1 

# Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability

August 20102 

# Acknowledgements

The following report was prepared on behalf of the Clean Energy Group’s Clean Air Policy Initiative, a coalition of electric companies dedic ated to responsible energy and environmental stewardship. The participating companies (listed b elow) are some of the nation’s largest generators of electricity, with over 170,000 megawa tts of electric generating capacity (including 110,000 megawatts of fossil generating capacity) th roughout the U.S., and serve nearly a fifth of all U.S. electric customers.

Calpine Corporation Constellation Energy Entergy Corporation Exelon Corporation NextEra Energy National Grid PG&E Corporation Public Service Enterprise Group

REPORT AUTHORS

Michael J. Bradley, M.J. Bradley & Associates LLC Susan F. Tierney, Analysis Group Christopher E. Van Atten, M.J. Bradley & Associates LLC Paul J. Hibbard, Analysis Group Amlan Saha, M.J. Bradley & Associates LLC Carrie Jenks, M.J. Bradley & Associates LLC

For questions or comments about this report, please contact:

Christopher Van Atten M.J. Bradley & Associates LLC 47 Junction Square Drive Concord, MA 01742 Telephone: 978 369 5533 E-mail: vanatten@mjbradley.com3 

# Executive Summary

In the 20 years since the Clean Air Act (“CAA”) Ame ndments of 1990, electric power companies throughout the United States have deployed a wide r ange of pollution-control technologies, new power plants with relatively low emissions, and demand-si de measures to reduce air emissions from electricit y production. The Environmental Protection Agency (“ EPA”) has found, however, that despite this significant progress in reducing emissions, in 2008 about 127 million Americans still lived in countie s with unhealthy air—many of which are located along the Ohio River Valley, in the Middle Atlantic, and in the Southeast. 1,2

To begin to address these issues, on August 2, 2010 , EPA published its draft Clean Air Transport Rule (the “Transport Rule”), regulating emissions in 31 Eastern states and the District of Columbia where controlling emissions will produce the greatest pub lic health benefit. 3 EPA plans to implement the Transport Rule on January 1, 2012. Additional rule makings are also underway to regulate hazardous air pollutants (“HAPs”), with EPA under court order to promulgate its final “Utility MACT” rule by November 2011. According to EPA, compliance would be required by early 2015. 4

These new rules regulating air emissions from fossi l fuel-fired power plants will require certain uncontrolled plants to install pollution control eq uipment. Third-party analysts have concluded that some coal plant owners may choose to retire units in lie u of such installations. For example, two recent s tudies suggested that between now and 2015, the combinatio n of low energy prices and EPA air regulations could result in the retirements of between 25 to 40 gigawatts (“GW”) 5,6 of the nation’s 1,030 GW of electric generating capacity. 7

Although some of the nation’s less efficient power plants may be retired, many existing coal plants wi ll be retrofit with new pollution controls. Approxima tely half of the nation’s coal-fired generating cap acity (150 GW) has already installed SO 2 scrubbers, another 55 GW plan to install scrubbers , and a significant number of coal units have already announced plans t o retire, 8 leaving approximately one-fourth of the nation’s coal-fired generation to add pollution con trols, switch to a cleaner fuel, or retire. Compan ies may also have the option to purchase allowances or adjust dispatch to comply with certain rules.

1 U.S. EPA, Draft FY 2011-2015 EPA Strategic Plan , at p. 7. Collectively, power plants are responsib le for 66 percent of SO 2 emissions, 19 percent of NOx emissions, and 39 perc ent of CO 2 emissions in the U.S. Also, in 2002, the EPA cata loged emissions in the United States and concluded that f ossil-fuel-fired power plants were responsible for the following percentages of nationwide emissions for the following HAPs (all fi gures are approximate): hydrochloric acid (60%); me rcury compounds (45%); arsenic compounds (35%); and nickel compound s (25%). U.S. EPA, 2002 National Emissions Inventory Booklet.

2 According to the recent National Academy of Scienc es, Hidden Costs of Energy: Unpriced Consequences of En ergy Production and Use (2010), “after ranking all the [power] plants acco rding to their damages, we found that the most dama ging 10% of plants produced 43% of aggregate air-pollution dama ges from all plants, and the least damaging 50% of the plants produce less than 12% of aggregate damages” ...(and) the most dama ging 10%...account for approximately one quarter of electricity generated at the 406 plants.” (at p. 88).

3 Office of Air and Radiation, U.S. EPA, Air Transport Rule Factsheet , at p. 1.
4 U.S. EPA, Proposed Rule: Federal Implementation Plans To Redu ce Interstate Transport of Fine Particulate Matter and Ozone. August 2, 2010.

5 PIRA Energy Group (“PIRA”), EPA’s upcoming MACT; Strict Non-Hg Can Have Far-Rea ching Market Impacts , April 8, 2010.
6 ICF International, EEI Preliminary Reference Case and Scenario Results

. May 21, 2010.

7 Energy Information Administration (“EIA”), Electric Power Monthly , July 2010. (Based on preliminary 2009 capacity, c apacity additions and retirements up through April 2010.)

8 PIRA, supra n.5.4

Some in the industry have raised concerns about the combined effects over the next five years of anticipated power plant retirements and outages req uired to install new pollution control equipment. Clearly, the nation must carefully consider how to maintain electric system reliability, while also improving our nation’s health and environmental qua lity.

In this paper, we highlight the impact of EPA’s upc oming air regulations, with a focus on the issue of possible power plant retirements on electric reliab ility. We conclude that, without threatening elect ric reliability, the industry is well-positioned to res pond to EPA’s proposed road map to “help millions o f Americans breathe easier, live healthier,” 9 provided that EPA, the industry and other agencies take practical steps to plan for the implementation of t hese regulations and adopt appropriate regulatory approaches. In particular, we conclude the followi ng:

1. Even though some units likely will retire in lieu o f complying with the new regulations, electric system reliability will not be compromised if the industry and its regulators proactively manage the transition to a cleaner, mor e efficient generation fleet.

o Power system reliability relates not only to genera tion capacity and availability, but also to consumption levels and patterns, and transm ission capacity and use. As such, all these factors must be considered when assessing reliability impacts. Existing power system capacity well in excess of minimum res erve levels, relatively modest projections of load growth over the next several ye ars, a large amount of proposed generating resources, and the availability of load management practices indicate the system can handle the level of projected retirement s.

o Each North American Electric Reliability Corporatio n (“NERC”) reliability region has excess capacity, totaling over 100 GW of excess capacity nationwide. Therefore, considering only the projected level of coal unit a ttrition relative to existing capacity resources, it appears there will be no capacity sho rtages even if projected retirement scenarios prove accurate.

o Further, economic conditions have reduced the deman d for electricity in recent years providing an additional capacity cushion to assist in managing any power plant outages required to install pollution controls.

o The industry has a proven track record of adding ne w generating capacity and transmission solutions when and where needed and of coordinating effectively to address reliability concerns. In the three years b etween 2001 and 2003, the electric industry built over 160 GW of new generation—about four times what analysts project will retire over the next five years.

o Notably, many of the regions of the country with or ganized wholesale markets, including many parts of the Midwest, Mid-Atlantic, and Northeast, have developed effective tools such as capacity markets and reserv e sharing mechanisms enabling electric generators to access other companies’ avai lable resources to assure regional reliability.

o Additionally, the industry is deploying enhanced de mand response actions, expanded energy efficiency programs, and new “smart grid” ad vances to manage consumption during the transition to cleaner, more efficient ge neration.

9 U.S. EPA, supra n.1, at p. 2.5

2. Industry data counter concerns that it will cost th e industry too much to comply with EPA’s proposed air regulations, that pollution controls c annot be installed soon enough, or that the EPA regulations will lead to the closure of otherwi se economically healthy power plants.

o The proven technologies for controlling air polluti on emissions, such as NO
x , SO 2 , mercury and acid gases, are commercially available and have already been, or soon will be, installed on the majority of the nation’s coal plants (65 percent with scrubbers; 50 percent with advanced NO
x controls), demonstrating that the costs can be managed.

o The industry has a demonstrated ability to schedule and sequence unit outages in an efficient and reliable manner and is capable of ins talling additional pollution control systems to comply with the Transport Rule and Utili ty MACT Rule.

o Many of the coal units that are the most likely can didates to shut down are smaller, 40 to 60 year old units, which are nearing the end of their design life expectancy and are already economically challenged.

o Additionally, the retirement of some existing gener ating capacity will create room on the transmission grid to accommodate additional pow er flows, or new generating capacity, without requiring attendant upgrades in t ransmission, thus mitigating reliability concerns while reducing the cost of tra nsitioning to a cleaner, more efficient generation fleet.

3. EPA, the Federal Energy Regulatory Commission (“FER C”), the Department of Energy (“DOE”) and State utility regulators, both together and separately, have an array of tools to moderate impacts on the electric industry.

o EPA may, and if needed, should exercise its statuto ry authority under the CAA to grant, on a case-by-case basis, extensions of time to complete pollution control installations where appropriate.

o To the extent that its legal authority allows, EPA should adopt regulatory approaches that allow for cost-effective compliance, such as t he emissions trading mechanism proposed in the Transport Rule.

o In circumstances in which power plant retirements t rigger localized reliability concerns, EPA and DOE should follow established pre cedent, including use of consent decrees, to permit continued operation for reliability purposes only, pending necessary upgrades or generation additions. Additi onally, the various federal agencies and offices with responsibility for assuri ng reliability for the nation's electricity capability should work together to help support the industry and states in complying with EPA’s new air regulations.

o Transparent, well-established market rules approved by FERC and overseen by independent market monitors, particularly the forwa rd capacity markets relied on by some Regional Transmission Operators (“RTOs”), as w ell as state regulatory agency oversight, provide additional safety nets to help e nsure adequate capacity.6 o Although EPA is under court order to promulgate its air regulations, the Agency can and should coordinate the implementation of anticip ated water regulations under Section 316(b) of the Clean Water Act (“CWA”) and n ew waste regulations to avoid possible reliability concerns. 10

10 EPA should also consider the possible greenhouse g as emissions implications of its 316(b) regulations . In 2007, the U.S. Supreme Court found the EPA has clear statutory aut hority to regulate greenhouse gases under the CAA. Transitioning to a cleaner generating fleet will help EPA fulfill this obligation.7



### I. MANAGING ELECTRIC SYSTEM RELIABILITY WHILE IMPLEMEN TING NEEDED ENVIRONMENTAL IMPROVEMENTS WITH SIGNIFICANT PUBLIC HEALTH BENEFITS

A. The Electric System Has Substantial Excess Gener ating Capacity and Appropriate Processes in Place to Assure Reliable Electricity S upply to Consumers

Currently, there are more than 17,000 electric gene ration units in the United States with a combined nameplate capacity of over 1,030 GW. 11 In 2009, coal-fired generation produced 45 percen t of the nation’s electricity, followed by natural gas (23 p ercent) and nuclear (20 percent), with the remainin g amount produced through a combination of hydroelect ric power, oil, wind and other miscellaneous fuel types. 12

Power plant owners, transmission system owners, and power system operators plan and operate their systems according to numerous federal, state and lo cal regulations, policies and protocols, applying planning requirements designed to ensure electricit y suppliers have adequate resources to meet current and future demand, and operational standards to ens ure power is available when consumers turn on the lights.

Power system reliability is tied to many things: ge neration plant capacity and availability, consumpti on levels and patterns, and transmission capacity and use. As such, electric system planners must consid er all of these relevant system infrastructure and dem and factors in assessing whether sufficient capacit y will be available to maintain reliability. Existing pow er system capacity well in excess of minimum reserv e levels, relatively modest projections of load growt h over the next several years, a large amount of proposed generating resources throughout the countr y, and the availability of load management practice s indicate the electric system should be able to hand le the transition to a cleaner, more efficient gene ration fleet.

Under FERC’s oversight, NERC sets standards to ensu re the reliability of the nation’s electric system. NERC comprises eight regional reliability organizat ions (or “regions,” as shown below), whose members include grid operators, utilities, generating compa nies and others in the electric industry.

11 EIA, supra n.7.
12 EIA, Net Generation by Energy Source , http://www.eia.doe.gov/cneaf/electricity/epm/tabl e1_1.html (accessed July 31, 2010).8 Figure/Table 1 - NERC Electric Reliability Regions

**FRCC – Florida Reliability Coordinating Council**  **SERC – Southeast Reliability Corporation** 

**MRO – Midwest Reliability Organization**  **SPP – Southwest Power Pool, RE** 

**NPCC – Northeast Power Coordinating Council**  **TRE – Texas Regional Entity** 

**RFC – Reliability First Corporation**  **WECC – Western Electricity Coordinating Council** 

**Note: NERC regional results shown in this presentation i**  **nclude the continental US only**

Most of the nation’s regional reliability organizat ions cover multiple states and each manages and monitors compliance with NERC’s reliability standar ds, including maintenance of minimum target reserve margins, a key indicator of resource adequa cy. Actual or expected reserve margins measure the extent to which generating capacity exceeds (or fal ls short of) peak electricity demand. All regions must have capacity above expected demand to accommodate power plant outages, transmission failures, unexpectedly high demand, or other contingencies. Most regions have a minimum target reserve margin at or below 15 percent. 13 In recent years, actual reserve margins around th e country have been well above the minimum target levels, due not only to new powe r plant additions in most regions, but also to redu ced demand attributable to the economic recession and i ncreasingly robust load management programs. 14

Table 2, below, illustrates that, in 2013, all NERC regions expect to have actual capacity levels well in excess of minimum reserve requirements. Although t his provides only one metric of reliability, and ea ch region will undertake more granular analysis in the months ahead, these capacity “cushions” indicate there should not be a capacity shortage even if pro jected retirement scenarios prove accurate. As the table further highlights, on an aggregate basis across al l NERC regions, the electric sector is expected to have over 100 GW of surplus generating capacity in 2013, about three times the 30 to 40 GW of retirements projected by PIRA Energy Group. 15,16 Reliability First Corporation (“RFC”) and the Sou theast Reliability Corporation (“SERC”) regions, for example, where mo st of the uncontrolled coal plants are located, are

13 Some regions are below 15%, such as TRE (12.5%), S PP (13.6%), WECC (14.7%). Regions that don’t estab lish a formal target are assigned one for planning purposes by NE RC, with 15% for regions like the Midwest and 10% f or regions with substantial hydroelectric power. NERC, 2010 Summer Reliability Assessment , May 2010.
14 Id

. 15 NERC, 2009 Long-Term Reliability Assessment: 2009-2018 , October 2009.

16 PIRA, supra n.5.9

expected to have high reserve margins at 24.3 perce nt and 26.3 percent, respectively. 17 These regions could retire 17.1 GW (RFC) and 23.9 GW (SERC) of ca pacity and still maintain the 15 percent NERC reserve margin target.

Table 2 - Estimated Reserve Margins in All NERC Reg ions:

Adequate Generating Capacity

NERC Electric Reliability

Region Projected Reserve Margin (1)
in 2013 Cushion Above NERC Target Reserve Margin (2)

In 2013

TRE 23.9% 7.8 GW

FRCC 28.6% 6.1 GW

MRO 22.1% 3.2 GW

NPCC 24.4% 5.9 GW

RFC 24.3% 17.1 GW

SERC 26.3% 23.9 GW

SPP 30.3% 7.7 GW

WECC 42.6% 35.6 GW

Total 107.3 GW

1. Includes capacity defined by NERC as Adjusted Pote ntial Reserve Margin, which is the sum of deliverab le capacity resources, existing resources, confidence factor ad justed future resources and conceptual resources, a nd net provisional transactions minus all derates and net internal dem and expressed as a percent of net internal demand. Source: NERC, 2009 Long-Term Reliability Assessment: 2009-2018 , October 2009, p. 396 (Summer Demand).
2. Capacity in excess of what is required to maintain NERC Reference Margin or the regional target reser ve levels.

Source: NERC, 2009 Long-Term Reliability Assessment: 2009-2018, October 2009.

Experience in the RFC region, which encompasses thi rteen states in the Midwest and Mid-Atlantic regions, is illustrative of the electric system’s a bility to tolerate retirements without jeopardizing reliability. Generators in the PJM Interconnection (“PJM”) retired about 6,000 MW of capacity between 2004 and 2007, and over 3,000 additional MW of capa city have been announced for retirement in PJM by 2012. 18 Despite almost 10,000 MW of retirements over this seven year period, the RFC region is still forecast to have a reserve margin of over 24 percen t in 2013, or an excess of 17,000 MW of generation above the 15 percent NERC target reserve margin tar get.

Moreover, as a result of the economic recession, NE RC projects “significant reductions in projected lo ngterm energy use in North America” 19 , which provide an additional capacity cushion. Wh ile total demand is still projected to increase in most regions, it will do so at a slower pace and from a lower starti ng point. See, for example, Figure 2 which shows the decrease in forecast energy use from NERC’s 2009 long-term reliability assessment as compared to its 2008 fore cast. Additionally, summer peak demand has decreased over 10 GW per year for two consecutive y ears. 20 Furthermore, in all regions of the country, well-established tools exist to analyze potential r egional power system impacts, and to facilitate pla nning, managing and operating the system to ensure ongoing reliability.

17 NERC, supra n.15.
18 PJM, Generation Retirement Summaries , http://www.pjm.com/planning/generation-retirement s/gr-summaries.aspx (accessed July 31, 2010).

19 NERC, supra n.15, at p. 13.
20 NERC, supra n.13, at p. 1.10 Figure 2

Source: NERC, 2009 Long-Term Reliability Assessment: 2009-2018, October 2009, p. 13.

B. The Electric Industry Has Proven Its Ability to Avoid Capacity Problems in the Past

— Through Power Plant Capacity Additions, Fuel Conver sions, Transmission Solutions, and Load Management Techniques

1. New Capacity is Already in the Pipeline

Even with the robust reserve margins in all NERC re gions, industry participants are pursuing various measures to safely and reliably transition to clean er, more efficient electric supply resources. Plan s are underway for a variety of new plants, even as less efficient ones are retired. While economics remain s the major consideration in deciding whether to develop or expand generating capacity or to mothball older plants, other major drivers, including reliability and environmental improvements, are in play. For example, the implementation of forward capacity mar kets in certain Independent System Operators (ISOs) has provided more price transparency, enabli ng the industry to see the value of various generat ion

resources.

Moreover, the industry has shown previously that it can efficiently add capacity or respond adequately to potential reliability issues. Between 1999 and 200 8, for example, in response to a variety of market, regulatory and economic signals, the electric secto r added almost 270 GW of natural gas-fired generati ng capacity, the equivalent of more than 80 percent of the entire existing U.S. coal fleet. 21 (See Figure 3 below, which shows the significant investment in ne w gas plants during the past decade.) Indeed, in j ust three years between 2001 and 2003, the electric ind ustry built over 160 GW of new generation, 22 about four times what analysts project will retire over t he next five years. Although conditions a decade a go

21 EIA, Annual Electric Generator Report: Form EIA-860 , 2008.
22 Id. 

### NERC 2009 to 2017 Projected11

differ in several respects, this robust constructio n cycle suggests that developers and investors will respond to strong signals if new capacity is needed

.
Figure 3 Power Plant Capacity Added by Year It Entered Servi ce

Source: Ceres, et al., Benchmarking Air Emissions of the 100 Largest Elect ric Power Producers in the United States , June 2010

.
There are also examples in which the industry respo nded quickly and effectively to resolve looming reliability problems. In the mid-1990s, for exampl e, three large nuclear generating units in Connecti cut, totaling almost 3,000 MW, were unexpectedly and sim ultaneously unavailable during lengthy outages 23

, transforming Connecticut from a power exporter to a net importer. To avert any reliability problems o ver the extended outages, the regional grid operator, a long with the region’s utilities and public officia ls, instituted a variety of measures including adjustin g unit maintenance schedules, executing additional interruptible contracts with large commercial custo mers, installing new generation and transmission equipment, and coordinating closely with neighborin g power systems to maximize out-of-state power purchases. 24 If necessary, the industry could employ similar s trategies in response to future coal plant retirements.

Further, as indicated in Table 3 below, substantial new capacity build has been announced, planned or is seeking grid interconnection studies. Across the N ERC regions, a recent report identified over 55 GW of proposed generation in advanced stages of developme nt in the queue for 2013. Although, not all of the se plants will be built, strong market incentives and signals from regulators that new capacity will be n eeded will promote generation development proposals beyon d those announced to date.

23 Western Massachusetts Electric Company, Form 8K , November 25, 1996, “Other Events.”

24 PRNewswire, NEPOOL: Power Supplies May be Tight in New England This Summer , June 11, 1996.12 Table 3 - Proposed New Build – 2013 25 NERC Region New Generation Proposed to Be Built (in Transmission Queues for 2013)

TRE 4.3 GW

FRCC 2.0 GW

MRO 3.6 GW

NPCC 7.5 GW

RFC 8.7 GW

SERC 10.3 GW

SPP 2.8 GW

WECC 16.3 GW

Total 55.5 GW

Note: There are substantial additional generating facili ties in the queue in each region.

Numerous electric companies have already announced substantial new capacity additions, many at the sites of existing coal units that will be retired. Georgia Power, which recently demolished a coal pl ant in Georgia and stated its intention to retire another, announced it plans to build three 840 MW combined cycle gas turbines (“CCGTs”) in Georgia. 26 Oglethorpe Power Corporation has proposed a 605 M W CCGT 27 and a 100 MW biomass facility in Georgia. 28 Also in the Southeast, Progress Energy plans to build a 950 MW CCGT at the site of three coal units , which will retire when the gas plant comes online

. 29 In Tennessee, TVA is building an 878 MW CCGT at the site of its John Sevier coal plant, and the City o f Vineland New Jersey plans to replace its 25 MW coal plant with a 60 MW gas plant. 30,31

Also, although they do not operate in the same base load mode as do nuclear or many coal plants, low emission energy facilities have expanded rapidly ov er the past several years. 32 For example, the total wind power capacity now operating in the U.S. is ov er 35,600 MW. In 2009 alone, the U.S. wind industry broke all previous records by installing n early 10,000 MW of new generating capacity, enough to serve over 2.4 million homes. Additionally, over 4 00 MW of solar was installed throughout the nation in 2009. Solar installations are poised to grow about 50 percent annually in the next three years, reach ing 1.5 GW to 2 GW of new installations in 2012. 33

The retirement of inefficient coal units may spur f urther development of cleaner generating capacity. Regional transmission studies include capacity even if it runs infrequently. Freeing room for new capacity through retirements means some low emissio n generation resources, including gas plants, can b e accommodated without having to invest in new transm ission.

25 ICF International, supra n.6.
26 Georgia Power, From Coal to Natural Gas, http://www.georgiapower.com/generation/home.asp (a ccessed July 31, 2010).
27 Oglethorpe Power, Oglethorpe Power to Build Gas-Fired Generating Plan t, March 10, 2010.

28 Power-Gen Worldwide, Oglethorpe plans a biomass plant , June 29, 2010.
29 Energy Business Review, Progress Energy Wins Approval To Build 950MW Gas-fi red Plant , October 2, 2009.

30 Marketwire, TVA Prepares to Begin Construction on 880-Megawatt Combined-Cycle Unit , March 16, 2010.

31 NJ Spotlight, NJ Coal Plants Face Cleanups and Closures, July 10, 2010.

32 Wind and solar are intermittent resources; therefo re, only part of their output is credited for relia bility purposes.

33 GTM Research, The United States PV Market Through 2013: Project E conomics, Policy, Demand and Strategy , December 2009.13 2. Existing Gas Units Have Untapped Power Production P otential

Given the significant addition of gas-fired capacit y in the past decade, as detailed earlier in Figure 3, and the relative price advantage of coal versus natural gas in the period from 2007 to 2008, gas plants we re not operated at their full design capability in man y parts of the country. As detailed in Table 4 bel ow, gas-fired CCGT power plants in 2008 had an average utilization rate of only 33 percent, as compared to coal’s 56 percent. Despite declines in natural gas prices, existing gas units have significant untapp ed power production potential, which can be expanded d uring off peak periods without constructing new generation. This excess capacity can assist in man aging power plant outages required to install pollu tion control systems.

Table 4 – Estimated Utilization of U.S. Coal and Ga s Plants (CCGT) by Region (2008)

**Region Total Installed**  **Capacity (MW) % Utilization Total Installed**  **Capacity (MW) % Utilization > 500 7,981 67% 17,678 46%**  **200 - 500 1,628 64% 2,410 26% < 200 199 53% 1,389 20%**  **> 500 18,113 73% 3,033 15% 200 - 500 4,915 59% 1,246 15%**  **< 200 3,111 42% 506 10% > 500 2,407 79% 13,791 44%**  **200 - 500 2,548 70% 4,326 36% < 200 1,079 47% 2,843 21%**  **> 500 99,474 61% 28,087 19% 200 - 500 11,479 54% 2,709 13%**  **< 200 4,664 48% 1,794 34% > 500 91,188 66% 40,529 24%**  **200 - 500 10,699 57% 4,995 29% < 200 4,109 36% 1,229 33%**  **> 500 17,970 71% 12,051 32% 200 - 500 2,361 72% 2,116 37%**  **< 200 647 44% 465 22% > 500 15,193 80% 28,869 44%**  **200 - 500 1,213 82% 5,025 36%**
**< 200 1,020 24%**  **> 500 30,081 73% 37,435 47% 200 - 500 2,992 78% 6,835 40%**  **< 200 2,465 60% 5,042 49% > 500 282,407 67% 181,473 35%**  **200 - 500 38,277 60% 30,136 32% < 200 16,616 45% 15,966 30%**  **Plant Size (MW) Coal Gas** 

**FRCC**

**MRO**

**NPCC**

**RFC**

**SERC**

**All US Plants SPP** 

**WECC TRE** 

Source: MJB&A analysis based on U.S. Energy Information Adm inistration’s Form EIA-860 (2008) and EIA-923 (2008)

Additionally, many coal plants have the potential t o repower their units, by replacing conventional co alfired steam electric generating units with CCGTs, t hus increasing the units’ efficiency and reducing air emissions—an approach already being used today by t he industry. For example, Xcel Energy has replaced a 270 MW coal plant in Saint Paul, Minneso ta with a 515 MW CCGT, reducing SO 2 emissions by 99.7 percent, NOx emissions by 96.9 percent, and eliminating mercury emissions. 34 It also repowered

34 Utility Engineering, Twin Cities to breathe easier thanks to UE , Value Connection, Issue 2, 2007.14

two coal units in Minneapolis. 35 In New Jersey, Calpine has announced its intent t o convert an 83 MW coal unit to a 158 MW gas unit. 36

3. Enhanced Load Management Programs Can Be Deploye d to Meet System Reliability Needs Economically

Historically, grid operators have dispatched plants to meet customers’ electricity requirements. Over the years, the industry has recognized that decreasing load requirements can be more efficient and economical than increasing supply by dispatching ge neration. As a result, load management tools, such as demand response (“DR”) and energy efficiency (“E E”) programs have been widely implemented across the nation.

DR programs manage load by temporarily reducing or shifting electricity use by homes or businesses during critical times like hot summer days. EE pro grams, on the other hand, primarily seek to reduce consumers’ energy use on a permanent basis through the installation of energy efficient technologies a nd conservation measures. Both means of load manageme nt provide an additional tool for system operators to manage electric reliability.

DR programs operate in all of the NERC Regions, as shown in Figure 4 below. In some regions, such as RFC, SERC, WECC, and MRO, a substantial fraction of the DR resources are available in the form of “contractually interruptible” or curtailable loads. These typically entail contracts between a utilit y and an industrial customer, in which the customer agrees t o curtail part of its usage when requested for a specified number of times during a certain period, in exchange for electric rate discounts. The other forms of DR—direct control load management, critica l peak pricing with control, and load as a capacity resource—are more dynamic forms of supply, in which the grid operator, in effect, dispatches the load to respond with a reduction or shift in load, much lik e a generating facility.

Figure 4 NERC Summer Peak Capacity Demand Response - 2009-20 18 Comparison

Source: NERC, Long-Term Reliability Assessment, 2009, Figu re 7 (page 18).

In particular, these other forms of DR have increas ed steadily in organized wholesale competitive markets. In PJM, for example, DR has increased fiv e-fold in the past five years and continues to grow

. 37

35 North Dakota Home Town Times, Xcel Energy Switches Minneapolis Coal Plant to Natu ral Gas , October 13, 2009.

36 NJ Spotlight, supra n.31.15

In the most recent PJM capacity auction, DR offers increased 32 percent over last year and over 9,000 MW cleared, which represents about six percent of t otal available capacity resources. 38 DR is expected to reduce the peak electricity use this summer in PJM by 8,525 MW, the equivalent output of ten large power plants. 39

DR is not just increasing in PJM. According to the ISO/RTO Council, competitive markets are “shattering barriers” in terms of attracting DR res ources. 40 In FERC’s recently released National Action Plan on Demand Response , it highlighted that DR has tripled in recent year s in the New England region 41 and identified strategies to further enhance DR. Already, about half of electric utilities across th e nation have some type of DR program. With continued suppo rt from regulatory agencies like FERC and the advancement of “smart grid” technologies, DR is exp ected to continue to grow as a viable supply alternative to traditional generation.

As with DR, EE programs have increased dramatically in the past several years. According to information compiled by the Consortium for Energy E fficiency, and as highlighted in Figure 5, the tota l budget for all US ratepayer-funded EE and DR progra ms has increased 80 percent since 2006 to $4.4 billion in 2009. 42 These programs resulted in savings of almost 105, 000 gigawatt hours (“GWh”) of electricity in 2008—the equivalent of the total ele ctricity consumption in Tennessee in the same year. 43 By 2018, new EE programs alone are expected to redu ce summer peak demands by almost 20,000 MW (a full year’s growth). 44

37 PJM, Demand Response To Play Significant Role In Meeting PJM’s Higher Summer Peak Electricity Use

, http://pjm.com/~/media/about-pjm/newsroom/2010-rele ases/20100505-summer-2010-outlook.ashx (accessed Au gust 6, 2010)

38 PJM, 2013/2014 RPM Base Residual Auction Results , at p. 1.
39 PJM, supra n.37.
40 ISO/RTO Council, 2009 State of the Markets Report , September 22, 2009.

41 The Federal Energy Regulatory Commission Staff, National Action Plan on Demand Response , June 17, 2010, at p. 7.
42 Consortium for Energy Efficiency (“CEE”), The State of the Efficiency Program Industry: Budge ts, Expenditures, and Impacts

, 2009, at p. 7.
43 Id.

44 NERC, supra n.15, at p. 12.16 Figure 5 Energy Efficiency and Demand Response Program Budge ts, 2006-2009

**- 500**  **1,000 1,500**  **2,000 2,500**  **3,000 3,500**  **4,000 4,500**  **5,000**

**2006 2007 2008 2009 Millions $USD**  **Commercial and Industrial**
**Residential**
**Low Income Load Management** 
**Other**

Source: Consortium for Energy Efficiency , The State of the Efficiency Program Industry: Budgets, Expenditures, and Impacts , 2009

Although California and the Northeast account for o ver half of the total, budgets for ratepayer-funded EE programs are expanding in all regions of the countr y. In 2009, EE budgets for Illinois, Wisconsin, an d Iowa increased in 2009, year-on-year, by 60 percent , 40 percent, and 36 percent, respectively. 45 In the Southeast, Alabama, Mississippi, North Carolina, an d Louisiana reported ratepayer-funded EE budgets for the first time in 2009. 46 EE’s use as a capacity resource is increasing in organized wholesale markets as well. For example, EE resources accounted for 7 57 MW of the resources offered into the most recent PJM RPM auction, an increase of 33 percent over the prior year. Of those resources, 90 percent, or 68 0 MW cleared the auction to serve as a firm capacity resource. 47

NERC estimates that current levels of EE and DR wil l shave off certain portions of expected growth in demand, as shown in Figure 6, below, underscoring g rowing acceptance of these load-management tools.

45 CEE, supra n.42, at p. 15.
46 Id. at p. 16.
47 PJM, supra n.38.17 Figure 6 Summer Peak Demand Growth Reduced by Demand-Side Ma nagement

Source: NERC, Long-Term Reliability Assessment, 2009, at p. 18.

Based on the experience of states and organized com petitive wholesale markets that have implemented EE and DR, it is clear these programs provide yet a nother cost-effective tool to help maintain reliabi lity in the face of generation retirements.18



### II. THE INDUSTRY HAS THE CAPACITY TO TIMELY RESPOND TO EPA’S FUTURE AIR REGULATIONS

A. The Majority Of Coal Plants Have Already Installed Air Pollution Controls

Proven pollution control technologies are widely av ailable to dramatically reduce emissions of NO
x , SO 2 , mercury, and other HAPs from coal plants, which acc ount for 98 percent of the electric sector’s SO 2 emissions, 86 percent of its NOx emissions, and 98 percent of its mercury emissions. 48,49

Over the last 20 years, the industry has deployed a number of different technologies to comply with federal and state SO 2 and NOx regulations. The three basic options for r educing SO 2 emissions from coal plants include: (1) switching from higher to lower sulfur coal; (2) blending higher sulfur coal with l ower sulfur coal; or (3) installing flue gas desulfuriza tion (“FGD”) control systems, commonly referred to as scrubbers. Wet scrubbers, which use a sorbent to c apture SO 2 , can typically achieve at least 95 percent SO 2 removal. Widely available NOx control technologie s for coal generation can be grouped into two broad categories: combustion modifications and post -combustion controls. Post-combustion controls can reduce NOx emissions by 90 percent or more by remov ing the NOx after it has been formed in the boiler. The most common post-combustion control is selectiv e catalytic reduction (“SCR”) technology, in which ammonia (NH 3 ) is injected, combining with the NOx in the flue g as to form nitrogen and water.

The majority of coal plants have already installed such controls. Of the 310 GW of coal capacity in t he United States, 150 GW have installed FGD systems an d another 55 GW have FGD controls planned, 50 representing 65 percent of the existing coal fleet. As detailed in Attachment A, numerous scrubber installations have been recently completed or soon will be completed. Additionally, about 50 percent of coal capacity in the U.S. has installed or soon wil l be retrofit with advanced NOx controls (SCR and selective non-catalytic reduction (“SNCR”) technolo gies). 51

To date, most studies put a heavy emphasis on deplo ying scrubbers to comply with the new EPA air regulations. Retirements occur where the costs of installing scrubbers does not make economic sense based upon the unit’s characteristics. However, a number of companies have announced that they will use other less costly technologies in lieu of scrub bers. For example, on August 5, 2010, Edison Missi on International, one of the nation’s largest merchant coal generators, announced it could achieve compliance without installing scrubbers by using tr ona injection technology. 52

B. With Proper Planning, the Industry Can Install t he Necessary Pollution Controls on a Timely Basis

EPA projects that about 14 GW of additional coal-fi red generating capacity will need to be retrofit wi th scrubbers and less than 1 GW with SCR controls by 2 014 to comply with the recently proposed Transport Rule. 53 This number of retrofits is significantly less th an the industry has added in past construction

48 EIA, U.S. Electric Power Industry Estimated Emissions by State (EIA-767 and EIA-906) , Electric Power Annual 2008, http://www.eia.doe.gov/cneaf/electricity/epa/emissi on_state.xls (accessed July 30, 2010)
49 U.S. EPA Office of Air Quality Planning and Standa rds, National Emissions Inventory for Hazardous Air Poll utants , 1999.
50 PIRA, supra n5, at p. 7.
51 U.S. EPA, National Electric Energy Data System (“NEEDS”) , version 3.02.

52 Trona is a naturally occurring sorbent that can be injected directly into boilers to remove harmful a ir toxics without the use of FGD scrubbers. Given that the PIRA and EEI analyse s did not consider trona and other less costly comp liance options, the predicted retirement scenarios are very likely over stated. Nonetheless, this report uses the predicte d retirements as a conservative input to test all of the reliability considerations

. 53 U.S. EPA, Proposed Rule: Federal Implementation Plans To Redu ce Interstate Transport of Fine Particulate Matter and Ozone , August 2, 2010.19

cycles. For example, during the peak of scrubber c onstruction, between 2008 and 2010, approximately 6 0 GW of coal capacity was retrofit with scrubber cont rols, 54 highlighting the industry’s ability to complete a substantial number of retrofits over a short period of time. In 2009 and 2010, the industry completed between 50 and 60 scrubber retrofits each year. 55

Moreover, the industry’s past successful installati on of pollution controls on numerous units undersco res its ability to schedule and sequence any required u nit outages in an efficient and reliable manner. T o help ensure reliability, generators and transmission own ers provide reasonable advance notice of any planne d outages to the respective transmission authorities. In turn, the transmission authorities develop a coordinated outage schedule to prevent any delivera bility problems. This illustrates a key benefit of a fully integrated national transmission system.

Further, the CAA allows three years for existing so urces to comply with the Utility MACT rule with the possibility of a one-year extension. EPA is under a court-imposed deadline to complete its regulation s by November 2011, with compliance required by late 201 4. As numerous states have adopted regulations limiting mercury emissions from coal-fired power pl ants, many companies have already begun to install mercury control technologies. Also, the scrubber a nd particulate control systems installed to comply with the Transport Rule and other EPA regulations will h elp companies to comply with future air toxics regulations.

In the event, however, that any required retrofit c onstruction schedules could not be completed within the pre-compliance period, EPA may, and should, exercis e its authority under Section 112(i)(3)(B) of the CAA to provide up to one-year extensions to complet e pollution control installations. In addition, to protect the national security interest of maintaini ng adequate electrical grid reliability, the Presid ent has the authority under Section 112(i)(4) of the CAA to grant one or more compliance extensions of up to t wo years each. Any such extensions would be unit-spec ific and based on clear demonstration that the technology to implement such standards is not avail able.

These federal tools combined with market rules and signals, industry reliability standards and enforcement mechanisms, and utility regulatory requ irements and incentives, provide a robust portfolio of techniques to assure compliance with health-based a ir regulations while maintaining reliable electrici ty supply.

C. The Coal Plants Most Likely To Retire Are Nearing T he End Of Their Design Life

Expectancies And Are Already Economically Challenge d

As indicated by Table 5 below, many of the uncontro lled coal units, which are the most likely to retir e, are smaller (250 MW and below) and are 40 to 60 yea rs old. Thus, the coal plants most likely to retir e are already nearing the end of their design life expect ancies, as confirmed in recent coal plant retiremen t announcements, detailed in Attachment B.

54 M. J. Bradley & Associates analysis based on U.S. EPA NEEDS Database v. 3.02.

55 Id.20 Table 5 - Characteristics of U.S. Coal Plants

Information included in the most recent annual State of the Market Report prepared by PJM’s Independent Market Monitor (“IMM”) suggests that fu ndamental economics, not the EPA regulations, are already challenging those units most likely to reti re. In that report, the IMM identified over 11 GW of coal units at risk for retirement, since they “did not recover avoidable costs even with capacity revenues.” 56 Of the 11 GW identified in the report, most opera ted less than 1,000 of the 8,760 hours in 2009 and tended to be significantly smaller with an average installed capacity of only 73 MW. 57 Of the 122 coal units in PJM with capacity less than or eq ual to 200 MW, 35 failed to recover their avoidable costs and another 52 were close to not recovering t hose costs. Therefore, in PJM, a region covering 1 3 states and DC, in addition to approximately 10 GW o f coal generation that has or will be retired durin g the seven years from 2004 to 2011, another 11 GW fa ces a troubling economic outlook. As such, the units’ economics already place them at risk of shut down, regardless of EPA’s future air regulations.

In reducing the air pollution emissions from some o f the nation’s most inefficient uncontrolled units, EPA will facilitate the development of cleaner, more ef ficient generation while improving air quality and reducing greenhouse gas emissions. The current lev els of air pollution in certain regions of the coun try require industrial facilities and power plants to o btain emission offsets to expand their operations. This requirement discourages economic development due to the increased permitting and financial obligations compared to areas that meet federal and state air q uality standards. Significantly as well, as shown in Figure 7, because these non-attainment areas are co ncentrated in highly populated areas, reducing emissions there will facilitate the development of cleaner, more efficient generation near electric lo ad centers where it is needed most.

Additionally, the retirement of generating capacity that has been previously supported by transmission investment could create room on the transmission gr id to handle power flows both within and outside th e regions, or the addition of new generating capacity , without requiring attendant transmission upgrades

. These considerations, too, will help mitigate relia bility concerns and reduce the cost of upgrading th e nation’s power system infrastructure.

56 PJM, State of the Market Report , Vol. 1, March 11, 2010, p. 21.

57 Id. Vol. 2 at p. 176. **Count % MW % SNCR SCR Scrubber Uncontrolled**

**> 60 years 46 5% 1,762 1% 38 2% 4% 11% 87% 51 - 60 years 313 31% 39,787 13% 127 21% 9% 19% 64%**  **41 - 50 years 233 23% 58,078 20% 249 15% 19% 33% 53% 31 - 40 years 229 23% 114,090 38% 498 4% 43% 65% 27%**  **11 - 30 years 163 16% 80,165 27% 492 6% 29% 66% 31% 10 years or younger**  **7 1% 2,444 1% 349 43% 29% 57% 29% Total 1,004 297,639 13% 23% 41% 48%** 

**Data Sources: 2007/2008 EPA IPM, ARP, NBP Databases & Commercial Sources, MJB&A Analysis**  **Pollution Control Installed (% of units)**  **Avg. Unit Size**  **(MW) Unit Age**  **Units Capacity**21 Figure 7

Source: U.S. EPA (with city locations added by M.J. Bradle y & Associates)22

III. 

### EPA, DOE, FERC AND STATE UTILITY REGULATORS HAVE TH E TOOLS TO MODERATE IMPACTS ON THE ELECTRIC INDUSTRY AND MA NAGE ELECTRIC SYSTEM RELIABILITY.

A. Statutory, Regulatory and Market Safeguards Exis t To Mitigate Risks of Retirement On Reliability

Assorted risk management procedures under the CAA, the Federal Power Act (“FPA”) and other statutes provide EPA, DOE, FERC, and the President tools to moderate potential impacts on electric system reliability. The procedures serve as a bridge, if necessary, to a permanent solution, helping ensure reliability while minimizing exposure to harmful ai r pollutants. EPA also has the authority to develo p cost-effective regulatory approaches, such as the e missions trading mechanism proposed in the Transpor t Rule, that will enable greater compliance flexibili ty and flexibility in managing potential reliabilit y issues.

In addition to the EPA’s and President’s authority to extend deadlines for installation of pollution c ontrols described in Section II B, where necessary to maint ain electric system reliability, DOE has the power under Section 202(c) of the FPA to override CAA-der ived control requirements in limited emergency circumstances. In such emergency situations, inclu ding extended periods of insufficient power supply as a result of shortage of electric facilities, DOE ha s the discretion to issue unit-specific orders desi gned to maximize CAA compliance and minimize health risks.

Two examples of DOE’s exercise of this authority il lustrate the point. In 2003, the Secretary of Ener gy ordered energizing a new underwater cable connectin g New Haven, Connecticut to Long Island, which had previously been constructed but remained inoper able due to legal actions appealing permits. Citin g August 2003’s massive electric service outage, the Secretary invoked his authority to alleviate the reliability emergency. 58

DOE’s actions related to the Potomac River plant se rving Washington, DC provide another example. In 2005, the plant’s owner, Mirant, had decided to shu t down all five generating units at its Potomac Riv er plant located outside Washington, DC. The DC Publi c Service Commission requested that DOE issue an emergency order directing Mirant to continue to ope rate the units, as their shutdown would have “immediate” and “drastic” effects on DC’s electric system reliability. In conjunction with the EPA, which required Mirant to enter into a consent decre e, DOE issued an Order 59 requiring Mirant to operate the plants under specific and limited circumstances tailored to relieve the risk of a DC area blackout

, while avoiding to the full extent possible exceedan ces of federal air quality standards.

The well-established consent decree template, as us ed to address the Potomac River situation, provides EPA yet another tool to synthesize reliability and environmental concerns. By restricting a unit to o perate for reliability purposes only, pending completion o f any required transmission upgrades or replacement

58 DOE, Order No. 202-03-2 , August 28, 2003. “I hereby determine that an emer gency continues to exist in the Northeast United States due to a shortage of electric energy, a shor tage of facilities for [...] the transmission of elec tric energy and other causes. [...] On August 14, 2003, the Northeast and Upper Mid west areas in the United States, as well as portion s of Canada, experienced the largest electric transmission grid failure and electric service outage ever to occur i n North America. Tens of millions of people were affected by this outage, an d it presented profound risks to the public health and safety throughout the affected areas. [...] Only hours after the outage occ urred, and after considering the unanimous recommen dation of the North American Electric Reliability Council, the New York Independent System Operator (NYISO), ISO New Engla nd, Inc. (ISO-NE), and electric utilities in both New York and Connect icut in support of the issuance of an emergency ord er, I issued an order directing the NYISO and ISO-NE to require the Cross -Sound Cable Company, LLC (CSC) to operate the Cros s-Sound Cable and related facilities as necessary to alleviate the di sruptions in electric transmission service. The Ca ble was energized a short time thereafter.”
59 DOE, Order No. 202-05-03 , December 20, 2005.23

generation, such consent decrees can maintain relia bility while minimizing adverse environmental impacts to the fullest extent possible.

Many regional wholesale competitive markets also ha ve well-established forward capacity markets such as PJM’s Reliability Pricing Model and New England’ s Forward Capacity Market, which are approved by FERC and overseen by independent market monitors, t o facilitate and provide advanced notice of the retirement of inefficient units while maintaining r eliability. Reliability impact studies are conduct ed for units that have announced retirement or fail to cle ar the forward capacity auctions, and those identif ied as being needed for reliability may continue to operat e past their planned retirement date pursuant to “reliability must run” (“RMR”) agreements. To help ensure reliability while minimizing adverse environmental impacts, the RMR agreements can provi de the units operate only to maintain reliability. For example, Exelon Generation recently coordinated with PJM and the Pennsylvania Department of Environmental Protection (“PA DEP”) to negotiate a consent decree and operating procedures related to an RMR agreement for its two retiring coal units, w hich require the units operate for reliability purp oses only. 60

In addition to these established ISO/RTO procedures , advance analysis in the long range reliability planning processes should lead to rational and time ly investments in new transmission that will mitiga te any service reliability issues associated with futu re generation retirements. The local transmission owners currently play an important supplemental role in ac complishing this objective. For example, Commonwealth Edison (“ComEd”), the local transmissi on owner in Chicago, proactively filed an application with the Illinois Commerce Commission 61 seeking permission to enhance its transmission system. In its application, ComEd noted the identi fied upgrades would be required to maintain system reliability in the event that two of Midwest Genera tion’s at-risk coal units, Fisk and Crawford, were to retire. 62

Procedures also exist to protect electric system re liability in regions where coal plants are not part of an organized wholesale competitive market, but are own ed by vertically-integrated utilities in traditiona lly regulated monopoly regimes. Generators regulated b y state regulatory commissions have a legal obligation to reliably serve their customers, and t o conduct long range resource planning. Typically, generators will have many options to meet their sta tutory obligation to serve including, but not limit ed to: (1) investing in existing plants; (2) building new plants; (3) decreasing load through DR and EE programs; (4) building transmission; or (5) a prude nt combination of all those tools. Too, state regu lators may adopt ratemaking policies to encourage such act ions, including ones that address utilities’ financ ial disincentives where aggressive EE and DR programs w ould otherwise produce lower revenues.

As such, FERC and other relevant agencies have a nu mber of tools available to moderate the impacts of air emission regulations, while maintaining reliabi lity and minimizing adverse environmental impacts. Moreover, EPA is also developing new water regulati ons under Section 316(b) of the Clean Water Act (“CWA”), new waste regulations, and greenhouse gas regulations affecting the electric power sector. EPA should consider efficiently coordinating these rules as it moves forward with its rulemakings to avoid possible reliability concerns.

60 Commonwealth of Pennsylvania Department of Environm ental Protection v. Exelon Generation Company, LLC.

, No. 382 MD 2010 (Pa. Cmmw. April 16, 2010) included in Operating Procedures for Cromby Generating Station Unit No. 2 and Eddystone Generating Station Unit No. 2 as Required for Relia bility Purposes at Appendix 1, http://pjm.com/planning/generationretirements/~/media/planning/gen-retire/must-run-op erating-procedures.ashx (accessed August 6, 2010).

61 Commonwealth Edison Company, Application for authorization under Section 4-101 o f the Illinois Public Utilities Act (“Act”), 220 ILCS § 5/4-101, or alternatively, for a Certificate of Public Convenience and Necessity, pursuant to Section 8-406 of the Act, to install, operate and maintain two ne w 345,000 volt electric transmission lines in Cook County, Illinois , No. 10-0385 (Ill. Cir. June 11, 2010).

62 Direct Testimony of Thomas W. Leeming, p. 2, Lines 25-35.24



### IV. CONCLUSION

Current industry practice and a review of applicabl e system data indicate the industry is well-positio ned to respond to EPA’s mission to “help millions of Am ericans breathe easier and live healthier” without threatening electric reliability. Generation plant capacity and availability, consumption levels and patterns, and transmission capacity and use must al l be considered when judging the reliability impact s of environmental regulatory action.

The existing substantial excess capacity, the indus try’s proven track record to timely construct new generation and to efficiently coordinate the schedu ling of planned outages, together with capacity upgrades, transmission enhancements, “smart grid” i nvestments, fuel conversions, DR, and EE, should mitigate reliability concerns.

The industry has already successfully employed thes e various strategies to reliably meet customers’ energy needs while reducing environmental impacts, and it will continue to do so in response to EPA’s new regulations. As a final backstop, existing sta tutory, market and regulatory safeguards will facil itate the retirement of inefficient units, and an orderly transition to cleaner, more efficient generation.25 ATTACHMENT A

Sampling of Recent Announcements of Scrubber Instal lations

**Plant Unit State Size (MW)**  **Highlights**

**Brandon Shores**  **1 MD 643**

**Brandon Shores**  **2 MD 643 This significant environmental upgrade supports Con**  **stellation Energy's environmental stewardship efforts by: Reducing Maryland's coal-fi**  **red power plant's SO 2**  **emissions by an estimated 95 percent; Reducing existing mercury emi**  **ssions by 90 percent; and Significantly reducing acid gases.**  **http://www.constellation.com/portal/site/constellat ion/menuitem.38d5d085b395c0cb2adedd10**  **d66166a0/ Kingston 1 TN 135**  **Kingston 2 TN 135 Kingston 3 TN 135**  **Kingston 4 TN 135 Kingston 5 TN 177**  **Kingston 6 TN 177 Kingston 7 TN 177**  **Kingston 8 TN 177 Kingston 9 TN 178**  **The two scrubbers added at Kingston will control su lfur dioxide from all nine boilers at the**  **fossil plant, which can generate 10 billion kilowat t-hours of electricity per year. "We now have**  **state-of-the-art control equipment on all of our un its at Kingston, allowing us to generate the**  **electricity needed by our customers," Kingston Plan t Manager Leslie Nale said. "This**  **translates into cleaner air in the Great Smoky Moun tains and across the region."**  **http://www.tva.gov/news/releases/aprjun10/kingston_ scrubbers.html** 

**Miller 3 AL 750 Miller 4 AL 750**  **Gaston 5 AL 861 Barry 5 AL 750**  **During peak construction, Alabama Power’s $1.7 bill ion scrubber initiative was responsible**  **for creating more than 2,300 jobs. “This investmen t is not only good for the environment, it’s**  **also good for Alabama’s economy,” Charles McCrary, Alabama Power president and CEO,**  **said. http://southerncompany.mediaroom.com/index.php?s=43**  **&item=2074 Coffeen 1 IL 340**  **Coffeen 2 IL 560 “Our investment in these technologies reflects our**  **commitment to environmental stewardship and our support for the communities we serve,” says**  **Chuck Naslund, AER chairman, president and chief executive officer. “Through the**  **se projects, we have not only offered continued permanent employment to hundreds of Illin**  **oisans, but we have also provided jobs to contract employees who call Illinois home. Clear**  **ly these projects have had a positive impact on the economies of central and southern Ill**  **inois – areas hard-hit by tough economic conditions.”**  **http://www.bloomberg.com/apps/news?pid=conewsstory& tkr=AEM:SP&sid=a.W8.1491R8g**  **Cardinal 1 OH 600 Cardinal 2 OH 600**  **Cardinal 3 OH 630 According to Buckeye Power, one of the owners of th**  **e Cardinal Plant, “the addition of these scrubbers means the Cardinal plant is able to reduc**  **e emissions while using Ohio coal, meaning jobs and economic benefits for eastern Ohio**  **and the region.” The unit 3 scrubber is still under construction.**  **http://www.buckeyepower.com/pages/buckeye-power-2 Monroe 4 MI 775**  **Monroe 3 MI 795 DTE Energy will also be installing two additional F**  **GD systems at Monroe units 1 and 2. According to DTE, “the $600 million project will cr**  **eate 900 jobs and be one of the largest construction projects in Michigan over the next few**  **years.” http://www.prnewswire.com/news-releases/dte-energy-**  **environmental-project-will-create-900- jobs-78770632.html**  **Cliffside 5 NC 550 According to Duke, the scrubber control installation at Cliffside Unit 5 will be co**  **mpleted by the Fall of 2010. Duke already has emission-control sc**  **rubbers on all its large Carolinas coal plants—Allen, Marshall and Belews Creek. According**  **to Duke spokesman Andy Thompson, Duke has reduced its NOx emissions by 80% since 199**  **7 and SO2 emissions have fallen 70% since 2005.**  **http://www.bizjournals.com/charlotte/blog/power_cit y/2010/07/duke_energy_assessing_new_**  **epa_rules.html Bowen 1 GA 713 Scheduled for completion in early 20**  **10, according to Georgia Power. http://www.georgiapower.com/pluggedin/construction_**  **2009_08.asp Crist 6 FL 302**  **Crist 7 FL 477 According to Gulf Power, since 1992, the company ha**  **s reduced regulated emissions by more than 70 percent despite increased electricity deman**  **d from 120,000 new customers. With the scrubber system fully operational, Gulf Power will**  **have reduced overall regulated emissions by more than 85 percent since 1992.**  **http://www.renewablesbiz.com/article/09/12/gulf-pow er-begins-scrubber-startup**  **Clifty Creek 1 IN 217 Clifty Creek 2 IN 217**  **Clifty Creek 3 IN 217 Clifty Creek 4 IN 217**  **Clifty Creek 5 IN 217 Clifty Creek 6 IN 217**  **Kyger Creek 1 OH 217 "The addition of these FGD systems represents a maj**  **or commitment to environmental quality in southeastern Ohio and southeastern Indiana," sai**  **d David L. Hart, vice president and assistant to the president of OVEC-IKEC. "The proje**  **cts will also produce an economic boost to the two regions." The scrubber installations at**  **Clifty Creek and Kyger Creek are scheduled for completion in 2010.**  **http://www.prnewswire.com/news-releases/ovec-ikec-t o-invest-820-million-for-environmental**  **controls-at-kyger-creek-and-clifty-creek-power-plan ts-56325052.html** 26

**Plant Unit State Size (MW)**  **Highlights**

**Kyger Creek 2 OH 217 Kyger Creek 3 OH 217**  **Kyger Creek 4 OH 217 Kyger Creek 5 OH 217**  **Chalk Point 1 MD 342 Chalk Point 2 MD 341**  **Morgantown 1 MD 624 Morgantown 2 MD 620**  **Dickerson 1 MD 182 Dickerson 2 MD 182**  **Dickerson 3 MD 182 "We are making a major investment in emission reduc**  **tion technologies," said Edward R. Muller, Mirant chairman and CEO. "This equipment of**  **fers an excellent solution for substantially improving air quality while maintaini**  **ng system reliability and efficient power generation for consumers and businesses."**  **http://investors.mirant.com/releasedetail.cfm?relea seid=351567** 

**Brunner Island**  **1 PA 344**

**Brunner Island**  **2 PA 397**

**Brunner Island**  **3 PA 754 According to PPL’s website, “[t]he unit’s scrubber**  **is now operating as designed, thanks to plant employees who safely made the final connectio**  **ns between the plant and the scrubber during a recent maintenance outage.”**  **http://www.pplweb.com/ppl+generation/ppl+brunner+is land.htm** 

**Hatfields Ferry**  **1 PA 530**

**Hatfields Ferry**  **2 PA 530**

**Hatfields Ferry**  **3 PA 530 According to an Allegheny Energy fact sheet, “[t]he**  **‘scrubbers’ will remove approximately 95 percent of the sulfur dioxide (SO**  **2 ) emissions and significantly reduce mercury emissi**  **ons from the station...In addition to improving the environmen**  **t, the scrubber system will enable Hatfield’s Ferry to purchase more local coal, which**  **will preserve regional coal mining and related coal mining support jobs. The project will**  **bring approximately 350 construction jobs to the region for a period of about three years. A**  **dditional full-time positions will be added to operate and maintain the scrubbers.”**  **http://www.alleghenyenergy.com/Newsroom/Scrubber.Ha t.2page.pdf**  **Hudson 2 NJ 583 Mercer 1 NJ 315**  **Mercer 2 NJ 310 According to PSEG Power, advanced emissions control**  **s would be installed at Hudson by 2010. Scrubbers at its Mercer plant are scheduled**  **for completion in late 2010, http://www.reuters.com/article/idUSN145007212008051**  **4**
Source: MJB&A analysis.27



### ATTACHMENT B

Recent Coal Plant Retirement Announcements

Source: MJB&A analysis based on U.S. EPA Acid Rain Program database and U.S. EIA File 860. **Name Owner State Installed Capacity (MW)**  **Age (years)**  **Advanced SO 2**  **/NOx**

**Controls Weatherspoon Progress Energy NC 48 60 None**  **Weatherspoon Progress Energy NC 49 59 None Weatherspoon Progress Energy NC 76 57 None**  **L V Sutton Progress Energy NC 93 55 None L V Sutton Progress Energy NC 102 54 None**  **L V Sutton Progress Energy NC 403 37 None H F Lee Progress Energy NC 74 57 None**  **H F Lee Progress Energy NC 77 58 None H F Lee Progress Energy NC 248 47 None**  **Cape Fear Progress Energy NC 172 51 SNCR Cape Fear Progress Energy NC 144 53 SNCR**  **Cameo Xcel Energy CO 54 49 None Arapahoe Xcel Energy CO 47 58 None**  **Arapahoe Xcel Energy CO 121 54 None Wabash River Duke Energy IN 95 53 None**  **Wabash River Duke Energy IN 85 55 None Wabash River Duke Energy IN 85 56 None**  **Wabash River Duke Energy IN 85 54 None Wabash River Duke Energy IN 318 41 None** 

**John Sevier TVA TN 176 53 SNCR**

**John Sevier TVA TN 176 52 SNCR**

**John Sevier TVA TN 176 54 SNCR**

**John Sevier TVA TN 176 54 SNCR Cromby Exelon PA 144 55 SNCR + Scrubber**  **Eddystone Exelon PA 309 49 SNCR + Scrubber Eddystone Exelon PA 279 50 SNCR + Scrubber** 

**Richard Gorsuch**  **American Municipal Power OH 50 59 None**

**Richard Gorsuch**  **American Municipal Power OH 50 59 None**

**Richard Gorsuch**  **American Municipal Power OH 50 59 None**

**Richard Gorsuch**  **American Municipal Power OH 50 59 None**

**Indian River NRG Energy DE 82 53 None Indian River NRG Energy DE 177 40 None** 

**Jack McDonough**  **Southern Co GA 258 46 None**

**Jack McDonough**  **Southern Co GA 259 45 None**

**Hunlock UGI PA 50 51 None Will County Midwest Generation IL 188 55 None**  **Will County Midwest Generation IL 184 55 None**
**Boardman Portland General Electric,**

**Others OR 585 29 None** 

**Howard Down Vineland Municipal Electric**

**Utility NJ 25 40 None** 

**TOTAL - - 4,939 - -**