## Tracking Progress

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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## Tracking Progress

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## 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 fo r 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 (CO 2 

### e) emissions per megawatt hour (MWh). All existing contracts with coal-fired generating facilities provide baseload energy supplies that exceed emissions lim its 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) regulations 2 

### may require extensive investments in pollution control retr ofit 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 ru lemaking, 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 retr ofit 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

## Tracking Progress

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 I PP 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

16% San Juan 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.

## Tracking Progress

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### 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/i nitiatives/boardman_plant_air_emissions.aspx.

## Tracking Progress

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) purc hased SCE’s interest in Units 4 and 5. By agreem ent 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 neg otiating 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 co alfired QFs in California. Comparison with this version of t he table makes it appear as though expected generation in coming year s has increased. For this version, staff corrected the errors and expects that coal-fired generation directly attributable to dis crete sources will not increase, save for potential short-term (fewer than five years in duration) acquisitions/contracts that may ta ke place.

## Tracking Progress

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### 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 (CO 2 

### e) 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 S enate 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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## Tracking Progress

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### Figure 4 shows how coal energy imports have been dec lining 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 signi ficant share of the fi rm 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.

## Tracking Progress

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### 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 Regul atory Practices Act of 1978 (PURPA). Also known

as qualifying facilities (QFs), these plants generate electricit y, 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 conv ersion 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/electr ic/gen-info/qual-fac/what-is.asp

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### 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 lignite 7 

### (about 24 tons per hour) from an existing waste pile. Production ceased in 1999 due to bankruptcy. Conversion to woody biomass fuel s 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 Cogener ation 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.

## Tracking Progress

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 subm itted 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.