following the low natural gas prices of the mid nineties was followed by an extended period

with little or no new coal plant construction; there was virtually no new coal construction in the 8 years 

between 1995 and 2004. During this eight year period, a total of only 1 GW of coal (125 MW per year 

on average) was built, compared to 190 GW of new natural gas plants. In that sense, the historical 

circumstances cited by commenters actually support EPA’s contention that current trends in power 

markets facing low natural gas prices can be expected to result in no new coal-fired capacity being built 

in the foreseeable future. Even so, EPA believes a closer examination reveals that current circumstances 

differ from this prior period of low natural gas prices in fundamental ways that actually increase 

confidence further in the expectation that limited new coal will be built in the foreseeable future. 

B. Fundamental Changes from the Historical Period of the Mid 1990s 

On closer examination, the historical analogy proves not to be a valid point of comparison with present 

market conditions. The analogy ignores several important factors showing that coal and natural gas 

supply conditions and competition from other generation alternatives have changed fundamentally 

since the mid-1990s, such that the conditions leading to coal plant construction in the recent past will 

not recur between now and 2020. These factors include: 

• Dramatic increases in the natural gas resource have changed the gas supply conditions 

compared to the 1990s 

0.0

10.0

20.0

30.0

40.0

50.0

60.0

1970 1975 1980 1985 1990 1995 2000 2005 2010

GW of Capacity Installed

Figure 2. Initial Operating Year for Existing Coal and Natural Gas Capacity

Coal_GW

NG_GW

Source: Energy Information Administration, Form 860.
4 

• Coal supply costs are significantly higher: coal productivity has been declining and is not 

likely to improve. 

• Price volatility is manageable and applies to coal as well as natural gas; consequently, 

natural gas price volatility will not form the basis for additional new coal plants. 

• Planning will be based on expected returns over longer periods (as opposed to shorter 

periods subject to relatively higher fuel price volatility) that show no reason for a return 

to coal under current conditions 

• Increasing competition from alternative sources 

o Increasing efficiency of combined cycle technology 

o Renewable resources 

o Conservation and demand response 

Each of these topics is discussed further in the sections below. 

1. Dramatic increases in the natural gas resource base

At first glance, there are apparent similarities between the forecasts of current natural gas prices and 

forecasts made in the 1990s, in the sense that projections in both periods are based on assumptions 

about continued improvements in natural gas extraction technology. In the 1990s, however, such 

projections assumed a continued ability to extract natural gas at then-current prices through horizontal 

drilling and other improvements. These developments increased the ability to add natural gas reserves

from existing resources and arrested a decline in total resources (See Figure 3); however, unlike current 

additions to resources from shale development, they did not add significantly to the recoverable natural 

gas resource base. While significant potential nonconventional resources, including shale gas, were 

known to exist, there was not a sufficient basis at the time using known production technology for 

calculating significant additions to gas reserves or to technically recoverable natural gas resources. 

These calculations have dramatically changed with the recently developed technical ability to recover 

natural gas shale resources in an economically attractive manner. It is these additions from shale 

resources that mark the shift from the development of reserves in the 1990s to the current increases to 

total natural gas resources. 

Although there are disagreements about the absolute level of recoverable natural gas resources and 

about the cost of extraction, all sources agree that there has been a substantial increase in natural gas 

shale resources that can be brought into the marketplace. Different researchers characterize the 

resource base in different ways, so comparisons across sources are difficult, but examining the internally 

consistent history of resources assessments performed by each researcher reveals how significant these

new additions to the resource base are compared to the additions during the period when natural gas 
prices were low in the 1990s. Figure 3 shows the series of estimates from the Potential Gas Comm

In these estimates, resources classified as “probable” have increase

cubic feet (Tcf) in the 1990s to around 500 Tcf today, while resources classified as 

“possible” have increased from approximately 

Resources assumed in the Annual Energy Outlook, shown in Figure 4

assume different levels from other 

the total recoverable resource in the Annual Energy Outlook 

in the 1990s to around 1,900 Tcf today, 

in the 1990s to around 275 Tcf today.

Figure 3. Natural Gas Resource (Potential Gas Committee)

 

2

 See http://potentialgas.org/biennial-report

group that has reported assessments of natural gas resources since 1964.

3

Source: Energy Information Administration, Annual Energy Outlook, 1990 to 2012, recoverable resources and 

proved reserves assumptions in the reference case for each year.

5 

prices were low in the 1990s. Figure 3 shows the series of estimates from the Potential Gas Comm

In these estimates, resources classified as “probable” have increased from a level around 200 

in the 1990s to around 500 Tcf today, while resources classified as “probable” or 

from approximately 400 Tcf in the 1990s to around 1,100 Tcf today. 

Resources assumed in the Annual Energy Outlook, shown in Figure 43, are classified differently and 

assume different levels from other data sources, but they show a similar pattern. As shown in Figure 4

in the Annual Energy Outlook has increased from approximately 1

today, while natural gas reserves have increased from around 170 Tcf 

in the 1990s to around 275 Tcf today.

ral Gas Resource (Potential Gas Committee)

report, Chapter 21. The Potential Gas Committee is a natural gas industry 

ssments of natural gas resources since 1964.

Source: Energy Information Administration, Annual Energy Outlook, 1990 to 2012, recoverable resources and 

proved reserves assumptions in the reference case for each year.

prices were low in the 1990s. Figure 3 shows the series of estimates from the Potential Gas Committee.2 

from a level around 200 trillion 

“probable” or 

400 Tcf in the 1990s to around 1,100 Tcf today. 

, are classified differently and 

As shown in Figure 4, 

has increased from approximately 1,000 Tcf 

natural gas reserves have increased from around 170 Tcf 

, Chapter 21. The Potential Gas Committee is a natural gas industry 

Source: Energy Information Administration, Annual Energy Outlook, 1990 to 2012, recoverable resources and 
6 

These increases in the natural gas resource base have led to fundamental changes in the outlook for 

natural gas. As noted above, while sources may disagree on the absolute level of increases from shale

resources, there is general agreement recoverable natural gas resources will be substantially higher for 

the foreseeable future, and will exert downward pressure on natural gas prices. EPA modeling for the 

rule incorporates the impact of these resources in the forecasts of the price of natural gas used by 

electric generating units. These changes are also reflected in current natural gas prices, in standard 

forecasts such as the Annual Energy Outlook, and in current capacity planning by utilities and electricity 

producers across the country. The impact on utility planning is shown as increased natural gas capacity 

and decreased coal capacity in NERC long term reliability assessments. These NERC assessments are 

based on utility plans for capacity over a 10-year period. For example, the 2009 assessment showed a 

10-year increase of 18 GW in coal capacity from 2009 to 2018, while the 2012 assessment showed a 29 

GW decrease in coal capacity over the same period.4 The corresponding data for natural gas show a 10-

year increase in the 2009 assessment of 106 GW from 2009 to 2018 and an even greater increase in the 

2012 assessment of 129GW. 

The expected continuation of low natural gas prices is also a major reason for the cancellation or 

suspension of development activity of planned coal plants that appeared economic to their developers 

only a few years ago; when coupled with other factors discussed in this document, low projected gas 

 

4

 NERC, Long-Term Reliability Assessments for 2009 (Table 5) and 2012 (Figure 51). Capacity includes both 

planned and conceptual resources as defined by NERC. 

50.00

100.00

150.00

200.00

250.00

300.00

500

700

900

1,100

1,300

1,500

1,700

1,900

2,100

2,300

2,500

1990 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Proved Natural Gas Reserves

Total Natural Gas Resources (Trillion Cubic Feet)

Figure 4. Natural Gas Resources in EIA Annual Energy Outlook

1996 - 2012

Total Recoverable Resource

Proved Reserves

Source: Energy Infomation Administration, Annual Energy Outlook.

Note: 1990 was used as the base year for AEO 1996-98
7 

prices tend to make proposed coal plants uneconomic. Table 1 shows 30 coal plants and 20 GW of 

previously planned coal capacity that are no longer expected to be built as coal plants in the foreseeable 

future. These data reinforce the indications of weak fundamentals for coal discussed in this document, 

showing that the weakness is driven by not merely current market prices but also the longer term 

market and resource outlook. Further, the cancellations and suspensions are dispersed across the US, 

showing that the poor prospects for coal are driven by broad economic and engineering factors that are

not limited to any one region. (While EPA believes none of the listed projects is still an active coal 

project, some have been converted to gas projects and may remain under development in that altered 

form.)Table 1. Summary of Proposed New Coal-Fired EGU (Continental U.S.) no Longer Under Active 

Development 

Station, Plant, Project Name State MW 

Beech Hollow Power Project PA 250

Black Stallion Energy Center KY 660

Bonanza UT 86

Buick Power Project (Limon Power Plant 

Project) 

CO 500

Carmi Minemouth (United Supply of America) IL 270

Cash Creek KY 761

Coleto Creek TX 660

Colorado IGCC CO 600

Cypress Creek Power Station VA 1,500

Desert Rock Power Plant NM 1,500

De Young MI 78

Ely Energy Center NV 1,500

Good Spring PA 600

J K Smith KY 278

Jamestown Clean Coal Project NY 50

Las Brisas TX 1,320

Lawrence Energy Center OH 600

Limestone TX 800

Lockwood IGCC Power Plant TX 1,200

M&M Energy Great Lakes Energy Plant MI 750

Mesaba MN 1,200

PurGen One NJ 400

SCE IGCC – Green River UT 500

Sevier Power Project UT 270

Taylorville IL 630

Trailblazer TX 765

University of Missouri, Columbia MO 40

Wallula Energy Resource Center WA 915

White Stallion TX 1,200
8 

Note: Excludes non-EGUs and completed projects 

2. Coal supply cost increases 

Figure 1 shows that coal prices declined through the 1980s and 1990s until around 2000, and have been

increasing since then. The prior decline results from a number of factors, including replacement of 

higher-cost coal from eastern coal regions by lower-cost coal from western supply regions and 

reductions in the cost of coal transportation. Another major factor in these declining coal supply prices 

was the increasing productivity of coal production, an increase that was common to both eastern and 

western coal mining areas as shown in Figure 5. Productivity peaked around the year 2000 for both 

underground and surface mines, but productivity has decreased for both types of mining since then. 

The productivity decline closely parallels increasing coal prices. A major component of this productivity 

decline is the need to mine coal under less favorable conditions, such as greater overburden ratios in

surface mines, thinner or deeper seams in underground mines, and fewer coal reserves with higher 

quality. None of these factors are expected to be reversed in the foreseeable future, if ever.5 As Figure 

4 shows, the prior increase in coal mine productivity occurred gradually over a 20-year period, and the 

decline since 2000 is happening at a similarly gradual rate. This trend in deteriorating coal mine 

productivity and increasing coal prices plays a substantial role in current and foreseeable planning 

decisions that have downgraded the economic attractiveness of new coal capacity. 

 

5

 In the 2012 AEO, EIA projects continued “higher stripping ratios and added labor needed to maintain more 

extensive underground mines”. For analysis of prior long period of mining productivity decline, see “A Case Study 

of Decline in Labor Productivity, Underground Coal Mining Industry, 1960 – 1976”, Libby Rittenburg and Ernest 

Manuel Jr., Quarterly Journal of Business and Economics, Vol 25, No. 1 (Winter 1986), pp 38-55 and “Sources of 

Labor Productivity Variation in US Surface Coal Mining Industry, 1960 – 1976,” The Energy Journal, Vol 8, No. 1 

(1987), pp 87-100. 
9 

3. Natural gas and coal prices, volatility, and methods for management 

Price volatility is generally a shorter-term concept, but comments on the impact of volatility often 

confuse this short-term concept with longer-term variations in the price of gas. (The issue of longerterm prices used for planning purposes is discussed in the next section.) The claim that volatile natural 

gas prices justify a “need” for development of new coal capacity may be predicated on assumptions of 

historic business practices under less liberalized energy markets, and ignore the current ability to 

manage short-term price volatility through hedging and other financial instruments. Full deregulation of 

the wellhead natural gas supply did not occur until the late 1980s; markets for delivered natural gas 

were maturing throughout the 1990s and the ability to manage volatile prices was not as well developed

then as it is today. During the 1990s, natural gas futures contracts for delivery to the Henry Hub 

(located in Louisiana at the intersection of multiple pipelines) became very actively traded on the New 

York Mercantile Exchange (NYMEX). Trade in these futures contract has developed substantially since 

then and are now well developed with a long history. Futures prices for natural gas are now listed for 

up to 10 years and are typically actively traded for shorter periods (up to 3 years. The Henry Hub futures 

price is used as a basis for trading natural gas prices; prices at different locations (e.g., Chicago citygate 

price) are typically cited in terms of differences from the price at the Henry Hub. 

Concerns about the potential for exposure to extremely high natural gas prices ignore two factors: first, 

most of these periods of volatility are quite short and, as noted above, can be managed through futures 

markets and hedging strategies; second, coal prices are also subject to a degree of volatility that 

sometimes tracks with natural gas volatility. Both of these conditions are illustrated in Figures 6 and 7. 

Figure 6 shows the series of futures prices for natural gas and coal on the NYMEX exchange. The first

period of high prices resulted from the impact of hurricanes Katrina and Rita and lasted from August of 

2005 until December of that year; as the Figure shows, that period of volatility in natural gas prices had 

0

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1

1.5

2

2.5

3

3.5

4

4.5

0

2

4

6

8

10

12

1980 1985 1990 1995 2000 2005 2010

Short Tons per Employee Hour

Figure 5. Coal Mine Productivity, 1980 - 2011

Surface Mines Underground Mines

Source: Energy Infformation Administration, Annual Energy Review 2011 --
10 

no corresponding volatility in coal prices. The second period of high prices occurred in 2008 when both 

natural gas and coal exhibited significant volatility – each more than doubled within approximately a 12-

month period -- driven by broader conditions in commodity markets experiencing turbulence just prior 

to the start of the recession (this pattern is clearer in Figure 7). The point of this comparison is that coal 

also carries commodity risk, even if somewhat less than natural gas. But what is more important is that 

the commodity risk of natural gas (like that of coal) occurs over a short enough time period that it can be 

managed. For all these reasons, any short run differences in price volatility between natural gas and

coal should not be seen as reasons for believing that continued investment in new coal plants will be 

necessary. 

Potential new natural gas export demand for LNG is also cited as a factor that could drive increased 

natural gas price and render new coal plants economic. However, a recent report by NERA Economic 

Consulting for the Department of Energy, Office of Fossil Energy, found that domestic natural gas prices 

would remain below $5.50/MMBtu through 2025 under scenarios with LNG exports, prices that are not 

sufficient to trigger the development of new coal plants.6

 These prices are in line with studies by 

Navigant 7and Deloit MarketPoint8 that have reached similar conclusions regarding LNG exports. 

 

6 Macroeconomic Impacts of LNG Exports from the United States, NERA Economic Consulting, December 2012. 

7

Southern LNG Export Project Market Analysis Study, Navigant Consulting, August 2012. 

8

Economic Impact of LNG Exports From the United States, August 2012. 

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$10.00

$15.00

$20.00

Apr-03 Apr-04 Apr-05 Apr-06 Apr-07 Apr-08 Apr-09 Apr-10 Apr-11 Apr-12

Near Month Futures Price 

($/MMBtu)

Figure 6. NYMEX Daily Near Month Natural Gas and Coal Prices

2003-2013

Coal_Btu

HH_NG_Price

Source: NYMEX, Ventx Velocity Suite
11 

 

4. Planning is based on expected returns over longer periods: the ten-year historic average NG 

remains below $6 (2007$) for all years from 1990 to 2012. 

As discussed above, there is an active futures market for natural gas that provides financial instruments 

so that annual variations in natural gas prices can be effectively hedged against short-run volatility; this 

market posts prices for up to ten years into the future and is highly liquid for at least three years. Power 

plant developers and owners are highly sophisticated in the use of these financial instruments. 

Consequently, short-term volatility in natural gas prices, frequently cited as a reason why natural gas 

cannot always replace coal in electric generation is not an issue that will cause development of new coal 

plants. 

Moreover, new power plants have asset lives measured in decades, not in months or years, and new 

capacity investment decisions are based on long-run expected prices, not on month-to-month variations 

in fuel prices. Shorter-term prices will affect how units are dispatched, but this dispatch impact is

unlikely to affect the long-run choice of natural gas over coal, because it is generally small when 

considered over a longer time horizon, and is typically hedged and factored into the choice of what type 

of plant to build. 

Typical power plant planning will reflect a longer term planning horizon. For example, a recent survey of 

the 26 states with some form of Integrated Resource Planning requirement found that mandated 

requirements for the planning horizon were up to 20 years, with a minimum of 10 years.9

 When the 

historical data are averaged over a longer period of years to be more representative of price 

assumptions typically used for planning power plant investments, they show that long-run natural gas 

prices are well below the periodic short-run price spikes experienced over the last decade. See Figure 8 

 

9

 “A Brief Survey of State Integrated Resource Planning Rules and Requirements,”, Rachel Wilson and Paul 

Peterson, Synapse Energy Economics, April 28, 2011.

0

100

200

300

400

500

600

Apr-03 Apr-04 Apr-05 Apr-06 Apr-07 Apr-08 Apr-09 Apr-10 Apr-11 Apr-12

Price Index (April 2003=100)

Figure 7. Coal and Natural Gas Prices Indexed to April 2003

2003-2013

CoalIndx

GasIndx

Source: NYMEX, Ventx Velocity Suite
12 

for a comparison of annual and 10-year average natural gas prices for the prior 10 years. Since 1990, 

the 10-year average natural gas price has not exceeded $5.60 per million cubic feet (Mcf) (in 2007 

dollars) – and this maximum 10-year price occurred under highly unusual circumstances in 2009, after 

recent prices had been inflated by two hurricanes wreaking unprecedented destruction on the country’s 

energy infrastructure and by an unsustainable global commodity bubble. This longer-term measure of 

natural gas fuel price is far more appropriate for new capacity planning than the short-run volatility

potential cited by commenters, and it is similar to the simulation and projection of fuel markets in 

power sector modeling conducted by both EPA and electricity producers considering new capacity 

investments. The modeling in the proposal’s RIA considered scenarios with equilibrium natural gas 

prices reaching up to $7.96 (in 2007 dollars) in 2020 (notably higher than the maximum $5.60 10-year 

price in observable market data since 1990) and still found no new coal plants projected to be built. 

In practice, planning is based on expectations of the future, whereas the data in Figure 8 are historical 

data from actual prior periods. When renewed planning for coal plants began in the early 2000s, few 

planners were expecting the recession, the technological advancement in shale gas production, or the 

extent of the decline in coal productivity of the last few years. As a result, coal appeared much more 

economically attractive than subsequent history has demonstrated. The 10-year average price of 

natural gas had doubled from 1997 to 2006; even if planners had assumed that temporary trend in rising

natural gas prices to slow significantly, assumptions of unabated electricity demand growth and 

improving coal productivity (both since proven wrong) led many planners to deem that new coal plant 

investment remained economic. 
13 

5. Increasing competition from alternative sources 

There are other market conditions that differ from history and will tend to reduce the likelihood of 

construction of new coal plants. One source of competition is increasing efficient combined cycle 

technology compared to the current technology assumed in forecasts. In addition, competition from 

natural gas is not the only alternative to renewed coal construction; other technologies have recently

become much more viable alternatives, including renewable sources. Leading competitive alternatives 

to coal are discussed below. 

a. More Efficient Natural Gas Combined Cycle 

The efficiency of natural gas combined cycle technology is expected to continue to improve. Natural gas 

combined cycle efficiencies are presently improving and will continue to decrease the cost of generation 

from natural gas. For example, the existing U.S. combined cycle EGU fleet uses primarily Frame E and F 

gas turbines, with advertised net efficiencies (high heating value basis) ranging from 45% to 52%, 

whereas combined cycles using more recently available Frame G and H gas turbines have advertised 

efficiencies up to 54%. These higher efficiency combined cycle units are larger and somewhat more 

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$2.00

$3.00

$4.00

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$9.00

1990 1995 2000 2005 2010

Average 2007$/Mcf for Previous Years

Figure 8. Henry Hub Prices 1990 - 2012

Average Annual and 10 Years

10-Yr

Annual 

Average

Source: Energy Information Administration
14 

capital intensive, but these units become economic at the base load capacity factors that many 

combined cycle units are now experiencing in the dispatch order. 

b. Renewables 

Renewable energy technologies have demonstrated improvements in performance and costs over the 

years, making them a viable option to fossil fuel generation. Technologies such as wind turbines and 

photovoltaics are now significantly more efficient and cost-competitive than they were even a few years 

ago. The data below shows the gains in renewable technologies that have led to their growing capacity 

and market penetration in the United States. These technologies are still maturing and performance and

cost improvement trends are expected to continue in coming years. 

Wind 

Capacity factors for wind turbines have been increasing steadily. Prior to 2000, wind turbines had an 

average capacity factor of less than 22 percent. For projects installed in 2003-2004, capacity factors

increased to 33 percent and then increased even further to 37 percent for projects installed in 2005. 

Higher capacity factors reduce the energy costs and help to offset higher capital costs of wind. 

Improvements in wind turbine technology have reduced cost of energy from $450/MWh in 1980 to 

about $70/MWh in 2007. As shown in Figure 9, historical costs continue to decrease and future capacity

factor improvements are likely to drive the cost of energy even lower, even if capital costs stay the 

same.10

Figure 9. Historical Cost of Wind Energy 

Source: NREL cost curve in Black & Veatch report, October 2007 

 

10 Black & Veatch for American Wind Energy Association. 20 Percent Wind Energy Penetration in the United States. 

October 2007. http://www.20percentwind.org/Black_Veatch_20_Percent_Report.pdf 
15 

According to Black & Veatch research, capacity factors for wind turbines have averaged 15 percent 

improvement every two years. Average hub heights increased from around 60 meters in 2000-2001 to 

85 meters in 2005 and rotor diameters increased from 47 meters to 80-90 meters, doubling swept area. 

Table 2. Onshore Wind Cost and Performance ($2006)

Resource 

Class

Install 

Year

Capacity 

Factor 

(%)

Overnight 

Capital 

Cost 

($/kW)

Variable 

O&M 

($/MWh)

Levelized 

Costs w/o 

PTC 

($/MWh)

Levelized 

Costs 

w/PTC 

($/MWh)

3 2005 32 1650 7.0 94 71 

3 2010 35 1650 5.5 86 63 

3 2015 36 1609 5.0 80 57 

3 2020 38 1568 4.6 76 53 

4 2005 36 1650 7.0 85 62 

4 2010 39 1650 5.5 77 54 

4 2015 41 1609 5.0 72 49 

4 2020 42 1568 4.6 68 45 

5 2005 40 1650 7.0 78 55 

5 2010 43 1650 5.5 71 48 

5 2015 44 1609 5.0 67 44 

5 2020 45 1568 4.6 64 41 

6 2005 44 1650 7.0 72 49 

6 2010 46 1650 5.5 67 44 

6 2015 47 1609 5.0 63 40 

6 2020 48 1568 4.6 60 37 

7 2005 47 1650 7.0 67 44 

7 2010 50 1650 5.5 62 39 

7 2015 51 1609 5.0 59 36 

7 2020 52 1568 4.6 56 33 

 Source: Black & Veatch report, October 2007

These improvements are having a significant impact on generation. A new turbine with a nameplate 

capacity seven times greater than a typical turbine in 1990 can produce 15 times more electricity. A US 

Department of Energy report found that the area of land that can support 35 percent plus capacity 

factors has increased by 130-270 percent since 2002-2003 due to these technological advances such as 

higher towers able to utilize stronger wind resources. DOE also reports that wind turbine prices have 

decreased by as much as one-third or more between 2008 and 2010. 

Table 3. Increase in Output of Typical Wind Turbine Over Time 

Year Generation 

1990 250kW 

1995 500kW 

2000 660kW 

2005 1.5MW 

2011 1.97MW 

Source: AWEA 
16 

In addition, the supply chain for wind turbines has become more efficient as installed capacity grows.

More efficient US-based manufacturing is saving on transportation costs. Prior to 2005, domestic 

content of US-installed turbines was only 25 percent compared to 60 percent in recent years.11 

Photovoltaics (PV) 

The cost for photovoltaics has also been declining over time as the technology improves. PV modules 

have declined in price by roughly 20 percent for every doubling of cumulative global production. In 

dollar terms, this means that prices have dropped by 95 percent from about $60/Watt to $2/Watt 

between 1976 and 2010. Economies of scale, technology, and manufacturing improvements have all 

contributed to the significant cost reductions.12

 Figure 10. Photovoltaic Prices over Time 

Installed prices of residential and commercial PV systems in the US declined by 5-7 percent per year, on 

average, from 1998-2011 and by 11-14 percent from 2010-2011 and further declines are expected. 

 

11 Wind Power Outlook 2012. American Wind Energy Association. 

http://awea.org/_cs_upload/newsroom/16582_1.pdf 

12 SunShot Vision Study. US Department of Energy. February 2012. 

http://www1.eere.energy.gov/solar/pdfs/47927_chapter4.pdf 
17 

Analysis for systems quoted in Q4 2011 (and installed in 2012) yields installed prices of $4.39/W for 5.1-

kW residential systems, $3.43/W for 221-kW commercial rooftop systems, and $2.79/W for 191.5-MW 

fixed-tilt utility-scale systems, corresponding to a 25–29 percent year-over-year reduction compared to 

Q4 2010 benchmarks. A recent DOE analysis estimated that the global module average selling price will 

decline from $1.37/W in 2011 to approximately $0.74/W by 2013 and that the price of inverters that 

change direct current to alternating current will also decline over this period. Analyst projections do not 

exist for balance of system (BOS) costs; however, the fact that PV system prices are substantially lower 

in Germany than in the United States, despite having similar module and inverter prices, suggests that

substantial BOS cost reductions are possible for US systems as well.13

There is limited data available for utility scale PV systems at this time. As a rough measure of this 

trend, the capacity-weighted average installed price declined from $6.21/W for projects installed 

during 2004–2008 to $3.94/W for projects installed during 2009–2010, and to $3.42/W for projects 

installed in 2011.14 These installations are able to benefit from economies of scale in purchasing and 

labor which result in a lower installed price. 

c. Energy Efficiency and Demand Response 

Several factors have contributed to the steady, long-term trend of lower and lower growth rates in 

electricity demand since the middle of the last century and before. These factors will continue to limit 

growth to historically low levels and they have the potential to lead to even lower growth rates than 

those projected in the EPA base case forecast for the rule (AEO 2010). These trends are shown clearly in 

Figure 11. 

Key continuing drivers of this trend include: structural changes in the U.S. economy (e.g., growth in 

service sector relative to manufacturing sector; effective policies to support increased energy efficiency 

investment (e.g., ratepayer-funded energy efficiency programs, building codes, and appliance 

standards); and policy support and new technology leading to development and growth of demand 

response as a resource. 

 

 

13 Balance of system costs are non-hardware costs, often referred to as “business process” or “soft costs.” These 

costs include permitting and commissioning, overhead, installation labor, and financing. Opportunities for cost 

reductions for these processes may be significant. http://www.nrel.gov/docs/fy13osti/56806.pdf 

14 Photovoltaic (PV) Pricing Trends: Historical, Recent, and Near-Term Projections. U.S. Department of Energy 

November 2012. http://www.nrel.gov/docs/fy13osti/56776.pdf 

 
18 

 Figure 11. U.S. Electricity Demand, 1950 – 1940 

Source: Energy Information Administration, historical data through 2011 and projected data from the 

Annual Energy Outlook 2013. 

-2%

0%

2%

4%

6%

8%

10%

12%

14%

1950 1960 1970 1980 1990 2000 2010 2020 2030 2040

Percent Change, 3-year Moving Average