California air board officials may seek to convince EPA that the state’s greenhouse gas cap-and-trade program is environmentally equivalent to the federal agency’s pending greenhouse gas regulations for large emission sources, a potentially groundbreaking move that aims to ease compliance burdens on the state’s industries.

Large and small energy consumers in California are protesting a request by utilities to recover from ratepayers more than $12 million in AB 32 greenhouse gas fees that will be levied by state regulators later this year, in a proceeding that could have broad impacts.

And California is seeking a fine line in regulating new bioenergy projects in the state, with top officials urging EPA to exclude these facilities from forthcoming federal greenhouse gas regulations for large sources while arguing that adequate state safeguards can be required.

In This Issue . . .

California May Argue Cap & Trade 'Equivalent' To EPA GHG Rules
California officials are indicating they may argue that a planned greenhouse gas (GHG) cap-and-trade program covering major industrial facilities in the state should be found "equivalent" to U.S. EPA's forthcoming GHG rules targeting such facilities, according to sources. It is unclear when the argument -- which state and industry officials believe could provide significant regulatory relief to their facilities -- might be made, given that EPA's rule is expected to take effect next year and the state's cap-and-trade program does not begin until 2012.

Energy Consumers Oppose California Rate Hike To Recover AB 32 GHG Fees
Groups representing large and small energy consumers in California are protesting an effort by the state's utilities to increase rates on customers to cover the costs of an impending greenhouse gas (GHG) emissions fee, authorized by the state's AB 32 climate change program. The dispute may elevate already fierce debate over the total costs of the GHG program, which supporters of a voter initiative to suspend the 2006 climate law have charged would cause fuel and electricity prices to soar.

California Seeks Fine Line In GHG Permitting Of Bioenergy Plants
California regulators are negotiating a fine line between competing interests to both support the deployment of new bioenergy plants while also ensuring that they employ "safeguards" to avoid emitting greenhouse gases (GHG), thereby satisfying both state and federal regulations. The state officials are under competing pressures -- on one hand, from companies and municipalities looking to gain renewable energy and low-carbon fuel credit with the plants; on the other, from environmentalists and academics who argue many of these facilities are far from "carbon-neutral" and must be stringently permitted.

Auto Industry Criticizes EPA Cost Estimates In Opposing Strict GHG Rules
Auto industry officials will fight possible greenhouse gas (GHG) rules equivalent to roughly 60 miles per gallon (mpg) fuel economy by model year 2025 cars and light-duty trucks by attacking a preliminary U.S. EPA-Department of Transportation (DOT) analysis that they contend simplifies and underestimates the economic costs associated with the strict GHG limit.

California May Argue Cap & Trade 'Equivalent' To EPA GHG Rules

California officials are indicating they may argue that a planned greenhouse gas (GHG) cap-and-trade program covering major industrial facilities in the state should be found "equivalent" to U.S. EPA's forthcoming GHG rules targeting such facilities, according to sources. It is unclear when the argument -- which state and industry officials believe could provide significant regulatory relief to their facilities -- might be made, given that EPA's rule is expected to take effect next year and the state's cap-and-trade program does not begin until 2012.

The possible California request would be considered groundbreaking, in that it could shape how other states could potentially seek "equivalency" under EPA's Clean Air Act rules for GHG emission controls.

Mary Nichols, chairwoman of the California Air Resources Board (ARB), the lead state agency implementing the state's AB 32 GHG regulations, indicated during an Oct. 1 state legislative hearing that an equivalency argument could be made to EPA at some point in the future.

"You know, most of the larger companies that do business in the state of California compete to some degree or anther in a global marketplace, and they are subject to rules that are in effect for example in the EU, if they do business there," Nichols said. "And increasingly they're worried about actions that are being taken at U.S. EPA, which in the absence of any federal legislation is moving to regulate greenhouse gases under the existing Clean Air Act authority, through permitting requirements and new source performance standards, best available control technology, and all that full panoply of clean air regulation. And increasingly we're seeing companies coming to us and asking us to move forward in a more definitive way, particularly on the cap-and-trade program, to get that program designed and ready to put in place for the simple reason that they would like to forestall the kind of uncertainty that will come into effect if U.S. EPA begins to take over this activity." She added: "So, I think as Californians we have a pretty good track record over the years of having addressed our smog problems and having dealt with our energy concerns at the state level in ways that met our environmental and economic needs, and I think that we can do it again using AB 32."

Nichols made her comments during a joint legislative hearing regarding California's Proposition 23, a referendum on the Nov. 2 ballot that would suspend AB 32 rules.

An oil industry source said Nichols was essentially saying that "if California wants to push back on EPA and federal requirements, California needs a program like cap-and-trade to say to EPA 'go away, we already have a program and are equivalent so we don't need yours.' So a well-designed California cap-and-trade program is better for business than the EPA prescriptive command-and-control program." The source said Nichols' comments indicate ARB is "willing to try" to make an equivalency argument.

Another industry source "suspects" ARB will seek the equivalency finding.

An ARB spokesman did not return requests for comment.

ARB is proposing to implement its cap-and-trade program in 2012 and link it to the Western Climate Initiative (WCI), a regional cap-and-trade scheme that includes New Mexico and three Canadian provinces.

The California and WCI programs would place caps on facilities that release more than 25,000 tons of GHG-equivalent emissions annually. This goes beyond EPA's GHG "tailoring rule," which initially targets facilities that emit 75,000 tons or more annually.

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Energy Consumers Oppose California Rate Hike To Recover AB 32 GHG Fees

Groups representing large and small energy consumers in California are protesting an effort by the state's utilities to increase rates on customers to cover the costs of an impending greenhouse gas (GHG) emissions fee, authorized by the state's AB 32 climate change program. The dispute may elevate already fierce debate over the total costs of the GHG program, which supporters of a voter initiative to suspend the 2006 climate law have charged would cause fuel and electricity prices to soar.

The rate hike dispute also provides a glimpse into the extent utilities around the country might try to pass on new costs from novel GHG regulations and fees, a dicey issue that state officials and utilities are likely to battle over in the coming years.

Three energy-consumer groups have filed protest letters with the California Public Utilities Commission (CPUC) to challenge a joint application by the state's investor-owned utilities to recover from their ratepayers the costs of paying new AB 32 fees to be assessed later this year by the California Air Resources Board (ARB). The utilities -- Pacific Gas & Electric Co. (PG&E), Southern California Edison (SCE), San Diego Gas & Electric (SDG&E) and Southern California Gas Co. (SoCalGas) -- asked the CPUC in an Aug. 2 application for authorization to increase their electric and gas rates and charges to collect the "reasonable level of revenue requirements to recover the costs" of ARB's AB 32 annual cost of implementation fee.

But last month, the three groups -- the Energy Producers & Users Coalition (EPUC), the Cogeneration Association of California (CAC) and the San Diego-based Utility Consumers' Action Network (UCAN) -- filed protest letters against the rate increase for several reasons. EPUC, which represents major oil companies, argues that its members could be hit with "double fees" under AB 32 and face an uneven playing field if the utilities can recoup the fees from ratepayers but oil companies cannot.

"In order to ensure that approval of the joint application will not lead to an uneven playing field, the commission should condition approval of this application on the inclusion of a similar pass-through provision to allow non-utility generators to pass through these same costs," states a Sept. 1 letter filed by EPUC and CAC, which asked CPUC to open a discovery phase for the application.

"Without this accommodation, the commission would be approving a mechanism through which pass-through of these AB 32 incremental costs will depend solely on ownership of generation resources," the letter states.

Additionally, the cogeneration industry fears that the utilities may overcharge their member companies. "The commission must ensure that utility tariffs do not force industrial sites with combined heat and power facilities to pay the AB 32 implementation fee in excess of the facility's use," the letter adds. "ARB's AB 32 implementation fee regulations clarify that the fee should be allocated based on consumption. The mechanisms proposed to recover these costs must be consistent with ARB's intent. Without changes to the proposed tariffs, combined heat and power facilities that are not allowed to 'net' meters will be forced to bear a larger share of the implementation fee than it should."

At the same time, the San Diego UCAN group charges that SDG&E lacks the legal basis to seek the rate increase to cover the GHG fee for several reasons, according to its Sept. 9 protest letter. For example, the group argues that because the state's budget has not yet been approved -- and ARB's fee bills have not been issued -- it is premature for the utility to seek cost recovery.

Utilities Defense Rate Hikes

The utilities sought to rebut the consumer organizations' arguments in reply letters filed with CPUC in mid-September. For example, regarding the EPUC argument that the utilities' cost recovery will result in double fees, the utilities respond that large industrial sites will pay for the AB 32 fee associated with the natural gas through its "gas transportation rate," according to a Sept. 13 joint reply letter to CPUC. In addition, "like all other electric customers, the industrial site will pay the costs incurred by electric generators via a higher electricity rate . . . for the electricity it purchases." But the industrial site will be compensated for electricity sold to the grid through a "short run avoided cost" formula, the utilities state.

Regarding impacts on competition, the utilities argue that because non-utility generation facilities will be reimbursed through the "short run avoided cost" formula, a fair level of competition is maintained.

It is unclear when CPUC officials will decide whether to approve or deny the utilities' application.

PG&E estimates its annual AB 32 fee will be approximately $4.8 million; SoCalGas will pay an estimated $4.5 million; SCE $2.4 million; and SDG&E estimates its bill will be $800,000, according to the August application.

Additionally, as part of a Sept. 27 filing with CPUC, SDG&E states that large industrial and electric generation energy bills will increase by 1.1% if CPUC approves the cost recovery application.

But SCE estimates in its Sept. 27 filing with CPUC that its bills for "large power" will only rise by 0.03% if the application is approved.

And PG&E says its rates will increase from between 1% and 2.8% for a variety of small and large industrial customers, according to a Sept. 23 filing.

One of the major points of debate in California over a Nov. 2 ballot initiative -- Proposition 23 -- to suspend the AB 32 GHG rules is to what extent the law will cause fuel and electricity prices to increase beginning in 2012 or sooner. Opponents of Prop. 23 have maintained that consumers will see manageable increases in the years to come, while supporters of the initiative point to studies showing sharp increases to utility bills, gasoline and diesel fuel.

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California Seeks Fine Line In GHG Permitting Of Bioenergy Plants

California regulators are negotiating a fine line between competing interests to both support the deployment of new bioenergy plants while also ensuring that they employ "safeguards" to avoid emitting greenhouse gases (GHG), thereby satisfying both state and federal regulations. The state officials are under competing pressures -- on one hand, from companies and municipalities looking to gain renewable energy and low-carbon fuel credit with the plants; on the other, from environmentalists and academics who argue many of these facilities are far from "carbon-neutral" and must be stringently permitted.

Complex and intensely debated, the issue of whether wood and other waste materials combusted in plants to produce electricity or fuel results in excess GHG emissions is a key piece of pending federal and state regulatory policies. In California, current law places permitting hurdles in front of some of these projects based on the definition of combustion and its associated air pollutants; however, leading state officials are asserting that with proper safeguards in place, these facilities should be able to be built and meet both the state's renewable power definition and its low carbon fuel standard (LCFS).

On the federal level, California officials are recommending that U.S. EPA exclude certain bioenergy plants from its pending GHG regulation for large industrial facilities, citing the state's current stringent rules and the uniqueness of bioenergy facilities proposed in the state. But at the same time, California environmentalists and some university researchers contend EPA must ensure these facilities are captured under EPA's GHG "tailoring" rule, that they implement best available control technology (BACT), and that they are stringently regulated by the state as well.

EPA earlier this year proposed to include bioenergy plants in its pending GHG "tailoring rule" that aims to set permit conditions for GHG emissions on large industrial facilities, under the Clean Air Act's prevention of significant deterioration and Title V programs. However, after receiving objections from a variety of stakeholders, EPA then opened a proceeding calling on parties to submit more detailed data about their positions on bioenergy facility GHG emissions. The comment period for this proceeding ended late last month. It is unclear when EPA will make a final decision on the issue, but most observers expect a decision before the end of the year because the tailoring rule permitting is supposed to take effect early next year.

Dan Pellissier, deputy cabinet secretary for California Gov. Arnold Schwarzenegger (R), is recommending EPA consider not placing bioenergy facilities under the GHG regulation, saying that the source of the biomass being combusted and the conversion process itself are critical in determining whether plants emit excess GHG emissions. The Schwarzenegger Administration is "confident that where appropriate safeguards protect against unsustainable practices, bioenergy can be a 'carbon-neutral,' sustainable energy source," Pellissier states in a Sept. 13 letter to EPA Administrator Lisa Jackson regarding the pending EPA regulation. "Indeed, California is counting on the substantial use of bioenergy to meet our GHG reduction goals." Pellissier does not specify the "safeguards" in his letter.

ARB Lays Out Policy

But in an attachment to Pellissier's letter, the California Air Resources Board (ARB), which is spearheading the state's climate change regulatory program, points out that it has developed GHG emission estimation methods, including for carbon dioxide (CO2) from biomass combustion in the production of bioenergy. These emissions "are considered part of the natural carbon cycle of annual carbon sequestration and emissions, and are tracked in the forest sector," ARB states. "Considering the importance of biomass emissions and concern for sustainability, ARB also tracks facility-specific emissions from biomass combustion through our regulation for the mandatory reporting of GHGs."

Critical to ARB's accounting and reporting structure is the "concept of sustainability and the circumstances under which forest stands are considered sustainable," the board states. "The definition of sustainability may vary depending on specific climate mitigation initiatives and program goals." For California's forthcoming cap-and-trade program, ARB is relying on the "existing bioenergy and forestry policies in California to help ensure a sustainable approach to biomass use. We believe that policy decisions on biomass utilization are contingent upon a complete and proper accounting of biomass CO2 as well as a consistent set of definitions."

Pellissier's position is being challenged by some University of California (UC) researchers and professors, as well as many environmental organizations.

UC Berkeley professors Richard Plevin and Michael O'Hare urged EPA to include bioenergy plants in the pending GHG regulation.

"The position expressed by Pellissier is based on a simplistic understanding of a complex problem," Plevin said in an interview. "As I demonstrate in my EPA comments, 'carbon neutral' is not 'climate neutral.' That forests provide net sequestration does not necessarily indicate that the use of biomass provides climate benefits. Specifically, if there would have been more sequestration absent the use of the biomass, that use might result in a net emission of GHG relative to the baseline."

The critical point is that "whether biomass use benefits the climate depends on many factors, such as avoided wildfires," Plevin said. "It is not preordained, and therefore assuming 'carbon neutrality' is inappropriate. There are clearly conditions in which bioenergy use benefits the climate, but this should be demonstrated analytically, not assumed."

A coalition of environmental groups also urged EPA to include bioenergy plants in its GHG regulation, citing recent studies that question whether current bioenergy processing trends will result in carbon-neutral outcomes. "Three key points are drawn from the literature: first, many bioenergy systems achieve carbon neutrality only after years or decades; second, carbon neutrality is a highly subjective designation, dependent on the system boundaries and accounting methods employed; and third, carbon neutrality does not imply climate neutrality, since biogenic CO2 contributes to climate change between combustion and uptake in new biomass," the coalition states in a Sept. 13 letter to EPA. The coalition includes the Natural Resources Defense Council, Clean Air Task Force, Conservation Law Foundation and Sierra Club.

But Pellissier's position is being strongly supported by numerous California utilities, the forestry industry, bioenergy developers, municipalities and other organizations that are eager to obtain GHG-reduction and renewable power credit under California's landmark renewable portfolio standard and LCFS.

For example, Sempra Energy argues that current practices by the European Union, International Panel on Climate Change, ARB and others consider GHG emissions from the combustion of biomass as carbon-neutral within the energy sector. "Considering the longstanding policy of carbon neutrality for biomass and biogas . . . taking a different approach at this time would considerably complicate GHG programs within the U.S. as well as increase the difficulty of connecting to international programs," states a Sept. 13 letter to EPA from the utility. "Additionally, reversing the current policy of carbon neutrality for combustion of biomass and biogas . . . would severely disrupt existing contracts for supply of what is currently considered to be renewable biomass generation."

California lawmakers have over the past several years rejected legislation that would qualify bioenergy plants that combust municipal solid waste into electricity and fuel for renewable energy credit and potential LCFS compliance. It is unclear whether ARB's support for the failed legislation this year, and Pellissier's position on bioenergy's carbon-neutrality, signals imminent changes to state policy or statute on the municipal solid waste issue.

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Auto Industry Criticizes EPA Cost Estimates In Opposing Strict GHG Rules

Auto industry officials will fight possible greenhouse gas (GHG) rules equivalent to roughly 60 miles per gallon (mpg) fuel economy by model year 2025 cars and light-duty trucks by attacking a preliminary U.S. EPA-Department of Transportation (DOT) analysis that they contend simplifies and underestimates the economic costs associated with the strict GHG limit.

The federal proposal is based in significant part on plans being drawn up by the California Air Resources Board (ARB) to propose state-specific GHG standards for vehicles late this year. ARB is scheduled to adopt its standards in January or February 2011, leaving a significant gap in time before the federal agencies finalize the national standards, expected in 2012.

The EPA-DOT data, which the agencies say they might have to revise in future analysis for the pending rules, likely overstate the ability of manufacturers to achieve a given level of performance at a given cost, an industry source said. "We will certainly bring it up" as a potential problem with the cost estimates, the source said.

Environmentalists, however, said the agencies' early estimates already show that even the most aggressive option for the next round of joint EPA-DOT vehicle GHG rules -- a 6% annual improvement in GHG and fuel economy standards -- is likely to result in lower costs to consumers over the life of a vehicle than less aggressive options.

EPA Oct. 1 issued a notice of intent and a technical assessment for its pending GHG rules for model year 2017-2025 cars outlining the benefits of annual GHG cuts 3% to 6% percent below EPA's existing model year 2016 rules. The notice begins a joint agency rulemaking effort following existing GHG rules for model years 2012-2016 that were finalized earlier this year.

In the notice, EPA and DOT say they will work with ARB as it develops the next round of state-specific standards. The federal notice is not a proposed rule, but rather includes an initial assessment for the 2017-2025 vehicle rules and outlines next steps that the agencies will take as they craft a formal proposal.

The initial assessment for the new rules analyzed the GHG reductions and other benefits that could be gained from four potential GHG targets -- 3%, 4%, 5% and 6% per year cuts in GHGs from the model year 2016 fleet-wide average of 250 grams of carbon dioxide (CO2) per mile. EPA says it chose that range as "a reasonably broad range of stringent increases for potential future GHG emissions standards." The agency in the notice also acknowledges that the 3%-6% range is consistent with increases suggested by ARB earlier this year.

A 3% reduction -- equivalent to a fuel economy of 47 mpg -- would result in a level of 190 grams of CO2 per mile compared to the 2016 average of 250 grams of CO2 per mile. A 4% cut would equal 173 grams of CO2 per mile, or 51 mpg, while a 5% cut would be 158 grams of CO2 per mile, or 56 mpg. A 6% cut would result in a fuel economy standard of 62 mpg and 143 grams of CO2 per mile by 2025, the notice says.

Environmentalists are highlighting estimates from the technology assessment that a 6% annual reduction would save consumers between $5,700 and $7,400 over the lifetime of the vehicles -- more than the $4,900-$5,200 in savings from a less ambitious 3% goal. "They have shown [6%] is very cost effective," said one environmentalist.

But EPA says it could pick a GHG limit outside the 3% to 6% range when it issues a regulatory proposal next year. EPA and DOT also concede that the initial assessment includes simplifying assumptions, and will be refined in part by additional steps, including a supplemental notice of intent to be issued by the end of November.

Those simplifying assumptions include treating the vehicle fleet as one single industry-wide fleet, "irrespective of individual manufacturer differences," and assuming the ability to average greenhouse gas performance across all vehicle platforms. The analysis also assumes "no statutory or other limits on ability of manufacturers to transfer [compliance] credits between car and light truck fleets," according to the agencies' notice.

Auto Industry Cites Costs

While several auto sector sources said they are still reviewing the assessment, one source said that these simplifying assumptions ignore real-world barriers to achieving projected targets at specific costs -- meaning actual costs for achieving a given level of improvement are likely to be higher than the assessment states.

Those barriers include statutory restrictions in current corporate average fuel economy (CAFE) law on transferring credits between car and light truck fleets when determining a manufacturer's compliance with the standard, and CAFE requirements for separate compliance of domestic and imports. The analysis also essentially assumes more liberal credit trading allowed under EPA's version of the rules and the Clean Air Act, the source said.

The assessment acknowledges these concerns -- including the potential for increased costs from revised estimates -- but it also notes that additional analysis will be done for the rulemaking on both cost and benefit of the rules.

On the potential for increased costs under future revised estimates, a footnote in the assessment says that "all other things being equal, limiting credit transfers between passenger cars and light trucks within a firm, and limiting credit trading among manufacturers, are two factors that would likely lead to higher cost estimates."

On additional benefits -- or costs -- from the rules, the assessment says that further analysis to be conducted for the rulemaking will include "improved energy security, monetized benefits of CO2 reductions, co-pollutant impacts, an assessment of the societal costs and benefits of potential standards, an assessment of potential safety impacts, an assessment of impacts on automobile sales and related employment, and other relevant impacts."

The concerns over the simplified analysis come as some auto industry sources are already raising a mix of old and new critiques on what is achievable on fuel economy or GHG improvements, including concerns over the ability of the industry to lighten its vehicles. Specifically, another auto industry source said that even the option of a 4% or 5% annual improvement could only be achieved by "downweighting" -- or lightening -- vehicles by 25% or more, which is "nearly double" what is realistic.

The source argued that assuming less downweighting would require a steep rise in the market share for electric drive vehicles -- as much as 60%-65% market share, to meet the 5% level, which the source said is also unrealistic. The source also flagged the issue of ensuring "equity" among manufacturers, and calculation of upstream emissions from electric vehicles as other concerns for the auto sector.

The source also questioned whether EPA and DOT are being realistic in their assumptions about the availability of electric vehicle and hydrogen fuel charging infrastructure to accommodate advanced vehicles.

The source also questioned why ARB -- which has stated its intent to work closely with EPA and DOT-- is moving to propose state-specific standards by the end of the year for 2017-2025 standards, with a final decision in January or February -- a timeline far quicker than EPA and DOT's schedule, which is not supposed to be finalized until 2012.

EPA and DOT's efforts come, meanwhile, with Canada also taking steps to harmonize its regulations with current and future U.S. rules. Canada Oct. 1 finalized GHG regulations for 2011-2016 model year passenger vehicles and light-duty trucks, with requirements the Canadian government says are meant to match those in the U.S. Canada also Oct. 1 released a notice of intent to regulate model year 2017 and later passenger vehicles and light trucks, and says it is working with EPA to harmonize the two countries future regulations.

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