Overcoming the Biggest Biogas Market Challenges

How California’s Biogas Market is Going to be Fixed… and When

California’s biogas market could be at a turning point in 2018 as regulatory bodies push to eliminate current barriers facing project developers.

“We’re getting successes in ones and twos and tens of projects, and we need a couple of hundred, 500, a thousand,” said Tim Olson, a senior policy adviser on transportation-related topics for the California Energy Commission, a state government agency.

“We’re looking for evolution and growth in the market,” he commented. Olson said California was “on the verge of pretty massive growth” in biofuel production, but that the market was still very much dependent on intervention in the form of targets and investment of seed money to help spur expansion to hundreds of projects.

California is studying new waste-related regulations to support moves to a lower-carbon economy, he said. One of the areas under review concerns short-lived climate pollutants such as methane, hydrofluorocarbons and black carbon.

Methane is between 26 and 85 times more intense than CO2 as a greenhouse gas pollutant, which has forced the Californian administration to set out separate policies to combat it.

Specifically, by 2030 the administration is seeking to reduce short-lived climate pollutants by 50 percent below 2003 levels. Dairy farms account for about half of all methane emissions in the state, and are due to become a major target for the policy. California is the biggest dairy producer in the U.S., with close to 1,400 farms.

“There’s potential legislation which means if you don’t act we’re going to force you to act,” said Olson.

The regulation affecting dairy farms will not be in place until 2024 at the earliest. In the meantime, California is channeling money into the dairy industry to encourage development of on-site methane recovery, for use in either electricity production or transportation.

The methane could be worth up to $8 a gallon in credits from the U.S. Federal Renewable Fuel Standard and California Low Carbon Fuel Standard (LCFS) schemes, Olson said.

An issue still to be resolved is how long these credits, and the value they offer, will remain available to the market. “We’re wrestling with how do you make that credit long term,” said Olson.

Nevertheless, the California Energy Commission expects various business models to evolve in response to the methane opportunity. Smaller dairies might cluster together to jointly fund methane recovery plants, for example. Alternatively, dairy producers could team up with other players looking to exploit biofuels. There are 100 or so wastewater treatment plants in the state that could be interested, for example.

An Added Boost

In addition, landfill sites face policy moves to divert 75 percent of their waste towards biofuel production by 2020. The policy could enter law after 2022, said Olson, giving an added boost to the biofuels market.

In the meantime, the biggest opportunity for project developers is in liquid biofuels.

“We’re deploying money into biofuel production plants, fueling infrastructure, electric charging infrastructure, vehicle demonstrations for new, nonpetroleum- fueled vehicles and manufacturing incentives for a whole range of things,” Olson said.

This support adds up to $100 million a year, he said, and is authorized through to 2024. Although typically, Olson said, “when we deploy money we’re doing it in conjunction with a private firm.”

The California Energy Commission does not intend to cover the cost of “every single project,” said Olson. “It’s really seed money to get projects started. We do it in a co-funded way with a private firm or group of private firms.” The Commission expects to see mostly private money supporting the replication of early projects.

And it sees renewable biogas as being used predominantly for natural gas displacement in transport, “which is a small market in the U.S.,” Olson said, perhaps representing 1 percent or 2 percent of the total transportation fuel volume in California today.

Growing Every Year

The market is growing every year, though, driven somewhat by federal regulations but mostly by state legislation. “This is heavily dependent on government intervention,” Olson said.

Californian public policy relating to renewable biogas has two main objectives. The primary one is to reduce greenhouse gas emissions. Related to this is a reduction in reliance on petroleum fuels. The state has numerous laws to help fulfill these objectives.

One is a cap-and-trade program, similar in design to the Kyoto Protocol, which gives free allowances to greenhouse gas polluters but also has a cap above which the polluter must pay. This is viewed as being friendlier to industry than simply imposing a carbon tax.

In California, the cap is ratcheted down every year and the program is authorized through to 2020, with possible plans for extension to 2030.

The program targets the petroleum sector and electric generation, along with large greenhouse gas polluters such as cement factories and food processors. Polluters can choose to reduce their emissions in a variety of ways, from improving efficiency to using biofuels alongside traditional fuels to reduce the carbon intensity of petroleum products.

A separate scheme, the LCFS, targets fuels rather than polluters. The LCFS aims to achieve a 10 percent reduction in carbon intensity across all fuels in California by 2020. Like the cap-and-trade program, the LCFS works on a ratcheting scale, having started at 0.25 percent and currently standing at 3.5 percent. The LCFS has the potential to create significant demand for biofuels, since it puts a value on fuels with a carbon intensity below that of petroleum, which has around 100 grams of CO2 equivalent per megajoule (g CO2 e/MJ) per gallon. Substituting petroleum with alternatives such as natural gas or corn ethanol can reduce the carbon intensity by amounts in the region of 20 to 25 g CO2 e/ MJ, but with biofuels polluters can achieve negative values.

The LCFS, which has been in operation for more than a decade, assigns monetary credits to these carbon intensities, so they can be traded on private markets and used to deliver revenues that help polluters shift to lower-carbon fuels.

However, the LCFS has come under fire because it rewards Californian and out-of-state providers equally, without accounting for the fact that California has one of the highest gas network interconnection costs in the U.S.

Olson said policymakers were determined to address such concerns. “We’ve learned a lot,” he said. “There are some things that work, that we want to continue. Others we’ve had to adjust on the way.”

In June 2017, regulators held a workshop in Sacramento to discuss scaling up biofuels production and “replicate early successes,” Olson said.

Focus on Transportation

The focus will likely be on transportation, since the carve-out for biogas-based electricity in California’s Renewable Portfolio Standard is rather modest, at 2 percent of total supply.

If selected in auction, biogas providers with under 3 MW of generation capacity could benefit from this carve-out with a 20-year fixed-price contract, which would likely be attractive to investors.

Transportation fuel production, however, could offer four to five times as much revenue, said Olson, albeit without the security of a long-term contract. Policy makers are currently looking at ways of achieving minimum 10-year contracts for transportation fuel, he said.

Another challenge lawmakers need to address is that, even though natural gas is about $0.30 per gallon cheaper than diesel, most fleet owners are reluctant to switch to gas because the vehicles are between $35,000 and $50,000 more expensive.

The California Energy Commission, among other state agencies, provides funds to help cover the difference, but the support has yet to result in widespread biogas offtake agreements needed to attract investors.

To deliver market stability, policymakers are considering three options: setting a floor price for the LCFS credit, imposing a renewable gas standard for California, or introducing a multi-year procurement requirement for utilities.

State agencies will likely be compelled by legislation to decide on the exact policy or policies by mid-2018, said Olson. A solution is needed because the Californian biofuels market is caught in a chicken-and-egg situation.

Strengthening Commitment to Biofuels

Policymakers and investors alike are wary of strengthening their commitment to biofuels before there is widespread evidence that projects will work commercially.

This evidence, in turn, is slow in coming because of lingering challenges that projects face in terms of regulation and investment.

Olson said government subsidies might be able to achieve a 5 percent to 10 percent market penetration of biofuels, beyond which private capital would need to carry the brunt of investment.

The biofuels sector benefits from low technology risk, Olson stated, but is still lacking the 17 percent to 18 percent return on investment levels needed to attract investors. Long-term contracts could help change that, which is why the authorities are now focusing on this issue.

“We think the ingredients are there,” Olson said. “The solution is being debated [and] if we do nothing, we have a big problem related to climate impacts.” And already, some Californian fleet owners, including FedEx and UPS, are showing a significant commitment to biofuels.

This is good news: the Californian Energy Commission expects that once gas-powered vehicle orders surpass around 3,000 units a year then there could be cost reductions that would hasten market growth.

But Paul Relis, senior vice president of CR&R, an environmental services company that provides recycling and waste services to 40 cities in Southern California, said that for now there are still significant obstacles facing biofuel project development in the state. The company has invested $45 million in a plant that will help cut short-lived climate pollutants by substituting diesel with renewable biogas that has “close to zero emissions,” Relis said. The biogas project was about 20 percent supported through grants and consists of four phases, each aiming to process 80,000 tons of organic waste. The first phase is up and running and the second is scheduled to complete in October 2017.

CR&R is aiming to connect its biogas plant to the natural gas grid in the near future. This will allow the company to inject fuel into the gas network and match it with withdrawals from various fleet locations around the CR&R service area.

Renewable biogas production is expected to cover 60 trucks. It has not been an easy endeavor to get off the ground, though. “This project has been 10 years in the making,” said Relis. “I would call that a challenge in itself.”

He said the company spent “many years” identifying the right platform and then assembling a team of technology vendors and gas upgrade system providers.

After that, it took three years to get the project started. “The timeframes involved are quite significant,” Relis noted.

Part of the delay may have been down to the scale of the CR&R plant, which Relis said was “unprecedented.”

Optimized to Use Green Waste

The prime technology provider, Eisenmann, had not built a project of this size before, and the plant had to be optimized to use municipal green waste, an unusual feedstock.

CR&R did not have to worry about availability of feedstock as it has long-term waste disposal contracts with several South Californian municipalities.

Nevertheless, “offering recycling of organics in this context was viewed as an added service,” he said, which meant CR&R had to increase its charges by several dollars a month.

This was a lot of money in the highly competitive Californian municipal waste sector, he said. “Cities had to be convinced this was a worthwhile expenditure for their ratepayers,” Relis said. “Fortunately for us, the storyline was good enough.”

So far, 13 cities have signed up to the scheme. In return, they get 100 percent recycling of organics and clean-fueled trucks hauling waste.

Relis said moves to divert waste from landfill would help companies such as CR&R overcome the fact that tipping costs are currently well below those of recycling.

The plant will also be the first in California to test Rule 30, which requires biogas injected into the state’s natural gas system to have a 90 percent heating value. Meeting this requirement costs about $1.2 million, Relis said. “We feel it’s a questionable requirement,” he said.

As California steps up efforts to encourage biofuels, it remains to be seen whether other developers will face similar roadblocks. For example, the California Public Utilities Commission is now studying whether to relax Rule 30. “Unfortunately, with our time-frame we couldn’t benefit,” said Relis.