Coal plant retirements

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This article is part of the CoalSwarm coverage of coal plants
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Since 2009, a combination of factors converged to produce a wave of coal plant retirement announcements by plant operators. These factors included:

  • The continued aging of the coal fleet, in which the median generating station was built in January 1966. (See Table 1 below) Since their efficiency is lower than newer plants, older plants are typically run less often and have poorer economics.[1]
  • New and proposed EPA regulations, including the proposed Clean Air Transport Rule, the proposed Coal Combustion Residuals rule, the proposed Tailoring Rule (covering greenhouse gas emissions), the Ozone NAAQS (National Ambient Air Quality Standards), the forthcoming National Emission Standard for Hazardous Air Pollutants (NESHAPs), and cooling water regulations under section 316(b) of the Clean Water Act. [2][3][4]
  • Low prices of power from natural gas plants.

Coal plant retirements have been the subject of a number of multiple studies:

Contents

Projected retirements range from 25,000 - 60,000 megawawatts

According to one analysis, the new regulations are expected to push approximately 25,000 - 40,000 megawatts (MW) of smaller, older coal plants into retirement, in addition to the 5,000 MW of retirements that have already been announced.[5] Another analysis estimated that 50,000 MW of capacity is "at risk" of retirement.[6] A third analysis placed the total at 60,000 MW between 2013 and 2017.[7]

Here's a breakdown of existing U.S. coal-fired generating units (not overall plants) by age:[8]

Table 1: Age of U.S. Coal Plants

Years Built # of Units Total Capacity (MW)
2005-2009 21 6,785
2000-2004 13 1,382
1995-1999 24 4,372
1990-1994 67 8,638
1985-1989 102 23,734
1980-1984 117 56,105
1975-1979 125 55,879
1970-1974 137 66,466
1965-1969 158 41,656
1960-1964 157 25,310
1955-1959 209 28,883
1950-1954 213 17,518
1940-1949 93 2,583
1930-1939 20 132
1920-1929 10 69
Total 1,466 339,509

Recent and Upcoming Retirements and Conversions

The following sortable table lists recent and upcoming (including probable) coal plant retirements and conversions in the United States. To sort the table by a column, click on the column header. Clicking a second time on the header will reverse the order of the sort.

Table 2: Recent and upcoming coal plant retirements and conversions, including probable retirements

State Plant Operator Boiler or Unit Year Built Capacity (MW) Retirement Year Notes
AK Chena Power Plant Aurora Energy LLC 3 1952 2 2009
AL Colbert Fossil Plant Tennessee Valley Authority 1 1955 200 2016
AL Colbert Fossil Plant Tennessee Valley Authority 2 1955 200 2016
AL Colbert Fossil Plant Tennessee Valley Authority 3 1955 200 2016
AL Colbert Fossil Plant Tennessee Valley Authority 4 1955 200 2016
AL Colbert Fossil Plant Tennessee Valley Authority 5 1955 200 2014
AL Gadsden Steam Plant Southern Company 1 1949 69 2011 Gas and coal
AL Gadsden Steam Plant Southern Company 2 1949 69 2011 Gas and coal
AL Gaston Steam Plant Alabama Power 1 1960 272 2015 Gas
AL Gaston Steam Plant Alabama Power 2 1960 272 2015 Gas
AL Gaston Steam Plant Alabama Power 3 1961 272 2015 Gas
AL Gaston Steam Plant Alabama Power 4 1962 245 2015 Gas
AL Gorgas Steam Plant Alabama Power 1 1951 125 2015
AL Gorgas Steam Plant Alabama Power 2 1952 125 2015
AL Greene County Steam Plant Mississippi Power 1 1965 299 2016 Gas
AL Greene County Steam Plant Mississippi Power 2 1966 299 2016 Gas
AL Widows Creek Fossil Plant Tennessee Valley Authority 1 1952 141 2013
AL Widows Creek Fossil Plant Tennessee Valley Authority 2 1952 141 2013
AL Widows Creek Fossil Plant Tennessee Valley Authority 3 1952 141 2014
AL Widows Creek Fossil Plant Tennessee Valley Authority 4 1953 141 2014
AL Widows Creek Fossil Plant Tennessee Valley Authority 5 1954 141 2015
AL Widows Creek Fossil Plant Tennessee Valley Authority 6 1954 141 2015
AL Widows Creek Fossil Plant Tennessee Valley Authority 8 1954 141 not announced
CA Mt. Poso Cogeneration Plant Red Hawk Energy 1 1989 62 2011 biomass
CA Port of Stockton District Energy Facility NextEra Energy Resources 1 1987 54 2013 biomass
CO Arapahoe Station Public Service Company of Colorado 3 1951 46 2012
CO Arapahoe Station Public Service Company of Colorado 4 1955 112 2012
CO Cameo Station Public Service Company of Colorado 1 1957 25 2010
CO Cameo Station Public Service Company of Colorado 2 1960 50 2010
CO Cherokee Station Public Service Company of Colorado 1 1957 125 2022
CO Cherokee Station Public Service Company of Colorado 2 1959 125 2022
CO Cherokee Station Public Service Company of Colorado 3 1962 170 2022
CO Cherokee Station Public Service Company of Colorado 4 1968 381 2017
CO Clark Station Black Hills Energy 1 1955 18.7 2012
CO Clark Station Black Hills Energy 2 1959 25 2012
CO Valmont Station Public Service Company of Colorado 5 1964 192 2017
CT AES Thames Generation Plant AES 1 1989 214 2011
DC Capitol Power Plant U.S federal government 1910 2009 natural gas
DE Edge Moor Power Plant Calpine Corporation 3 1954 75 2010 gas
DE Edge Moor Power Plant Calpine Corporation 4 1966 177 2010 gas
DE Edge Moor Power Plant Calpine Corporation 5 1973 446 2010 gas
DE Edge Moor Power Plant Calpine Corporation 10 1963 35 2010 diesel
DE Indian River Power Station NRG Energy 2 1959 82 2010
DE Indian River Power Station NRG Energy 1 1957 82 2011
DE Indian River Power Station NRG Energy 3 1970 177 2013
FL Crystal River Energy Complex Progress Energy 1 1966 440 2020
FL Crystal River Energy Complex Progress Energy 2 1969 524 2020
GA Harllee Branch Generating Plant Southern Company (Georgia Power) 1 1965 299 2013
GA Harllee Branch Generating Plant Southern Company (Georgia Power) 2 1967 359 2013
GA Harllee Branch Generating Plant Southern Company (Georgia Power) 3 1968 544 2015
GA Harllee Branch Generating Plant Southern Company (Georgia Power) 4 1969 544 2015
GA Kraft Plant Southern Company (Georgia Power) 1 1958 50 2016
GA Kraft Plant Southern Company (Georgia Power) 2 1961 54 2016
GA Kraft Plant Southern Company (Georgia Power) 3 1965 104 2016
GA McDonough Steam Generating Plant Southern Company (Georgia Power) 1 1963 299 unknown
GA McDonough Steam Generating Plant Southern Company (Georgia Power) 2 1964 299 unknown
GA Mitchell Plant Southern Company (Georgia Power) 1 1964 163 unknown
GA Yates Steam Generating Plant Southern Company (Georgia Power) 1 1950 123 2015
GA Yates Steam Generating Plant Southern Company (Georgia Power) 2 1950 123 2015
GA Yates Steam Generating Plant Southern Company (Georgia Power) 3 1952 123 2015
GA Yates Steam Generating Plant Southern Company (Georgia Power) 4 1957 156 2015
GA Yates Steam Generating Plant Southern Company (Georgia Power) 5 1958 156 2015
IA Council Bluffs Energy Center MidAmerican Energy 1 1954 49 2016
IA Council Bluffs Energy Center MidAmerican Energy 2 1958 82 2016
IA Dubuque Generating Station Interstate Power and Light (Alliant) 2 1929 15 2013
IA Dubuque Generating Station Interstate Power and Light (Alliant) 3 1959 29 2015
IA Dubuque Generating Station Interstate Power and Light (Alliant) 4 1952 38 2015
IA George Neal Station North MidAmerican Energy 1 1964 147 2016
IA George Neal Station North MidAmerican Energy 2 1972 349 2016
IA Lansing Power Station Alliant Energy 2 1949 12 2010
IA Lansing Power Station Alliant Energy 3 1957 38 2010
IA Milton Kapp Generating Station Alliant Energy 1 1967 218 2010
IA Pella Municipal Power Plant Pella Municipal Power & Light 1 1964 11.5 2012
IA Pella Municipal Power Plant Pella Municipal Power & Light 2 1972 26.5 2012
IA Prairie Creek Generating Station Alliant Energy 2 1958 50 2010
IA Riverside Generating Station (Iowa) MidAmerican Energy 1 1949 5 2016
IA Riverside Generating Station (Iowa) MidAmerican Energy 2 1961 136 2016
IA Sixth Street Generating Station Interstate Power and Light (Alliant) 1 1921 10 2010
IA Sixth Street Generating Station Interstate Power and Light (Alliant) 2 1930 6 2010
IA Sixth Street Generating Station Interstate Power and Light (Alliant) 4 1942 15 2010
IA Sixth Street Generating Station Interstate Power and Light (Alliant) 6 1925 10 2010
IA Sixth Street Generating Station Interstate Power and Light (Alliant) 7 1945 15 2010
IA Sixth Street Generating Station Interstate Power and Light (Alliant) 8 1950 29 2010
IA Sutherland Generating Station Interstate Power and Light (Alliant) 2 1955 38 2010
IL Crawford Generating Station Midwest Generation 1 1958 239 2012
IL Crawford Generating Station Midwest Generation 2 1961 358 2012
IL Fisk Generating Station Midwest Generation 1 1968 374 2012
IL Hutsonville Power Station Ameren 1 1953 75 2011
IL Hutsonville Power Station Ameren 2 1954 75 2011
IL Joliet 9 Generating Station NRG Energy 1 1959 360 2016 gas
IL Joliet 29 Generating Station NRG Energy 1 1965 660 2016 gas
IL Joliet 29 Generating Station NRG Energy 2 1966 660 2016 gas
IL Lakeside Station City Water, Light and Power 6 1961 38 2009
IL Lakeside Station City Water, Light and Power 7 1965 38 2009
IL Meredosia Power Station Ameren 1 1948 58 2011
IL Meredosia Power Station Ameren 2 1949 58 2011
IL Meredosia Power Station Ameren 3 1960 239 2011
IL Pearl Station Prairie Power 1 1967 22 2013 biomass
IL University of Illinois Abbott Power Plant University of Illinois T11 2004 13 2017
IL University of Illinois Abbott Power Plant University of Illinois T12 2004 7 2017
IL University of Illinois Abbott Power Plant University of Illinois T6 1959 8 2017
IL University of Illinois Abbott Power Plant University of Illinois T7 1962 8 2017
IL Vermilion Power Station Dynegy 1 1955 74 2011
IL Vermilion Power Station Dynegy 2 1956 109 2011
IL Waukegan Generating Station Midwest Generation 6 1952 121 2007
IL Will County Generating Station Midwest Generation 1 1955 188 2010
IL Will County Generating Station Midwest Generation 2 1955 184 2010
IL Will County Generating Station Midwest Generation 3 1957 299 2015
IN Dean Mitchell Generating Station Northern Indiana Public Service Co 11 1970 128 2012
IN Dean Mitchell Generating Station Northern Indiana Public Service Co 5 1959 128 2012
IN Dean Mitchell Generating Station Northern Indiana Public Service Co 6 1959 128 2012
IN Dean Mitchell Generating Station Northern Indiana Public Service Co 4 1956 138 2012
IN Eagle Valley Station AES 3 1951 50 2017
IN Eagle Valley Station AES 4 1953 69 2017
IN Eagle Valley Station AES 5 1953 69 2017
IN Eagle Valley Station AES 6 1956 114 2017
IN Edwardsport Generating Station Duke Energy 7 1949 40 2011
IN Edwardsport Generating Station Duke Energy 8 1951 69 2011
IN Frank Ratts Generating Station Hoosier Energy 1 1970 117 2015
IN Frank Ratts Generating Station Hoosier Energy 2 1970 117 2015
IN Gallagher Generating Station Duke Energy 1 1959 150 2012
IN Gallagher Generating Station Duke Energy 3 1960 150 2012
IN Harding Street Station AES 5 1958 114 2017
IN Harding Street Station AES 6 1961 114 2017
IN Perry K Steam Plant Citizens Energy Group 1 1925 15 2014 Gas
IN Perry K Steam Plant Citizens Energy Group 2 1938 5 2014 Gas
IN State Line Plant Dominion 1 1955 100 2012
IN State Line Plant Dominion 2 1955 125 2012
IN State Line Plant Dominion 3 1962 180 2012
IN State Line Plant Dominion 4 1962 209 2012
IN Tanners Creek Plant American Electric Power 1 1951 153 2014
IN Tanners Creek Plant American Electric Power 2 1952 153 2014
IN Tanners Creek Plant American Electric Power 3 1954 215 2014
IN Tanners Creek Plant American Electric Power 4 1964 580 2015
IN Wabash River Generating Station Duke Energy 2 1953 112 2009 restarted in 2010
IN Wabash River Generating Station Duke Energy 3 1954 123 2009 restarted in 2010
IN Wabash River Generating Station Duke Energy 5 1956 125 2009 restarted in 2010
IN Whitewater Valley Generating Station Richmond Power & Light 1 1955 33 2013
IN Whitewater Valley Generating Station Richmond Power & Light 2 1973 61 2013 Waste gasification
KY Big Sandy Plant American Electric Power 1 1963 281 2015 natural gas
KY Big Sandy Plant American Electric Power 2 1969 816 2015
KY Cane Run Station Louisville Gas and Electric Company 1 1962 163 2016
KY Cane Run Station Louisville Gas and Electric Company 2 1966 209 2016
KY Cane Run Station Louisville Gas and Electric Company 3 1972 272 2016
KY Green River Generating Station Kentucky Utilities Company 1 1954 75 2016
KY Green River Generating Station Kentucky Utilities Company 2 1959 114 2016
KY Henderson Station One Henderson City Utility Commission 1, 2 1956, 1968 11.5, 32,3 2008
KY Paradise Fossil Plant Tennessee Valley Authority 1 1963 704 not announced natural gas
KY Paradise Fossil Plant Tennessee Valley Authority 2 1963 704 not announced natural gas
KY Shawnee Fossil Plant Tennessee Valley Authority 10 1956 175 2015
KY Tyrone Generating Station Kentucky Utilities Company 1 1953 75 2016
MA Brayton Point Station Dominion 1 1963 241 2017
MA Brayton Point Station Dominion 2 1964 241 2017
MA Brayton Point Station Dominion 3 1969 643 2017
MA Mount Tom Station GDF Suez 1 1960 136 2014
MA Salem Harbor Station Dominion 1 1952 82 2014
MA Salem Harbor Station Dominion 2 1952 82 2014
MA Salem Harbor Station Dominion 3 1958 166 2014
MA Somerset Power Generating Station NRG Energy 1 1951 74 2010
MA Somerset Power Generating Station NRG Energy 2 1959 100 2010
MD Chalk Point Generating Station NRG Energy 1 1964 364 2017
MD Chalk Point Generating Station NRG Energy 2 1965 364 2017
MD Dickerson Generating Station NRG Energy 1 1959 196 2017
MD Dickerson Generating Station NRG Energy 2 1960 196 2017
MD Dickerson Generating Station NRG Energy 3 1962 196 2017
MD R. Paul Smith Power Station Allegheny Energy 1 1947 35 2012
MD R. Paul Smith Power Station Allegheny Energy 2 1958 75 2012
MI Cobb Generating Plant Consumers Energy 2 units unspecified unspecified 2014
MI Harbor Beach Power Plant DTE Energy 1 1968 121 2015
MI Karn Weadock Generating Complex Consumers Energy 2 units unspecified unspecified 2014
MI Marysville Power Plant Detroit Edison 7 1943 75 2011
MI Marysville Power Plant Detroit Edison 8 1947 75 2011
MI S.D. Warren Muskegon Power Plant Sappi 1 1938 3.5 2009
MI S.D. Warren Muskegon Power Plant Sappi 2 1968 19.1 2009
MI S.D. Warren Muskegon Power Plant Sappi 3 1989 28.3 2009
MI Whiting Generating Plant Consumers Energy 1 1952 106 2014
MI Whiting Generating Plant Consumers Energy 2 1952 106 2014
MI Whiting Generating Plant Consumers Energy 3 1953 133 2014
MN Black Dog Generating Station Xcel Energy 3 1955 114 2016 natural gas
MN Black Dog Generating Station Xcel Energy 4 1960 180 2016 natural gas
MN Hoot Lake Plant Otter Tail Power 1 1956 54 2020 natural gas
MN Hoot Lake Plant Otter Tail Power 2 1964 75 2020 natural gas
MN Syl Laskin Energy Center Minnesota Power 1 1953 58 2015 natural gas
MN Syl Laskin Energy Center Minnesota Power 2 1953 58 2015 natural gas
MN Taconite Harbor Energy Center Minnesota Power 3 1967 84 2015
MS Jack Watson Generating Plant Southern Company 1 1968 250 2015 natural gas
MS Jack Watson Generating Plant Southern Company 2 1973 500 2015 natural gas
MT Corette Plant PPL 1 1968 173 2015 mothball
NC Buck Steam Station Duke Energy 3 1941 80 2011
NC Buck Steam Station Duke Energy 4 1942 40 2011
NC Buck Steam Station Duke Energy 5 1953 125 2013
NC Buck Steam Station Duke Energy 6 1953 125 2013
NC Cape Fear Steam Plant Progress Energy 5 1956 141 2013
NC Cape Fear Steam Plant Progress Energy 6 1958 188 2013
NC Cliffside Plant Duke Energy 1 1940 40 2012
NC Cliffside Plant Duke Energy 2 1940 40 2012
NC Cliffside Plant Duke Energy 3 1948 65 2012
NC Cliffside Plant Duke Energy 4 1948 65 2012
NC Dan River Steam Station Duke Energy 1 1949 70 2011
NC Dan River Steam Station Duke Energy 2 1950 70 2012
NC Dan River Steam Station Duke Energy 3 1955 150 2012
NC Lee Steam Plant Progress Energy 1 1952 75 2013
NC Lee Steam Plant Progress Energy 2 1951 75 2013
NC Lee Steam Plant Progress Energy 3 1962 252 2013
NC Riverbend Steam Station Duke Energy 4 1952 94 2013
NC Riverbend Steam Station Duke Energy 5 1952 94 2013
NC Riverbend Steam Station Duke Energy 6 1954 133 2013
NC Riverbend Steam Station Duke Energy 7 1954 133 2013
NC Sutton Steam Plant Progress Energy 1 1954 113 2014
NC Sutton Steam Plant Progress Energy 2 1955 113 2014
NC Sutton Steam Plant Progress Energy 3 1972 447 2014
NC UNC Chapel Hill Cogen University of North Carolina TG3 1991 28 2020 biomass
NC Weatherspoon Plant Progress Energy 1 1949 46 2017
NC Weatherspoon Plant Progress Energy 2 1950 46 2017
NC Weatherspoon Plant Progress Energy 3 1952 74 2017
NJ Deepwater Generating Station Pepco Holdings 1 1958 82 2010
NJ England Generating Station RC Cape May Holdings 1 1962 136 2013
NJ England Generating Station RC Cape May Holdings 2 1964 163 2016 natural gas
NJ Howard Down Generating Station Vineland Municipal Electric 1 1970 25 2010 natural gas
NM Raton Power Plant Raton Public Service Company 1 1961 7.5 2006
NM Four Corners Steam Plant Arizona Public Service Company 1 1963 190 2013
NM Four Corners Steam Plant Arizona Public Service Company 2 1963 190 2013
NM Four Corners Steam Plant Arizona Public Service Company 3 1964 253 2013
NM San Juan Generating Station Public Service Company of New Mexico 2 1976 369 2017
NM San Juan Generating Station Public Service Company of New Mexico 3 1979 555 2017
NV Mohave Generating Station Southern California Edison 1 1971 818 2005
NV Mohave Generating Station Southern California Edison 2 1971 818 2005
NV Reid Gardner Station NV Energy 1 1965 114 2014
NV Reid Gardner Station NV Energy 2 1968 114 2014
NV Reid Gardner Station NV Energy 3 1976 114 2014
NV Reid Gardner Station NV Energy 4 1983 295 2017
NY AES Greenidge Generation Plant AES 3 1950 50 2009
NY AES Westover Generation Plant AES 8 1951 75 2011
NY Cornell University Central Heating Plant Cornell University TG1 1988 2 2011 natural gas
NY Cornell University Central Heating Plant Cornell University TG2 1988 6 2011 natural gas
NY Danskammer Generating Station Dynegy 3 1959 147 2012
NY Danskammer Generating Station Dynegy 4 1967 239 2012
OH Ashtabula Plant FirstEnergy 1 1958 256 2015
OH Avon Lake Power Plant GenOn Energy 1 1949 86 2015
OH Avon Lake Power Plant GenOn Energy 2 1970 680 2015
OH Bay Shore Plant FirstEnergy 2 1959 141 2012
OH Bay Shore Plant FirstEnergy 3 1963 141 2012
OH Bay Shore Plant FirstEnergy 4 1968 218 2012
OH Beckjord Generating Station Duke Energy 1 1952 115 2015
OH Beckjord Generating Station Duke Energy 2 1953 113 2015
OH Beckjord Generating Station Duke Energy 3 1954 125 2015
OH Beckjord Generating Station Duke Energy 4 1958 163 2015
OH Beckjord Generating Station Duke Energy 5 1962 245 2015
OH Beckjord Generating Station Duke Energy 6 1969 461 2015
OH Burger Plant FirstEnergy 4 1955 156 2010
OH Burger Plant FirstEnergy 5 1955 156 2010
OH Conesville Power Plant American Electric Power 3 1962 165 2012
OH Eastlake Power Plant FirstEnergy 1 1953 123 2015
OH Eastlake Power Plant FirstEnergy 2 1953 123 2015
OH Eastlake Power Plant FirstEnergy 3 1954 123 2015
OH Eastlake Power Plant FirstEnergy 4 1956 208 2015
OH Eastlake Power Plant FirstEnergy 5 1972 680 2015
OH Hutchings Station DPL 1 1948 69 2015
OH Hutchings Station DPL 2 1949 69 2015
OH Hutchings Station DPL 3 1950 69 2015
OH Hutchings Station DPL 4 1951 69 2013
OH Hutchings Station DPL 5 1952 69 2015
OH Hutchings Station DPL 6 1953 69 2015
OH Lake Shore Plant FirstEnergy 1 1962 256 2015
OH Miami Fort Station Duke Energy 6 1960 163 2015
OH Muskingum River Plant American Electric Power 1 1953 220 2014
OH Muskingum River Plant American Electric Power 2 1954 220 2014
OH Muskingum River Plant American Electric Power 3 1957 238 2014
OH Muskingum River Plant American Electric Power 4 1958 238 2014
OH Muskingum River Plant American Electric Power 5 1968 615 2015
OH Niles Plant GenOn Energy 1 1954 133 2015
OH Niles Plant GenOn Energy 2 1954 133 2015
OH Ohio University Lausche Heating Plant Ohio University OUG1 1994 1 2009
OH Picway Power Plant American Electric Power 1 1955 106 2014
OH Richard H. Gorsuch Generating Station American Municipal Power - Ohio 1 1988 50 2012
OH Richard H. Gorsuch Generating Station American Municipal Power - Ohio 2 1988 50 2012
OH Richard H. Gorsuch Generating Station American Municipal Power - Ohio 3 1988 50 2012
OH Richard H. Gorsuch Generating Station American Municipal Power - Ohio 4 1988 50 2012
OH Shelby Municipal Light Plant American Municipal Power Ohio 1 1948 5 2012
OH Shelby Municipal Light Plant American Municipal Power Ohio 2 1954 7 2012
OH Shelby Municipal Light Plant American Municipal Power Ohio 3 1968 12.5 2012
OH Shelby Municipal Light Plant American Municipal Power Ohio 4 1973 12.5 2012
OK Northeastern Station American Electric Power 3 1979 473 2016
OK Northeastern Station American Electric Power 4 1980 473 2026
OR Boardman Plant Portland General Electric 1 1980 601 2020
PA Armstrong Power Station Allegheny Energy 1 1958 163 2012
PA Armstrong Power Station Allegheny Energy 1 1959 163 2012
PA Cromby Generating Station Exelon 1 1954 188 2011
PA Eddystone Generating Station Exelon 1 1960 354 2011
PA Eddystone Generating Station Exelon 2 1960 354 2012
PA Elrama Power Plant GenOn Energy 1 1952 100 2012
PA Elrama Power Plant GenOn Energy 2 1953 100 2012
PA Elrama Power Plant GenOn Energy 3 1954 125 2012
PA Elrama Power Plant GenOn Energy 4 1960 185 2012
PA Hatfields Ferry Power Station FirstEnergy 1 1969 570 2013
PA Hatfields Ferry Power Station FirstEnergy 2 1970 570 2013
PA Hatfields Ferry Power Station FirstEnergy 3 1971 570 2013
PA Hunlock Power Station UGI Development Co 3 1959 50 2010 gas
PA Mitchell Power Station FirstEnergy 3 1963 288 2013
PA New Castle Plant GenOn Energy 1 1952 98 2015
PA New Castle Plant GenOn Energy 1 1958 114 2015
PA New Castle Plant GenOn Energy 1 1964 136 2015
PA Penn State West Campus Plant Penn State 1 1929 20 2014 natural gas
PA Portland Generating Station GenOn Energy 1 1958 172 2014
PA Portland Generating Station GenOn Energy 2 1962 255 2014
PA Shawville Generating Station GenOn Energy 1 1954 125 2015
PA Shawville Generating Station GenOn Energy 2 1954 125 2015
PA Shawville Generating Station GenOn Energy 3 1959 188 2015
PA Shawville Generating Station GenOn Energy 4 1960 188 2015
PA Sunbury Steam Station Sunbury Generation 1 1949 75 2015
PA Sunbury Steam Station Sunbury Generation 2 1949 90 2015
PA Sunbury Steam Station Sunbury Generation 3 1951 104 2015
PA Sunbury Steam Station Sunbury Generation 4 1953 156 2015
PA Titus Generating Station GenOn Energy 1 1951 75 2015
PA Titus Generating Station GenOn Energy 2 1951 75 2015
PA Titus Generating Station GenOn Energy 3 1953 75 2015
SC Canadys Station SCE&G 1 1962 136 2012
SC Canadys Station SCE&G 2 1964 136 2013
SC Canadys Station SCE&G 3 1967 218 2013
SC Grainger Generating Station Santee Cooper 1 1966 82 2012
SC Grainger Generating Station Santee Cooper 2 1966 82 2012
SC McMeekin Station SCE&G 1 1958 147 2018
SC McMeekin Station SCE&G 2 1958 147 2018
SC Robinson Steam Plant Progress Energy 1 1960 207 2012
SC Savannah River D-Area Power House US Department of Energy HP-1 1952 9 2013
SC Savannah River D-Area Power House US Department of Energy HP-2 1952 9 2013
SC Urquhart Station SCE&G 3 1955 100 2018
SC W.S. Lee Steam Station Duke Energy 1 1951 100 2020
SC W.S. Lee Steam Station Duke Energy 2 1951 100 2020
SC W.S. Lee Steam Station Duke Energy 3 1958 170 2020
SD Ben French Power Plant Black Hills Corporation 1 1961 25 2014
TN Allen Fossil Plant Tennessee Valley Authority 1 1959 330 2018
TN Allen Fossil Plant Tennessee Valley Authority 2 1959 330 2018
TN Allen Fossil Plant Tennessee Valley Authority 3 1959 330 2018
TN John Sevier Fossil Plant Tennessee Valley Authority 1 1955 200 2012
TN John Sevier Fossil Plant Tennessee Valley Authority 2 1955 200 2012
TN Johnsonville Fossil Plant Tennessee Valley Authority 1 1951 125 2015
TN Johnsonville Fossil Plant Tennessee Valley Authority 2 1951 125 2015
TN Johnsonville Fossil Plant Tennessee Valley Authority 3 1952 125 2015
TN Johnsonville Fossil Plant Tennessee Valley Authority 4 1952 125 2015
TN Johnsonville Fossil Plant Tennessee Valley Authority 5 1952 147 2015
TN Johnsonville Fossil Plant Tennessee Valley Authority 6 1953 147 2015
TN Johnsonville Fossil Plant Tennessee Valley Authority 7 1958 173 2017
TN Johnsonville Fossil Plant Tennessee Valley Authority 8 1959 173 2017
TN Johnsonville Fossil Plant Tennessee Valley Authority 9 1959 173 2017
TN Johnsonville Fossil Plant Tennessee Valley Authority 10 1959 173 2017
TX J.T. Deely Station CPS Energy 1 1977 486 2018
TX J.T. Deely Station CPS Energy 2 1978 446 2018
TX Monticello Steam Station Energy Future Holdings 1 1974 593 2012
TX Monticello Steam Station Energy Future Holdings 2 1975 593 2012
TX Welsh Power Plant American Electric Power 2 1980 558 2014
UT Carbon Power Plant MidAmerican Energy 1 1954 75 2015
UT Carbon Power Plant MidAmerican Energy 2 1957 114 2015
UT Utah Smelter Power Plant Rio Tinto 1 1943 25 unknown
UT Utah Smelter Power Plant Rio Tinto 2 1943 50 unknown
UT Utah Smelter Power Plant Rio Tinto 3 1946 25 unknown
VA Altavista Power Station Dominion 1 1992 80 2012
VA Bremo Bluff Power Station Dominion 3 1950 69 2012
VA Bremo Bluff Power Station Dominion 4 1958 185 2012
VA Chesapeake Energy Center Dominion 1 1953 111 2014
VA Chesapeake Energy Center Dominion 2 1954 111 2014
VA Chesapeake Energy Center Dominion 3 1959 156 2014
VA Chesapeake Energy Center Dominion 4 1962 217 2014
VA Clinch River Plant Appalachian Power Company 1 1958 185 2014
VA Clinch River Plant Appalachian Power Company 2 1958 185 2014
VA Clinch River Plant Appalachian Power Company 3 1961 185 2014
VA Glen Lyn Plant Appalachian Power Company 5 1944 100 2014
VA Glen Lyn Plant Appalachian Power Company 6 1957 238 2014
VA Hopewell Power Station Dominion 1 1992 71 2012
VA North Branch Station Dominion 1 1992 80 2014 or 2015
VA Potomac River Generating Station GenOn Energy 1 1949 92 2012
VA Potomac River Generating Station GenOn Energy 2 1950 92 2012
VA Potomac River Generating Station GenOn Energy 3 1954 110 2012
VA Potomac River Generating Station GenOn Energy 4 1956 110 2012
VA Potomac River Generating Station GenOn Energy 5 1957 110 2012
VA Southampton Power Station Dominion 1 1992 71 2012
VA Yorktown Power Station Dominion 1 1957 159 2015
VA Yorktown Power Station Dominion 2 1959 158 2022
WA Centralia Power Plant TransAlta 1 1972 730 2020
WA Centralia Power Plant TransAlta 2 1973 730 2025
WI Alma Station Dairyland Power Cooperative 1 1947 15 2011
WI Alma Station Dairyland Power Cooperative 2 1947 15 2011
WI Alma Station Dairyland Power Cooperative 3 1951 15 2011
WI Blount Street Station Madison Gas & Electric 1 1925 10 2011 gas
WI Blount Street Station Madison Gas & Electric 2 1938 20 2011 gas
WI Blount Street Station Madison Gas & Electric 3 1948 23 2011 gas
WI Blount Street Station Madison Gas & Electric 4 1953 35 2011 gas
WI Blount Street Station Madison Gas & Electric 5 1957 50 2011 gas
WI Blount Street Station Madison Gas & Electric 6 1961 50 2011 gas
WI Capitol Heat and Power Plant Madison City Government 1 1963 1.5 2010 gas
WI Capitol Heat and Power Plant Madison City Government 2 1964 1.5 2010 gas
WI Charter Street Heating Plant University of Wisconsin 1 1965 10 2010 biomass
WI Edgewater Generating Station Wisconsin Power & Light Company 3 1951 60 2015
WI Edgewater Generating Station Wisconsin Power & Light Company 4 1969 330 2018 Retire or gas
WI Manitowoc Power Plant Manitowoc Public Utilities 1 1950 10 coal, gas, and waste
WI Manitowoc Power Plant Manitowoc Public Utilities 2 1956 22 coal, gas, and waste
WI Menasha Power Plant Menasha Electric & Water Utility 1, 2 1954, 1964 7.5, 13.6 2009
WI Nelson Dewey Generating Station Wisconsin Power & Light Company 1 1959 100 2015
WI Nelson Dewey Generating Station Wisconsin Power & Light Company 2 1962 100 2015
WI Stoneman Generating Station DTE Energy 1 1952 18 2010 wood waste
WI Stoneman Generating Station DTE Energy 2 1952 35 2010 wood waste
WI Valley Power Plant Wisconsin Electric Power Company 1 1968 136 2015
WI Valley Power Plant Wisconsin Electric Power Company 2 1969 136 2015
WI Waupun Correction Central Heating Plant State of Wisconsin 1 1951 1 2011 natural gas
WI Waupun Correction Central Heating Plant State of Wisconsin 2 1951 1 2011 natural gas
WV Albright Power Station Monongahela Power Company 1 1952 69 2012
WV Albright Power Station Monongahela Power Company 2 1952 69 2012
WV Albright Power Station Monongahela Power Company 3 1954 140 2012
WV Kammer Plant American Electric Power 1 1958 238 2014
WV Kammer Plant American Electric Power 2 1958 238 2014
WV Kammer Plant American Electric Power 3 1959 238 2014
WV Kanawha River Plant American Electric Power 1 1953 220 2014
WV Kanawha River Plant American Electric Power 2 1953 220 2014
WV North Branch Station Dominion 1 1992 80 2014
WV Philip Sporn Power Plant Appalachian Power Company 1 1950 152 2014
WV Philip Sporn Power Plant Appalachian Power Company 2 1950 152 2014
WV Philip Sporn Power Plant Appalachian Power Company 3 1951 152 2014
WV Philip Sporn Power Plant Appalachian Power Company 4 1952 152 2014
WV Philip Sporn Power Plant Appalachian Power Company 5 1960 496 2011
WV Rivesville Power Station Monongahela Power Company 1 1943 35 2012
WV Rivesville Power Station Monongahela Power Company 2 1951 75 2012
WV Willow Island Power Station Monongahela Power Company 1 1949 50 2012
WV Willow Island Power Station Monongahela Power Company 2 1960 163 2012
WY Naughton Power Plant PacifiCorp 3 1971 326 2014 Gas
WY Neil Simpson Power Plant Black Hills Corporation 1 1969 22 2014
WY Osage Power Plant Black Hills Corporation 1 1948 11.5 2014
WY Osage Power Plant Black Hills Corporation 2 1949 11.5 2014
WY Osage Power Plant Black Hills Corporation 3 1952 11.5 2014

Notes on Plant Retirements

For notes on conversions, go to Coal plant conversion projects

The decline of U.S. coal 2012-2016.

Alabama: Colbert Fossil Plant Units 1-4 to be idled or retired in 2016; Unit 5 also to be retired

In July 2013 TVA announced plans to idle or remove from service Colbert Fossil Plant units 1-4 starting June 30, 2016. The plans are the result of a 2011 Consent Decree arising out of consolidated litigation brought by several states and environmental groups for violations of the Clean Air Act. Under the decree, TVA was required to notify EPA of its plan for controlling air pollution at units 1-4 by June 30, 2013. Rather than installing new equipment, TVA opted to idle or retire the plants. According to the Southern Alliance for Clean Energy, unit 5 of the plant, which operated at only 15% of capacity in 2012, appeared also to be heading toward retirement.[9] On November 14, 2013, TVA added Unit 5 of the Colbert plant to the retirement list. The closure date was not specified. TVA also announced retirements at the Widows Creek Fossil Plant and the Paradise Fossil Plant in Tennessee.[10][11]

Alabama: TVA announces retirement plans for Widows Creek Fossil Plant Units 1-6 and 8

On April 14, 2011, TVA and North Carolina settled a 5-year-old lawsuit - North Carolina v. TVA - over TVA emissions from its coal-fired plants. As part of the agreement, TVA agreed to phase out 18 units of its coal plants, including six units at the Widows Creek Fossil Plant, taking all but two offline.[12][13] In May 2012, TVA began considering a switch to natural gas for the plant, linked up to a proposed natural gas pipeline from Tennessee through Alabama to Georgia.[14] On November 14, 2013, TVA announced that unit 8, one of the two remaining units of the plant, would be retired. The agency left the timeframe of the retirement to the discretion of the CEO. TVA also announced retirements at the Colbert Fossil Plant and the Paradise Fossil Plant.[15][16]

Alabama, Kentucky, Tennessee: TVA to phase out 18 coal units, install pollution controls (April 2011)

In August 2009, CEO Tom D. Kilgore announced that TVA was studying the possibility of closing its John Sevier Fossil Plant in Tennessee and the oldest six units at its Widows Creek Fossil Plant in Alabama. A federal judge has ordered TVA to install pollution equipment on the plants by the end of 2013, at an estimated cost of more than $1 billion. However, the company has not yet budgeted any money for the improvements. In 2010 TVA is planning to begin building an $820 million gas-powered plant to replace the generation at its John Servier Plant. The agency has already reduced power production from the oldest six units at Widows Creek. Environmental groups want TVA to shut down or convert to cleaner fuels the oldest and least efficient of its coal plants, including Widows Creek, John Sevier, and Johnsonville plants.[17]

On April 14, 2011, North Carolina settled a 5-year-old lawsuit - North Carolina v. TVA - with the TVA over emissions from its coal-fired plants. The deal was part of a larger settlement with the U.S. Environmental Protection Agency over TVA violations of the clean air act at 11 of its coal-fired plants in Alabama, Kentucky and Tennessee.[18][13][19]

As part of the North Carolina agreement, TVA agreed to phase out 18 units of its coal plants, adding up to 2,700 MW, and to install modern pollution controls on three dozen additional units.[20] The phase out includes two units at the John Sevier Fossil Plant, all 10 units at the Johnsonville Fossil Plant, both in Tennessee, and six units at the Widows Creek Fossil Plant in north Alabama.[21]

As part of the EPA agreement, TVA will invest an estimated $3 to $5 billion on pollution controls, invest $350 million on clean energy projects, and pay a civil penalty of $10 million.[22]

Colorado: Closure Planned for W.N. Clark Station

It was announced in the fall of 2010 that Black Hills Energy proposed retiring its two coal-fired units at the Clark Station in Canon City and would build a unit in Pueblo, Colorado that would be powered by natural gas. The retirement would be part of the company's proposal to reduce its greenhouse gas emissions. The proposal will be decided on by the Colorado Public Utilities Commission by the middle of December, 2010. The company originally stated it would consider using biomass to replace the coal at the plant, but later stated that it would cost too much to run the units on biomass.[23] On December 15 2010, the Public Utilities Commission approved Black Hills Energy's plan to close its coal-fired power plant in Canon City as well as an associated rate increase for customers estimated at about 5 percent. Black Hills opted to expand its gas-fired plant presently under construction in Pueblo to replace the load generated by the Clark plant. The Pueblo plant is expected to be operational by the end of 2012, and could replace the Canon City plant immediately at that point.[24]

On August 6, 2012, Black Hills Corporation announced the following scheduled retirements at its Colorado Electric subsidiary. [25]

Colorado: Arapahoe Station and Cameo Station

In August 2008, Colorado regulators approved Xcel Energy’s plan to shut down two coal plants: the Arapahoe Station (Denver) and the Cameo Station (east of Grand Junction). According to Western Resource Advocates, "The utility’s decision to shut down the plants has been praised as the nation’s first voluntary effort to cut coal power generation in an attempt to reduce greenhouse gas emissions. In its decision to support Xcel’s plan, the Colorado Public Utilities Commission (PUC) cited public health benefits and shared concerns about carbon emissions as major selling-points in the company’s groundbreaking proposal. The verdict marks a collective effort to move the state and its utilities toward the carbon reduction goals outlined in Governor Bill Ritter’s Climate Action Plan."[26]

Xcel plans to replace the combined 229 MW of coal power with 850 MW of wind power and a 200 MW utility-scale solar power plant with storage capacity by 2015. Another key component of Xcel’s proposal, to build a 480 MW natural gas plant at the Arapahoe station, has been postponed pending approval by the Colorado PUC.[26]

Colorado: Units at Cherokee and Valmont Generating Stations

The Cherokee Station 4 coal-fired plant is also scheduled to be shuttered in 2022. However, Xcel Energy announced in November 2010 its intent to close the plant, located north of Denver, in 2017, five years earlier than expected. The change of plans comes on the heels of the recently enacted Colorado Clean Air-Clean Jobs Act. As part of the legislation, Xcel receives financial incentives in exchange for a $1.3billion program of phasing out coal-fueled plants in favor of natural gas. The program targets plants in Boulder and Denver for conversion while facilities in Brush and Hayden would be upgraded to reduce pollution.[27]

As of November 2010, Xcel is also considering shutting down its Valmont Station Unit 5.[28]

Connecticut: AES Thames Generation Plant

On February 1, 2011, AES Thames Generation Plant filed for Chapter 11 bankruptcy in the state of Delaware, calling the shutdown temporary. AES Thames cited the increased cost of energy production and an "uneconomic and onerous" contract with Smurfit-Stone's predecessor. Smurfit-Stone sought a temporary restraining order and injunction to prevent the closing, which were to be heard by the New London Superior Court on Feb. 2, but AES Thames filed for bankruptcy the day before.[29]

The plant ceased operating after the bankruptcy. In December 2011, Thames and was sold to a subsidiary of BTU Solutions, based in Sugar Land, Texas. BTU plans to close and dismantle the plant, and lay off its workers by December 28, 2011.[30]

Delaware: Indian River Power Station Units 1 and 2

Under a 2007 consent decree reached with the Delaware Department of Natural Resources and Environment, NRG Energy agreed to shut down Indian River Power Station Units 1 and 2 in 2010 and 2011. Unit 1 is an 82 MW unit built in 1957; Unit 2 is an 82 MW unit built in 1959. The company also agreed to install air pollution controls on Units 3 and 4 by the end of 2011 to reduce emissions of nitrogen oxides, sulfur dioxide and mercury.[31]

Delaware: Indian River Power Station Unit 3

On February 3, 2010, the Delaware Department of Natural Resources and Environment announced that it is evaluating a potential agreement with NRG Energy to shut down Indian River Power Station Unit 3, a 177 MW generator built in 1970, after operating the plant through 2013. The plan would replace a previous plan to install pollution controls and continue to operate the plant for decades. According to the DNREC, no permanent jobs are expected to be lost as a result of the shutdown due to attrition, retraining, and redeployment.[31] According to the DNREC, benefits of the shutdown include the following: Expected environmental benefits of the shutdown include:[31]

  • Elimination of between 30 and 40 billion gallons of cooling water drawn annually from Indian River;
  • Elimination of annual kills of aquatic life including hundreds of thousands blue crabs, millions of bay anchovy, and hundreds of thousands of Atlantic menhaden, Atlantic croaker, winter flounder and weakfish;
  • Reduction by about 1,173 tons annually of nitrogen oxide and 6,252 tons of sulfur dioxide;
  • Elimination of 837,000 tons annually of the greenhouse gas carbon dioxide;
  • Reduction in annual fly ash production of between 40,000 and 70,000 tons; and
  • Reduction of mercury emissions by five pounds annually.

Florida: Crystal River to close by 2020, replaced by nuclear plant

In December 2008, Progress Energy Florida announced it will close two of the state's worst polluting coal-fired generators when its new Levy County nuclear plant is up and running in 2020. The company said the closure of two units at its Crystal River Energy Complex in Citrus County represents the equivalent of removing 830,000 vehicles from Florida's roads. The decision follows months of talks with state officials, including Gov. Charlie Crist and Department of Environmental Protection Secretary Michael W. Sole, said Progress Energy Florida chief executive Jeff Lyash. Crist has hoped to reduce state carbon dioxide emissions to the 1990 level by 2025. The scheduled closure of the two Crystal River plants means the company would be 60 percent of the way toward the governor's goal, according to Progress Energy officials. Independent studies have listed the two coal plants among the nation's top 50 polluters.[32]

The energy created by the two Crystal River coal plants, which opened in 1966 and 1969, will be replaced by the new nuclear plant set to be built at a cost of $17-billion in Levy County. Two coal-fired power generators will remain in operation at the Citrus County site, as will a nuclear reactor. Progress Energy will spend $1.3-billion installing air emission-reduction equipment at the two remaining coal-fired plants. Early in 2007, Progress Energy won approval to raise bills 25 percent starting in January to pay for higher 2008 fuel costs and for early costs of the $17-billion nuclear project. The nuclear charge will add about $13 a month to the bill of the average residential customer, about 10 percent more.[32]

Georgia: Georgia Power plans to retire Harlee Branch units 1 and 2 by 2013

In March 2011, Georgia Power announced that it expects to request approval from the Georgia Public Service Commission to decertify two coal-generating units 1 and 2 at the Harllee Branch Generating Plant, totaling 569 megawatts. The company plans to ask for decertification of the units as of the effective dates of the Georgia Multipollutant Rule, which are currently anticipated to be Dec. 31, 2013 for unit 1 and Oct. 1, 2013 for unit 2. GP said the costs of upgrades would be uneconomical for its customers. The commission is expected to vote on the decertification request in spring 2012.[33]

Georgia: Branch, Yates, and Kraft

On January 7, 2013, Georgia Power said it plans to seek approval from Georgia regulators to retire 15 coal-, oil- and natural gas-fired power plants in the state, totaling 2,061 megawatts (MW). The coal plants would be units 3 and 4 at Plant Branch in Putnam County; units 1-5 at Plant Yates in Coweta County; and units 1-3 at Kraft Plant in Port Wentworth. The company said it expects to ask to retire the units, other than Kraft 1-4, by the April 16, 2015, effective date of the U.S. Environmental Protection Agency's (EPA) Mercury and Air Toxics (MATS) rule. The company said it expects to seek a one-year extension of the MATS compliance date for Plant Kraft and retire those units by April 16, 2016.[34]

Georgia: McDonough Steam Generating Plant

In August, 2009, the Chattanooga Times Free Press reported that Georgia Power is moving ahead with plans to replace the McDonough Steam Generating Plant in Smyrna, Ga., with a natural gas-fired plant.[35]

Illinois: Ameren's Meredosia and Hutsonville stations

In October 2011, Ameren announced it will likely shutter its Meredosia Power Station and Hutsonville Power Station by the end of the year, saying the price of complying with impending U.S. Environmental Protection Agency rules - particularly the Transport Rule - was too costly. The Meredosia Energy Center is also the proposed site for FutureGen 2.0, and Ameren said shuttering the plant will not impact the FutureGen project.[36] The power stations were shut down in 2011.[37]

Illinois: Vermillion to close in first quarter 2011

On Dec. 28, 2010, Dynegy announced that it plans to mothball its Vermilion Power Station in Illinois in the first quarter of 2011. Factors influencing the company’s decision, according to a news release from Dynegy, include the relatively small size of the facility, older technologies and coal delivery challenges that lead to high production costs, as well as weak electricity demand, low prices for power and uncertainties over future regulation. Vermilion’s coal is transported from western states by rail to Danville and then trucked to the Vermilion site. This is the most significant factor leading to Vermilion’s higher production costs, according to the news release.[38]

Illinois: University of Illinois Abbott Power Plant

In May 2010, the University of Illinois pledged to stop using coal within seven years as part of a plan to reduce energy use and cut carbon emissions: the Illinois Climate Action Plan, finalized that month. The plan was developed by the campus Sustainability Council. It was submitted to the American College and University Presidents' Climate Commitment, signed by more than 600 schools. The UI is the first Big Ten school to formally submit a climate plan.[39]

To meet its goals, UI is considering alternative fuels that could be used by University of Illinois Abbott Power Plant or another central generation facility, officials said. University buildings – which account for 85 percent of the campus's energy use – are primarily heated by steam produced at Abbott. The plant also produces electricity as a byproduct, with the UI buying additional electricity from private suppliers. Abbott runs primarily on natural gas and coal, with the fuel mix decided by market costs, according to UI officials. The sustainability team concluded that Abbott's natural gas capacity can provide almost enough steam to meet campus demand by itself and should be able to do so in a few years if conservation trends continue. The campus burned 94,171 tons of coal in fiscal 2009, although that figure has dropped 30 percent in fiscal 2010 so far, said Tom Abram, sustainability coordinator in UI Facilities and Services.[39]

Illinois: Midwest Generation retires three units at Will County Station and Waukegan Station

As part of a 2006 agreement with the state of Illinois, Midwest Generation said it plans to shut down the three smallest generating units in its fleet -- two units at the Will County Generating Station in Romeoville and one at its Waukegan Generating Station -- between the end of 2007 and the end of 2010. According to the 2010 Annual Report for Edison International, under an Illinois rule called the Combined Pollutant Standard (CPS), aimed at reducing mercury, NOx and SO2 at Illinois plants, Will County Station Units 1 and 2 were retired in 2010 and Waukegan Generating Station Unit 6 was retired in 2007.[40]

The company also has committed that its smallest plant -- the single-unit Fisk Generating Station in Chicago -- will either have additional controls for sulfur dioxide emissions or be shut down by the end of 2015. The same agreement to shut down or install additional controls applies to the Waukegan Generating Station by the end of 2014 and to the Crawford Generating Station in Chicago by the end of 2018.[41]

In November 2010, the Illinois EPA issued a construction permit to Midwest Generation to install flue gas desulfurization equipment to cut emissions of sulfur dioxide and particulates from Waukegan Generating Station Unit 7. The permit authorizes the company to use a dry scrubbing system with sodium-based sorbents to cut sulfur dioxide emissions as required by state and federal rules at the company's Waukegan coal-fired power plant unit 7 north of Chicago. Midwest Generation spokesman Doug McFarland said the company may wait until "sometime in 2012" to decide whether to invest in the pollution-control equipment or shut down Unit 7. The decision will depend on market conditions and air quality rules.[42]

In 2014 NRG announced that it will close one of its remaining two units at Will County Station by April 2015.[43]

In 2014 NRG announced that it would convert one of the coal units at its Joliet 9 and 29 power stations to natural gas by 2016 and run it as a peaking plant.[44]

Illinois: Midwest Generation to close Fisk and Crawford Stations

In a deal announced on February 29, 2012, after a multi-year community groups, Midwest Generation said it will close its Fisk Generating Station in the Pilsen neighborhood by December 2012 and the Crawford Generating Station in Little Village by the end of 2014.[45] On May 1, 2012, Midwest said it will shutter both plants in September 2012.[46]

Indiana: Edwardsport

Duke Energy closed the Edwardsport Generating Station (existing) in spring 2010, and will begin demolishing the structure by October 2011. Company spokesman Lew Middleton said Duke will turn the site of the old plant in a storage area for burned coal, or slag, produced by Duke's new coal-gasification plant - the Edwardsport Plant - planned for Fall 2012.[47]

Indiana: Tanners Creek Plant

On June 9, 2011, AEP announced that, based on impending EPA regulations as proposed, AEP’s compliance plan would retire nearly 6,000 megawatts (MW) of coal-fueled power generation; upgrade or install new advanced emissions reduction equipment on another 10,100 MW; refuel 1,070 MW of coal generation as 932 MW of natural gas capacity; and build 1,220 MW of natural gas-fueled generation.[48]

Included in the plan:[49]

  • Tanners Creek Plant, Lawrenceburg, Indiana - Units 1, 2 and 3 (495 MW) retired by Dec. 31, 2014; Unit 4 (500 MW) would continue to operate with retrofits.

On February 25, 2013, AEP agreed to stop burning coal at three of its stations by 2015, updating an earlier 2007 settlement of a lawsuit filed in 1999. The three plants are Tanners Creek Generating Station Unit 4 in Indiana, the Muskingum River Power Plant Unit 5 in Ohio, and the Big Sandy Power Plant Unit 2 in Kentucky.[50]

Indiana: IPL to retire Eagle Valley and two units at Harding Street; replacing capacity with new natural gas plant

In May 2013, Indianapolis Power & Light, a subsidiary of AES, announced that the Eagle Valley Station will be retired, with a 650 MW combined cycle gas plant to be constructed at the same site by 2017. At the same time IPL announced plans to retire or refuel two of the three coal-fired units at the Harding Street Station (Units 5 and 6, but not Unit 7).[51]

Indiana: Dean Mitchell station to close, pollution controls at three other plants

On January 13, 2011, the Obama administration brokered a settlement in which Northern Indiana Public Service Co. will permanently shut down an idled coal-fired power plant in Gary, Indana - the Dean Mitchell Generating Station - and spend $600 million to install and improve pollution controls at the company's three other aging electric generators - Schahfer Generating Station in Wheatfield, Bailly Generating Station in Chesterfield, and the Michigan City Generating Station. NIPSCO faced legal troubles for upgrading the power plants to keep them operating while failing to install modern pollution controls required under the Clean Air Act's New Source Review provisions. The plants avoided the toughest provisions of the law for decades, in part because regulators assumed during the 1970s that they wouldn’t be running much longer.[52]

Indiana: Duke ordered to shut down three coal-fired units

On May 29, 2009, U.S. District Judge Larry J. McKinney ordered Duke to shut down three units of the Wabash River Generating Station in Indiana for violations of the federal Clean Air Act. In 2008, a jury found that Duke-owned Cinergy had modified the facilities without installing best-available pollution control technology. In his ruling, Judge McKinney cited increased sulfur dioxide emissions from the units and gave a deadline of September 30, 2009 for closing them. Duke's Chief Legal Officer Marc Manly said the company was disappointed with the court's decision to "accelerate the shutdown." The units, which supply 39 percent of the station's power, were slated to be taken off line in 2012.[53] An appeals court overturned that order in 2010, allowing Duke Energy to restart the units.[54] In Sep. 2011, Duke Energy said it is considering shutting down several of the six units at Wabash River Station, in expectation of impending coal regulations.[54]

Indiana: Duke proposes closing two units at Gallagher station

Under a plan submitted to the Indiana Utility Regulatory Commission on May 24, 2011, Duke Energy said it plans to shut down two coal-burning units at its Gallagher Generating Station and purchase a share of the Cayuga Generating Station in Indiana to make up the difference. The plan is being considered as a potential settlement option in a more than a decade-old lawsuit the company has with the EPA. Duke had been exploring the idea of converting two of the Gallagher burners to natural gas via running a gas pipeline from Kentucky. But the gas pipeline would cost $71 million, while Duke would pay $68 million for its share of the Vermillion Plant, owned by both Duke Ohio — an unregulated subsidiary of Duke Energy — and Wabash Valley Power Association. Duke Energy would own 62.5 percent of that plant and Wabash would own the remainder.

The lawsuit that initiated the filing relates to air quality: the EPA alleges Cinergy — which merged with Duke Energy in 2006 — undertook six power-plant upgrades that added new coal burners in Indiana and Ohio without obtaining new permits as required by New Source Review provisions. Both the Indiana Utility Regulatory Commission and the Federal Energy Regulatory Commission will have to approve either option before Duke moves ahead.[55]

Indiana: Dominion to shut down State Line Plant by 2012

In a May 2011 conference call with financial analysts, Dominion executives announced they had decided that, financially, it is not worth upgrading the State Line Plant to comply with the federal Clean Air Act. The company plans to shutter State Line as early as 2012 and no later than 2014.[52] Later in its 2011 financial documents, Dominion said it will shutter the plant by March 2012. The company opted in early 2011 to withdraw State Line from an auction for long-term electricity contracts. If it had included the plant in its bid, the company said, it would have needed to spend several million dollars installing new pollution controls, which they did not see as economical.[56]

Indiana: Frank Ratts Generating Station

In May 2012 Hoosier Energy announced plans to retire the Frank Ratts Generating Station near Petersburg, IN, by 2015, citing costs associated with new and proposed US Environmental Protection Agency rules. However the company said that new technologies, lower capital costs, changes in environmental compliance time lines, or delays in implementing environmental rules could extend the plant's life.[57]

Iowa: Alliant to close coal boilers at six sites

According to plans filed with the Minnesota Public Service Commission on November 1, 2010, Alliant Energy plans to close coal-fired boilers at six sites in Iowa:[58]

The plan also designates two boilers at Dubuque Generating Station and another at the Sutherland Generating Station for retirement in 2015. Of this list, only one boiler (Lansing 3) is currently operational, and the replacement generation will come in significant part from running newer coal boilers at higher capacity.[58]

Iowa: Pella Municipal Power Plant

On June 8, 2011, the Pella City Council approved a Long-term Comprehensive Power Supply Arrangement with Missouri River Energy Services and Western Minnesota Municipal Power Agency. The agreement would lead to the retiring of the Pella Municipal Power Plant by 2012. A city council member said the size of the plant made it hard to operate economically given impending environmental regulations.[59]

Kentucky: Big Sandy Plant Units 1 and 2

On December 19, 2012, Kentucky Power said it would retire Big Sandy Plant units 1 and 2 in 2015. Unit 1 may be converted to natural gas. The power from Unit 2 will be obtained from AEP Ohio's Dean Mitchell Generating Station.[60]

On February 25, 2013, AEP agreed to stop burning coal at three of its stations by 2015, updating an earlier 2007 settlement of a lawsuit filed in 1999. The three plants are Tanners Creek Generating Station Unit 4 in Indiana, the Muskingum River Power Plant Unit 5 in Ohio, and the Big Sandy Power Plant Unit 2 in Kentucky.[61]

Kentucky: Henderson Station One

Henderson Station One was a coal-fired power station owned and operated by the Henderson City Utility Commission in Henderson, Kentucky. Citing rising costs and mounting environmental regulations, Henderson Municipal Power and Light closed the 58-year-old Station One power plant on Water Street at the end of 2008.[62] HMP&L said it told the 13 full-time employees at the plant that it would assist them in identifying new job openings at HMP&L, the city of Henderson or the Henderson Station Two power plant. According to HMP&L General Manager Gary Quick, "There are constantly openings at Station Two and other plants out there."[62]

Kentucky: LG&E Energy and Kentucky Utilities Company discuss retiring three plants

According to long-range planning documents filed in mid-April 2011 with the Public Service Commission, LG&E Energy and Kentucky Utilities Company are making initial plans to retire coal-burning units at three aging power plants by 2016, including the Cane Run Station in western Louisville, KU's Green River Generating Station in Central City in Western Kentucky, and KU's Tyrone Generating Station in Versailles, which has already been mothballed temporarily. In all, 979 megawatts of coal-burning capacity would be retired in 2016, while the two utilities would add 2,721 megawatts from natural gas — though it's not clear yet where the new gas turbines would be. The utilities currently produce about 8,000 megawatts of electricity.[63]

In September 2011, LG&E said in filings with the Kentucky Public Service Commission that it plans to replace its Cane Run coal plant with a 640 MW natural gas-fired plant by 2016, to be built at the same site. LGE and Kentucky Utilities reportedly also asked the commission to approve the purchase of Bluegrass Generation Co’s 495 MW natural gas-fired power plant, to replace their Green River Generating Station and Tyrone Generating Station.[64]

November 2013: TVA announces plans to retire Paradise Fossil Plant units 1 and 2

On November 14, 2013, TVA announced that it would retire Paradise Fossil Plant units 1 and 2. The board also approved construction of a new gas-fired plant at a cost not to exceed $1.12 billion. The time frame for the retirements was left to the discretion of the CEO.[65][66]

Maryland: NRG to retire Chalk Point Generating Station and Dickerson Generating Station

In December 2013, NRG Energy signaled that it plans to retire the Chalk Point Generating Station and Dickerson Generating Station in May 2017.[67]

Maryland: FirstEnergy closing R. Paul Smith Power Station along with plants in Ohio and Pennsylvania

On January 26, 2012, FirstEnergy said it is permanently closing six of its coal plants by September 1, 2012: Bay Shore Plant, Units 2-4, in Oregon, Ohio; Eastlake Power Plant in Eastlake, Ohio; Ashtabula Plant in Ashtabula, Ohio; Lake Shore Plant in Cleveland, Ohio; Armstrong Power Station in Adrian, Pennsylvania; and the R. Paul Smith Power Station in Williamsport, Maryland. The company said the decision to close the plants is based on the EPA's Mercury and Air Toxics Standards (MATS), which were recently finalized, and other environmental regulations. The total capacity of the retired plants is 2,689 megawatts (MW). Recently, the plants served mostly as peaking or intermediate facilities, generating approximately 10 percent of the electricity produced by the company over the past three years.[68] In August 2010, FirstEnergy had announced it would throttle back power production at four of its smaller, coal-burning power plants, beginning in September and continuing for three-years. The company cited the lackluster economy, low demand for power, and pending federal rules tightening emission standards. The plants were the Lake Shore Plant in Cleveland, OH, all but the largest boiler at the Eastlake Power Plant in Lake County, OH, the Ashtabula Plant, and three of four boilers at the Bay Shore Plant near Toledo, OH. The largest Bay Shore unit, which burns petroleum coke from the nearby BP/Husky oil refinery, continued operating. [69]

Massachusetts: Energy Capital Partners to close Brayton Point in 2017

Just month after purchasing Brayton Point Station from Dominion, private equity firm Energy Capital Partners announced that it would retire the plant in 2017.[70]

Massachusetts: Dominion's Salem and State Line Plants

On November 18, 2010, Dominion said it expects to shut the Salem Harbor coal/oil-fired power plant in Massachusetts within seven years "as the high cost of keeping up with ever more stringent pollution rules could make it uneconomic to keep operating the plant," a company executive said. Dominion CFO Mark McGettrick also told investors that, in addition to the 738-megawatt Salem Harbor, the company may also close the 515 MW State Line Plant in Indiana. The first of the coal units still operating at both plants entered service more than half a century ago. The environmental regulations McGettrick referred to was the U.S. Environmental Protection Agency's planned one-hour ozone rule for 2015-2017, known as the Transport Rule: "If that rule goes into effect, we do not plan to install expensive environmental controls at either of those two stations," Dominion spokesman Dan Genest told Reuters.[71]

Independent System Operator (ISO) New England, which operates the regional power grid, could again decide Salem Harbor is needed for "reliability" -- as the ISO has over the past couple of years. Dominion recently asked the ISO to withdraw the plant from the grid's June 2011 forward capacity auction for 2014-15. The ISO is not expected to decide on the request until 2011. Dominion reportedly wants to withdraw from the auction not because the company wants to shut the plant but because the capacity price has been coming down over the past few years. The capacity auction pays power suppliers (and demand response customers who agree to reduce usage) to remain available to maintain the long-term reliability of the grid.[71]

In Feb. 2011, Dominion said it could retire the Salem plant in June 2014 when the 2013-2014 forward capacity contract ends, if it cannot recover the cost of environmental upgrades needed to run after that date. In October 2010, Dominion filed what is known as a "permanent delist bid" that included a request to recover the cost of the environmental upgrades that would have allowed the plant to opt out of the 2014-2015 forward capacity auction. The ISO rejected that bid in January 2011.[72]

In May, 2011, Dominion announced that all four units of the plant, including the three units that use coal, would shut down by June 2014.[73]

Massachusetts: GDF Suez to shut down Mount Tom Station

In June 2014 GDF Suez said the Mount Tom Station, which has been in operation since 1960, will close in October 2014 after more than three years of on-and-off operation. GDF Suez spokesperson Carol Churchill said the Holyoke plant cannot compete with cheaper natural gas, and confirmed that the company will consider converting the plant to producing electricity from solar energy. In 2013 legislation enabled the state’s Clean Energy Center to allot $100,000 to Holyoke to work on shaping plans for reuse of the Mount Tom site in the event of its closing. GDF Suez had earlier sought approval to halt power production in 2016-17.[74]

Massachusetts: NRG Energy to shut Somerset Power Generating Station

In November, 2009, NRG Energy announced that it would close the Somerset Power Generating Station, a 174 MW coal plant in Somerset, Massachusetts, on January 2, 2010. A company spokesman cited "market forces" and a "requirement that we close down or repower [by] September of 2010." NRG plans to convert the plant from burning coal to a plasma gasification process, which breaks down coal into its component parts before converting it into energy. No timetable for that conversion has been announced.[75]

Opponents of the Somerset plant, including the Conservation Law Foundation, the Massachusetts Clean Air Coalition, and the Toxics Action Center, expressed optimism that the conversion to gasification would prove to be infeasible. "Shutting down Somerset for an indefinite period shows that this old coal-fired plant is not necessary for reliability and undermines the likelihood that the coal gasification project will move forward," said Shanna Cleveland, staff attorney for CLF.[76]

Sylvia Broude, lead organizer for Toxics Action Center, said, “Closing this plant will immediately improve public health in the area, and we will continue to fight to ensure that NRG will not proceed with experimental coal gasification technology that is expected to have significant public health impacts.”[77]

In December 2009, the Conservation Law Foundation (CLF) released a statement saying that an announcement by the Deval Patrick administration would likely stall NRG's plans to retrofit the smaller of the Somerset plants to burn biomass. According to CLF, the state of Massachusetts intends to maintain its incinerator moratorium, suspending projects that would burn construction and demolition debris pending a complete environmental review.[78]

Michigan: Harbor Beach Power Plant

In July 2012 DTE Energy said it plans to retire the Harbor Beach Power Plant in 2015 to comply with new US Environmental Protection Agency rules.[79]

Michigan: Consumers Energy cancels Karn/Weadock expansion, announces retirement of seven aging coal units, and develops two new wind farms

On December 2, 2011, Consumers Energy announced that is was cancelling the proposed 800 megawatt Karn/Weadock Generating Complex Expansion because of "reduced customer demand for electricity due to the recession and slow economic recovery, surplus generating capacity in the Midwest market, and lower natural gas prices linked to expanded shale gas supplies." In addition, the company announced that it was suspending operations by the end of 2014 at seven existing generating units, included two units at the Whiting Generating Plant, two units at the Cobb Generating Plant, and two at the Karn Weadock Generating Complex. The company reported that it began construction in November 2011 of its first wind farm, the 100 MW Lake Winds Energy Park, in Mason County. Consumers Energy is also developing the 150 MW Cross Winds Energy Park in Tuscola County.[80]

Michigan: Marysville Power Plant

DTE's Marysville Power Plant was decommissioned in 2011. The first unit was built in 1943.[81]

Michigan: S.D. Warren Muskegon Power Plant

S.D. Warren Muskegon Power Plant was a 51-megawatt (MW) coal-fired power station owned and operated by Sappi, a South African multinational pulp & paper corporation, in Muskegon, Michigan. The plant provided power to Sappi's Muskegon pulp & paper mill until the entire facility was shut down in 2009.

Minnesota: Xcel Energy plans to retire Black Dog Generating Station and replace with natural gas

On March 15, 2011, Xcel Energy asked Minnesota regulators to approve a certificate of need for a project of retiring Black Dog Generating Station units 3 and 4, and replace the units with natural gas generators. If approved, the new gas plants would begin site preparation in 2012 and come on line in 2016. (Black Dog 1 and 2 were coverted to natural gas in 2002.)[82]

Minnesota: Otter Tail Power will convert Hoot Lake Plant to natural gas

In January 2013, the Minnesota PUC approved a plan to convert the plant to natural gas by 2020. In addition, Otter Tail will install pollution controls at the plant by 2015.[83]

Minnesota: Minnesota Power to convert Syl Laskin to natural gas

On January 30, 2013, Minnesota Power announced that it will convert the Syl Laskin Energy Center to a natural gas peaking plant by 2015.[84][85]

Minnesota: Minnesota Power announces plan to retire Taconite Harbor Energy Center Unit 3

On January 30, 2013, Minnesota Power announced that it will retire the 84 MW Unit 3 of the Taconite Harbor Energy Center by 2015.[86][87]

Missouri: Ameren's Meramec plant may close between 2015 and 2020

In Feb. 2011, Ameren filed its integrated resource plan, outlining the company's strategy for meeting energy demand for the next 20 years, and said the updated coal regulations for air pollution, water use and coal waste disposal would probably prompt the company to close its 58-year-old Meramec Power Plant in St. Louis, Missouri, sometime between 2015 and 2020. The company is looking at a nuclear- or natural gas plant to make up for the plant, rather than improvements in energy efficiency. Although the company found in the report that efficiency is cheaper, they said the company cannot collect the revenue from efficiency measures quickly enough to please its shareholders.[88]

Montana: Corette Plant

In September 2012 PPL said its Corette Plant near Billings, Montana will be mothballed starting in April 2015 because it will cost too much to comply with the Environmental Protection Agency's Mercury and Air Toxics Standard that take effect in April 2015. The plant will then be placed in reserve status, commonly called mothballing. Mothballing the Corette plant, rather than shutting it down permanently, gives PPL Montana the opportunity to resume operations at some point if conditions change.[89]

Nevada: Mohave Generating Station

In 2005, the Mohave Generating Station ceased operations due to a Clean Air Act lawsuit and because Navajo and Hopi tribes passed resolutions ending Peabody’s use of the Black Mesa aquifer. According to the EPA, the coal plant was the dirtiest in the Western U.S., emitting up to 40,000 tons of sulfur dioxide per year.[90]

Nevada: Reid Gardner Station

In June 2013, Nevada Governor Brian Sandoval signed a law accelerating the retirement of Reid Gardner Station. Three of the plant's four units will close in 2014, and the remaining unit will close in 2017.[91] Prior to the new law units 1, 2, and 3 had been scheduled for retirement in 2020 under Nevada Power Company's 2010-2029 Integrated Resource Plan.[92]

New Jersey: England Generating Station

In June 2012 RC Cape May Holdings LLC said it will shut down one coal-fired unit at the B.L. England plant in Marmora and retrofit a second coal-fired unit to a natural gas turbine and will re-fuel a third, oil-burning unit with natural gas. The agreement resolves violations of the Clean Air Act that occurred when the plant was under the ownership of Atlantic Electric, Conectiv, and Pepco Holdings Co., who did not make pollution-control upgrades as required by the federal Clean Air Act when adding significant upgrades to operational features of the plant.[93]

The agreement calls for the cessation of operation of coal-fired Unit 1 by fall 2013; until that occurs, the company must take steps to minimize emissions from this unit. Unit 2, which currently burns coal, and Unit 3, which burns fuel oil and only operates during peak demand periods, are to be converted to natural gas by May 2016. Unit 2 is to be shut down by May 2015 to allow for the conversion.[93]

New Jersey: Howard Down Generating Station

According Bill O’Sullivan, administrator of air quality for the New Jersey Department of Environmental Protection, the Howard Down Generating Station, a 25 MW coal plant operated by Vineland Municipal Electric in New Jersey, was scheduled to replace its last coal-fired generator with natural gas in 2010.[94]

New Mexico: APS to close Four Corners Steam Plant Units 1, 2, and 3

On November 8, 2010, Arizona Public Service announced that it had entered into an agreement to purchase Southern California Edison's share of Four Corners Steam Plant Units 4 and 5, which it plans to retrofit with additional emission controls. The company will close Units 1, 2, and 3. There will be no layoffs at the plant, which employs 549 workers, 74 percent of whom are Navajo.[95] Closing the three units will reduce the capacity of Four Corners by 633 megawatts (nameplate capacity) or 560 megawatts (net summer capacity). Units 1 and 2 were built in 1963, and Unit 3 was built in 1964.

New Mexico: Raton Power Plant

The Raton Power Plant in Raton, NM, stopped generating electricity in February 2006 after the coal source dried up and owner Raton Public Service Company (RPS) was unable to find any other coal sources at similar prices, according to RPS.[96]

New Mexico and Utah: Los Angeles Department of Water and Power 2010 IRP calls for accelerated pullout from Navajo Generating Station and Intermountain Power Station

The 2010 Integrated Resource Plan, a strategic plan for the next 20 years, recommended that LADWP add 630 new megawatts of solar capacity by 2020 and 970 megawatts of solar capacity by 2030. The plan recommended 580 megawatts of new wind power by 2020. The plan designated that 40 percent of solar be in-basin. It recommended incentive programs, feed-in tariff schemes, and other mechanisms for promoting solar. The plan recommended ending purchases of power from the coal-fired Navajo Generating Station by 2014, which is five years ahead of the deadline established by California state law. The plan recommends ending use of power from the coal-fired Intermountain Power Station by 2020, seven years ahead of the scheduled end of such purchases. The plan states that "LADWP is open to a mutually agreeable early compliance plan between the project participants that preserves the site and transmission for clean fossil and renewable generation."[97]

Table 1: Generation Sources for LADWP in 2010 and 2030[98]

Power Source Megawatts (2010) Megawatts (2030)
Coal 1,679 0
Natural Gas 3,415 5,797
Nuclear 387 387
Large Hydro 1,738 1,738
Small Hydro 200 200
Wind 1,000 1,680
Solar 25 995
Geothermal 0 320
Generic 0 160

New York: AES Westover closes in March, 2011

In March 2011 the AES Westover retired its Unit 8 power station in March 2011. Additionally, AES announced it wanted to sell four of its New York coal plants, including Westover. The other plants included AES Cayuga, AES Greenidge and AES Somerset.[99]

North Carolina: Progress Energy announces plan to close N.C. coal plants

On August 18, 2009, Progress Energy announced a plan to close 3 units at its Lee Steam Plant in North Carolina. The company is seeking regulatory approval to build a new natural gas-fired plant at the site. As proposed, the new plant would increase generation capacity at the site by about 550 megawatts, while still reducing overall emissions, including carbon dioxide. The project will cost an estimated $900 million, and is expected to be operational in 2013.[100]

On December 1, 2009, Progress Energy Carolinas announced that by the end of 2017 it would permanently close all of its North Carolina coal plants without sulfur dioxide scrubbers. The 11 units at L.V. Sutton, Cape Fear, Weatherspoon, and Lee total almost 1,500 megawatts and represent about a third of the utility's coal-fired power generation in N.C. The retirement plan includes the following:

  • Lee is still scheduled for retirement in 2013.
  • Sutton is slated for closure in 2014. Progress hopes to replace it with a natural gas-fired power plant.
  • Cape Fear and Weatherspoon will be shut down between 2013 and 2017. The company is considering converting 50 to 150MW of the total capacity to burn wood waste.

The closure plan was filed in response to a request by the N.C. Utilities Commission, which ordered Progress to provide its retirement schedule for "unscrubbed" coal-fired units in North Carolina. The request was a condition of the commission's approval of Progress' plan to close Lee and build a 950-MW natural gas plant at the site.[101][102]

North Carolina: Progress Energy announces plan to close Lee coal plant

On August 18, 2009, Progress Energy announced a plan to close 3 units at its Lee Steam Plant in North Carolina. The company is seeking regulatory approval to build a new natural gas-fired plant at the site. As proposed, the new plant would increase generation capacity at the site by about 550 megawatts, while still reducing overall emissions, including carbon dioxide. The project will cost an estimated $900 million, and is expected to be operational in 2013.[103] North Carolina State regulators approved the plan on October 1.[104]

North Carolina: Duke to close units at Cliffside, Buck Steam, Lee Steam, and Riverbend

Duke has agreed to retire 800 megawatts of older coal units as part of an N.C. permit to build a new 825-megawatt unit under construction at the Cliffside Plant in Rutherford County. That will shutter four old units at Cliffside, two at Buck Steam Station in Rowan County, three at Dan River Steam Station, and two at Riverbend Steam Station in Gaston County.

In September 2010, Duke Energy said it might close seven coal-fired units at its Carolinas power plants within five years as environmental regulations intensify. It may retire by 2015 all coal-fired units for which it's not economical to install sulfur dioxide controls called scrubbers. That would increase by 890 megawatts the coal plants Duke had planned to retire in 2009. The retired units would be at Duke's Riverbend Steam Station in Gaston County, Buck Steam Station in Rowan County, and Lee Steam Plant in Anderson County, S.C. Duke said it might convert Lee from coal to natural gas fuel.[105]

On February 1, 2013, Duke announced it will close Riverbend Steam Station and Buck Steam Station in April 2013, ahead of schedule, saying the plants were being little used.[106]

Ohio: Duke's Beckjord Generating Station

On July 15, 2011, Duke Energy said it expects to retire all six coal-fired generation units at its Beckjord Generating Station in Ohio by Jan. 1, 2015, due to the proposed Environmental Protection Agency (EPA)'s Utility Maximum Achievable Control Technology (MACT) rule, which will be finalised in November 2011, and will require coal-fired plants to reduce emissions of particular toxic air pollutants. The company said it plans to meet demand by buying electricity on the competitive wholesale market or by constructing or acquiring natural gas-fired combined-cycle generating assets.[107]

Ohio: Hutchings Station

In 2012 AES's DPL said it was determining whether it will shut its Miamisburg, Ohio-based Hutchings Station down or retrofit it to run on natural gas, as it was not cost-effective to refit the plant with pollution-control devices to meet impending MACT regulations by 2015.[108]

In May 2013, AES's DPL said it plans to retire units 1, 2, 3, 5 and 6 by June 2015, as the cost of converting the units from coal to gas exceeded the expected return. (The 63-MW coal-fired Unit 4 is already out of service due to damage and will be retired by June 2013).[109]

Ohio: Miami Fort Station

In August 2011, Duke Energy announced that the Miami Fort Station will shut down one of three coal boilers on January 1, 2015. Boiler 6 came online in 1960 and has no pollution controls (scrubbers), and Duke said it would be more economic to shut the boiler down than retrofit it for impending environmental regulations.[110]

Ohio: Richard H. Gorsuch Generating Station

On May 18, 2010, the U.S. Environmental Protection Agency (EPA) and the U.S. Justice Department announced that American Municipal Power - Ohio would be permanently retiring the Richard H. Gorsuch Generating Station by Dec. 31, 2012, under a settlement to resolve violations of the Clean Air Act's New Source Review requirements. Interim sulfur dioxide and nitrogen oxide emission limits will be implemented until that date. Also part of the settlement, AMP will spend $15 million on an environmental mitigation project and pay a civil penalty of $850,000.[111]

Ohio: Picway Power Plant, Conesville Power Plant, and Muskingum River Plant

On June 9, 2011, AEP announced that, based on impending EPA regulations as proposed, AEP’s compliance plan would retire nearly 6,000 megawatts (MW) of coal-fueled power generation; upgrade or install new advanced emissions reduction equipment on another 10,100 MW; refuel 1,070 MW of coal generation as 932 MW of natural gas capacity; and build 1,220 MW of natural gas-fueled generation. The cost of AEP’s compliance plan could range from $6 billion to $8 billion in capital investment through the end of the decade.[48]

AEP’s current plan for compliance with the rules as proposed includes permanently retiring the following coal-fueled power plants:[48]

In addition, six other plants would reduce their power output, including:[112]

  • Conesville Power Plant, Conesville, Ohio - Unit 3 (165 MW) retired by Dec. 31, 2012; Units 5 and 6 (800 MW total) would continue operating with retrofits; and
  • Muskingum River Plant, Beverly, Ohio - Units 1-4 (840 MW) retired by Dec. 31, 2014; Muskingum River Unit 5 (600 MW) may be refueled with natural gas with a capacity of 510 MW by Dec. 31, 2014, depending on regulatory treatment in Ohio.

Ohio (January 2012): FirstEnergy to close Bay Shore Plant Units 2-4, Eastlake Power Plant, Ashtabula Plant, Lake Shore Plant, and plants in Pennsylvania and Maryland

On January 26, 2012, FirstEnergy said it is permanently closing six of its coal plants by September 1, 2012: Bay Shore Plant, Units 2-4, in Oregon, Ohio; Eastlake Power Plant in Eastlake, Ohio; Ashtabula Plant in Ashtabula, Ohio; Lake Shore Plant in Cleveland, Ohio; Armstrong Power Station in Adrian, Pennsylvania; and the R. Paul Smith Power Station in Williamsport, Maryland. The company said the decision to close the plants is based on the EPA's Mercury and Air Toxics Standards (MATS), which were recently finalized, and other environmental regulations. The total capacity of the retired plants is 2,689 megawatts (MW). Recently, the plants served mostly as peaking or intermediate facilities, generating approximately 10 percent of the electricity produced by the company over the past three years.[113] In August 2010, FirstEnergy had announced it would throttle back power production at four of its smaller, coal-burning power plants, beginning in September and continuing for three-years. The company cited the lackluster economy, low demand for power, and pending federal rules tightening emission standards. The plants were the Lake Shore Plant in Cleveland, OH, all but the largest boiler at the Eastlake Power Plant in Lake County, OH, the Ashtabula Plant, and three of four boilers at the Bay Shore Plant near Toledo, OH. The largest Bay Shore unit, which burns petroleum coke from the nearby BP/Husky oil refinery, continued operating. [114]

On May 2, 2012, FirstEnergy said it was delaying the anticipated 2012 closing of its Lake Shore Plant, Ashtabula Plant, and Eastlake Power Plant until 2015 so that it could make upgrades to its transmission lines.[115]

Ohio: FirstEnergy to close Burger Plant units 4 and 5

According to a Nov. 17, 2010 report from Power-Gen Worldwide, FirstEnergy Corp. is planning to permanently shut down two coal-fired units, Units 4 and 5, at the Burger Plant by the end of the year. The units were included in the 2005 Consent Decree settlement with the U.S. Environmental Protection Agency, and FirstEnergy had the option to re-power, install scrubbers, or shut down the units as part of an effort to reduce the company's sulfur dioxide emissions. Rather than refit the Burger plant units, First Energy will complete a $1.8 billion retrofit at its Sammis Plant in Stratton, Ohio, according to the report.[116]

Ohio: Ohio University Lausche Heating Plant

In March 2011, the Ohio University administration made a promise not to consider coal as an energy source for a new heating plant. The administration has said that it must replace the Lausche facility by the year 2016, as the useful life of its boilers draws to a close.[117]

Ohio: GenOn to close Niles and Avon Lake stations

On February 29, 2012, GenOn Energy said it will close seven of its coal generating stations by 2015 (and a natural gas station for a total 13 percent of its generating capacity), citing impending environmental regulations. The coal stations and proposed closing dates are:[118]

Ohio: Muskingum River Plant

On June 9, 2011, AEP announced that, based on impending EPA regulations, AEP would retire nearly 6,000 megawatts (MW) of coal-fueled power generation; upgrade or install new advanced emissions reduction equipment on another 10,100 MW; refuel 1,070 MW of coal generation as 932 MW of natural gas capacity; and build 1,220 MW of natural gas-fueled generation. Retirements included:[48]

  • Muskingum River Plant, Beverly, Ohio - Units 1-4 (840 MW) retired by Dec. 31, 2014; Muskingum River Unit 5 (600 MW) may be refueled with natural gas with a capacity of 510 MW by Dec. 31, 2014, depending on regulatory treatment in Ohio.

On February 25, 2013, AEP agreed to stop burning coal at three of its stations by 2015, updating an earlier 2007 settlement of a lawsuit filed in 1999. The three plants are Tanners Creek Generating Station Unit 4 in Indiana, the Muskingum River Power Plant Unit 5 in Ohio, and the Big Sandy Power Plant Unit 2 in Kentucky.[119]

Oklahoma: Public Service Company of Oklahoma to close 946 MW at Northeastern Station

Under an agreement between Public Service Company of Oklahoma (PSO) and the U.S. Environmental Protection Agency, PSO will retire Unit 3 (473 MW) of its Northeastern Station by 2017, and Unit 4 (473 MW) of the station by 2026. In addition, PSO will install emissions controls on Unit 4. The agreement does not affect Units 1 and 2, which are fired by natural gas.[120]

Ontario shutting 4 plants, considering conversion for remaining 11 plants

Ontario Power Generation will shut down four of its 15 coal-fired power plants in late 2010. The closures include two of eight units at Nanticoke Generating Station, and two of four units at Lambton. The four plants represent about 2,000 megawatts of total generation capacity. The closure of the four units, in addition to the 2005 closure of Lakeview Generating Station in 2005, will reduce the Canadian province's coal capacity by 40 percent. OPG said it would continue to assess converting its remaining 11 units to other types of fuel such as biomass, beginning with the conversion of Atikokan Generating Station by 2012.[121][122]

Oregon: Boardman Plant

On January 14, 2010 it was announced that Portland General Electric will be closing its 601 MW Boardman Plant twenty years ahead of schedule. The plant will close in 2020 instead of 2040. The plant was originally going to invest more than a half billion dollars in pollution controls (scrubbers) by 2017 to comply with EPA and state clean air regulations, then keep it running until 2040.

Instead, the company wants regulators to allow it to make a $45 million investment by 2011 to partially clean up its emissions of mercury and oxides of nitrogen, then operate the plant until 2020.[123] The Oregon Sierra Club and Friends of the Columbia Gorge argue, that while a 2020 close date is better than a 2040 closure, it is still more economical for the plant to shut its doors in 2014. [124]

On February 1, 2010 it was announced that PGE was considering using biomass to continue operating the plant after it ends its use of coal in the future. PGE is said to be considering if it can replace all of the millions of tons of coal it burns every year at Boardman with plant based material that has been pre-treated through a process called torrefaction. While still in experimental phases, torrefaction produces a substance similar to coal, and is also energy intensive to produce. Critics on the other hand cite that no commercial size torrefaction facilities exist and it is still not clear how much carbon will be used in the process of torrefaction.[125]

Pennsylvania: Exelon announces plan to shut coal plants

On December 2, 2009, Exelon announced that it would retire Cromby Generating Station and two units at Eddystone Generating Station in 2011. The closures include 144 MW of coal-fired power at Cromby and another 588 MW at Eddystone. Eddystone will continue to operate 820 MW of natural gas- and oil-fired generation. Exelon senior vice president Doyle Beneby said the retirements were due to "decreased power demand, over supply of natural gas and increasing operating costs," adding that, "these aging units are no longer efficient enough to compete with newer resources."[126] The announcement comes just one day after Progress Energy said it would shut 11 aging coal-fired power units totaling almost 1,500 MW in North Carolina.[127]

Pennsylvania: FirstEnergy closing Armstrong Power Station along with plants in Ohio and Maryland

On January 26, 2012, FirstEnergy said it is permanently closing six of its coal plants by September 1, 2012: Bay Shore Plant, Units 2-4, in Oregon, Ohio; Eastlake Power Plant in Eastlake, Ohio; Ashtabula Plant in Ashtabula, Ohio; Lake Shore Plant in Cleveland, Ohio; Armstrong Power Station in Adrian, Pennsylvania; and the R. Paul Smith Power Station in Williamsport, Maryland. The company said the decision to close the plants is based on the EPA's Mercury and Air Toxics Standards (MATS), which were recently finalized, and other environmental regulations. The total capacity of the retired plants is 2,689 megawatts (MW). Recently, the plants served mostly as peaking or intermediate facilities, generating approximately 10 percent of the electricity produced by the company over the past three years.[128] In August 2010, FirstEnergy had announced it would throttle back power production at four of its smaller, coal-burning power plants, beginning in September and continuing for three-years. The company cited the lackluster economy, low demand for power, and pending federal rules tightening emission standards. The plants were the Lake Shore Plant in Cleveland, OH, all but the largest boiler at the Eastlake Power Plant in Lake County, OH, the Ashtabula Plant, and three of four boilers at the Bay Shore Plant near Toledo, OH. The largest Bay Shore unit, which burns petroleum coke from the nearby BP/Husky oil refinery, continued operating. [129]

Pennsylvania: GenOn to close Elrama, Portland, New Castle, Shawville, and Titus stations

On February 29, 2012, GenOn Energy said it will close seven of its coal generating stations by 2015 (and a natural gas station for a total 13 percent of its generating capacity), citing impending environmental regulations. The coal stations and proposed closing dates are:[130]

Pennsylvania: Hunlock Power Station

Hunlock Power Station's coal units 1 & 2 were retired in 1975. In 2009, the Pennsylvania DEP approved the retrofitting of Hunlock Creek-3 with two gas turbines. At the end of May 2010, the coal-fired boiler was retired, and the gas units installed in 2011.[132]

Pennsylvania: Mitchell Power Station and Hatfields Ferry Power Station to close by October 2013

In July 2013 FirstEnergy announced that it planned to decommission the 288 MW coal-fired unit at the Mitchell Power Station as well as all three coal-fired units at the Hatfields Ferry Power Station by October 9, 2013. In both cases the reason cited for retiring the plants was the the costs of complying with the Environmental Protection Agency's Mercury and Air Toxics Standards (MATS).[133]

Pennsylvania: Portland Generating Station

On February 29, 2012, GenOn Energy said it will close seven of its coal generating stations by 2015, citing impending environmental regulations. This included the Portland Generating Station near Portland, Pennsylvania, with a proposed closure date of January 2015.[134]

In May 2013 NRG Energy, which merged with GenOn Energy in 2012, settled a lawsuit over Clean Air Act violations at the plant with New Jersey and Connecticut, and said it will shut down the Portland coal units early, in June 2014.[135]

Pennsylvania: Sunbury Steam Station

In December 2011, Sunbury Generation announced plans to close five of its six coal-fired generators in Pennsylvania by 2015, including Sunbury Steam Station.[136]

South Carolina: Retirements announced at Canadys, McMeekin, and Uruhart stations

On May 30, 2012, SCANA subsidiary SCE&G announced plans to retire up to six coal-fired generating units at three locations in South Carolina by the end of 2018. The units range in age from 45 to 57 years and are the utility's oldest and smallest coal-fired units. The announcement included the following retirements:[137]

  • Retirement of Unit 1 at the Canadys Station by the end of 2012
  • Planned retirement of the remaining two units (Units 2 and 3) at Canadys by the end of 2017
  • Planned retirement of both units (1 and 2) at the McMeekin Station by the end of 2018
  • Planned retirement of Unit 3 at Urquhart Station by the end of 2018

In addition, the utility announced fuel switching at the following:

  • Switching Unit 3 at the Urquhart Station from coal to natural gas by the end of 2012
  • Planned switching of Units 1 and 2 at the McMeekin Station (both units) and Units 2 and 3 at the Canadys Station from coal to natural gas by 2015

In June 2013 SCE&G said it had re-evaluated its plans and decided to close Units 2 and 3 of its Canadys Station by the end of December 2013.[138]

South Carolina: Grainger Generating Station

In 2012 owner Santee Cooper idled the Grainger station, and decided in October 2012 not to reopen it, saying it would be too costly to comply with the EPA's new Mercury and Air Toxins Standard for air emissions.[139]

South Carolina: Robinson Steam Plant

After the merger of Duke Energy and Progress Energy, Progress Energy Carolinas announced in July 2012 that it would be accelerating the closing of the Robinson Unit 1 coal plant by October 2012, but it would remain online through the summer season to help meet heightened electricity demand.[140]

South Dakota: Black Hills to shutter Ben French Power Plant

On August 6, 2012, Black Hills Corporation announced the following scheduled retirements at its Colorado Electric subsidiary. Prior to final retirement, the company will suspend operations at the coal-fired unit at the Ben French Power Plant in Rapid City, S.D. by August 31, 2012. [141]

Tennessee: TVA Announces Plans to Retire John Sevier Fossil Plant Units 1 and 2

On August 24, 2010 TVA announced that it will retire 9 coal-fired generating units totalling about 1,000 megawatts of capacity at three locations beginning in fiscal year 2011: Shawnee Fossil Plant Unit 10 in Kentucky, John Sevier Fossil Plant Units 1 and 2 in Tennessee, and Widows Creek Fossil Plant Units 1-6 in Alabama. In addition TVA stated that it will eliminate 200 jobs at these plants starting in 2011, but the workers will be placed in other positions within TVA. CEO Tom D. Kilgore said that TVA would replace the sidelined coal power with greater reliance on nuclear power and energy efficiency.[142]

Texas: Energy Future Holdings announces potential coal plant and mine shutdown

It was announced on September 12, 2011 that Texas based coal plant Monticello Steam Station Units 1 and 2 would be idled in January 2012 if Energy Future Holdings, owner of Luminant, failed in its legal challenge to pending federal air pollution rules. It was also reported that the company would close both its Thermo Mine and Winfield South Mine at the same time.[143]

Texas: San Antonio coal plant to be 1st in Texas to close

In June 2011 CPS Energy announced that its San Antonio based J.T. Deely Station would be shut down in 2018. The coal-fired power plant that supplied electricity in San Antonio since the 1970s. The CPS Deely plant is the first publically-owned coal plant announced to retire in Texas.

According to the president of CPS Energy, Doyle Beneby, their plans will cut emissions of sulfur dioxides by 85%, nitrus oxide by 30%, carbon dioxides by 25%, and mercury by 58% by the time the plant closes.

"Closing Deely coal plant and transitioning to a clean energy economy will be a tremendous benefit for San Antonio," according to a joint news release released by the Sierra Club, SEED Coalition, and Public Citizen.[144]

Texas: Welsh Power Plant, Unit 2

On June 9, 2011, AEP announced that, based on impending EPA regulations as proposed, AEP’s compliance plan would retire nearly 6,000 megawatts (MW) of coal-fueled power generation; upgrade or install new advanced emissions reduction equipment on another 10,100 MW; refuel 1,070 MW of coal generation as 932 MW of natural gas capacity; and build 1,220 MW of natural gas-fueled generation. The cost of AEP’s compliance plan could range from $6 billion to $8 billion in capital investment through the end of the decade. AEP’s current plan for compliance with the rules as proposed includes permanently retiring five of its coal-fueled power plants.[48]

Included in the plan:[145]

  • Welsh Power Plant, Pittsburg, Texas - Unit 2 (528 MW) retired by Dec. 31, 2014; Units 1 and 3 (1,056 MW) would continue to operate with retrofits.

Utah: Utah Smelter Power Plant

In December, 2010, Kennecott Utah Copper announced that it would repower units 1-3 of its Utah Smelter power plant to run on natural gas. However, unit 4 of the plant will continue to be powered by coal. [146]

Virginia: Glen Lyn Plant and Clinch River Plant

On June 9, 2011, AEP announced that, based on impending EPA regulations as proposed, AEP’s compliance plan would retire nearly 6,000 megawatts (MW) of coal-fueled power generation; upgrade or install new advanced emissions reduction equipment on another 10,100 MW; refuel 1,070 MW of coal generation as 932 MW of natural gas capacity; and build 1,220 MW of natural gas-fueled generation. The cost of AEP’s compliance plan could range from $6 billion to $8 billion in capital investment through the end of the decade.[48]

AEP’s current plan for compliance with the rules as proposed includes permanently retiring the following coal-fueled power plants:[48]

  • Glen Lyn Plant, Glen Lyn, Va. – 335 MW (retired by Dec. 31, 2014).

In addition, six other plants which will reduce their power output, including:[147]

  • Clinch River Plant, Cleveland, Va. - Unit 3 (235 MW) retired by Dec. 31, 2014; Units 1 and 2 (470 MW total) would be refueled with natural gas with a capacity of 422 MW by Dec. 31, 2014.

Virginia: TVA to close Allen Fossil Plant

In April 2014, the TVA board of directors voted to retire the Allen Fossil Plant and build a new, combined-cycle natural gas plant nearby. The new gas plant will be 1,000 MW and operable by the end of 2018.[148]

Virginia: Dominion to convert Altavista, Hopewell, and Southampton plants to biomass

In Feb. 2011, Dominion Virginia Power said it could reopen its 63 MW Altavista Power Station as a biomass electricity plant by 2013, and is starting the approval process. In Fall 2010, Dominion placed the Altavista station on “cold reserve status,” meaning it could be restarted if needed. At the time, Dominion was studying whether to convert the plant to a biomass facility. The study suggested that a biomass facility would be competitive economically against natural gas plants. If the town of Altavista grants Dominion’s special use permit request, the company said it will seek a new air permit and approval from the State Corporation Commission.[149]

In April 2011, Dominion Resources announced that its subsidiary Dominion Virginia Power, has decided use biomass instead of coal in three of its power stations: Altavista Power Station, Hopewell Power Station and Southampton Power Station. The plants will mainly use waste wood left from timbering operations as a source of fuel. If approved by the local authority and the regulators will begin production from the converted units in 2013. The units can presently produce 63 megawatts (MW) power each and are only used when demand is at its peak. After conversion, these units will produce 50 MW each.[150]

Virginia: Dominion proposes closing North Branch Station for approval of new natural gas plant

In a December 2010 accord reached with the National Park Service and the Virginia Department of Environmental Quality, Dominion volunteered to close its North Branch Station when the proposed natural gas-fired Warren County Power Station near Front Royal begins commercial operations, which is scheduled for late 2014 or early 2015. Emissions reductions credits from closing the station will be combined with various other offsets to be applied as the emission mitigation plan for the new power station. The agreement is conditioned upon the Virginia Air Pollution Control Board's approval of the air permit for the proposed station, other regulatory approvals and the construction and operation of the proposed station. The air board is expected to vote on Dominion's application for the Warren County air permit at its Dec. 17, 2010 meeting. The company anticipates seeking permission from the Virginia State Corporation Commission in 2011 to build the new power station.[151]

North Branch was put in cold reserve status in August 2010, and has not been generating electricity. Without this agreement, the station could be returned to service in a short time if needed.[151]

Virginia: Chesapeake Energy Center and Yorktown Power Station

Dominion announced on Sept. 1, 2011 "potential generation retirements" at both the Chesapeake Energy Center and the Yorktown Power Station by 2016.[152] According to the company's 2011 Integrated Resource Plan, Chesapeake Energy Center Units 1 (111 MW) and 2 (111 MW) will be retired by 2015. Chesapeake Energy Center Units 3 (156 MW) and 4 (217 MW) will be retired by 2016. Yorktown Unit 1 (159 MW) will be retired by 2015. Yorktown Unit 2 (156 MW) will be retired by 2022. of the four units at the Chesapeake center are expected to be shut down by 2015 and the remaining two units would likely be shut down a year later.[153]

In July 2014, the company said it planned to shut down all units of its Chesapeake Energy Center by the end of 2014.[154]

Virginia: City of Alexandria and GenOn Agree to Close Potomac River Generating Station

The City of Alexandria and GenOn Energy have reached an agreement to retire this power plant by October 1, 2012, unless needed for reliability purposes.[155]

Washington: TransAlta to close Centralia Power Plant

On April 11, 2011 the Washington State House of Representatives voted overwhelming to approved Senate Bill 5769, which would shut down one of two boilers at the Centralia Power Plant coal-fired plant by 2020 and phase out coal-burning by 2025. TransAlta, state officials and environmental groups negotiated a deal in March 2011 to close the plant in Centralia. The measure requires the company to provide $55 million for economic development and other assistance, and to install additional air pollution controls called scrubbers to further reduce emissions of nitrogen oxides at the plant.

In exchange, TransAlta would be allowed enter into long-term agreements to sell its electricity to other utilities, which is currently prohibited by state law.

Lawmakers in the House made mostly technical changes to the bill, which passed by an 87-9 vote. The bill was later passed by the Washington State Senate.[156]

On May 3, 2011, Governor Chris Gregoire signed legislation today that will close the plant by 2025.[157] It was also reported that natural gas was being discussed as the replacement fuel for the TransAlta plant.[158]

Text of SB 5769 here

West Virginia: Albright Power Station, Willow Island Power Station, and Rivesville Power Station

On February 8, 2012, FirstEnergy announced that its Monongahela Power Company (Mon Power) subsidiary would be retiring three older coal-fired power plants located in West Virginia by September 1, 2012: Albright Power Station, Willow Island Power Station, and Rivesville Power Station. The total capacity of the regulated plants is 660 megawatts (MW), about 3 percent of FirstEnergy’s total regulated and competitive generation portfolio.

Recently, the plants had served mostly as peaking facilities, generating around less than 1 percent of the electricity produced by FirstEnergy over the past three years. The company said the decision to close the plants was based on the EPA's Mercury and Air Toxics Standards (MATS) that were recently finalized, and other environmental regulations.[159]

West Virginia: Kammer Plant, Kanawha River Plant, and Philip Sporn Power Plant

On June 9, 2011, AEP announced that, based on impending EPA regulations as proposed, AEP’s compliance plan would retire nearly 6,000 megawatts (MW) of coal-fueled power generation; upgrade or install new advanced emissions reduction equipment on another 10,100 MW; refuel 1,070 MW of coal generation as 932 MW of natural gas capacity; and build 1,220 MW of natural gas-fueled generation. The cost of AEP’s compliance plan could range from $6 billion to $8 billion in capital investment through the end of the decade.[48]

AEP’s current plan for compliance with the rules as proposed includes permanently retiring the following coal-fueled power plants:[48]

  • Kammer Plant, Moundsville, W.Va. – 630 MW (retired by Dec. 31, 2014) (pictured above)
  • Kanawha River Plant, Glasgow, W.Va. – 400 MW (retired by Dec. 31, 2014); and
  • Philip Sporn Power Plant, New Haven, W.Va. – 1,050 MW (450 MW expected to retire in 2011, 600 MW retired by Dec. 31, 2014).

West Virginia: Dominion's North Branch Station

In a December 2010 accord reached with the National Park Service and the Virginia Department of Environmental Quality, Dominion volunteered to close its North Branch Station when the proposed natural gas-fired Warren County Power Station near Front Royal begins commercial operations, which is scheduled for late 2014 or early 2015. Emissions reductions credits from closing the station will be combined with various other offsets to be applied as the emission mitigation plan for the new power station. The agreement is conditioned upon the Virginia Air Pollution Control Board's approval of the air permit for the proposed station, other regulatory approvals and the construction and operation of the proposed station. The air board is expected to vote on Dominion's application for the Warren County air permit at its Dec. 17, 2010 meeting. The company anticipates seeking permission from the Virginia State Corporation Commission in 2011 to build the new power station.[151]

North Branch was put in cold reserve status in August 2010, and has not been generating electricity. Without this agreement, the station could be returned to service in a short time if needed.[151]

Wisconsin Considers Five Plant Closures

In 2007 the Sierra Club challenged the State of Wisconsin over pollution emissions from five of its state-run coal plants used to provide heat and power to four state-run university buildings and one hospital. The plants include those that function at UW-Eau Claire, UW-La Crosse, UW-Oshkosh, UW-River Falls and Mendota Mental Health Institute. The State's Department of Natural Resources sided with the Sierra Club, and now the state of Wisconsin has to decide on whether or not to install pollution-control equipment to greatly reduce emissions, or reduce the use of coal all together. As decision is to be made by spring 2010.[160]

The Sierra Club alleged that the millions of dollars in upgrades made at these facilities were significant and actually increased the potential for the plants to emit more pollution.[161]

Wisconsin: Alma Station

In December 2011, Dairyland Power Cooperative said it will stop using three aging coal-burning units at the Alma Station, adding up to about 60 megawatts. The three units, all built in the 1950s, generated just 0.4 percent of the cooperative’s power in 2011, and will now only be used only for emergencies. Two other Alma coal plants with 120 megawatts of capacity will continue supplying the network.[162]

Wisconsin: Menasha Power Plant Closed

In 2009 the Menasha Power Plant in Menasha, Wiconsin stopped burning coal. In May 2011, it was reported that the plant was considering reopening with biomass pellets replacing coal as its energy source.[163]

Wisconsin: Nelson Dewey Generating Station and Edgewater Generating Station

In July 2012 Wisconsin Power & Light said it will shut down three aging, coal-fired electricity generating units by the end of 2015, and had not decided yet how to replace the power.

Plans include:[164]

Close the Nelson Dewey Generating Station in Cassville;
Close the 60-megawatt Edgewater Generating Station Unit 3 generator in Sheboygan;
Either close Edgewater Generating Station Unit 4 or convert it to burn natural gas by the end of 2018; and
Add scrubbers to Edgewater Generating Station Unit 5 to reduce sulfur dioxide emissions.

Wyoming: Black Hills to shutter Osage Power Plant and Neil Simpson Unit 1

On August 6, 2012, Black Hills Corporation announced the following scheduled retirements at its Colorado Electric subsidiary. Prior to final retirement, the company will suspend operations at the coal-fired unit at the Ben French Power Plant in Rapid City, S.D. by August 31, 2012. [165]

Sierra Club calls for closure of three coal plants in Texas

On March 18, 2011 the Sierra Club released a report stating that three of plants owned by Energy Future Holdings/Luminant in East Texas should be shut down because the facilities do not meet Clean Air Act standards and need $3.6 billion in upgrades in order to comply with federal regulations.

The three plants targeted were Big Brown, Monticello Steam Station and the Martin Lake Steam Station plant. The Sierra Club expressed concern about "the major threats to air and water pollution that citizens in the Barnett Shale [in North Texas] are dealing with firsthand."[166][167]

The study recommended:

"[R]eplacement of three coal fired power plants built in the 1970’s (Big Brown, Monticello and Martin Lake) is a financial and environmental necessity. The plants, currently owned by Energy Future Holding/Luminant and serving North Texas are financially mismanaged, cannot compete profitably in the current market, require pollution control upgrades that are unaffordable and have suffered deep losses in market value. The financial outlook for the company and the plants going forward show very little upside. A broad look at the national and Texas energy market suggest planning tools and resources exist to ensure a smooth transition to a more financially stable and reliable supply of electricity."

Resources

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