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Last updated 6/2/2014 Current and Expected Energy From Coal for California 1 

Actual and Expected Energy From Coal for California − Overview 

Electricity supplies from existing coal and petroleum coke plants represented about 8 percent of 

the total energy requirements to serve loads in California load during 2012. A little over 93 

percent of this coal-based energy came from power plants located outside California. 

From 2007 to 2012, coal energy imports declined by 18 percent, a trend that will continue 

through 2019 as existing contracts expire and as ownership interests are divested or retired. 

From 2007 to 2012, energy from in-state coal and petroleum (pet) coke plants declined by 62 

percent. These trends are shown in Figure 1. Eight in-state coal and pet coke plants retired or 

stopped operating in 2011 and 2012. Of the 16 in-state coal and pet coke plants that once 

operated in California, only two coal plants and one pet coke plant continued to operate in 

2013, and the capacity of in-state coal-fired generation dropped almost 200 megawatts from 

2012 to 2013. However, two in-state coal plants that have not been operating since 2012, each 

with a capacity of 38 MW, announced that operations would resume in June 2014. By 2022, 

coal energy from imports and in-state plants are expected to equal 4.7 percent of the firm 

energy requirements for all load-serving entities (LSEs) statewide, down from 9.2 percent in 

2007. 

Figure 1: Actual and Forecast Energy From Coal for California Loads (2007-2032) 

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

GWh

Total Energy

Supplies from

Coal

Coal Energy

Imports

Energy from

In‐State Coal

& Pet Coke

Plants

Actual Forecast

Source: Electricity Supply Forms (S-2 and S-5) submitted by LSEs for the California Energy Commission’s 2009, 2011, and 2013 

Integrated Energy Policy Reports (IEPR) available at http://energyalmanac.ca.gov/electricity/. 
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Last updated 6/2/2014 Current and Expected Energy From Coal for California 2 

Additional Information 

Coal Energy Imports 

Coal-based energy supplies totaled 23,323 gigawatt hours (GWh) in 2012, equal to about 

8 percent of the statewide energy requirements to serve California loads. A little over 93 percent 

of this coal-based energy came from power plants located outside California. Nearly all these 

energy imports are tied to long-term utility power purchase agreements, ownership interests, or 

procurement contracts, some of which have been in place for several decades. 

Publicly owned utilities in Southern California have most of the long-term contracts with out-ofstate coal plants. These contracts include obligations to pay for shares of energy from coal 

plants when they are generating. Utilities pay for this as-available energy and take ownership at 

a point of delivery near the power plant. If there are constraints that limit the ability to deliver this 

energy to load, utilities will lay off or resell the energy to other parties. Wholesale energy 

transactions in short-term and spot markets have been used to make room for renewable 

energy purchases, to balance loads and resources in real-time grid operations, and to 

accommodate dispatch limitations caused by system constraints. Thus, a long-term utility 

obligation to pay for coal-fired energy supplies does not include a requirement to transmit the 

energy into California for delivery to their retail customers. 

The state’s Emissions Performance Standard (EPS) prohibits California utilities from signing 

new contracts that would increase the generating capacity or extend the life of any baseload 

generating facility that exceeds 1,100 pounds of carbon dioxide equivalent (CO2e) emissions 

per megawatt hour (MWh). All existing contracts with coal-fired generating facilities provide 

baseload energy supplies that exceed emissions limits defined in the EPS. As these contracts 

expire, they cannot be renewed or extended with another long-term contract.1

Furthermore, U.S. Environmental Protection Agency (U.S. EPA) regulations2 may require 

extensive investments in pollution control retrofit technology. There is uncertainty about what 

will happen to coal-burning power plants in response to these state and federal regulations; 

some facilities may shut down or be repowered to burn natural gas or biomass. 

At a January 29, 2013, workshop in the EPS rulemaking, publicly owned utilities provided 

updates on progress they have made regarding expenditures and investments that are needed 

to meet existing U.S. EPA pollution control retrofit technology requirements. Several publicly 

owned utilities reported significant progress in negotiating early divestiture or early termination 

                                                           

1 Adopted regulations, FAQs, public notices, and utility compliance filings are posted at 

http://www.energy.ca.gov/emission_standards/index.html. 

2 http://www2.epa.gov/carbon-pollution-standards 
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Last updated 6/2/2014 Current and Expected Energy From Coal for California 3 

of contractual obligations related to these plants. Early divestitures and early terminations may 

allow utilities to avoid significant costs that could be required to make coal plants compliant with 

recent U.S. EPA regulations and determinations. 

In 2012, California utilities imported 21,743 GWh of electricity from coal-burning plants located 

in other western states. As shown in Figure 2, the largest share, 44 percent, came from the 

Intermountain Power Plant (IPP) near Delta, Utah. IPP is owned by 23 municipal utilities in Utah 

and has a rated capacity to generate 1,800 MW. IPP supplies energy to six Southern California 

utilities under long-term power sales contracts that began in August 1990 and are scheduled to 

expire in June 2027. In 2012, imports from IPP declined sharply because of a catastrophic 

failure in the Intermountain Unit 1 generator on December 28, 2011, that forced this unit offline 

for several months. Average annual imports from IPP for five prior years (2007-2011) were 

12,865 GWh. The majority of energy exports from IPP go to the Los Angeles Department of 

Water and Power (LADWP). Information about the contract expiration, operation, and ownership 

status can be found in Table 1. 

Figure 2: Coal Energy Imports in 2012 (21,743 GWh) 

Intermountain

44% Four Corners

24%

Navajo

San Juan 16%

11%

Reid Gardner

4%

Boardman

1%

Source: Electricity Supply Forms (S-2 and S-5) submitted by LSEs for the California Energy Commission’s 2009, 2011, and 2013 

Integrated Energy Policy Reports (IEPR) available at http://energyalmanac.ca.gov/electricity/. 

The second largest source of imported coal-fired energy in 2012 was the Four Corners 

Generating Station near Fruitland, New Mexico, on the Navajo Indian Reservation. Until the end 

of 2013, Southern California Edison (SCE) owned a 48 percent share of Four Corners Units 4 

and 5, an ownership interest that totaled 740 MW. 
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Last updated 6/2/2014 Current and Expected Energy From Coal for California 4 

The third largest source of coal-fired energy in 2012 was the 2,250 MW Navajo Generating 

Station near Page, Arizona. LADWP owns a 21 percent interest (477 MW) in Navajo that 

terminates at the end of 2019. 

The fourth largest source of coal-fired energy in 2012 was the San Juan Generating Station 

near Farmington, New Mexico. This 1,800 MW plant came on-line in 1972 and is operated by 

the Public Service Company of New Mexico (PNM). The Southern California Public Power 

Authority (SCPPA) has a 41.8 ownership interest in San Juan Unit 3 that is contractually 

allocated to five of its member utilities: Azusa, Banning, Colton, Glendale, and the Imperial 

Irrigation District (IID). As of early 2013, the IID expected the energy supply from San Juan 3 to 

continue through at least 2022, but the other SCPPA members expected this supply to 

terminate after 2017. The City of Anaheim has a 10 percent ownership interest in San Juan Unit 

4 through calendar year 2022. Three other California utilities have a 28.8 interest in Unit 4. 

These three are the Modesto Irrigation District (MID), Silicon Valley Power (SVP), and Redding 

Electric Utility through a joint powers agency, the M-S-R Public Power Agency. In early 2013, 

MID and Redding expected their energy supply from San Juan 4 would terminate after 2017, 

though SVP expected this supply to continue. 

The fifth largest source of coal-fired energy in 2012 was Reid Gardner Generating Station near 

Moapa, Nevada. This four-unit 557 MW power plant is operated by NV Energy. The California 

Department of Water Resources (CDWR) and NV Energy jointly owned 257 MW Unit 4 that 

came on-line in 1983. CDWR’s 67.8 percent ownership interest in Unit 4 terminated on July 25, 

2013. 

The sixth largest source of coal-fired energy imports to California is the Boardman Plant in 

northeastern Oregon. Portland General Electric (PGE) operates this 585 MW power plant and 

owns 65 percent of it. Turlock Irrigation District (TID) has a power purchase agreement with 

PGE for a pro rata 58.5 MW unit-contingent share of energy production. This purchase 

agreement began in January 1994 and terminates at the end of 2018. From 1989 through 2013, 

San Diego Gas & Electric Co. (SDG&E) had a power purchase agreement for a share of 

Boardman’s energy production equal to 89 MW. In June 2013, PGE announced plans to close 

Boardman by the end of 2020.3

Table 1 provides a summary of actual coal-based energy supplies in 2012 and a 2022 forecast, 

along with information on contract, ownership, and plant status. 

                                                           

3 PGE at: 

http://www.portlandgeneral.com/community_environment/initiatives/boardman_plant_air_emissions.aspx. 
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Last updated 6/2/2014 Current and Expected Energy From Coal for California 5 

Table 1: Expiration of Coal Energy Contracts and Ownership Interests That Serve California Loads 

Plant Name 2012 

GWh 

2022 

GWh 

CONTRACT & 

OWNERSHIP 

STATUS 

POWER PLANT STATUS 

Four Corners 

Units 4 and 5 

5,156 0 Terminated in 

2013 

In March 2012, the CPUC approved SCE’s request to 

sell its 740 MW ownership in Units 4 and 5 by 2016. 

[http://docs.cpuc.ca.gov/word_pdf/AGENDA_DECISIO

N/162229.pdf.] On December 30, 2013, Arizona Public 

Services Company (APS) purchased SCE’s interest in 

Units 4 and 5. By agreement with the U.S. EPA, APS 

will add selective catalytic reduction equipment on 

Units 4 and 5 by July 2018 and shut down Units 1-3. 

Intermountain 

Power Plant 

9,543 12,812 Expires 2027 Los Angeles Department of Water and Power 

(LADWP) announced changing its contract to retire 

coal-firing two years earlier than planned, from 2027 to 

2025. The contract may be replaced with another that 

is based on natural gas-fired generation. 

[http://www.ladwpnews.com/go/doc/1475/1727379/] 

Navajo 3,436 0 Expires 2019 LADWP is negotiating the terms to sell its contract 

share to the Salt River Project (SRP, plant operator) 

and expects to terminate deliveries by the end of 2015. 

[http://www.ladwpnews.com/go/doc/1475/1727379] 

The SRP plans to shut down Unit 1 and is awaiting a 

U.S. EPA decision on new emission control 

requirements ($500 million to $1.1 billion costs) that 

may force plant closure. 

Reid Gardner 

Unit 4 

993 0 Expired 

July 25, 2013 

NV Energy may shut down Units 1-3 by 2020 and 

continue to operate Unit 4 for its customers. 

San Juan 

Units 3 and 4 

2,347 1,626 SJ3 contracts 

through SCPPA 

expire 2030; 

Anaheim’s 

contract for SJ4 

expires 2022; 

M-S-R owns 

28.8% of SJ4 

New Mexico Environmental Department settlement to 

shut down Units 2 and 3 by December 31, 2017. 

Negotiations are underway to meet U.S. EPA rules 

($77-$750 million for different emission reduction 

technologies) for later divestiture, conversion to natural 

gas, or shut down remaining units. 

Boardman 268 0 SDG&E’s 

contract expired 

2013; TID’s 

contract expires 

2018 

PGE will terminate burning coal by 2020. 

[http://www.portlandgeneral.com/community_environm

ent/initiatives/boardman_plant_air_emissions.aspx] 

Coal-Fired 

QFs in CA 

1,580 327 All but one of 

the QF 

contracts expire 

by 2020 

See Table 2. 

Total GWh 23,323 14,486 38% decline*

2012 to 2022 

 

MMT CO2e 

Emissions 

24 15 38% decline*

2012 to 2022 

 

Source: Electricity Supply Forms (S-2 and S-5) submitted by utilities for the 2013 IEPR and available at 

http://energyalmanac.ca.gov/electricity/index.html. 

*NOTE: Due to calculation errors, the May 24, 2013, version of this table underestimated generation in 2020 from IPP and the coalfired QFs in California. Comparison with this version of the table makes it appear as though expected generation in coming years 

has increased. For this version, staff corrected the errors and expects that coal-fired generation directly attributable to discrete 

sources will not increase, save for potential short-term (fewer than five years in duration) acquisitions/contracts that may take place. 
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Last updated 6/2/2014 Current and Expected Energy From Coal for California 6 

As shown in Table 1, the supply of coal-fired energy procured by California utilities from out-ofstate plants or generated in California by coal and pet coke plants is expected to decline by 38 

percent between 2012 and 2022. In these years, associated greenhouse gas emissions are 

expected to drop from about 23.8 million metric tons (MMT) of carbon dioxide equivalent (CO2e) 

to 14.8 million tons. On average, coal combustion releases 2,249 pounds of carbon dioxide into 

the atmosphere for each MWh generated.4

 This decline in coal contract deliveries is due in 

large part to the constraints imposed by the EPS created by Senate Bill 1368 (Perata, Chapter 

598, Statutes of 2006). Figure 1 shows actual coal-based energy imports for years 2007-2012 

and the forecast for these supplies through 2032. 

Of the coal energy imports in 2012, the largest share, 44 percent, went to LADWP, followed by 

24 percent to SCE, 7 percent to Anaheim, and 5 percent to CDWR. The other 19 percent went 

to the nine publicly owned utilities shown in Figure 3: Riverside, Pasadena, IID, Burbank, MID, 

SVP, Glendale, TID, Colton, Azusa, Redding, Banning, and Truckee Donner Public Utility 

District, which had a negligible 14 GWh from a short-term contract that expired in 2012. 

Figure 3: Out-of-State Coal Energy Supplies to California LSEs in 2012 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

GWh

LADWP

SCE

Anaheim

CDWR

Riverside

Pasadena

IID

Burbank

MID

SVP

Glendale

TID

Colton

Azusa

Redding

Banning

Truckee

Source: Electricity Supply Forms (S-2 and S-5) submitted by LSEs for the California Energy Commission’s 2009, 2011, and 2013 

Integrated Energy Policy Reports (IEPR) available at http://energyalmanac.ca.gov/electricity/. 

                                                           

4 http://www.epa.gov/cleanenergy/energy-and-you/affect/coal.html. 
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Last updated 6/2/2014 Current and Expected Energy From Coal for California 7 

Figure 4 shows how coal energy imports have been declining as a share of the firm energy 

requirement for California load-serving entities (LSEs), from 9.2 percent in 2007 and 2010, 

down to 7.7 percent in 2012. This trend is expected to continue: 4.7 percent in 2020 and 4.5 

percent in 2022. The firm energy requirement includes retail sales, utility uses, transmission and 

distribution losses, and firm wholesale supply obligations. 

Figure 4: Coal Energy Imports as a Percentage of Firm LSE Energy Requirements 

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

8.0%

9.0%

10.0%

Coal Energy Imports

as a Percentage of

Firm LSE Energy

Requirements

Source: Electricity Supply Forms (S-2 and S-5) submitted by LSEs for the California Energy Commission’s 2009, 2011, and 2013 

Integrated Energy Policy Reports (IEPR) available at http://energyalmanac.ca.gov/electricity/. 

For LADWP, coal energy supplies were equal to 34 percent of the firm energy requirement in 

2012. Since IPP production was lower than usual in 2012, this share is expected to return to 

about 49 percent until early divestiture of Navajo lowers that share to about 36 percent. While 

SCE had the second largest procurement of coal-fired energy among California LSEs, the share 

from coal represented only 6 percent of SCE’s firm energy requirement. 

Coal energy procurement in 2012 represented a significant share of the firm energy requirement 

for eight other Southern California utilities, led by Banning (86 percent), Azusa (67 percent), 

Anaheim (63 percent), Colton, (55 percent), Pasadena (48 percent), Burbank (40 percent), 

Riverside (29 percent), and Glendale (16 percent). These utilities have long-term obligations to 

pay for as-available, unit-contingent energy from IPP and San Juan. Some utilities are already 

laying off this energy supply to other wholesale parties including power marketers and to LSEs 

in other western states. Many utilities are exploring early divestiture. 
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Last updated 6/2/2014 Current and Expected Energy From Coal for California 8 

Coal and Petroleum Coke Power Plants in California 

In 2007, there were 16 power plants in California that burned coal or pet coke to generate 4,148 

GWh of electricity. Of this total, 7 percent was generated at two privately owned plants and used 

entirely for onsite use in cement making or oil refining. The other 14 plants (with 93 percent of 

generation in this category) are cogeneration facilities that produce electricity under contract to 

investor-owned utilities. These cogeneration facilities qualified for special rates and regulatory 

treatment afforded by the Public Utility Regulatory Practices Act of 1978 (PURPA). Also known 

as qualifying facilities (QFs), these plants generate electricity, produce thermal energy (steam or 

heat) for industrial uses, and were deemed more efficient than the separate production of 

thermal and electrical energy.5

 

By 2012, energy from in-state coal and pet coke plants dropped to 1,580 GWh, down 61 percent 

from 2007. Since 2007, 11 of the 16 in-state coal and pet coke plants have retired, reducing 

total nameplate capacity from 593 MW to 275 MW (down 54 percent). Ten of these QF plants 

retired in 2011 or 2012. Two other plants (76 MW) stopped operating in October 2012, but 

announced in May 2014 that operations would resume. Only two coal-burning plants and one 

pet coke plant continued to supply electricity to investor-owned utilities at the end of 2012. 

Table 2 shows the operational and contractual status of coal and pet coke power plants in 

California, including 2012 energy production in MWh. 

As shown in Figure 1, there is a clear trend of declining in-state energy production from QFs 

that use coal or pet coke as their primary fuel. In-state coal and petroleum coke plants in 

California supplied a small, declining share of total firm LSE energy requirements: 1.6 percent in 

2007 and 0.6 percent in 2012. Energy Commission staff expects this share to decline to 0.2 

percent in 2016 with only the Argus Cogen Plant and Wilmington Calciner remaining in 

operation. However, if the Rio Bravo Jasmin and Rio Bravo Poso plants resume operations 

equal to 2010 energy production (total 567,294 MWh), the share of total firm LSE energy 

requirements supplied by in-state coal and pet coke plants would be 0.4 percent in 2016. 

Current Status of Coal Conversions to Biomass 

Two plants that were operational in 2007 and one other plant that was not operating in 2007 

have converted to biomass or are in the conversion process. Table 2 provides data on the 

status of these plants. 

Mt. Poso Cogeneration came on-line in September 1989 as a 64 MW coal-burning plant and 

retired on November 1, 2011, when the new 44 MW woody biomass plant (using the same 

name) came on-line. Mt. Poso Cogeneration was and is still under long-term contract to Pacific 

                                                           

5 http://www.ferc.gov/industries/electric/gen-info/qual-fac/what-is.asp. 
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Last updated 6/2/2014 Current and Expected Energy From Coal for California 9 

Gas and Electric (PG&E) for another 15 years. The $40 million conversion was completed in 

February 2012. Steam is still used in the adjacent oil field.6

 

The Port of Stockton District Energy Facility ceased operations as a 49.9 MW coal plant in April 

2009. In June 2011, the San Joaquin Air Pollution Control District approved converting this plant 

to use 100 percent biomass, a project expected to cost $100 million for a new 45 MW power 

plant, expected on-line in 2013. 

The Jackson Valley plant was under contract to PG&E from June 1986 until it ceased 

operations in July 1999. This 18.4 MW QF plant was unique in the United States for burning 

lignite7 (about 24 tons per hour) from an existing waste pile. Production ceased in 1999 due to 

bankruptcy. Conversion to woody biomass fuels was completed on December 31, 2012, at a 

cost of about $20 million. The renamed Buena Vista Biomass Power Plant will supply renewable 

energy to SMUD through November 30, 2032. 

 

                                                           

6 An overview of biomass-fueled Mt. Poso Cogeneration with construction and operation photos and 

videos are posted at http://macphersonenergy.com/mt-poso-conversion.html. 

7 Lignite is a soft brownishblack coal with a low energy density and high moisture content. Commonly 

called “brown coal”, lignite is an intermediate between peat and bituminous coal. 
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Last updated 6/2/2014 Current and Expected Energy From Coal for California 10 

Table 2: Status of Coal and Petroleum Coke Plants in California 

Plant Name County 

Nameplate 

Capacity 

(MW) 

Primary Fuel 

Type Status 

ACE 

Cogeneration 

San 

Bernardino 

108 Bituminous coal Operational. Contract end date: 

11/1/15. Owner announced intention 

to convert to natural gas by 2017. 

Argus 

Cogeneration 

San 

Bernardino 

55 Bituminous coal Operational 

Wilmington 

Calciner 

Los Angeles 36 Pet coke Operational. QF contract end date 

was 3/16/2000. 

Rio Bravo 

Jasmin 

Kern 38 Bituminous coal Stopped operating after 10/1/2012; 

expected to return to operation in 

June 2014 still using coal 

Rio Bravo 

Poso 

Kern 38 Bituminous coal Stopped operating after 10/1/2012; 

expected to return to operation in 

June 2014 still using coal 

Stockton 

Cogeneration 

San Joaquin 55 Bituminous coal Retired 3/31/2012 

GWF East 

Third Street 

Contra Costa 19 Pet coke Retired 4/26/2012 

GWF 

Loveridge 

Road 

Contra Costa 19 Pet coke Retired 4/26/2012 

GWF Nichols 

Road 

Contra Costa 19 Pet coke Retired 4/26/2012 

GWF Wilbur 

East 

Contra Costa 19 Pet coke Retired 4/26/2012 

GWF Wilbur 

West 

Contra Costa 19 Pet Coke Retired 4/26/2012 

Hanford LP Kings 24 Pet Coke Retired 10/18/2011 

TXI Riverside 

Cement 

San 

Bernardino 

12 Bituminous Coal Retired 3/31/2008 

Mt. Poso 

Cogeneration 

Kern 64 Converted from 

bituminous coal 

to biomass 

100% biomass since 11/1/11. Under 

contract with PG&E through 

2/27/2027. 

DTE Stockton San Joaquin 50 Converted from 

bituminous coal 

to biomass 

100% biomass since on 2/21/2014. 

New contract end date: 6/30/2038 

Jackson 

Valley 

Amador 18 Converted from 

lignite to biomass 

Renamed Buena Vista Biomass 

Power Plant, online 12/1/2012 and 

under contract to SMUD through 

11/30/2032 

Total for 16 Plants in 2007 543 MW 4,217 GWh 16 plants operational 

Total for 16 Plants in 2012 425 MW 1,580 GWh 11 plants operational, 2 retired, 

3 converted to biomass 

 Total for 16 Plants in 2013 199 MW 1,018 GWh 3 plants operational, 2 not operating, 

8 retired, 3 converted to biomass 

Source: Quarterly Fuels and Energy Reports submitted to the Energy Commission and available at 

http://energyalmanac.ca.gov/electricity/web_qfer/ with updates verified by Energy Commission staff. 

 
Tracking Progress 

Last updated 6/2/2014 Current and Expected Energy From Coal for California 11 

Contact: Jim Woodward, Jim.Woodward@energy.ca.gov

Media inquiries should be sent to the Media and Public Communications Office at 

(916) 654-4989, or by e-mail at mediaoffice@energy.ca.gov. 

Next Update: 

Annual California energy production data on in-state coal and pet coke plants are updated in 

October each year. The next update of utility-provided information on energy from coal 

resources, including historical and forecast data, will not be available until 2015.