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 addition al 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 Uti lity 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 mo deling projections of limited or no construction of such generation during certain periods in the future. I n particular, this discussion addresses three conce rns expressed by commenters on the original proposal, 7 7 Fed. Reg. 22,392 (April 13, 2012) that, in the vi ew of the commenters, pointed towards additional const ruction of new coal-fired electric capacity, – through at least 2030:

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

• Forecasts of coal and natural gas prices and coal p lant 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 an d renewed construction of coal plants
In the original proposal and reproposal, EPA addres sed 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 fut ure even if an unexpected and large upswing occurs in n atural 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 , a nd that these projections are robust against a large r ange of potential future natural gas prices.
The comment in the second bullet lacks any compelli ng evidence to suggest that an alternative forecast including new coal-fired facilities would somehow b e more accurate than the plethora of currently informed modeling scenarios that project no new coa l-fired facilities being built. Such general criti cism about the inherent limitations to modeling cuts bot h ways: for example, forecasts of significant coal plant construction in the 1990s were followed by li ttle 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 a nd why, in contrast, current projections are more in a ccord with the structure and trends in the industry through 2020.

The comment in the third bullet is the focus of thi s document. This comment depends on there being a sufficient analogy between present market condition s and historical conditions to support the claim th at a pattern of recurring coal plant construction foll owing periods of low natural gas prices will repeat in the near future. EPA believes that a closer examin ation of historical and current conditions shows th at there is no basis in history for this comment. Thi s document discusses the historical conditions used to2

support claims of the recurrence of coal plant cons truction, followed by a discussion of reasons why present market conditions differ from the historica l market experiences cited by commenters in ways that support EPA’s finding that no more than a smal l amount of new coal-fired generation is likely to be built in the foreseeable future. The document also discusses claims that future market conditions, su ch as increased demand for natural gas exports, will c ause the construction of new coal plants, and demonstrates why these claims are unwarranted. 1

A. The Historical Basis for Future Coal Plant Construc tion Claims
Commenters frequently cite the volatility of gas pr ices in criticizing the EPA projections of no new c oal plants through 2020. These commenters provide data to demonstrate the historical variability of natural gas prices. They then argue that the curre nt dearth of new coal plant activity cannot be assumed to last through 2020. The argument is base d on historical data that show natural gas prices were very low during the mid-1990s and led to subst antial construction of new natural gas plants and historically low levels of new coal plants, only to be followed by dramatic increases in natural gas p rices and renewed construction of coal plants. The histo rical 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 an d economic trends that underlie the model projectio ns of no new coal, but EPA recognizes there remain a limited number of factors outside the scope of these trend s that could point to a small amount of new coal. Those fa ctors include the desire for fuel diversification a nd the ability of some sources to link electricity generation from co al with the manufacture and sale of coal-derived co mmodities.

$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 2011Price in 2012$ / MMBtu 

## Figure 1. Coal and Natural Gas Prices 1976 - 2012
NG2012$ Coal2012$

Source: Energy Information Administration, Annual En ergy Review 20123

As discussed below, the analogy between low natural gas prices in the 1990s and the current natural ga s market is misleading with respect to conclusions ab out new coal plant capacity. These historical circumstances do not support the return of coal cap acity 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; ther e was virtually no new coal construction in the 8 y ears between 1995 and 2004. During this eight year peri od, a total of only 1 GW of coal (125 MW per year on average) was built, compared to 190 GW of new na tural 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 expect ed to result in no new coal-fired capacity being bu ilt in the foreseeable future. Even so, EPA believes a closer examination reveals that current circumstan ces differ from this prior period of low natural gas pr ices 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 prove s not to be a valid point of comparison with presen t market conditions. The analogy ignores several imp ortant factors showing that coal and natural gas supply conditions and competition from other genera tion alternatives have changed fundamentally since the mid-1990s, such that the conditions leadi ng to coal plant construction in the recent past wi ll not recur between now and 2020. These factors incl ude:

• 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 2010GW 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 pr oductivity 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 basi s for additional new coal plants.

• Planning will be based on expected returns over lon ger periods (as opposed to shorter periods subject to relatively higher fuel price vol atility) 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 se ctions below.

1. Dramatic increases in the natural gas resource base

At first glance, there are apparent similarities be tween the forecasts of current natural gas prices a nd forecasts made in the 1990s, in the sense that proj ections in both periods are based on assumptions about continued improvements in natural gas extract ion technology. In the 1990s, however, such projections assumed a continued ability to extract natural gas at then-current prices through horizont al drilling and other improvements. These development s increased the ability to add natural gas reserves from existing resources and arrested a decline in t otal resources (See Figure 3); however, unlike curr ent additions to resources from shale development, they did not add significantly to the recoverable natur al gas resource base. While significant potential no nconventional 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 o r to technically recoverable natural gas resources. These calculations have dramatically changed with t he recently developed technical ability to recover natural gas shale resources in an economically attr active manner. It is these additions from shale resources that mark the shift from the development of reserves in the 1990s to the current increases t o 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 tha t there has been a substantial increase in natural gas shale resources that can be brought into the market place. Different researchers characterize the resource base in different ways, so comparisons acr oss sources are difficult, but examining the intern ally consistent history of resources assessments perform ed by each researcher reveals how significant these new additions to the resource base are compared to the additions during the period when natural gasprices were low in the 1990s. Figure 3 shows the s eries of estimates from the Potential Gas Comm

In these estimates, resources classified as “probab le” have increase cubic feet (Tcf) in the 1990s to around 500 Tcf today, while resourc es classified as “possible” have increased from approximately Resources assumed in the Annual Energy Outlook, sho wn 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. Natu ral Gas Resource (Potential Gas Committee)

2 See http://potentialgas.org/biennial- report group that has reported asse ssments of natural gas resources since 1964.
3 Source: Energy Information Administration, Annual E nergy Outlook, 1990 to 2012, recoverable resources and proved reserves assumptions in the reference case f or each year.

5 prices were low in the 1990s. Figure 3 shows the s eries of estimates from the Potential Gas Comm In these estimates, resources classified as “probab le” have increase d from a level around 200

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

from approximately 400 Tcf in the 1990s to around 1,100 Tcf today. Resources assumed in the Annual Energy Outlook, sho wn in Figure 4 3 , 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 nat ural gas industry ssments of natural gas resources since 1964. Source: Energy Information Administration, Annual E nergy Outlook, 1990 to 2012, recoverable resources and proved reserves assumptions in the reference case f or each year. prices were low in the 1990s. Figure 3 shows the s eries of estimates from the Potential Gas Comm ittee. 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 nat ural gas industry

Source: Energy Information Administration, Annual E nergy Outlook, 1990 to 2012, recoverable resources and6

These increases in the natural gas resource base ha ve led to fundamental changes in the outlook for natural gas. As noted above, while sources may dis agree on the absolute level of increases from shale resources, there is general agreement recoverable n atural gas resources will be substantially higher f or the foreseeable future, and will exert downward pre ssure 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 standar d forecasts such as the Annual Energy Outlook, and in current capacity planning by utilities and electri city producers across the country. The impact on utility planning is shown as increased natural gas capacit y and decreased coal capacity in NERC long term relia bility 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 20 09 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 facto rs 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 2012Proved Natural Gas ReservesTotal Natural Gas Resources (Trillion Cubic Feet) 

### Figure 4. Natural Gas Resources in EIA Annual Ener gy Outlook 1996 - 2012

Total Recoverable Resource Proved Reserves

Source: Energy Infomation Administration, Annual Ene rgy Outlook. Note: 1990 was used as the base year for AEO 1996-9 87

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 foresee able future. These data reinforce the indications of we ak fundamentals for coal discussed in this document , showing that the weakness is driven by not merely c urrent market prices but also the longer term market and resource outlook. Further, the cancel lations 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 believe s none of the listed projects is still an active co al project, some have been converted to gas projects a nd 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 1,2008

Note: Excludes non-EGUs and completed projects

2. Coal supply cost increases

Figure 1 shows that coal prices declined through t he 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. Ano ther major factor in these declining coal supply pr ices 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. Pr oductivity 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 increasi ng coal prices. A major component of this producti vity decline is the need to mine coal under less favorab le conditions, such as greater overburden ratios in surface mines, thinner or deeper seams in undergrou nd 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 productivi ty occurred gradually over a 20-year period, and th e decline since 2000 is happening at a similarly grad ual rate. This trend in deteriorating coal mine productivity and increasing coal prices plays a sub stantial role in current and foreseeable planning decisions that have downgraded the economic attract iveness 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 prio r 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 Econo mics, Vol 25, No. 1 (Winter 1986), pp 38-55 and “So urces of Labor Productivity Variation in US Surface Coal Mini ng Industry, 1960 – 1976,” The Energy Journal, Vol 8 , No. 1 (1987), pp 87-100.9

3. Natural gas and coal prices, volatility, and me thods for management

Price volatility is generally a shorter-term concep t, but comments on the impact of volatility often confuse this short-term concept with longer-term va riations in the price of gas. (The issue of longer

term prices used for planning purposes is discussed in the next section.) The claim that volatile natu ral 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 multip le pipelines) became very actively traded on the Ne w York Mercantile Exchange (NYMEX). Trade in these fu tures contract has developed substantially since then and are now well developed with a long history . Futures prices for natural gas are now listed f or up to 10 years and are typically actively traded fo r shorter periods (up to 3 years. The Henry Hub fu tures price is used as a basis for trading natural gas pr ices; 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 extrem ely high natural gas prices ignore two factors: fir st, most of these periods of volatility are quite short and, as noted above, can be managed through future s 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 a nd 7. Figure 6 shows the series of futures prices for nat ural gas and coal on the NYMEX exchange. The first period of high prices resulted from the impact of h urricanes Katrina and Rita and lasted from August o f 2005 until December of that year; as the Figure sho ws, that period of volatility in natural gas prices had 0 0.5 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 2010Short Tons per Employee Hour 

### Figure 5. Coal Mine Productivity, 1980 - 2011

Surface Mines Underground Mines

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

no corresponding volatility in coal prices. The se cond period of high prices occurred in 2008 when bo th natural gas and coal exhibited significant volatili ty – each more than doubled within approximately a 12- month period -- driven by broader conditions in com modity markets experiencing turbulence just prior to the start of the recession (this pattern is clea rer 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 th at the commodity risk of natural gas (like that of coa l) occurs over a short enough time period that it c an be managed. For all these reasons, any short run diff erences in price volatility between natural gas and coal should not be seen as reasons for believing th at 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 econom ic. However, a recent report by NERA Economic Consulting for the Department of Energy, Office of Fossil Energy, found that domestic natural gas pric es would remain below $5.50/MMBtu through 2025 under s cenarios with LNG exports, prices that are not sufficient to trigger the development of new coal p lants. 6 These prices are in line with studies by Navigant 7 and Deloit MarketPoint 8 that have reached similar conclusions regarding L NG exports.

6 Macroeconomic Impacts of LNG Exports from the Unite d 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 Stat es , August 2012. $0.00 $5.00 $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-12Near 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 Suite11

4. Planning is based on expected returns over longe r 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 mark et for natural gas that provides financial instrume nts 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 fu ture and is highly liquid for at least three years. Power plant developers and owners are highly sophisticate d in the use of these financial instruments. Consequently, short-term volatility in natural gas prices, frequently cited as a reason why natural ga s cannot always replace coal in electric generation i s not an issue that will cause development of new c oal plants.
Moreover, new power plants have asset lives measure d 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 ho w units are dispatched, but this dispatch impact is unlikely to affect the long-run choice of natural g as over coal, because it is generally small when considered over a longer time horizon, and is typic ally hedged and factored into the choice of what ty pe of plant to build.
Typical power plant planning will reflect a longer term planning horizon. For example, a recent surve y 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 o f 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 Figur e 8

9 “A Brief Survey of State Integrated Resource Plann ing Rules and Requirements,”, Rachel Wilson and Pau l 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

- 12Price Index (April 2003=100) 

### Figure 7. Coal and Natural Gas Prices Indexed to A pril 2003 2003-2013

CoalIndx

GasIndx

Source: NYMEX, Ventx Velocity Suite12

for a comparison of annual and 10-year average natu ral gas prices for the prior 10 years. Since 1990 , the 10-year average natural gas price has not excee ded $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 w reaking unprecedented destruction on the country’s energy infrastructure and by an unsustainable globa l 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 ele ctricity producers considering new capacity investments. The modeling in the proposal’s RIA co nsidered scenarios with equilibrium natural gas prices reaching up to $7.96 (in 2007 dollars) in 20 20 (notably higher than the maximum $5.60 10-year price in observable market data since 1990) and sti ll found no new coal plants projected to be built.
In practice, planning is based on expectations of t he future, whereas the data in Figure 8 are histori cal data from actual prior periods. When renewed plann ing for coal plants began in the early 2000s, few planners were expecting the recession, the technolo gical advancement in shale gas production, or the extent of the decline in coal productivity of the l ast few years. As a result, coal appeared much mor e 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, assumptio ns of unabated electricity demand growth and improving coal productivity (both since proven wron g) 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 com petition is increasing efficient combined cycle technology compared to the current technology assum ed 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 ren ewable sources. Leading competitive alternatives to coal are discussed below.

a. More Efficient Natural Gas Combined Cycle
The efficiency of natural gas combined cycle techno logy is expected to continue to improve. Natural g as combined cycle efficiencies are presently improving and will continue to decrease the cost of generati on from natural gas. For example, the existing U.S. c ombined cycle EGU fleet uses primarily Frame E and F gas turbines, with advertised net efficiencies (hig h heating value basis) ranging from 45% to 52%, whereas combined cycles using more recently availab le Frame G and H gas turbines have advertised efficiencies up to 54%. These higher efficiency com bined cycle units are larger and somewhat more $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00

1990 1995 2000 2005 2010Average 2007$/Mcf for Previous Years 

# Figure 8. Henry Hub Prices 1990 - 2012

Average Annual and 10 Years

10

- Yr

Annual Average

Source: Energy Information Administration14

capital intensive, but these units become economic at the base load capacity factors that many combined cycle units are now experiencing in the di spatch order.

b. Renewables
Renewable energy technologies have demonstrated imp rovements in performance and costs over the years, making them a viable option to fossil fuel g eneration. Technologies such as wind turbines and photovoltaics are now significantly more efficient and cost-competitive than they were even a few year s ago. The data below shows the gains in renewable te chnologies 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 increa sing steadily. Prior to 2000, wind turbines had an average capacity factor of less than 22 percent. Fo r projects installed in 2003-2004, capacity factors increased to 33 percent and then increased even fur ther 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 reduce d cost of energy from $450/MWh in 1980 to about $70/MWh in 2007. As shown in Figure 9, histor ical 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, Oc tober 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_Ve atch_20_Percent_Report.pdf15

According to Black & Veatch research, capacity fact ors for wind turbines have averaged 15 percent improvement every two years. Average hub heights in creased from around 60 meters in 2000-2001 to 85 meters in 2005 and rotor diameters increased fro m 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 U S 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 resourc es. DOE also reports that wind turbine prices have decreased by as much as one-third or more between 2 008 and 2010.

Table 3. Increase in Output of Typical Wind Turbin e Over Time Year Generation 1990 250kW 1995 500kW 2000 660kW 2005 1.5MW 2011 1.97MW Source: AWEA16

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 percen t 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 ev ery doubling of cumulative global production. In dollar terms, this means that prices have dropped b y 95 percent from about $60/Watt to $2/Watt between 1976 and 2010. Economies of scale, technolo gy, 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 s ystems in the US declined by 5-7 percent per year, on average, from 1998-2011 and by 11-14 percent from 2 010-2011 and further declines are expected.

11 Wind Power Outlook 2012. American Wind Energy Asso ciation. http://awea.org/_cs_upload/newsroom/16582_1.pdf
12 SunShot Vision Study. US Department of Energy. Febr uary 2012. http://www1.eere.energy.gov/solar/pdfs/47927_chapte r4.pdf17

Analysis for systems quoted in Q4 2011 (and install ed in 2012) yields installed prices of $4.39/W for 5.1- kW residential systems, $3.43/W for 221-kW commerci al 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 t o 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, t he fact that PV system prices are substantially low er in Germany than in the United States, despite havin g 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 P V systems at this time. As a rough measure of this trend, the capacity-weighted average installed pric e 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 econo mies 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, lon g-term trend of lower and lower growth rates in electricity demand since the middle of the last cen tury and before. These factors will continue to li mit 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 t he rule (AEO 2010). These trends are shown clearly in Figure 11.
Key continuing drivers of this trend include: struc tural changes in the U.S. economy (e.g., growth in service sector relative to manufacturing sector; ef fective policies to support increased energy effici ency investment (e.g., ratepayer-funded energy efficienc y programs, building codes, and appliance standards); and policy support and new technology l eading to development and growth of demand
response as a resource.

13 Balance of system costs are non-hardware costs, of ten referred to as “business process” or “soft cost s.” These costs include permitting and commissioning, overhe ad, installation labor, and financing. Opportuniti es for cost reductions for these processes may be significant. http://www.nrel.gov/docs/fy13osti/56806.pdf
14 Photovoltaic (PV) Pricing Trends: Historical, Recen t, and Near-Term Projections. U.S. Department of En ergy November 2012. http://www.nrel.gov/docs/fy13osti/56 776.pdf18

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

Source: Energy Information Administration, historic al 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 2040Percent Change, 3-year Moving Average