California is by far the No. 1 dairy state in the U.S. with roughly 1.8 million head, concentrated mostly in the Central Valley. According to the California Milk Advisory Board, about one in every five U.S. dairy cows resides in California on some 1,500 to 1,600 farms. On average, each dairy cow produces about 27 to 29 tons of manure a year, meaning annual manure generation from California’s dairy industry reaches an astounding 52.2 million tons annually. And with this much cow manure comes voluminous methane emissions, a potent greenhouse gas (GHG). Michael Boccadoro, executive director of the organization Dairy Cares, says 48 percent of California’s methane emissions come directly from the dairy industry.

Not only does California lead the nation in dairy production, but it is also a trailblazer in GHG reduction legislation with programs such as cap-and-trade and the low carbon fuel standard (LCFS), both fostered under the California Global Warming Solutions Act of 2006 (AB 32). The state also has one of the most ambitious renewable portfolio standards (RPS) in the country. With all of these legislative tools in place, and with more than 100 billion pounds of manure a year responsible for half of the state’s methane GHGs, why are there fewer than two dozen dairy digesters established in California?

“That’s the great question,” says Neil Black, president of California Bioenergy LLC (CalBio). “Because of those issues, we established CalBio. We have the largest dairy industry, the most sophisticated renewable energy environment and leaders on addressing climate change. I’d say that the focus on the renewable energy side has historically been on solar and wind in California.” Black says California is playing a major role in developing world-leading climate change initiatives, “but those programs are just now getting put into place, and that is leading regulators to look at how to develop specific programs to develop dairy digesters.”

Black says there are ongoing discussions with California Air Resources Board to create a program to take dairy digestion to the much-needed next level. Boccadoro says the dairy industry is pushing ARB to tap into funds from the GHG Reduction Fund—proceeds from the cap-and-trade program—to develop 100 to 200 new dairy digester projects by 2022. “The GHG Reduction Fund sits at about $2.3 billion so far this year alone,” Boccadoro says. “We’ve asked for $100 million a year for five years. That’s the impetus needed to get this industry off the ground. ARB recognizes something needs to be done, and we argue dairy digestion has the most bang for the buck in GHG reduction.”

Boccadoro says development of a robust dairy digester industry in California has little to do with permitting obstacles and boils down to availability of incentive funding and long-term contracts with utilities. He says when federal 1603 Recovery Act funding was available in 2013, procurement contracts were signed and five new projects got built, but in 2014 funding ceased and no contracts got signed and therefore no projects were built. He says there is still $10 million available in this year’s state budget for dairy digesters allocated to the state food and agriculture department, and the next budget cycle looks even more promising. “The governor wants $25 million and the legislature has requested $30 to $50 million,” he says.

In June 2013, Boccadoro and several other experts drafted a report for USDA titled “Economic Feasibility of Dairy Digester Clusters in California: A Case Study,” in which the authors lay out the regulatory and permitting environment in California. The report lists several legislative tools on the books that can be leveraged, or that were specifically designed, to promote dairy digesters, including the cap-and-trade program, the RPS, the LCFS, AB 1900, AB 2196 and SB 1122. 

The report notes AB 1900 was passed in 2012 to clarify and facilitate requirements for injection of biomethane into California’s vast natural gas pipeline system. State law previously prohibited landfill gas from being injected into the pipelines and utilities imposed strict quality and testing requirements on other sources of biogas, such as dairy biogas, making pipeline injection difficult. AB 1900 requires the California Public Utilities Commission, in consultation with the Office of Environmental Health Hazard Assessment and ARB, to develop standards for constituents in biogas to protect human health and pipeline integrity and safety. AB 1900 was expected to facilitate and streamline biomethane injection and promote in-state production and distribution of renewable natural gas. In May, the CPUC issued a proposed decision on regulatory implementation of AB 1900 that imposed the cost of testing on biomethane producers and announced development of an incentive program to offset interconnection costs. Patrick Serfass, executive director of the American Biogas Council, says the proposed rule is “a nice gesture and very well intentioned, but there are some problems in execution.”

“Bearing the cost of testing the gas species listed in the ‘constituents of concern,’ especially to the extremely low levels required, is generally not viewed as fair, especially since nonrenewable natural gas suppliers do not have to pay to test for potentially hazardous trace components present in nonrenewable natural gas, which are not present in renewable natural gas (RNG),” says Sean Mezei, principal with Dekany Consulting Inc. and co-chair of ABC’s RNG working group. “The ABC also appreciates the CPUC’s proposal to offset some of these [interconnection] costs, but the limit of $1.5 million per connection, and the uncertainty of this offset being available when the pipeline connection is constructed, has our membership generally expecting this offset program to be insufficient to change the fact that zero RNG-to-pipeline projects have been installed since AB 1900 was implemented in California.”     

Matt Schmitt, business development director for Colony Energy Partners Tulare LLC, says pipeline injection is a better route for his biogas project than electrical generation. Phase one of Colony Energy Partner’s multifeedstock hybrid project entails procuring 500 MMBtu per day of gas from the Tulare wastewater treatment facility and producing 500 MMBtu of biogas from 200 to 300 tons a day of dairy manure and other agriculture and food processing wastes. The gases will be conditioned on-site and then injected into the pipeline grid. The project received $5 million from the California Energy Commission renewable transportation fuel funds, $3 million from the solid waste authority and $500,000 from the air district. “The key with getting these grants is that your project must support GHG reductions, and you must have your permits before applying,” Schmitt says, adding that permitting takes time and money. “It’s been rather simple for us, we haven’t made it complicated by putting a digester on dairy with all of the regulations on water discharge—we avoided that nightmare. We’re just going into sewer so there are no issues with regard to the water quality board.” Black says California requires double-lined lagoons, a much higher standard than elsewhere, and that adds to the costs. Schmitt says with all of the grid interconnection regulations in the electricity market, his project would be “bogged down for years.” SoCal gas interconnection, CEQA conditional use, air and solid waste permits were all “straight forward,” Schmitt adds.

For dairy projects intending to produce electricity for the grid, SB 1122 requires California’s three investor-owned utilities (IOUs) to purchase 250 MW of bioenergy-based electricity from 3-MW or smaller distributed energy projects, with 90 MW set aside (in category two) for agriculture and dairy biomass and biogas projects. Projects classified as “dairy” must be 100 percent dairy manure, while ag waste biogas projects may have up to 20 percent waste from other categories (i.e., urban or forest wastes). The regulations developed to implement SB 1122 are complicated and imperfect.

The ABC and the Bioenergy Association of California held a joint webinar May 14 titled “California’s New Bioenergy Program Set to Launch This Summer.” Christa Darlington, special counsel with the Placer County Air Pollution Control District, presented and identified key requirements to participate in the program. “There are a few things CPUC asks you to show,” she said. “One is whether interconnection is possible for your facility.” Darlington said projects are required to have a system impact study and be strategically located, and transmission-level upgrade costs must be below $300,000. “If upgrade costs are above that, the project will have to pay it down,” she said. “So it’s not a project development barrier, it’s just a pay-down requirement.” The project must also show that its team has experience, “a low bar to prove,” Darlington said. The project must also demonstrate the facility can comply with requirements, such as having 100 percent site control and an effective capacity of no more than 3-MW electricity production. The facility must be certified as RPS-eligible, qualify under the Federal Energy Regulatory Commission, have commenced operations on or after June 1, 2013, and be online within 30 months of an execution of a power purchase agreement (PPA).

The pricing mechanism is “one of the more complicated pieces of the program,” Darlington said. The first auction is expected this fall, and every six days there’s a potential for new auction and, at that time, a review of what happened at the previous auction will be performed to determine a new price. The price starts at $127.72 per megawatt hour and may go up as high as the $197 cap. The price moves at increments of $4, then $8, and then $12 thereafter. The minimum number of bidders in a specific category is initially three, then after the first bidder strikes at a price there must be at least five projects in the queue before the price will start to move again for that category. The price will rise if less than 20 percent of the MW available per category is allocated. Then the price remains static for the next auction, and then the prices will rise at the following auction. Black says the concern is that it’s expensive to get into the queue, and a higher price is needed to attract projects, but the price doesn’t go up until a sufficient number of projects are involved. “That’s an example of the complexity,” Black says, adding that, while this may work well for solar, it may be problematic for biogas. The IOUs had input in drafting the regulations for SB 1122, and they intentionally made the process “as cumbersome as possible,” Boccadoro says. “They are using it as an obstacle to getting these projects built.”

Peter Brown, president of FFA Fuels, a company selling biodiesel processors and biogas digesters in cooperation with Polygen, says “Petroleum companies and the utilities are very powerful here,” and says that it’s no surprise that SB 1122 regulations are this burdensome, complex and discouraging for biogas projects. “I think SB 1122 is about people trying to make believe they’re moving on something that they haven’t budged on in 50 years,” Brown says. “It’s an unholy combination of regulators banking on businesses banking on individuals from keeping this from happening.”

The utilities “don’t love this program,” Black says. “It’s a small program for them that takes a lot of time, and these projects take a lot of money.” He says the bioenergy community is waiting to hear how PUC implements these regulations, particularly on important issues such as inflation adjustment. “The way this is structured, it could take a very long time to get to the price that’s needed,” Black says. “That’s why the grant side is so important when they’re taking a price at the low end of SB 1122.”

Brandon Moffatt, Harvest Energy Inc.'s senior vice president of energy, presented on the ABC-BAC webinar and said a core issue in implementation of SB 1122 is what to do with attributes from fuel diversion. He said the utilities have proposed a definition that could be interpreted in favor of them taking fuel diversion as well as electricity generation credits. “We reject this,” he said. “BAC and others objected that this approach is inconsistent with prior CPUC and legislative intent. The green attributes issue is complex and needs updating from prior commission rulings.” He said a CPUC workshop to clarify this is likely.

Despite a complicated regulatory environment that simultaneously promotes and discourages bioenergy production in California, two dairy digester projects under control of the American Biogas Energy Co., which is part of CalBio, are moving forward and have recently received grant funding: Lakeview Farms Dairy, Bakersfield and West Star North Dairies, Buttonwillow. Lakeview Farms Dairy received $4 million to install and demonstrate a covered lagoon digester that converts dairy manure into biogas to generate renewable electricity and to prepare a 1-MW generator platform capable of being expanded by using biogas from neighboring dairies. This would be the state’s first genuine dairy cluster, what many believe is a long time coming. Another project in that cluster is Carlos Echeverria & Sons as well as CalBio’s existing 2 -W Old River project. “What’s unique and important about Lakeview is that we’re planning to build a 1-MW dairy digester, but the platform for that will be designed to add a second or third MW from neighboring dairies if and when we build dairy digesters in those,” Black says. “We’re trying to develop economies of scale both in capital expenses and in ongoing operations and management expenses. We’re delighted to have the large Old River project up and running, and to have received funding for two new projects in this cluster.”

Regulations in California are tougher than in other states because of its unique issues: nonattainment zones from dense human populations and associated vehicle and power plant emissions along the coastal regions, juxtaposed with nonattainment zones from multiple sources, including the dense dairy population in the Central Valley. Black says all-in-all, the regulatory environment is improving for dairy digester development in California. “I think the regulatory community is filled with very smart, hard-working public servants trying to address two important issues,” he says. “That’s how to develop projects that protect the environment, and help this industry get created. And those are the right two things to be doing. We are hopeful the CPUC helps adjust SB 1122 since a successful program is a very important next step. Ideally the utilities, which helped on our independent projects, will come onboard, too.”

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