December 2003 • NREL/SR-510-35114 

G. Morris 

Green Power Institute 

Pacific Institute for Studies in Development, 

Environment, and Security 

Oakland, California 

The Status of Biomass Power 

Generation in California, 

July 31, 2003 

National Renewable Energy Laboratory 

1617 Cole Boulevard 

Golden, Colorado 80401-3393 

NREL is a U.S. Department of Energy Laboratory 

Operated by Midwest Research Institute • Battelle 

Contract No. DE-AC36-99-GO10337 
December 2003 • NREL/SR-510-35114 

The Status of Biomass Power 

Generation in California, 

July 31, 2003 

G. Morris 

Green Power Institute 

Pacific Institute for Studies in Development, 

Environment, and Security 

Oakland, California 

NREL Technical Monitor: L. Wentworth 

Prepared under Subcontract No. KCL-0-30040-03 

National Renewable Energy Laboratory 

1617 Cole Boulevard 

Golden, Colorado 80401-3393 

NREL is a U.S. Department of Energy Laboratory 

Operated by Midwest Research Institute • Battelle 

Contract No. DE-AC36-99-GO10337 
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TABLE OF CONTENTS 

The Status of Biomass Power Generation in California, July 31, 2003 ....................... 1

Introduction..................................................................................................................... 1 

The 1980s: Decade of Growth ........................................................................................ 2 

The 1990s: Maturity, Consolidation, Deregulation ........................................................ 3 

The 2000s: Energy Crisis and Consequences ................................................................. 6 

The Crisis of 2000 – 2001........................................................................................... 6 

The Crisis Evaporates as Suddenly as it Appeared..................................................... 9 

The Future of the California Biomass Power Industry ................................................. 11 

The California RPS Program .................................................................................... 11 

Prospects for a Biomass Policy in California ........................................................... 13 

Use of New Biomass Technologies in California..................................................... 16 

Conclusion .................................................................................................................... 17 

References..................................................................................................................... 18
 1

The Status of Biomass Power Generation in California, July 31, 2003 

Introduction 

California has the largest and most diverse biomass energy industry in the world. More 

than sixty solid-fuel fired biomass power generating facilities have been built in the state 

since 1980, with a combined generating capacity of almost 1,000 MW. The California 

biomass power plants are fueled by a combination of sawmill residues, in-forest residues, 

agricultural residues, and wood residues diverted from disposal in the state’s sanitary 

landfills. In all cases, energy production from these materials provides a disposal option 

that is environmentally superior to the alternatives, which include open burning and 

landfill burial. 

At its peak, the California biomass energy industry produced almost 4.5 billion kWhs per 

year of electricity, and provided a beneficial use outlet for more than ten million tons per 

year of the state’s solid wastes. The peak, however, occurred during the early 1990s. 

During the middle 1990s, when California launched the national movement to deregulate 

the electric utility industry, one-quarter of the operating biomass energy facilities in the 

state agreed to buyouts of their power sales contracts and terminated operations. In 

addition, some of the facilities that remained in operation reduced their production levels 

during off-peak hours. By 1996, biomass power generation in California stabilized at 

approximately 3.2 billion kWhs per year, and the enterprise provided a disposal outlet for 

slightly less than six million tons per year of the state’s solid waste. 

Electric utility deregulation was originally focused exclusively on reducing the costs of 

power generation, but as the process proceeded, the renewable energy industries, in 

cooperation with environmentalists and consumer advocates, were able to put 

environmental concerns on the agenda. By the time deregulation went into effect in 1998, 

a program had been developed to assist the various renewable power producers in making 

the transition to a competitive power-generation market. Biomass generators who were 

not operating under old fixed-price energy provisions were eligible to claim a production 

credit of up to 1.5 ¢/kWh for power produced during the first two years of the program. 

This supplement provided the incentive necessary to encourage the generators that were 

still operating to operate at a higher overall capacity factor, but it was not enough to 

allow any of the idled facilities in the state to resume operations. By the end of the 1990s 

biomass power generation in California had increased to 3.5 billion kWh/yr, and fuel use 

to a level of 6.4 million tons per year. 

The dawn of the new century brought a nasty electricity crisis to California. Supplies of 

natural gas and electricity were short, and wholesale prices shot through the roof. The 

crisis stimulated ten of the state’s idle biomass power generators to initiate restart 
 2

investigations, with five eventually achieving restart, although one of the five only 

operated for a few months and then shut down again. As of mid 2003, the California 

biomass power industry was producing 4.2 billion kWh/yr of electricity, and was 

providing a beneficial use disposal outlet for 8.0 million tons per year of biomass residue. 

This report describes the development of the biomass power industry in California over 

the past quarter century, and examines its future outlook. Much of the industry history 

has been published before (see, for example, Morris 2000, Morris 2002a), but is included 

here to allow this to be a stand alone report. The development of a state biomass policy, 

which has been under discussion in California for the better part of the past decade, has 

never gotten off the ground, but a number of smaller initiatives have helped to keep the 

biomass power industry afloat and have promoted the use of some targeted types of 

residues. In this report we will analyze the prospects for policy development and the 

application of new biomass technologies in California 

The 1980s: Decade of Growth 

The early 1980s mark the nascent period for the modern California biomass energy 

industry. Prior to 1980 a handful of biomass power plants operated in conjunction with 

lumber or pulp mills in the state, and mostly supplied power for on-site uses. During the 

early 1980s several pioneering biomass energy-generating facilities were built and placed 

into service. The early facilities tended to be small; generally in the size range of 2 - 10 

MW, and most were associated with sawmills or food-processing operations that were 

looking for beneficial-use outlets for their wastes. Figure 1 shows a map of the state’s 

operating biomass energy facilities at the end of 1985. 

The early 1980s were also the period when the California electric utility companies 

developed standard-offer contracts for power purchases from independent generators. 

These contracts had particularly favorable provisions for renewable energy projects. A 

great deal of biomass project development activity was initiated during this period, which 

led to an explosion of new facility openings during the second half of the decade. 

During the later 1980s the California biomass energy industry established itself as an 

important part of the state’s electricity supply infrastructure, as well as its waste-disposal 

infrastructure. The incentives for renewable energy development that were offered 

during the first half of the decade led to the opening of 33 new biomass generating 

facilities between 1985 and 1990. A few of the pioneering facilities were shut down 

during this period, but the state’s total operating biomass energy capacity grew by more 

than 650 MW. The average size of the facilities brought on-line during this period was 

about 17.5 MW, with the largest facilities producing as much as 50 MW. The explosive 

growth of biomass generating capacity in California culminated in 1990, when 11 new 

facilities were commissioned in a single year, adding 232 MW of biomass generating 

capacity to the state’s electricity supply. Figure 2 illustrates graphically the development 

of the biomass energy generating industry in California from 1980 to the present. Figure 

1 shows a map of the state’s installed biomass power infrastructure at the end of 1990. 
 3

Many of the facilities that entered service during the late 1980s had Interim Standard 

Offer No. 4 (SO#4) power purchase agreements with the state’s two major electric utility 

companies, Pacific Gas and Electric Co. (PG&E), and Southern California Edison (SCE) 

Co. The most significant feature of the SO#4s was an option for energy sales from 

electricity generated from renewable resources to be based on a forecasted schedule of 

energy prices for the first ten years of facility operations, rather than being subject to 

fluctuating, short-term prices. These schedules were based on the high avoided cost rates 

that were in effect when the contracts were signed (5 – 6 ¢ per kWh), and an expectation 

that rates would grow from there throughout the terms of the agreements. At the 

completion of the ten-year fixed price period generators were to be compensated based 

on the then current market price. 

The second half of the 1980s was also significant for a major reversal in world oil 

markets. World oil prices, which had remained high since the price explosions of the 

1970s, collapsed during the period 1985-1986. Short-run avoided cost rates in California 

fell by 50% over an 18 month period. Most of the biomass power plants, however, were 

immune to the decline in SRAC rates during this period, because they were receiving 

fixed-schedule rates under their contracts based on early 1980s energy prices. 

Instead, the attention of the biomass generating facilities was focused on a looming crisis 

in the biomass fuels market. Because the state’s installed biomass-generating capacity 

grew rapidly during the later half of the 1980s, the demand for fuel soon overwhelmed 

the readily available supply. Virtually all of the sawmill and food processing residues in 

the state that did not have higher-value uses were being sold into the fuel market, yet 

there was a significant deficit between supply and demand for biomass fuels. A variety 

of efforts were under way to develop technologies to produce biomass fuels from new 

sources, such as agricultural prunings, agricultural field residues, forestry residues, and 

urban waste wood, with rising fuel prices providing the incentive, as illustrated in Figure 

3. The state’s biomass fuels crisis peaked in 1990 with average prices topping $40 per 

bdt1

 of fuel, and spot prices reaching upwards of $60 per bdt. Moreover, several major 

new facilities were approaching completion at this time, and there was a fear that biomass 

fuel prices might continue to rise. 

The 1990s: Maturity, Consolidation, Deregulation 

At the end of 1990 more than 770 MW of biomass energy generating capacity were 

operating in California, and an additional 100 MW of capacity were in advanced stages 

of construction. The next several years saw the state’s biomass energy industry stabilize 

at a level of about 750 MW of operating capacity (see Figure 2). During this period the 

startup of the last of the SO#4 facilities was balanced by the retirement of several of the 

pre-SO#4 facilities, some of which had serious design flaws or chronic operational 

 

1

 bdt = bone-dry ton equivalent, a unit of measurement used for biomass fuels. A bdt refers to an amount of 

material that contains a ton of moisture-free biomass fiber. Generally, one bdt is equivalent to 1.5 – 2.2 

actual, or green tons of biomass. In this paper the term “ton” used alone refers to green tons of biomass, 

and bdt refers to bone-dry ton equivalents of biomass. 
 4

problems. The year 1993 saw the first retirement and dismantling of a facility with a 

SO#4 contract. This was a facility that had been beset with technical and operational 

problems that prevented its profitable operation. 

The California biomass fuels market also stabilized during the early 1990s, with average 

market prices settling at about $37.50 per bdt, at an average statewide consumption level 

of approximately nine million tons per year. This stability was reached despite the 

beginning, in 1990, of a long-term decline in the state’s commercial wood-products 

industry. This is significant because wood processing residues are the lowest-cost 

biomass fuels in the state, and their supply was declining, as shown in Figure 4. Figure 5 

shows how fuel pricing had reached equilibrium among fuel types in the early 1990s. By 

the end of 1993 the biomass energy industry in California appeared to have attained a 

level of maturity, and a workable equilibrium between fuel supply and fuel demand had 

been established. While there had been winners and losers, the California biomass 

energy industry as a whole appeared to have successfully weathered the storm of the fuel 

crisis that marked the beginning of the decade. 

The stability, however, was short lived. In April of 1994 the California Public Utilities 

Commission (CPUC) issued its landmark Blue Book proposal for restructuring the state’s 

regulated electric utility industry (CPUC 1994). The Blue Book provided for competition 

among generating sources on the basis of price alone, without regard to non-market 

factors such as resource diversity and environmental impact. This represented a major 

threat to the future of biomass energy generation. For a number of reasons, the cost of 

power production from biomass is inherently higher than the cost of power generation 

using natural gas. Competition based on price factors alone would not favor biomass 

energy generation. 

The most immediate effect of the Blue Book restructuring proposal for the biomass 

energy industry was that it provided an incentive for the state’s regulated electric utility 

companies to buy out the SO#4 PPAs held by the biomass generators in their service 

territories. Many of the biomass generators were receptive to these offers because of 

their concern about their own long-term liabilities to the utility companies in connection 

with the firm-capacity obligations in their contracts. Over the next three years 17 

biomass facilities, rated collectively at more than 215 MW, accepted buyout offers and 

shut down.2

 Unlike in earlier years, when only marginal facilities were closed, most of 

the facilities that shut down in the mid-1990s were first-rate facilities that had been 

operating efficiently and profitably until the buyouts of their PPAs. 

Annual biomass fuel use in the state shrank by 37% during the two years following the 

appearance of the Blue Book proposal (see Figure 6). More than three million tons per 

year of biomass residues that were being used for energy production in the early 1990s 

were again burned and landfilled for disposal. In addition, at its peak the state’s biomass 

industry was supporting forest treatment operations on approximately 60,000 acres per 

 

2

 One of the seventeen facilities was sold and restarted during this period. This facility was purchased by a 

buyer who operated it at about one-half of its rated capacity, supplying steam and electricity to an over-thefence industrial customer. 
 5

year of forest land that was not otherwise being commercially harvested or treated. 

These treatments reduced the risk of destructive wildfires, and improved the health and 

productivity of the thinned forest. With the retraction in the demand for biomass fuels, 

forest-treatment activities in the state declined dramatically. 

The CPUC’s original restructuring proposal underwent a process of refinement that lasted 

for more than two years. By the summer of 1996 the CPUC had acknowledged the 

desirability of incorporating environmental factors into the choice of energy sources for 

the state, and embraced the concept of a minimum purchase requirement for renewable 

energy sources. A working group made up of the utility companies, independent power 

generators, and public interest groups were working on formulating a consensus proposal 

to the CPUC for the implementation of a minimum renewables purchase requirement for 

California’s regulated electric utility sector (Morris et. al., 1996). The biomass industry, 

which pioneered the concept of a renewables portfolio standard, played a key role in this 

process. 

In late August of 1996, just before the end of the session, the California legislature 

formulated its own electric utility restructuring program, superceding the efforts of the 

CPUC. The legislation that emerged, AB 1890, included a program of short-term support 

for renewable energy during the four-year transition period (1998-2001) between 

initiation and full implementation. However, no long-term support program for 

renewables was included. AB 1890 explicitly recognized the special waste-disposal 

benefits associated with biomass energy in California. The legislation directed the 

California Environmental Protection Agency (Cal/EPA) to study policies that would shift 

some of the costs of biomass energy production away from the electric ratepayer, and 

onto the beneficiaries of the waste-disposal services. 

The legislature made an additional attempt to develop the background necessary for 

biomass support policies in California. In 1998, AB 2273 was passed and signed into law. 

AB 2273 directs the Cal/EPA to report annually to the legislature on progress being made 

to develop biomass cost shifting policies in the state. The California Integrated Waste 

Management Board is assigned the lead role in developing reports under this legislation. 

Despite the cloud of uncertainty over the future viability of biomass energy production in 

California, the state’s biomass energy industry operated with relative stability during the 

latter half of the 1990s. Following the shutdowns of 1994-1996, a total of twenty-seven 

biomass facilities, representing 540 MW of generating capacity, remained in operation. 

Twenty of the facilities were operating intact under SO#4s. The other seven had special 

circumstances, such as a captive fuel supply, or an ability to earn retail-offset for most or 

all of their electricity output, that allowed them to continue operating. The fixed-price 

periods in the SO#4 PPAs were coming to an end, but the renewables transition fund 

created by AB 1890 offered biomass generators a supplementary payment of 1.5 ¢/kWh 

for facilities that were not receiving SO#4 fixed-scheduled prices for their sales of 

electricity. 
 6

The operating biomass energy generating capacity in California actually increased 

slightly at the end of the 1990s, to a level of almost 600 MW. This was mainly because 

two, twenty-five MW facilities that had accepted contract buyouts and shutdown 

operations in 1994 had provisions in their buyouts that provided for restarting the 

facilities at the end of their fixed-price periods. Biomass fuel use increased by 15% over 

its lowest point following the 1994-1996 shutdowns, but it was still more than 30% lower 

than the peak level achieved during the early part of the decade. Figure 7 shows maps of 

California’s biomass energy facilities as of 1995 and 2000. 

The close of the 1990s saw a renewal of interest in PPA buyouts. One small biomass 

facility, which was already operating beyond its fixed-price period, accepted a buyout 

agreement for its remaining capacity obligation and shutdown. One of the state’s largest 

biomass facilities accepted a buyout of its contract and remained in operation as a 

merchant power facility. The industry was concerned because the transition support 

payment for biomass energy was scheduled to drop to 1.0 ¢/kWh in 2000, and no tangible 

progress had been made on implementing cost-shifting measures. 

The 2000s: Energy Crisis and Consequences 

The Crisis of 2000 – 2001 

Natural gas prices in California, which had been stable throughout the 1990s, abruptly 

shot upwards during the winter of 2000. Electricity prices in San Diego, where 

deregulation was already in effect, immediately doubled. Prices for customers of PG&E 

and SCE held steady, due to continuing regulatory control. The staggering increase in 

gas prices, combined with rapidly growing electricity demand fueled by the booming 

high tech industries in California, a drought-caused decrease in hydroelectric production 

in the Pacific Northwest, and increasingly brazen manipulation of the market by major 

gas and electric producers and marketers, led to electricity supply shortages across 

California. 

Wholesale electricity prices, which had remained within a penny of three cents per kWh 

for more than 15 years, broke through the four-cent barrier in May of 2000. In June, they 

hit double digits. By August prices at the state power exchange were averaging more 

than 15 ¢/kWh. Figure 8 shows the explosion of wholesale electricity prices in California 

during 2000 and 2001. Suddenly, California was engulfed in a full-fledged energy crisis. 

The Governor resolved to hold the line on consumer electricity prices, but FERC declined 

to impose wholesale price controls. Caught in the middle, the utilities’ saw their cash 

reserves vanish virtually overnight. 

Biomass power generators in the state responded quickly to what was a considerable 

opportunity. Each of the operating biomass facilities looked to expand its fuel purchasing, 

and pushed its facility to maximize output around the clock. All of the facilities that were 

eligible opted to convert to power exchange pricing in order to take advantage of the 

higher prices available there. Ten of the biomass facilities in California that had been 

shut down during the 1990s, representing 130 MW of generating capacity, began 
 7

investigations to see whether they could profitably resume operations. The ten facilities, 

many of which are located near the state’s Central Valley region, are shown in Table 1. 

The state support payments to the biomass generators were suspended because market 

prices exceed the target level. By the end of the year biomass fuel prices were on the rise, 

but few of the generators were complaining. 

Table 1 

Idle California Biomass Facilities that Began Re-Start Investigations in 2000 

 Auberry Energy, Auberry 7.5 MW restart abandoned 

 Blue Lake Energy, Blue Lake 10.0 MW restart abandoned 

 Capitol Power, Ione 18.0 MW restart abandoned 

 Chow II, Chowchilla 10.0 MW restart abandoned 

 Dinuba Biomass, Dinuba 11.5 MW started up in 2001 

 El Nido, Chowchilla 10.0 MW restart abandoned 

 EPI Madera, Madera 25.0 MW started up in 2001 

 Primary Power, Brawley 15.0 MW started 2001, shut 2002

 Sierra Forest Products, Terra Bella 9.5 MW started up in 2001 

 Soledad Energy, Soledad 13.5 MW started up in 2001 

The complaints started in December 2000, when the utility companies stopped paying 

power producers for energy. Six months of unprecedented wholesale energy prices had 

mortally wounded the utility companies, and they were teetering on the verge of 

bankruptcy. Additionally, prices at the power exchange suddenly shot up again in 

December, averaging more than 35 ¢/kWh during the month. They remained at that level 

into January 2001, when the power exchange itself was shut down. The electricity 

market in California was in chaos, and the state’s investor-owned electric utility 

companies were crippled. 

California’s biomass power producers were faced with a mind-boggling irony. At the 

very time that they were earning unprecedented profits, on paper, they were facing 

insolvency at the bank. With their revenues suspended, fuel prices elevated, and the state 

demanding that they produce as much power as they could, their short-term cash 

positions were precarious. Many biomass operators talked openly of giving up and 

shutting down for good. 

In spite of the troubles faced by the operating biomass facilities, the efforts to restart ten 

of the state’s idled biomass facilities were proceeding at full-speed. Wholesale electricity 

prices had never been higher, actual operations for these facilities were months away, and 

it was reasonable to assume that something would be done to get the flow of money 

moving again before they would be ready to operate. In fact in some ways, it appeared at 
 8

the beginning of 2001 that the idled facilities that were trying to restart would enjoy a 

couple of distinct advantages over the operating facilities. They would not be hobbled by 

enduring a prolonged period of operating without receiving revenues, and they would not 

be saddled by old power purchase contracts that now were paying below-market prices. 

An emergency session of the state legislature was convened in January 2001 to deal with 

the still burgeoning energy crisis. Many commentators predicted that a long, hot summer 

of brownouts and blackouts lay ahead. The governor was negotiating bailout deals with 

the utility companies that would allow them to sell their entire transmission systems to 

the state for prices that were well above book value. In March the CPUC, for the first 

time since the energy crisis hit, granted the utility companies across-the-board rate 

increases of 10%. Nevertheless, negotiations with PG&E broke down and the utility 

company declared bankruptcy. Negotiations with SCE eventually broke down too, 

although SCE avoided bankruptcy. 

The state’s electricity generators were desperately searching for a way to get the utility 

companies to pay them. A deal was struck in late March at the CPUC that allowed the 

utility companies to resume payments to the power generators on a going-forward basis, 

with the matter of payments for past due bills left unresolved. None of the thirty 

operating biomass facilities had been forced to shutdown, although many were severely 

stretched. Short-run avoided cost rates hovered in the neighborhood of 10 ¢/kWh 

through the Spring of 2001, well below their unbelievable levels of December and 

January, but still some three times higher than historical levels. 

With the collapse of the state power exchange and the crippled financial status of the 

utility companies, the state legislature passed legislation that allowed the state to begin 

buying electricity on behalf of the state’s utility consumers. The Department of Water 

Resources (DWR) immediately set up a trading unit and created a power exchange for 

short-term energy purchases. In addition to purchasing energy on a short-term basis, the 

DWR embarked on a program of negotiating long-term energy contracts at prices below 

the then prevailing rates, but above historical levels. Many of the state’s generators were 

eager to join the negotiations, and the state began to deal. 

The ten idled biomass generating facilities in the state that had initiated startup 

preparations during late 2000 and early 2001 looked at long-term contracts with DWR as 

the obvious way to go. At first they were rebuffed. DWR’s initial request for proposals 

specified a minimum generating unit size of 50 MW. This excluded all of the candidate 

biomass facilities that were trying to restart. 

In parallel with the state’s efforts to negotiate long-term contracts with large generators, 

the CPUC developed a program to allow biomass facilities operating under old standard 

offer PPAs to select a five-year fixed price payment of 5.37 ¢/kWh, instead of being paid 

at variable short-term market rates. Many, but not all, of the biomass facilities operating 

under standard offer contracts accepted this offer, and began receiving the fixed price 

payments beginning in July 2001. 
 9

At this point the biomass power plants in California could be divided into two functional 

groups based on their power sales arrangements. The first group, which included most of 

the facilities operating under the old standard offer PPAs, had fixed price agreements that 

would cover the next five years, with prices that were high enough to ensure their 

continued ability to operate throughout this period. The second group, which included a 

few of the facilities that had operated continuously during the 1990s, and most of the 

facilities that were in various stages of restarting, were stuck without long-term PPAs. 

The operating facilities in this group were selling their output on the short-term market, 

where prices were in the neighborhood of 10 ¢/kWh during the spring of 2001. Many of 

the facilities in this group were actively trying to negotiate long-term contracts (five years 

or more) with the DWR. A few were content to remain players in the short-term market. 

Available power supplies for the California grid remained at very low levels during the 

spring of 2001, as unusually large numbers of the state’s fossil fuel-fired power plants 

seemed to be out of operation for servicing, many for prolonged periods of time. Rolling 

blackouts of two or three hours duration each were imposed on many PG&E customers, 

despite the fact that spring is traditionally a period of low electrical demand in the state. 

Rumors and charges began to surface that some of the state’s largest generators were 

manipulating their production units to game the market. The state was pleading with 

FERC to impose price controls on the wholesale market, but the FERC still refused to 

respond. The situation was rapidly coming to a boiling point. 

By the beginning of the summer of 2001, the DWR had signed about forty long-term 

contracts with generators for more than 10,000 MW of power. Although the contracts 

were not made public, prices were rumored to be in the range of 7 - 10 ¢/kWh, with terms 

ranging from 2 - 10 years. One re-starting biomass power plant was among the recipients 

of the first set of DWR contracts, and was already firing fuel. Seven of the biomass 

restarts were now actively engaged in negotiations with DWR. The other two attempted 

restarts, twin 10 MW facilities near Chowchilla (Chow II and El Nido), had already 

suspended their restart efforts. 

The newspapers continued to be full of dire warnings of looming summer blackouts. The 

crisis was beginning to spread to the entire Western United States, and electricity supplies 

were reportedly strained in the Northeast. The Governor pushed hard for conservation in 

California, and for FERC price caps to be imposed in Washington. Finally FERC acted 

and imposed price caps on the wholesale electric market in the western United States. 

The Crisis Evaporates as Suddenly as it Appeared 

Then something totally unexpected happened. The long-dreaded summer of 2001 arrived. 

But wholesale energy prices fell from May to June by more than a third, despite the fact 

that it was the beginning of the peak demand season. By the middle of the summer, 

prices had fallen below four cents per kWh, which was within the range of pre-crisis 

levels. Not one blackout occurred during the entire summer. A combination of factors, 
 10

including aggressive conservation efforts by consumers, an economic recession, an 

unusually cool summer, the long-term contracts signed by the DWR, the end of the 

drought in the Northwest, and the breaking of the bottleneck in the natural gas market, 

seemed to have combined to knock out the energy crisis. The FERC price caps were 

reached a couple of times soon after their imposition, then quickly became irrelevant. By 

late summer there were grumblings that the state had signed too many contracts at too 

high of prices. There were even periods when the state was purchasing more contract 

electricity than it could use, and had to sell the excess into out-of-state markets at a loss. 

More than 99% of the long-term contracts signed by the state in the spring of 2001 were 

for energy generated from natural-gas fired power plants, a result of the crisis atmosphere 

that had been in effect when the DWR began to seek long-term power supplies. Due to 

size and other considerations, renewables had been put on the back burner in the spring, 

and were just coming up for consideration at the DWR as the summer reached its peak, 

and the energy crisis ebbed. 

Timing was distinctly against the biomass facilities seeking power contracts. The DWR 

was coming under fire for the contracts they had already signed with the natural gas 

generators. Negotiations for additional long-term power purchase contracts suddenly 

ground to a halt, even in cases where there were signed letters of intent. Biomass project 

proponents complained that their questions went unanswered, and their phone calls were 

not returned. With the exception of Soledad, all of the facilities attempting to restart, as 

well as several operating biomass power plants that did not have standard-offer PPAs, 

found themselves relegated to selling into the short-term market at prices that were 

insufficient to cover their fuel and operating costs. 

December 2001 was the sixth consecutive month in which short-run avoided cost rates 

were insufficient to cover the operating costs of biomass power generation. The group of 

facilities that did not have long-term contracts were nearing the end of their ability to 

hang on. Two restart projects, Capital Power Ione, and Imperial Power Brawley, were 

able to finalize contracts with DWR during the last months of 2001. They both came to 

terms that were substantially less favorable than those that had been granted to natural 

gas generators earlier in the year. Capital Power, on the basis of its DWR contract, never 

was able to secure financing to initiate operations, while Imperial Power did startup, but 

shut down again in 2002, and has no plans to resume operations. 

Recognizing that long-term contracts were not going to be available anytime soon, the 

DWR signed 90-day interim contracts with eleven biomass facilities before the end of the 

year, with a common intention to enter into long-term contracts as soon as it became 

possible to do so. The interim contracts were given a series of extensions, carrying them 

into mid-2003. The DWR’s authority to contract expired at the end of 2002, so these 

contracts have been extended as far as they could go, and have now expired. 

The interim contracts provided for average revenues of 6.5 ¢/kWh, differentiated by timeof-use and seasonal factors. The payment level covers both energy and capacity, and as 

such is below the level earned by the facilities with old standard offer utilities contracts 
 11

(5.37 ¢/kWh energy plus 2.0 ¢/kWh capacity), and on the low side of the range of the 

legitimate costs of energy production from biomass (see, e.g., Morris 2000). 

California currently has thirty-one biomass power plants in operation, representing a total 

of 631 MW of electricity generating capacity. Figure 9 shows the current map of 

California’s biomass generating facilities. Approximately two-thirds of the total are 

operating under old standard-offer power purchase agreements with fixed energy prices 

that will remain in effect through the middle of 2006. These facilities are well served by 

their contracts, and should be able to operate viably through July 2006. The other onethird of California’s biomass power plants are operating under a variety of arrangements. 

The long-term fate of this group of facilities is a function, in large part, of whether they 

are ultimately able to obtain longer-term contracts with adequate power purchase 

provisions. 

The Future of the California Biomass Power Industry 

The California RPS Program 

Natural gas shortages helped to trigger the California energy crisis. Natural gas-fired 

generators were the worst manipulators during the crisis. Nevertheless, ninety-nine 

percent of the long-term power purchase contracts signed by the DWR were for 

electricity produced from natural gas. Renewables, which provide almost 10% of the 

state’s electricity supply, were virtually shut out of the DWR process. Of the ten idle 

biomass facilities that initiated startup activities during the crisis, only three were able to 

obtain long-term PPAs with the DWR, and two of those contracts turned out to be 

inadequate to allow operations to proceed. Four of the attempted restarts abandoned their 

efforts, and the other three started up with short-term contracts with the DWR. The 

problem for renewables was that, with the DWR already exiting the long-term 

contracting arena by the middle of 2001, direct access suspended, and the utilities either 

bankrupt or on the brink, there was no credit-worthy buyer for a new renewable project to 

contract with. Many promising renewable generation projects were simply left adrift. 

In order to bring some amount of balance to the situation, California enacted a 

Renewable Portfolio Standard (RPS) during the summer of 2002 (SB1078). SB 1078 

seeks to double the contribution of renewable energy production to the state’s electricity 

supply over a fifteen year period, from the current level of approximately 10% to a target 

level of 20%. The RPS program covers the entire state’s electricity supply, which means 

that it has to be applied in several different jurisdictions, by a variety of state and local 

agencies. The CPUC is expected to lead the way with respect to utility regulation, with 

public utilities expected to follow with the development of their own programs. The 

California Energy Commission (CEC) is charged with a variety of support and 

compliance functions, including certifying and tracking renewable energy production, 

and designing and administering the system to use public goods charge funds to provide 

incentives for renewables. 
 12

The CPUC and CEC have each opened rulemakings to implement the RPS at their 

respective agencies. The rulemakings are coordinated, and the agencies have designated 

a collaborative staff to work on the various issues of mutual concern. The collaborative 

staff issued a proposed work plan in February. The plan identified all of the functions 

that each agency was charged with performing by the end of 2003, and divided them into 

three categories: those needing immediate action, those needing action in the mid-term 

(by the end of June), and those that could wait until the second half of the year. 

The legislation required the CPUC to report to it by the end of June 2003 on four specific 

issues: 

• compliance and flexible compliance rules 

• standard contract terms and conditions 

• least cost and best fit bid ranking 

• setting of the market referent price 

The workplan provided for workshops on each of these topics, on four consecutive 

Tuesdays during March. Following the workshops, the sixteen participating parties, 

including the Green Power Institute, filed testimony on the four topic areas, which was 

followed by hearings, briefs, and reply briefs. On May 20, the CPUC issued a Proposed 

Decision (PD) on the four issues, which itself elicited comments, reply comments, and a 

proposed Alternative Decision (AD). The PD and AD were both revised, and brought 

before the Commission on June 19, 2003. The two documents differed only with respect 

to the issue of flexibility in compliance requirements, with the AD proposing compliance 

rules that are more stringent for the utility companies. The CPUC voted unanimously for 

the AD, which has been designated Decision 03-06-071 in Rulemaking 01-10-024.3

Decision 03-06-071 has many features that will affect the current and future biomass 

energy industry in California. Many elements of the decision are highly favorable to the 

existing biomass generators. For example, the decision reinforces the importance of the 

existing renewable generating infrastructure in the state, and requires utilities to maintain 

their existing base of renewable procurement, or face having to replace their losses in 

addition to acquiring a specified amount of new renewable generators each year until the 

level of 20% of the overall energy supply is attained, and then maintained. This was a 

heavily litigated issue, as both SCE and PG&E maintained that their only requirement for 

new procurement was the specified annual increment of 1% of retail sales, regardless of 

what happened to their existing supply portfolio. If the utilities had prevailed, electricity 

from existing renewables generators would have been effectively cut out of the RPS 

program, and the utilities would have had little incentive to work cooperatively with these 

facilities. 

During the RPS proceeding at the CPUC, California’s two largest utilities, PG&E and 

SCE, argued for compliance rules that were so flexible that the ultimate goals of the RPS 

program would have been placed in serious risk. Instead, the Decision adopts 

 

3 http://www.cpuc.ca.gov/WORD_PDF/FINAL_DECISION/27360.PDF
 13

compliance rules that allow for a reasonable amount of flexibility while applying 

sufficient rigor to ensure that ultimate compliance can be achieved. Adopting unlimited 

forward banking of RECs, combined with limited rights to under-procurement, will help 

to maintain the market value of electricity from existing biomass and renewable 

generators. 

One of the interesting aspects of the RPS proceeding was that many of the parties, 

including the utilities and several consumer and environmental advocates, favored the 

concept that a Renewable Energy Certificate (REC), which is the accounting tool that 

was adopted for the RPS, would include all of the non-energy attributes of renewable 

energy. Such a finding could threaten the financial viability of many biomass power 

generators by depriving them of the right to market the ancillary waste-disposal benefits 

they produce. It would also be contrary to prior efforts by the legislature to encourage 

cost-shifting measures for biomass power generation, many of which involve separating 

some of the environmental benefits of renewable energy from the attributes required for 

compliance with the RPS program. Due to the efforts of the Green Power Institute, as 

well as other parties, the Decision leaves the definition of a REC open, and recognizes 

the principle that the environmental products produced by a generator should be marketed 

separately from RPS-qualifying renewable energy (D.03-06-071, page 62). 

Prospects for a Biomass Policy in California 

Biomass power generators in California have long recognized their predicament, which is 

that generating electricity from biomass is inherently more expensive than generating 

electricity from fossil fuels or hydro power. At the same time, a variety of sources have 

demonstrated that biomass power generation produces ancillary waste-disposal services 

that, although not usually compensated, are worth considerably more than the electricity 

produced. An NREL report written just prior to the energy crisis (Morris 2000) lays out 

the case for why California needs an integrated biomass policy that coordinates the work 

of a variety of agencies and jurisdictions. While initiatives and committees have come 

and gone, a comprehensive approach has never materialized. 

The California biomass power industry pioneered the concept of a renewable portfolio 

standard when they introduced legislation during the mid-1990s that would have created 

a minimum purchase requirement for biomass energy of 11⁄2%, which was its contribution 

to the state’s electricity supply at that point in time. At the time, the CPUC was engaged 

in their electric utility restructuring proceeding, and in 1996 an RPS had been 

incorporated into the CPUC’s restructuring plan. While details were never finalized, 

some versions of the CPUC’s RPS program included a specific tier, or allotment, for 

biomass. The state RPS program was derailed by the legislature’s adoption of its own 

deregulation plan, but when that program was abandoned in the wake of the state energy 

crisis, a state RPS program was resurrected and passed in 2002. While the California 

RPS program offers some attractive features for existing biomass generators, it does not 

differentiate among renewable power sources, and thus may not do much to promote any 

significant growth of biomass power generation in the state in the absence of additional 

policy support for biomass. 
 14

While a comprehensive state biomass policy has not coalesced, a number of policy 

initiatives have been enacted that provide support for targeted forms of biomass 

utilization. Policies aimed at reducing air pollution from the open burning of agricultural 

residues, diverting usable forms of solid waste from landfill disposal, and improving the 

health and fire resistance of California’s forests, are all components of what a 

comprehensive biomass policy might entail. 

One of the early policy initiatives undertaken by former Governor Gray Davis was an 

economic development program for the San Joaquin Valley launched in the spring of 

2000. The initiative included a number of environmental components. Of particular 

relevance to the biomass energy industry was a grant program for diverting agricultural 

residues that were then not being used as fuel in appreciable quantities, such as orchard 

prunings. Agricultural residues that were already well represented in the biomass-fuel 

marketplace, such as whole-tree chips from orchard removals, were not eligible for the 

grants. The Ag Grant program was initially funded with $10 million for the first year of 

the program (state fiscal year 2000-2001), and grants were made for the use of qualifying 

fuel for up to $10 per ton. The following year the program was funded at a level of $11.5 

million, but after functioning for two years it was allowed to expire. 

During the summer of 2003, the legislature, through SB 704, created a new grant 

program for agricultural residues. This measure, which at publication was awaiting 

signature from the governor, will make $6 million available in fiscal year 2003-2004 to 

support the diversion of residues from open burning to use as fuel, making grants of up to 

$10 per ton of material diverted, as in the previous program. The funding for SB 704 

comes from public-goods charge monies collected in accordance with SB 90, but not 

dispersed under their original allocation. Future funding for the program is highly 

uncertain, considering California’s current fiscal situation. 

The open burning of agricultural residues has long been known as a major source of air 

pollution in California’s agricultural valleys. However, the right to burn as a part of 

regular agricultural practice is a cherished right of farmers, and limiting open burning can 

only be accomplished at a cost (unregulated burning is the lowest-cost disposal option). 

This has made the task of improving air quality in agricultural regions of the state very 

difficult. 

Rice-straw in the Sacramento Valley was the first agricultural residue to come under 

intense pressure to prevent open burning. The California Air Resources Board (CARB) 

funded millions of dollars of research during the 1990s aimed at developing beneficial 

use options for the disposal of rice straw. Options studied included a variety of building 

materials applications, and conversion to ethanol or electricity. To date, no major 

commercial application has come forward to relieve the state of its rice straw disposal 

problem. Nevertheless, rice straw burning was banned as of September 2001. As a result, 

the state’s rice farmers are left with a difficult disposal problem. Many are incorporating 

the straw into their soil. This practice uses large amounts of water as an additional 

flooding of the fields is required after incorporating the straw. In addition to increased 
 15

water use, the practice is causing an increase in disease problems in treated fields, and is 

leading to significant levels of methane emissions from anaerobic decomposition. The 

other disposal alternative that is being used is baling and storage, which is leading to a 

legacy of unwanted piles of bales. Rice straw does not make a good fuel for solid-fuel 

combustors, so the existing power-generating industry is not a viable solution to the ricestraw disposal problem. 

Air quality across the San Joaquin Valley is plagued by the open burning of a variety of 

agricultural residues, some of which are suitable fuels for solid-fuel combustors, such as 

orchard and vineyard prunings. The Ag Grant program described above has helped to 

bring some of this material into the biomass fuel mix, but the amount of material still 

being open-burned is considerable. In this year’s session (2003), the California 

legislature passed a ban on all agricultural burning in the state (SB 705). At publication, 

the measure was awaiting signing by the Governor, which was expected to happen. SB 

705 phases out open-field burning by 2010, and requires local air districts to help farmers 

find alternatives for disposing of agricultural residues. While the law leaves a good deal 

of discretion for enforcement to the local districts, it should provide an inducement to 

divert material to the biomass fuels market. 

The major disposal option for unused biomass residues in California is landfill burial. 

However, state policy strongly favors minimizing the amount of material that is landfilled. 

In 1990 California passed a landmark landfill diversion law, AB 939, that mandates a 

50% diversion rate for the state’s solid waste as compared to the 1990 baseline, to be 

achieved by 2000. Although the statute limits, to some extent, the amount of material 

used for fuel that can be counted as diversion, for the most part the law has promoted the 

diversion of a significant portion of the state’s waste-wood stream from landfill disposal 

to use as a fuel. Although the deadline for compliance has come, about half of the State’s 

Counties are not in full compliance with the law. The law’s enforcement mechanism, 

which entails draconian fines for cash-strapped public entities, is not being used. If some 

mechanism can be applied to move more jurisdictions into compliance, that could only 

have a positive effect for the state’s biomass fuel supply. 

California’s forests are in rather poor condition today. Extensive stands are severely 

overstocked with both live and dead biomass material, and as a result are at severe risk of 

destructive wildfires, and are not providing the level of ecosystem services that healthy 

forests provide, such as wildlife habitat and functioning watersheds. Federal forestlands, 

which account for approximately half of California’s commercial forests, are in 

considerably worse condition than state and private holdings. There has been a good deal 

of talk over the past few years at the U.S. Forest Service (USFS) about the need to 

perform thinning operations of all kinds on federal lands, in California, and throughout 

the West. Federal funds have been allocated to perform treatments on federal forestlands, 

and studies are underway. However, there is little evidence in the field of increased 

thinning activity on USFS holdings. Forestry contractors in California are anxious to go 

to work on timber stand improvement operations, however many are so discouraged by 

the lack of available projects that they are talking about selling their equipment and 

closing shop. In-forest residues represent the state’s most extensive under-tapped source 
 16

of additional biomass fuel. The value of using this material is much greater than the 

value of the electricity that can be derived from it, and significantly less that the cost of 

delivering it to the market (Morris, 1999). Thus, a serious program of funding for 

increased forest thinning would be highly desirable. 

At the present time, there is sufficient unused capacity in the state’s existing biomass 

power industry to accept a limited amount of additional fuel, should current or proposed 

programs increase the supply of targeted fuels (see Figure 10). Ultimately, however, 

incentives to increase the use of targeted types of biomass fuels will lead to a zero-sum 

process, in which other types of biomass will be squeezed out of the marketplace, unless 

additional idle biomass facilities in the state are restarted, and/or new biomass facilities 

are built. That will not be easy, for a couple of reasons. First, new facilities are 

expensive, and require higher revenues than existing, amortized facilities. Second, 

expanding the use of biomass fuels in the state will cause the average cost of fuel in the 

state to increase in accordance with the observed state biomass fuel supply curve, as 

shown in Figure 11. These factors need to be taken into account in the design of an 

integrated biomass energy policy. The amount of increased production of forest residues 

alone that could be recovered from thinning operations could easily exceed 250 MW 

equivalent, if sufficient incentives were enacted to underwrite the program. The existing 

industry alone could not absorb the amount of residues that could be produced if a strong 

and funded biomass policy was put into effect. As far as we can see, however, there is 

little chance of that happening in the near future. 

Use of New Biomass Technologies in California 

California’s biomass power plant developers have shown themselves to be willing to 

innovate, and have repeatedly expressed interest in future technological innovations, 

subject to the understanding that they have to operate in a sound business environment. 

During the 1980s, when the major part of the industry’s development took place, 

seventeen California biomass power plants were built with fluidized-bed combustors. 

This represented more than 50% of the total global installation of these units during this 

period, and was a major contributor to the advancement of the technology. Fluidized-bed 

combustion is still considered state-of-the-art with respect to efficient and low-emissions 

combustion of solid biomass fuels. 

Only a few new biomass power plants have been built in California since the end of the 

development cycle that was spurred by the 1980s PPAs. One new project that started up 

in 2001, a seven MW project built by Sierra Pacific Lumber Co. at their sawmill in 

Anderson, utilizes a close-coupled gasifier / combustor technology. This technology has 

the potential to decrease emissions below the level achievable with a fluidized bed, and 

may contribute to the deployment of gasifier technology in the future. 

As interest has grown in developing technology to convert cellulose to ethanol, ethanol 

developers have become interested in the possibility of co-locating ethanol production 

facilities with existing biomass power plants. Co-location would allow each process to 

share facilities and coordinate operations, with benefits for each (see, for example, Morris 
 17

2002b). Several California biomass generators have shown an interest in exploring colocation options, with two or three having conducted comprehensive engineering studies 

for projects at their sites. Ethanol-from-cellulose has not yet achieved competitiveness 

with grain-based ethanol produced in the mid-west, so these projects have not been able 

to move forward. 

California’s biomass power producers recognize that their costs of operations are higher 

than those of their fossil-based competitors. While they have managed to persevere 

through wild and wooly changes in the electricity market, they understand the 

precariousness of their position. For this reason alone, they are always open to the 

possibility of incorporating new technologies and processes into their operations that will 

allow them to increase their competitiveness. Indeed, significant new development of 

biomass generating capacity in California appears unlikely in the current environment, 

unless new technology becomes available that can increase efficiencies and/or decrease 

the costs of operations. 

Conclusion 

California currently has thirty-one biomass power plants in operation, representing a total 

of 631 MW of electricity generating capacity. This is less than the 750 MW that were 

operating during the beginning of the 1990s, but considerably more than the 540 MW 

that were operating during the later 90s. 

Approximately two-thirds of the state’s operating biomass facilities are operating under 

old standard-offer power purchase agreements with fixed energy prices that will remain 

in effect through the middle of 2006. These facilities should be able to operate viably 

until their fixed-price periods expire, then they will have to make other arrangements to 

continue operating. The CPUC’s reinforcement of the RPS program’s rules requiring 

utilities to maintain their baselines as part of their overall compliance requirements will 

maintain pressure on the utilities to deal with these facilities when the expiration date 

comes. 

The other one-third of California’s biomass power plants are operating under a variety of 

shorter term power sales arrangements. Short-term prices have been relatively high in 

California during 2003, so most of these facilities have been able to persevere while they 

pursue longer-term arrangements. However, the immediate future of some of these 

facilities remains in doubt, more so than the future of the facilities that have longer term 

contracts. 

California’s ambitious RPS program is designed to restore the state’s leading role in 

renewable energy production. Biomass energy production is one of the keystone 

resources in California’s existing renewable energy infrastructure, and it has the potential 

to be a key contributor to the growth of renewable power production in the state. It has 

also become a key component of the state’s solid-waste disposal infrastructure. However, 

converting biomass to electricity is expensive, and the future of biomass energy 

production in the state is dependent in large part on policy decisions that will be made 
 18

over the coming years. The RPS program by itself, which is designed to advance the 

lowest-cost renewables, may not be much of a stimulus to new biomass energy 

development in California if supplementary policy actions aren’t taken to support 

biomass energy. 

A variety of elements over the past decade have been attempting to foment an integrated 

biomass policy for California, which combines energy concerns with environmental and 

waste-disposal issues. So far little progress has been made, although several limited 

programs have been put into effect. Biomass power production reduces the open burning 

of agricultural and forest residues, and reduces the amount of material entering the state’s 

landfills. It also promotes forestry treatment operations that improve the fire-tolerance of 

the state’s forests, and increases their health and productivity. Although it is well 

documented that the ancillary benefits of biomass energy production are worth far more 

than the cost of providing incentives, establishing a biomass policy will be extremely 

difficult in the current budget climate. 

References 

CPUC, Proposed Policy Decision Adopting a Preferred Industry Structure, Order 

Instituting Rulemaking / Order Instituting Investigation on the Commission’s Proposed 

Policies Governing Restructuring California’s Electric Services Industry and Reforming 

Regulation, OIR.94-04-031 / OII.94-04-032, San Francisco, CA, April, 1994. 

Morris, G., Wiser, R., Pickle, S., eds., Renewables Working Group Report to the CPUC, 

Report supported by NREL, the California IOUs, the California renewable industries 

associations, and environmental organizations, August, 1996. 

Morris, G., The Value of the Benefits of U.S. Biomass Power, NREL Report No. 

NREL/SR-570-27541, November 1999. 

Morris, G., Biomass Energy Production in California: The Case for a Biomass Policy 

Initiative, NREL Report No. NREL/SR-570-28805, November 2000. 

Morris, G., Biomass Energy Production in California 2002: Update of the California 

Biomass Database, NREL Report No. NREL/SR-510-33111, December 2002a. 

Morris, G., Bioethanol Co-Location Study: August 15, 2000—February 28, 2002, NREL 

Report No. NREL/SR-510-33000, November 2002b. 
 19

Figure 1 

California Biomass Power plants 1985 California Biomass Power plan

 MW net 

0-15 

15-30 30-60 

 operating 

 idle  dismantled 
 20

Figure 2 

California Biomass Power Capacity

-

50

100150200250300350400

1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002

MW new and shut down capacity

Operating Capacity (scale on right)Shut Down Capacity (scale on left)Capacity Additions (scale on left)
 21

Figure 3 

California Wholesale Electricity and Biomass Fuels Prices

0.01.53.04.56.07.59.0

10.512.013.515.0

1980 1985 1990 1995 2000

¢ / kWh

PG&E SO#4 fixedPG&E SRACIndustry Ave. Ele. Inc. CapacityFuel Price (scale on right)
 22

Figure 4 

1980

1981

1982

1983

1984

1985

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002 -

500

1,00

1,50

2,0

2,5

3,

California Biomass Fuels Market by Category

In-Forest ResidueAg. ResidueUrban ResidueMill Residues
 23

Figure 5 

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

10

15

20

25

30

35

40

45

50

$ / bdt

Biomass Fuel Prices by Category

Mill ResiduesIn-Forest ResidueAg. ResidueUrban Residue
 24

Figure 6 

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

2,0

2,

3,

3

4

4

California Biomass Fuel Use and Electricity Production

Electric ProductionTotal Fuel Use
 25

Figure 7 

California Biomass Power plants 1995 California Biomass Power plan

 MW net 

0-15 

15-30 30-60 

 operating 

 idle  dismantled 
 26

Figure 8 

SRAC and PX Prices in California 

0.005.00

10.0015.0020.0025.0030.0035.0040.00

1990 1992 1994 1996 1998 2000 2002 

¢/kWh

PG&EPX
 27

Figure 9 

California Biomass Power plants 2003

 MW net 

0-15

15-3030-60

 operating

 idle dismantled

Facility Codes from

Table
 28

Figure 10 

California Biomass Fuels Market

0

1,0002,0003,0004,0005,0006,0007,000

1988 1990 1992 1994 1996 1998 2000 200

thousand BDT/year

Unused Fuel Use CapacityTotal Fuel UseFuel Price (scale on right)
 29

Figure 11 

 California Biomass Fuel Supply Curve 

1999 2000

1992

1991

1987

1986 

1988

1989

1993

1994

1995

1997

1996

1998

2001

2002 

10.0015.0020.0025.0030.0035.0040.0045.00

2,500 3,000 3,500 4,000 4,500 5,000 5,500 

mbdt

$/bdt
REPORT DOCUMENTATION PAGE Form Approved 

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Subcontract Report 

4. TITLE AND SUBTITLE

The Status of Biomass Power Generation in California, July 31, 2003 

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G. Morris 

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KCL-0-30040-03 

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Green Power Institute, Pacific Institute for Studies in Development, Environment, and 

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National Renewable Energy Laboratory 

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13. ABSTRACT (Maximum 200 words)

This report describes the development of the biomass power industry in California over the past quarter century, and 

examines its future outlook. The development of a state biomass policy, which has been under discussion in California for the 

better part of the past decade, has never gotten off the ground, but a number of smaller initiatives have helped to keep the 

biomass power industry afloat and have promoted the use of some targeted types of residues. In this report we analyze the 

prospects for policy development and the application of new biomass technologies in California. 

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biomass; California; power generation 16. PRICE CODE

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