California's Homeless Biomass Problem

Biomass power generation in California is threatened by expiring contracts, low energy prices and an unlevel playing field, leaving millions of tons of biomass fuel without a use.
By Ron Kotrba | August 25, 2015

California’s immense stores of waste biomass once had a plush abode in the equitably priced, long-term power purchase agreements (PPA) that stemmed from the state’s aggressive interpretation of federal legislation—the Public Utilities Regulatory Policy Act of 1978—born out of the energy crisis of the early 1970s. At its peak in the early 1990s, the California biomass energy industry produced almost 4.5 billion kilowatt-hours (kWh) per year of electricity, according to the National Renewable Energy Laboratory, and each year provided a good home to more than 10 million tons of the state’s solid wastes. PURPA required electric utility companies to buy privately produced power at their avoided cost of generation, in essence spawning development of the independent power industry in the U.S. High avoided cost rates, particularly in California, and favorable federal tax policy for renewable energy projects provided the impetus under PURPA for explosive growth for the state’s biomass power industry.

NREL states that many of the facilities that entered service during the late 1980s had what’s called Interim Standard Offer No. 4 PPAs with California’s two major electric utility companies, Pacific Gas and Electric Co. and Southern California Edison Co. Only available for signing in 1984-‘85, standard offer No. 4 allowed pricing of biomass power based on energy price forecasts for the first 10 years of facility operations—a much more attractive option than using fluctuating, short-term prices. Forecasts were based on the high avoided cost rates of the time, 5 to 6 cents per kWh. After the 10-year fixed-price period was up, biomass power plants were compensated based on the then-current market price, referred to as the short-run avoided cost (SRAC). Most of the contracts were written with 30-year terms.

As energy prices dropped in the early 1990s, SRAC rates dropped. Many biomass power plants were immune since they were locked into 10-year fixed prices, but increased biomass demand led to high feedstock prices. Since then, the industry has gone back and forth with unfavorable regulations such as the California Public Utilities Commission’s Blue Book Proposal, which prompted PPA buyouts as biomass power plant owners grew concerned about their 30-year performance obligations amidst higher feedstock costs and lower SRAC pricing, and favorable short-term legislative fixes such as AB 1890, which superseded CPUC’s Blue Book Proposal and recognized the waste disposal benefits of biomass power. AB 1890 directed the state EPA to study policies that would shift some costs of biomass energy production away from the electric ratepayer and onto the beneficiaries of the waste disposal services it provides. Even though biomass power plants that were unable to secure fixed pricing under a standard offer No. 4 PPA received a short-lived 1.5-cent-per-kWh subsidy from a renewable transition fund established by AB 1890, enactment of cost-shifting regulations never came to fruition.

Industry, Jobs, Air Quality in Jeopardy
Today, despite a strong renewable portfolio standard (RPS), the most aggressive greenhouse gas (GHG) reduction efforts in the nation, bans on open-burning and various landfill diversion regulations, the California biomass power industry teeters on extinction, leaving untold tons of waste biomass—and a significant number of jobs tied to the collection, transport and preparation of this material—in limbo.

While SRAC pricing is established using a complicated formula, according to Julee Malinowski-Ball, executive director of the California Biomass Energy Alliance, they are fundamentally based on the price of natural gas. “It’s abundant and super cheap,” she says. “In the post-crisis world, fixed energy pricing has been five years at a time, and we’re on the very last opportunity under any fixed pricing. Those fixed energy prices are expiring, and contracts themselves are expiring.” She says those plants whose fixed contracts are expiring are being offered 3 cents per kWh or less, a fetch unable to sustain a facility that must pay for the fuel itself along with its collection and transport. “Facilities can’t run on SRAC, so they’re shutting down.”

She says at the peak in the 1980s, there were 63 biomass power plants operating in California. “Today, there are 25,” she says. “We lost five plants in the past 18 months. Prior to that, we were losing a plant a year. Today, we have 535 MW of capacity and at the peak I’m guessing there was about a thousand.” 

Depending on their size, Malinowski-Ball says facilities whose contracts are expiring have a couple of options. The first option is bidding into new request for proposal. “Facilities are bidding into them, but they’re not winning,” she says. “The reason is that the solar stuff is coming in so cheap—5 or 6 cents—and while biomass may meet California’s least-cost, best-fit standard, it’s not just about cost. The utilities don’t actually just use least-cost, best-fit, they use the cheapest they can find and contract with that.” As a result of contracting with intermittent renewable sources of power such as solar and wind, the grid has had a “tough time balancing,” Malinowski-Ball says. “It’s not the utilities’ responsibilities to care about how the grid functions. They just want to procure the least-cost option—and that’s not us. Biomass is a different bird in the renewable world. We have to pay for fuel, collection and transport to facilities. It puts us in a range that’s far above the brand new solar PV stuff coming in.”

The second option is to bid into an auction opportunity under 20 MW. “But there’s no must-take mandate there, and no biomass facility has procured a contract under those options,” she says. “The way our RPS program is implemented, there’s bias against baseload resources. We’re trying to fix that, but it’s not going to be quick.”

With AB 32 (the GHG reduction mandate) and a robust RPS, “this should clearly add up to a variety of renewable technologies,” Malinowski-Ball says, “but when it came to reality and the way the RPS program is implemented, we said, ‘Wow, we’re never going to win these RFOs.’”

Greenleaf Power shut down two California biomass facilities last fall; a 38-MW facility in Humboldt County that uses timber slash and sawmill residuals, and a 17-MW plant in Tracy, which uses urban diversion from San Francisco Bay combined with agricultural materials from the Central Valley, including orchard trimmings, prunings and removed trees. The company has six plants altogether, four in California.

Rob Pennington, vice president of finance for Greenleaf Power, says the CPUC drives the decision-making of the investor-owned utilities in the state, and there is inadequate valuation of the attributes biomass power offers versus intermittent renewables. “Little value is given to the baseload nature of biomass facilities that have a flexible level of generation,” he says. “Furthermore, no value is given to the economic benefits of these facilities, which are more jobs per MW hour than any others.” Part of this jobs equation includes fuel suppliers up and down the state. These are small businesses with small trucking operations that own one or two wood chippers. “These folks are not supplemented by large corporations,” Malinowski-Ball says. “We call them dedicated indirect jobs, jobs that mostly don’t exist without facilities to serve, so they send people home and the fuel supply infrastructure loses jobs. They’re the middle man. They deal with the growers and farmers. They reach out to them and then sign contracts with us for delivery.”

Pennington also notes the undervalued environmental service biomass power plants provide to California’s air quality by avoiding open burning. “What doesn’t go to the shutdown facilities will be burned in the field,” Pennington warns. “Over the past 20 years, this material has been diverted to biomass facilities.” Biomass power plants also divert urban wastes from landfills. And the state’s wooded areas have benefited by thinning, which improves forest health and wild fire risk. Biomass power facilities are not being credited for these benefits.

Pennington says without a home, this material is destined for open burning, rolling back decades of progress in renewable baseload power generation and air quality. “Our biggest problem is not landfill diversion,” Malinowski-Ball says. “The bigger issue is more of a health-based problem—the return of open burning. In the San Joaquin Valley there’s a ban, but you can get permits.”

Morgan Lambert, deputy air pollution control officer for the San Joaquin Valley Air Pollution Control District, says he’s seen no significant increases in open-burning permitting requests yet, but several meetings with biomass interest groups have made him acutely aware of the ongoing situation. “From their perspective, it’s a serious issue,” Lambert says. Though open burning has been banned in the valley for years and phased-in reductions outside the valley have also been in effect, these all rely on there being an economically feasible alternative to open burning. “If not, then we can still allow agriculture waste burning in the valley,” he says. Lambert adds that the SJVAPCD will continue to monitor this matter, working with stakeholders to understand what their issues are to make sure the agency is in the loop. “At some point we will see more of an impact,” he says. “It’s harmful to our agriculture community in valley, and we’re sensitive to that.” 

Legislative Aid
At the heart of the problem is an unleveled playing field. “No technology is getting by without any government support except biomass facilities,” Malinowski-Ball says. “Wind and solar get tons of incentives that our facilities are not getting. We’ve not gotten a dime from the government in many years. In a perfect world, no one would have incentives, but we don’t live in perfect world. Solar in California gets property tax exemptions worth billions of dollars—it’s a full production tax credit. It’s a very unleveled playing field in the RPS and, until it’s leveled, we need some support. Even if everything gets leveled, we can still make the argument that the beneficiaries to biomass power technology are not paying. If local governments are under [landfill diversion] mandates but are not contributing to it, then that’s a problem.”

Pennington says there are tax credits available for construction of new facilities, including biomass, “but there’s no support to maintain existing facilities,” he says. “We feel it makes more sense to maintain existing facilities than to build new, especially when existing biomass facilities provide benefits other technologies don’t. But none of that occurs. Solar power produces when the sun shines, and then the grid has to find ways to store it when needed, and dispose of the excess generated. There are costs going into building out transmission to support that level of intermittent generation, and storage to deal with those issues, none of which is being factored into the economics of the buying decisions of the utilities. They’re looking to buy cheapest dollar per-MW basis. None of the attributes we bring to the table are being factored.”

And it’s not just about subsidies, Pennington says. “That’s part of it, but we have a higher-value product, and we’re being forced to compete with technologies and generation that should be valued less than what we produce, resulting in the closure of a number of facilities. The state and regulations haven’t addressed the issue to level the playing field.”

Passage of AB 2363 last year was the first attempt to level the playing field. “What the bill did is [require] CPUC to review and come up with grid integration costs for all renewable technologies so that can be a part of the bidding process in future RFOs,” Malinowski-Ball says. “And this affects solar, so if our and the utilities’ numbers are correct, it’s another penny-and-a-half or more.” According to a press release from Assemblyman Brian Dahle, the sponsor of AB 2363, the act acknowledges that wind and solar electricity require expensive backup power or storage to ensure consistent availability of electricity despite changes in the weather, yet the CPUC has not included those costs when figuring the cost of renewable energy sources as it reviews utilities’ power purchases. A better accounting, initiated by AB 2363, will help level the playing field within the renewable sector and ensure small hydroelectric, geothermal, and biomass energy producers have a fair shot at selling power into the market. While repeated requests to interview Dahle were ignored, his press release states that “large tax credits and other incentives for wind and solar have undermined the financial viability of some of the North State’s most valuable contributions to the state’s renewable energy future.”

While regulations for AB 2363 get drafted, another important piece of legislation has passed the Assembly and awaits action in the Senate: AB 590. Also cosponsored by Dahle, AB 590 will add incentives for biomass utilization of agriculture and forest wastes. The legislation will divert biomass from landfills and creates renewable energy along with jobs and a myriad of cobenefits to wildlife, air quality and water supply, according to Dahle’s press release. “Biomass power generation is a clean and efficient way to produce renewable energy and help improve our air,” said AB 590 cosponsor Assemblyman Rudy Salas. “In fact, the Delano biomass facility has helped reduce 96 percent of the pollutants released from open-field burning. This facility alone converts 300,000 tons of agricultural waste per year into clean, renewable energy. AB 590 provides the necessary structure and resources to protect and incentivize biomass power in California.”

Malinowski-Ball says AB 590 is a standalone bill proposing a biomass cost-share account using GHG reduction funds from AB 32 cap-and-trade auction revenue. “Electric ratepayers currently pay for their share, but no one is paying for these other societal benefits generated,” she says. “No one is paying landfill diversion and burn bans, so there needs to be a beneficiaries-paid process, and the GHG reduction fund is the seed money for that. In the short term, this fund is designed to be accessed for biomass power plants falling off fixed energy prices or fixed contracts to make sure they don’t go off line. If they do shut down, we can count on GHG emissions increasing from open burning or landfilling. In the long-term, we can do other things with these funds, but in the short-term they’re needed to stabilize the industry while the state puts together a post-2020 climate plan.”

As the bill sits in the senate fiscal committee, there’s another parallel path forward. “The money will be appropriated in the annual GHG reduction fund budget trailer bill, and we hope to be a part of that,” she says. “Technically, we don’t even need the bill [to pass the Senate]. We can work on the budget behind the scenes. However, it’s very important for our industry to take on a standalone bill to educate legislators, so I don’t want to make it sound like we don’t need the bill.” At press time, the Senate was on summer recess, scheduled to return Aug. 17.

“Government support like AB 590 would be great,” Pennington says. “It’s a shame that we as a state provide so much money to fight fires, but we’re not spending money to actively remove the risk on federal lands within the state. A very small amount of dollars go to subsidize the removal of material in a way that could benefit the biomass industry and prevent fire risks and damage to the forests.” 


Dahle noted in his press release that, “In the past few years, we have seen the catastrophic results of forests that are too loaded with forest fuels. The people of my district have lived in a cloud of smoke, as thousands of acres have burned destroying lives, property, critical animal habitat, ruining our watersheds and wasting valuable resources. I introduced AB 590 to address this crisis.”

Pennington says he’s hopeful about the emerging legislation to aid the suffering biomass industry by leveling the playing field while providing a beneficial home to millions of tons of biomass once again, but he’s concerned that when the state finally gets around to valuing the benefits of biomass, these assets may no longer be there. “That language will take time to be written into law and regulations, and allowing the utilities to react to that,” he tells Biomass Magazine. “Our concern with idle facilities is that they won’t be around once the legislation is worked out, and it would be a shame to lose an entire asset class in that time period.”


Author: Ron Kotrba
Senior Editor, Biomass Magazine
218-745-8347
rkotrba@bbiinternational.com