Inside Cal/EPA

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Inside Cal/EPA

Inside Cal/EPA
An exclusive weekly report on environmental legislation, regulation and litigation
from the publishers of Inside EPA
Vol. 26, No. 8 — February 27, 2015
Ethanol Sector Details Likely New Legal Challenges To California LCFS
Growth Energy, a trade association that represents some of the largest corn ethanol producers in the country, is
detailing extensive legal objections to California’s low-carbon fuel standard (LCFS) “re-adoption” process, potentially
signaling a new round of litigation that could force state officials to further weaken the controversial regulation.
The group — one of whose members, POET, LLC, led a successful challenge to the LCFS that is forcing the
current re-adoption — Feb. 17 submitted hundreds of pages of comments to the California Air Resources Board (ARB)
reiterating earlier charges that the board’s re-adoption process does not comply with a host of state laws.
An attorney for POET LLC, the South Dakota-based ethanol producer, endorsed Growth Energy’s arguments in a
Feb. 17 letter.
continued on page 6
Cal/EPA Says ARB Crafting New Plan For Spending Additional GHG Funds
Cal/EPA Secretary Matt Rodriquez told lawmakers this week that the state air board is working on an updated
“three-year investment plan” that will steer how the administration proposes to spend potentially billions more dollars in
revenue from the state’s greenhouse gas (GHG) cap-and-trade than reflected in the administration’s proposed 2015-16
fiscal year budget.
How the state spends the additional GHG allowance auction revenue is one of the hottest topics in this year’s
budget debate in the Legislature, with various lawmakers and special interests ramping up proposals to steer large
chunks of the money to their preferred programs and projects.
While the Brown administration forecasts in its proposed budget unveiled in January that $1 billion will be genercontinued on page 8
State Court Backs California’s GHG Offset Rules In Face Of Advocates’ Suit
A California appellate court has upheld the state’s rules governing greenhouse gas (GHG) offset protocols for its
cap-and-trade program, rejecting arguments by environmental justice advocates that they fail to ensure “additional”
GHG emission reductions beyond what would have occurred without the program.
A three-judge panel of the state’s First Appellate District Court ruled Feb. 23 in Our Children’s Earth Foundation
(OCE) v. California Air Resources Board (ARB) to uphold a lower court ruling that had also backed the rules. The
decision appears to end the plaintiffs’ challenge, though attorneys for the environmental group say they are still reviewing the decision and considering next options.
The case was being watched around the country as a test of the legitimacy of GHG offsets, measures that have the
continued on page 10
Industry Cites New Science To Fight OEHHA Prop. 65 Plan To Re-List BPA
The chemical industry is attacking a new plan by the health hazard office to have bisphenol-A (BPA) re-listed as a
reproductive toxicant under Proposition 65, charging that the office is ignoring overwhelming new scientific data
showing the product plasticizer is safe and should remain off the list of substances regulated by Prop. 65.
The Office of Environmental Health Hazard Assessment last week announced that the state’s Developmental &
Reproductive Toxicant Identification Committee (DART) will consider at a meeting scheduled for May 7 whether to relist BPA as a female reproductive toxicant.
Prop. 65 listing subjects manufacturers and retailers to requirements to post warning notices on products containing
certain amounts of chemicals, and opens them to state enforcement actions and citizen suits.
continued on next page
INSIDE
BUDGET: LAO Doubles Brown’s GHG Revenue Estimate, Sparking Spending Debate ............... 3
ENERGY: Natural Gas Industry Presses ARB To Further Ease GHG Scores Under LCFS .......... 5
FUELS: Fuels Sector Seen Buying California’s GHG Credits, Casting Doubt On Suit ................. 9
FEDERAL: FERC Meeting Addresses Concerns Over ESPS’ Citizen Suits, Safety Valve .........12
BPA is used mainly as a plastic softener in myriad products, such as bottles, food containers and medical devices.
OEHHA says in the announcement that the DART requested at a July 15, 2009, meeting that it desired to revisit
consideration of BPA if additional epidemiological or other specific types of data on reproductive and developmental
toxicity became available. DART at that meeting declined to list BPA under Prop. 65.
“Substantial new epidemiological and toxicological data on BPA and female reproductive toxicity have become
available since 2009, and thus OEHHA has assembled materials on BPA and female reproductive toxicity for the
[DART’s] consideration,” the announcement says. Relevant documents are available on InsideEPA.com. See below for
details. (Doc. ID: 179206)
BPA was listed under Prop. 65 as a developmental toxicant in April 2013. However, the American Chemistry Council
(ACC) immediately sued OEHHA in Sacramento County Superior Court, charging that OEHHA relied on flawed health
studies and exceeded its authority by adding BPA to the list.
The judge in the case issued an injunction ordering OEHHA to remove BPA from the Prop. 65 list, which was
executed on April 19, 2013, according to OEHHA.
ACC representatives are now attacking the new effort by OEHHA to put BPA back on the list, citing even more
recent scientific studies as backing their arguments.
“In light of the very recent conclusions from the European Food Safety Authority (EFSA) and the U.S. Food & Drug
Administration (FDA) that BPA is safe for use in consumer products for people of all ages, including unborn children and
infants, we are dismayed to hear that the state of California yet again intends to evaluate if BPA should be listed as a
reproductive toxicant under Prop. 65,” said Steven G. Hentges, Ph.D., an ACC scientist, in a Feb. 20 written statement.
“Once again, OEHHA is operating out of synch with the scientific consensus of other government agencies across the
globe.”
The new scientific data cited by OEHHA in its announcement to have BPA reconsidered for listing “has recently been
reviewed by other prominent government bodies,” Hentges says. For example, in January 2015 EFSA concluded that
“‘BPA poses no health risk to consumers of any age group (including unborn children, infants and adolescents) at current
exposure levels,’” he says.
Similarly, in November 2014 the FDA “updated its assessment of BPA and concluded that ‘FDA’s current perspective, based on its most recent safety assessment, is that BPA is safe at the current levels occurring in foods,’” Hentges
says.
“Compared to these clear safety conclusions from impeccable sources, the relevance of OEHHA’s initiative on BPA
to consumer safety is questionable at best,” he adds. “We look forward to fully participating in the [DART] process and
sharing the extensive, robust science on the safety of BPA.”
Background Documents For This Issue
Subscribers to InsideEPA.com have access to hundreds of documents, as well as a searchable archive of back issues of
Inside Cal/EPA. The following are some of the documents available from this issue of Inside Cal/EPA. For a full list of documents,
go to the latest issue of Inside Cal/EPA on InsideEPA.com. For more information about InsideEPA.com, call 1-800-424-9068.
Documents available from this issue of Inside Cal/EPA:

California Legislative Analyst Forecasts More Than $2 Billion From GHG Auction Revenue (179203)

Ethanol Industry Details Multiple Potential Legal Challenges To California LCFS (179204)

Natural Gas Industry Presses California To Lower GHG Estimates Under LCFS (179205)

California Considers Controversial Re-Listing Of BPA Under Prop. 65 (179206)

California Court Upholds GHG Offset Protocols (179207)

Transportation Fuels Bolster Latest California GHG Auction (179208)

Environmentalists Sue EPA To Halt Offshore Fracking In California (179214 )
Not an online subscriber? Now you can still have access to all the background documents referenced in this issue through
our new pay-per-view Environmental NewsStand. Go to www.EnvironmentalNewsStand.com to find out more.
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INSIDE Cal/EPA - www.InsideEPA.com - February 27, 2015
LAO Doubles Brown’s GHG Revenue Estimate, Sparking Spending Debate
The Legislative Analyst’s Office (LAO) is estimating that California will receive at least twice as much from its
greenhouse gas (GHG) allowance auctions in fiscal year 2015-16 than the Brown administration has forecast and is
detailing multiple options for spending the billions of “additional” dollars ahead of an upcoming legislative debate.
In a report issued to the Legislature last week, the LAO suggested subsidizing sources not regulated under the state’s
cap-and-trade program, providing first-time funding for energy efficiency and storage projects, and offsetting state
program funding to allow spending on non-GHG programs. The report is available on InsideEPA.com. See page 2 for
details. (Doc. ID: 179203)
The LAO’s proposals are expected to be debated in upcoming budget subcommittee meetings where lawmakers consider
changes and additions to Gov. Jerry Brown’s (D) proposed budget for fiscal year 2015-16, which was unveiled in January.
Some top lawmakers are already indicating the additional revenue could assist the state in achieving recently proposed goals for curbing emissions after 2020. “The estimated increase in cap-and-trade funding will certainly help
California reach the goals proposed in our climate leadership package,” Senate President Kevin de Leon (D-Los Angeles)
says in a written statement provided by a spokesman.
“Now we must ensure that we maximize every penny to clean our air, create jobs, and create a more efficient transportation system — especially in poor communities disproportionately impacted by pollution,” de Leon says. “The LAO
report proves we can implement ambitious climate policies and grow California’s economy and investments at the same time.”
While the Brown administration forecasts in its proposed budget that $1 billion will be generated by the state’s GHG
allowance auctions in the 2015-16 fiscal year, the LAO predicts that the amount will be at least $2 billion and potentially
as high as $4.9 billion.
In addition, more money will be generated during the current fiscal year through the auctions than Brown administration officials have assumed, the LAO says. While the governor has projected roughly $700 million for the current fiscal
year, the LAO projects between $1.3 billion and $2.8 billion.
The primary reason for the significantly higher revenue projections is the administration’s decision to subject
transportation fuels to the cap-and-trade program beginning Jan. 1, along with more realistic and less conservative
assumptions about the economy.
Experts have said that subjecting gasoline, diesel and natural gas to the cap-and-trade program roughly doubles the total
amount of emissions captured. The auction revenue is deposited into the state’s Greenhouse Gas Reduction Fund (GGRF).
Under fiscal year 2014-15 budget legislation approved by state lawmakers last June, 60 percent of GGRF
money must be continually used for certain programs and projects, including high-speed rail, new transit projects,
affordable housing and sustainable communities. This means that 40 percent of the revenue will be subject to annual
appropriations by lawmakers, where advocates of low-carbon transportation, natural land management, energy efficiency
and other programs will compete for funding every year.
In addition, 25 percent of the total funding must be spent to benefit “disadvantaged communities,” with 10 percent of
total funding required to be used for projects or programs located within such communities.
Brown proposed in his 2015-16 budget that $650 million out of the $1 billion expected to be collected through the
GHG allowance auctions be spent on low-carbon transportation initiatives, including $250 million on high-speed rail,
$200 million on subsidies for zero-emission cars and low-emission heavy-duty vehicles, and $200 million on transit and
intercity rail projects.
In addition, the governor wants to spend another $200 million on affordable housing and sustainable communities
programs, which aim to reduce California residents’ vehicle miles traveled primarily through land-use changes (Inside
Cal/EPA, Jan. 16).
Under the LAO’s “moderate” scenario forecast, which anticipates an extra $3.7 billion in fiscal years 2014-15 and
2015-16, the following projects and programs would automatically receive the additional amounts of money in the 201516 fiscal year: high-speed rail — $570 million; affordable housing and sustainable communities — $456 million; transit
and intercity rail — $220 million; and low-carbon transit operations — $114 million, the report says.
The remaining 40 percent in additional funding — about $1.3 billion for both fiscal years 2014-15 and 2015-16 —
would remain unallocated and subject to legislative debate and approval.
The LAO report provides a list of options for spending that money, in addition to a brief discussion of pros and cons
for each proposal.
For example, the Legislature could wait to spend the additional funds until future years; allocate funds to existing
GGRF programs in 2015-16, or allocate money to other programs in 2015-16; or choose a combination of these options,
the report says.
While waiting to spend the funds may be wise to gain new knowledge about how well and cost-effectively existing
spending programs are working, “we caution the Legislature that it may be years before the current GGRF-funded
projects are implemented and there is reliable information that can be used to adequately evaluate their effectiveness,” the
report says.
“In addition, if the Legislature elected to allocate the funds in future years, it would likely delay the benefits that
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could be achieved with these funds — such as GHG reductions, air quality improvements, and public health benefits.”
Simply adding the extra money to projects and programs already receiving GGRF funding could be beneficial in part
because “agencies already have experience developing and administering these programs and, thus, there may be relatively little additional work needed to administer increased funding,” the report says.
On the flip side, however, “there may be diminishing returns to providing additional funding to these programs.” For
instance, if state agencies are currently allocating funds to projects with the greatest benefits per dollar spent, additional
funding “would likely be used to fund projects that provide fewer benefits per dollar spent,” the LAO says.
Lawmakers could also fund programs that did not receive any money in 2014-15 and are not proposed to receive any
money in 2015-16, the report suggests. For example, lawmakers could support the development of technology integrating
energy storage into the electricity grid. “Energy storage has the potential to support state efforts to increase the proportion
of energy coming from renewable sources, such as solar.”
When considering providing more money to emission sources that are already covered under the cap-and-trade
program, the LAO provides lawmakers with several issues to consider. “If the cap is limiting total GHGs, GHG reductions from one covered entity simply allows other covered entities to emit more GHGs,” the report says. “Therefore,
spending cap-and-trade revenues on activities that reduce GHG emissions from the capped economy might not reduce
overall GHG emissions. It may simply change the mix of emission reduction activities.”
In addition, subsidizing reductions from capped sources also likely leads to more costly emission reduction activities,
LAO says. “This is because it is unlikely that state expenditures would be directed at the least costly GHG emission
reduction strategies.”
On the other hand, spending money on emission reduction activities in the capped economy could help achieve other
legislative goals, such as improving air quality, improving public health, and addressing inequities in disadvantaged
communities, the LAO acknowledges.
But the Legislature “should evaluate how different spending options help address these benefits relative to what
would have otherwise occurred,” the report says. “For example, spending on activities that reduce transportation emissions —
both GHGs and local air pollutants — will help improve local air pollution where transportation emissions are reduced.
However, those emission reductions might be at least partially offset by an increase in emissions somewhere else.”
As a result, lawmakers could consider spending the additional funding on reducing GHG emissions from sources that are
not under the cap, because this would not be offset by an increase in GHG emissions from other sources, the report says.
Another option would be to spend the money on activities that the private market is failing to adequately carry out,
such as certain types of energy efficiency projects, LAO says. “Some evidence suggests that the owners of existing
apartment buildings might not invest in the optimal amount of energy efficiency. Since renters typically pay the energy
bills, apartment building owners do not have much of a financial incentive to make energy efficiency investments that
reduce utility bills. In theory, spending on energy efficiency could potentially provide low-cost GHG reductions that the
private sector otherwise would not provide.”
Finally, the Legislature could use GGRF funds to offset spending from other sources of state funds, including special
funds and the General Fund, according to the report. Using revenues to offset other state spending could free up state
funds to be used for other legislative priorities.
“For example, the Legislature could consider using the additional revenue to offset special fund spending — thereby
freeing up such funds for alternate uses or allowing the Legislature to reduce the fees that are collected to support these
programs.”
Using GGRF funds to offset General Fund expenditures would make additional General Fund dollars available for
other legislative priorities, the report adds.
An environmentalist closely following the spending plans is most supportive of LAO’s option of allocating the
additional funds to existing GGRF programs in fiscal year 2015-16. “We have joined other groups to recommend an
increase to $350 million (from $200 million) in low-carbon transportation, and we also support increased funding for
public transit, sustainable communities, low-income energy and urban forestry,” the source says. “These programs are
already up and running and could use additional funds to reduce greenhouse gas emissions, as well as serve other needs.”
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Natural Gas Industry Presses ARB To Further Ease GHG Scores Under LCFS
Natural gas industry representatives will be pressing state air board officials over the coming months to further lower
carbon intensity levels for various forms of the fuel under pending amendments to the low-carbon fuel standard (LCFS),
arguing the board is using flawed modeling in its calculations and that even the smallest change in the levels can negatively impact their potential market share by tens of millions of dollars.
The California Air Resources Board (ARB) is tentatively scheduled in July to finalize a number of amendments to
the LCFS, including the adoption of new carbon intensity factors for numerous fuel blends. The board passed a resolution
at its Feb. 19 meeting to advance the rule changes, which were summarized by board staff. Relevant documents are
available on InsideEPA.com. See page 2 for details. (Doc. ID: 179205)
The state’s LCFS requires fuel providers to reduce the carbon intensity of gasoline and diesel 10 percent by the end
of 2020, compared with a 2010 baseline. Companies can comply by blending cleaner fuels such as ethanol and biodiesel
into gasoline and diesel and by purchasing credits generated by utilities and other companies that provide natural gas for
natural gas vehicles, electricity for electric vehicles, or hydrogen for hydrogen fuel-cell vehicles.
Along with a number of other regulatory amendments, ARB is proposing to update the carbon intensity levels of
fuels based on an updated version of its “CA-GREET” emissions estimation model. The new “CA-GREET 2.0” model is
based on the 2013 GREET 1 model developed by Argonne National Laboratory in Illinois.
One of the most significant impacts of the new model is that it shows a substantial rise in GHG emissions from
natural gas compared with what is assumed under the current carbon intensity levels under the LCFS, including compressed natural gas (CNG) and liquefied natural gas (LNG) from conventional North American fossil sources as well as
from landfills.
The primary reasons for the jump in GHG emissions from natural gas is because of newly updated information
showing higher methane leakage rates from natural gas operations, such as pipelines and extraction and processing
operations at landfills, in addition to higher emission readings from vehicle tailpipes, according to ARB staff.
Last summer, ARB released a preliminary regulatory proposal estimating that the carbon intensity of CNG from
landfills is 33.52 grams of carbon dioxide (CO2)-equivalent emissions per megajoule (g/MJ), nearly triple the current
score under the LCFS of 11.26 for the same fuel. For LNG from landfills, ARB’s new estimate was 54.5 g/MJ, up from
the current 26.31 g/MJ score.
For CNG from North American fossil sources, ARB proposed last summer a 78.37 g/MJ score; the current score
under the regulation for the same gas is 68.01 g/MJ. And for LNG from North American fossil sources, ARB estimated
the accurate score was 96.92 g/MJ instead of the current 83.13 g/MJ.
While ARB intends to adopt these new levels in the regulatory changes slated for approval in July, they would not
take effect until 2016; fuel providers would likely face a future “sunset date” on the use of the existing carbon intensity
levels as part of the regulatory changes, ARB staff said last year.
Since the preliminary proposal last summer, however, ARB staff has relaxed some of the draft carbon intensity
scores for the fuels, according to the final regulatory amendment plan released last month. Industry groups claim that
ARB staff has verbally committed to compromising by using a combined carbon intensity value of 70 g/mj for conventional natural gas, including fossil CNG and LNG, and a carbon intensity range of 15-25 for renewable natural gas
(RNG).
But natural gas industry representatives are still adamant that the new draft scores are far too high and are pressing
for meetings between now and the July board meeting to convince ARB staff to lower them.
Representatives of the California Natural Gas Vehicle Coalition, NGVAmerica and Coalition for Renewable Natural
Gas make their case in a recent letter to ARB Executive Officer Richard Corey, detailing technical concerns and calling
for a more transparent regulatory development process.
“There are several major issues associated with the current CA-GREET model’s natural gas pathways that remain
unresolved to our satisfaction,” the Jan. 21 letter states. “These unsettled technical issues each relate to the critical
parameter of fugitive methane emissions (both upstream and downstream).”
In addition to challenging the methods ARB is using to estimate methane emissions from vehicle tailpipes and
various gas-production and distribution facilities, the groups object to ARB assuming there is a 1 percent methane
leakage rate at landfill gas facilities that produce renewable natural gas.
“U.S. landfills are subject to New Source Performance Standard (NSPS) operational requirements for collection and
control systems,” the letter states. “Moreover, California landfills are subject to more-stringent landfill methane rules
requiring leak testing of any components that contain landfill gas under pressure. This includes the entire upgrading and
treatment system.”
Consequently, “we continue to support the position that the methane leakage rate at RNG production facilities
located at any North American landfill is effectively zero. We see no credible or defensible basis for staff’s position that a
leakage rate of one percent must be assumed.”
Regarding methane leakage from conventional natural gas processes and transport, the groups charge that ARB is
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wrongly using national data that do not reflect lower emissions from California facilities or locations that serve California.
The industry groups say in the letter that ARB staff has made several commitments in the coming months to conduct
further discussions to better quantify lifecycle GHG emissions from the fuels; understand and incorporate new research
results as they become available over the next 12 months; continue to engage with all stakeholders on CA- GREET 2.0,
“right up” until the board meeting in July; and incorporate any further updates to CA-GREET 2.0 through ARB’s normal
15-day change rulemaking process.
Nevertheless, they remain doubtful that ARB staff will stand by their commitments, and are seeking a more
formal process to meet with officials, according to the letter. “We believe it is essential that ARB implements an improved
process to obtain and document public input, as well as provide a timely and iterative approach to reviewing and integrating the latest technical information,” the letter says. “This should include establishment of an ARB-industry working
group that can convene several times within the period between the Feb. 19-20 and July 23-24 board meetings. This will
help ensure that legitimate stakeholder concerns and questions are addressed, while also improving the pipeline of useful
technical inputs from industry to ARB staff.”
While the groups have been “repeatedly assured by ARB staff that ‘nothing is cast in stone’ for CA-GREET 2.0,” and
that changes can routinely be made by ARB right up until the board considers adoption in July 2015, “much of the critical
details remain a mystery,” the letter asserts. “For example, we have been told by staff that after the LCFS issue comes
before the board at its February 2015 [meeting], ‘the public record will be closed’ until the LCFS program is again heard
at the July 2015 board meeting.”
As a result, “under a worst-case scenario, our industry assumes that: 1) no formal meetings could take place between
the February and July board meetings, 2) ARB staff would not continue to meet with our industry on these issues, 3) no
additional data could be considered, and 4) no public testimony could be heard at the July board meeting.”
If this is the case, “we have very significant concerns that ARB’s process will not be able to accommodate further
industry inputs needed for important CA-GREET 2.0 model modifications,” the industry groups add.
Several natural gas industry representatives and utility officials reiterated these concerns during ARB’s meeting last week.
An ARB spokesman says this week that “the LCFS does not discriminate against different types of fuel . . . changes
in carbon intensity are the result of new science, and we’re always willing to meet with industry to hear their concerns.”
Ethanol Industry Seeks Repeal Of LCFS . . . begins on page one
Should ARB face new litigation over the re-adopted rule, it will likely perpetuate regulatory uncertainty for many
producers of low-carbon advanced biofuels, who are looking to California’s LCFS as an important growth market for
their product, especially given uncertainty with U.S. EPA’s renewable fuel standard (RFS).
California’s LCFS requires fuel providers to reduce the carbon intensity of gasoline and diesel 10 percent by the end
of 2020, compared with a 2010 baseline. Companies can comply by blending cleaner fuels, such as ethanol and biodiesel,
into gasoline and diesel and by purchasing credits generated by utilities and other companies that provide natural gas,
electricity or hydrogen for transportation purposes.
But Midwest producers of corn ethanol oppose the standard, charging it assesses a GHG emissions “penalty” on
ethanol not produced in California, in part by including the emissions created when ethanol is transported to
California via rail or truck. They also oppose state methods for assessing GHG emissions from “indirect land use
changes” for producing feedstock. The result is that the Midwest ethanol has a higher carbon intensity level than
ethanol produced in the state, making it less attractive to fuel providers to purchase to comply with the regulation,
the groups have argued.
While the standard overcame a federal constitutional challenge, POET and others successfully challenged the LCFS
in state court, charging that officials violated the California Environmental Quality Act (CEQA) and Administrative
Procedure Act (APA) when they first adopted the rules.
The state appellate court’s 2013 ruling in POET LLC, et al., v. ARB found that ARB failed to comply with CEQA and
APA when it approved the LCFS and an accompanying environmental assessment in part because it failed to adequately
calculate the potential release of smog-forming pollutants, among other environmental effects.
One part of the ruling held that ARB violated a fundamental policy of CEQA by improperly delegating responsibility
for completing the environmental review process to its executive officer.
As a result of the 2013 decision, ARB was forced to freeze its 2013 LCFS requirement — a 1 percent reduction in
carbon intensity — through 2015. Clean fuel researchers recently found that ARB’s action contributed to a reduction in
estimated production capacity for low-carbon advanced biofuels in 2014 and increased uncertainty for the industry, which
has now been pushing for formal re-adoption of the standard.
ARB Feb. 19 passed a resolution to re-adopt the LCFS and a host of regulatory amendments in accordance with
CEQA and administrative procedure rules, and tentatively plans a final vote on the revised regulation in July.
ARB was also forced to implement a new two-step process to adopt regulations as a result of the 2013 court decision
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over the LCFS, where proposed rules are presented to the board, returned to staff for environmental analysis and then
rescheduled for final board votes months later (Inside Cal/EPA, Feb. 20).
Alleged Violations
Even as ARB takes steps to address earlier concerns, Growth Energy is charging that the board has again failed to
comply with CEQA, APA and AB 32, the 2006 law requiring the state to reduce greenhouse gas (GHG) emissions to 1990
levels by the end of 2020.
In general, the industry group asserts that ARB has failed to properly assess alternative “projects” to the LCFS to
accomplish the same goal, as required under CEQA; failed to allow adequate time for public review and comment on the
LCFS re-adoption as required by the APA and subsequent related laws; and failed to ensure that the LCFS reduces GHG
emissions while not hiking other pollutants, as required by AB 32.
The group is claiming many of the same legal shortcomings for a related regulation — the Alternative Diesel Fuel
(ADF) rule — that ARB is also scheduled to finalize in July. The ADF puts in place new regulatory specifications for
various blends of biodiesel and renewable diesel fuel.
David Bearden, Growth Energy’s general counsel and secretary, charged in the comments that the revised version of
the LCFS that the state plans to readopt is based on faulty assumptions that the standard has reduced GHG emissions.
Compounding this error, the proposal also assumes it will achieve further GHG reductions, he adds.
“In fact, there is no evidence that the LCFS regulations have done so, to date, and the available evidence demonstrates that there have been no such GHG reductions,” Bearden states. “The staff’s LCFS proposal invites a further
assumption that the new LCFS regulations will achieve further reductions in net GHG emissions, but remarkably, the staff
has offered no definitive quantitative estimate of those GHG reductions,” he says.
As a result, the revised LCFS “cannot properly be treated as a regulation that meets the purposes of AB 32 because
there is no reliable demonstration that the regulation will reduce GHG emissions, and the proposal is therefore not
authorized by AB 32 and is invalid under the Government Code,” the group says.
Growth Energy also charges that the board’s CEQA assessment fails to adequately mitigate adverse environmental impacts that will result from the use of biodiesel fuel and also fails to comply with other CEQA requirements, he says.
In terms of APA and other procedural rules, the industry argues in part that ARB has never disclosed to the
public “critical information about the assumptions and data on which the LCFS and ADF proposals are based,” he
adds.
More broadly, Growth Energy argues the LCFS regulation is no longer needed to achieve the GHG reductions sought
by the 2009 regulation. The group claims it has proposed to ARB a “better alternative” to the LCFS, through the expansion of California’s existing GHG cap-and-trade program, the comments say. The letter is available on InsideEPA.com.
See page 2 for details. (Doc. ID: 179204)
Specifically, the group proposed that ARB adjust the economy-wide GHG cap-and-trade program to account for
whatever increment of GHG emissions reductions would be foregone by eliminating the LCFS.
Growth Energy’s proposal “had none of the unintended negative environmental consequences of the 2009 LCFS
regulation, which have been the subject of litigation, and would have eliminated the need for California businesses and
consumers to pay for the LCFS program — costs which the ARB staff now says may range up to about 12 cents per
gallon by 2020,” Bearden asserts.
Market Disruption
In addition, ARB’s new justification for the LCFS regulation “ignores” the federal RFS program, Bearden claims.
“When it rejected Growth Energy’s proposal last fall, the ARB staff did not properly account for the beneficial effects of
the [RFS] program in stimulating fuels diversification and in the commercialization of cellulosic renewable fuels. The
ARB staff still has not done so.”
By disrupting the national market for renewable fuels, “the LCFS regulation may increase global GHG emissions,”
the group further claims. “Under the new LCFS regulation, corn ethanol produced at Midwest biorefineries will likely be
displaced in large part by sugarcane ethanol from Brazil. Midwest corn ethanol biorefineries will be forced to choose
between curtailing or shutting down production, or finding other markets for the ethanol that can no longer be sold in
California.”
Because external economic factors constrain the output of the Brazilian sugarcane ethanol industry, and may continue
to do so, “the practical effect of the new LCFS regulation may be the shipment of Brazilian ethanol to California and
Midwest ethanol to Brazil,” the group says. “The ethanol would travel on oceangoing tankers powered with fossil fuels.
Intercontinental shipments of ethanol in response to California’s regulation would have the unintended effect of increasing global GHG emissions.”
The organization also reiterates its longstanding argument that the LCFS discriminates against ethanol producers
outside of California.
Asked to comment on Growth Energy’s charges, an ARB spokesman says board officials “are following the law.”
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LAO Queries Budget Proposal For New ARB Mobile Source Testing Facility
The Legislative Analyst’s Office (LAO) is questioning a budget proposal by the state air board for $5.9 million to
evaluate a proposed site to build a new mobile source emissions testing facility in southern California estimated to cost a
total of $366 million.
Specifically, the proposal lacks a clear justification for the size and scope of the project; a complete analysis of
alternatives; and a clear strategy for long-term funding, states a Feb. 19 LAO report on the Brown administration’s
proposed fiscal year 2015-16 budget for resources and environmental protection programs.
The questions raised by the LAO are likely to surface in forthcoming legislative budget subcommittee hearings on
the Air Resources Board’s proposed 2015-16 fiscal year spending plan.
ARB is proposing to consolidate and expand its multiple mobile source testing facilities into a larger building in
southern California, in part to accommodate growing research needs due to its vehicle emission regulations.
For the upcoming fiscal year, ARB is asking lawmakers to approve $5.9 million to evaluate the site ($200,000) and
develop “performance criteria” ($5.7 million), according to the LAO report. The administration will use the performance
criteria to develop documents that will then be used to solicit bids for the construction of the building.
Funding for the activities would be supported by $3.8 million from the Motor Vehicle Account, $1.2 million from the
Air Pollution Control Fund, and $900,000 from the Vehicle Inspection Repair Fund, the report says.
After the performance criteria have been approved by the Public Works Board, the administration plans to proceed to
bid in mid-2016, award a contract in mid-2017, and complete the project by early 2020, the LAO says. The report is
available on InsideEPA.com. See page 2 for details. (Doc. ID: 179203)
While the LAO agrees that ARB’s mobile source testing facilities should be upgraded and expanded, it questions
whether the administration’s proposal is the preferred approach, noting that the plan “lacks several critical components.”
For example, the administration should address several issues before the Legislature, “particularly one of this size,
scope, and cost,” the report says.
“While the administration identifies a wide variety of future testing and research activities that will be conducted as
vehicles and fuels evolve, it has not provided a clear analysis of future workload that justifies the size and scope of the
proposed project,” according to the LAO.
For example, the administration’s proposal includes three chassis dynamometers to conduct over 860 heavy-duty
tests per year beginning in 2020. “However, it is unclear how the administration arrived at an estimate of 860 tests.
Furthermore, the proposed project is scheduled to be completed in 2020, but the administration does not provide estimates of the future workload and needs beyond 2020,” the report states. “As a result, it is difficult to evaluate whether the
size and scope of the proposed project is appropriate.”
An ARB spokesman says board officials are working with LAO representatives to answer their questions.
Lawmakers Question GHG Spending Plans . . . begins on page one
ated by the state’s GHG allowance auctions in the 2015-16 fiscal year, a new report by the Legislative Analyst’s Office
(LAO) predicts that the amount will be $2 billion minimum and potentially as high as $4.9 billion (see separate story,
p3). The report is available on InsideEPA.com. See page 2 for details. (Doc. ID: 179203)
In addition, more money will be generated during the current fiscal year through the auctions than Brown administration officials have assumed, the LAO says. While the governor has projected roughly $700 million for the current fiscal
year, the LAO projects between $1.3 billion and $2.8 billion.
The primary reason for the increase is due to the Jan. 1 addition of transportation fuels under the cap, along with
more realistic and less conservative assumptions about the economy. Experts have said that the inclusion of gasoline,
diesel and natural gas under the cap-and-trade program roughly doubles the total amount of emissions captured. The
auction revenue is deposited into the state’s Greenhouse Gas Reduction Fund (GGRF).
Rodriquez, speaking at a Feb. 25 hearing of the Assembly budget subcommittee on resources and transportation, said
Cal/EPA has “resisted” efforts to make exact projections of how much money will be generated by the state’s quarterly
GHG allowance auctions in part because “this is a market, and you can’t really control a market, and you have to be
concerned about making projections that might somehow affect the market in some way.”
While Rodriquez noted that state law currently requires 60 percent of the funding to be continuously appropriated for
certain activities — including high-speed rail, new transit projects, affordable housing and sustainable communities — he
acknowledged that the remaining 40 percent will be in “play,” with lawmakers in charge of deciding how best to spend
the money.
However, Rodriquez noted that state law also requires ARB to craft three-year investment plans for the GHG revenue
and that board officials will be “starting a new investment plan process this year.” Once drafted, ARB will submit it to the
Department of Finance (DOF) for approval. “And that should help us to direct future expenditures of cap-and-trade
funding,” Rodriquez told lawmakers.
An ARB spokesman says this week that “there won’t be a new investment plan until after” the administration releases its
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revised budget proposal in May. The state’s first investment plan was submitted to the Legislature in May 2013.
The three-year investment plan’s influence over the administration’s budget has been controversial in the past.
Numerous lawmakers and stakeholders criticized the administration last summer for implementing the continuous
appropriation provision in the final fiscal year 2014-15 budget, which ensures that 60 percent of the GHG revenue is
permanently reserved for high-speed rail, new transit projects and affordable housing and sustainable communities. These
priorities were recommended by the investment plan, according to sources.
Critics charged that the administration’s 2014-15 budget violated AB 1532, a 2012 law that required ARB and DOF
to develop the three-year investment plans so that lawmakers could decide how to spend 100 percent of the revenue,
rather than merely 40 percent.
Assemblyman Jim Patterson (R-Fresno) said during this week’s committee hearing that the substantial additional
revenue expected to be collected through the cap-and-trade program intensifies concerns over whether the state should be
funneling any money to the high-speed rail project, given that the LAO and other experts have said the project will not
produce any GHG emission reductions for several decades.
Patterson indicated it is incredulous that the state would merely sweep another 25 percent of the additional funding to
the high-speed rail project without any additional analysis, review or debate. “We’re sort of on automatic pilot here, with
respect to cap-and-trade,” Patterson said. “If it generates more, the autopilot will scrape off a significant amount of that
revenue and send it to high-speed rail, notwithstanding the concerns raised over the fact that it simply does not mitigate
its emissions footprint” for 30 years.
Earlier in the hearing, Assemblyman Das Williams (D-Santa Barbara) said he believes the administration should
provide the transportation department more money to support new mass transit projects to help reduce GHG emissions,
especially in disadvantaged communities. He noted that spending more in this area could also help achieve Gov. Jerry
Brown’s (D) goal of reducing petroleum use in the state 50 percent by 2030.
Rodriquez responded that while administration officials will be considering transit projects as part of the updated
three-year investment plan process, he noted that apart from the transportation department’s budget ARB is proposed to
receive $200 million in the fiscal year to fund low-carbon transportation projects. In addition, the Strategic Growth
Council is considering approving millions of dollars from GHG revenue on sustainable communities projects, which aim
in part to concentrate development around transit hubs to reduce vehicle miles traveled, Rodriquez said.
Fuels Sector Seen Buying California’s GHG Credits, Casting Doubt On Suit
California’s inclusion of transportation fuels and natural gas under the state’s greenhouse gas (GHG) cap-and-trade
program last month significantly expanded the number of credits that were sold at the most recent auction, an indication,
an industry attorney says, that the sector is purchasing credits and is unlikely to challenge the program’s expansion.
According to a summary of the Feb. 18 auction, which the California Air Resources Board (ARB) released Feb. 25,
all 73,610,528 2015 vintage allowances offered for sale were sold at a price of $12.21. The auction floor price for the
allowances was $12.10.
In comparison, ARB offered for sale roughly 23 million current year vintage allowances in the last auction held in
November.
In addition, all 10,431,500 2018 vintage allowances offered for sale in last week’s auction — the second to include
Quebec — were sold at the floor price of $12.10, according to the report. The report is available on InsideEPA.com. See
page 2 for details. (Doc. ID: 179204)
Under the GHG program, 2015 vintages can be used to comply this year or any time in the future; but 2018 vintages
can only be used in 2018 or later.
Some observers noted that last week’s auction offered for sale more than three times the number of current-year vintage
allowances than offered for sale in the previous auction — to reflect the new inclusion of emissions from the consumption of
gasoline, diesel and home-heating natural gas — and that all of them sold at a level higher than the floor price.
The increased number of allowances offered for sale “is attributable to expanded program scope” due to transportation fuels and natural gas distribution now being subject to the compliance obligation, the attorney says.
While the oil and gas industry opposed ARB’s inclusion of fuels under the cap-and-trade program, charging it would
hike fuel prices, the industry attorney says the latest auction results appear to show that the oil and gas sector is purchasing future allowances to comply with the program, indicating that it is unlikely they are planning any legal challenges or
legislation to remove transportation fuels and natural gas from cap-and-trade.
“The fact that they all sold suggests that the entities subject to the compliance obligation under the expanded program that need allowances to meet that obligation . . . are, in fact, procuring to meet their needs, which means they likely
aren’t planning on any legislative or judicial intervention to excise transportation fuels from the cap-and-trade program,”
the attorney says.
The attorney adds that the most interesting thing about the latest auction is that “even though the volume of current
vintage allowances available was so much greater than prior auctions . . . they all sold above the floor price.”
Environmentalists offered similar assessments on the program’s stability though without the focus on the oil and
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gas industry.
Results of the auction “indicate that the strong foundation built over the first two years of the program allowed the
market to easily pass this important growth test, remaining stable and strong even in the face of a considerable change in
allowance supply and shifting market dynamics,” says Katie Hsia-Kiung, a carbon market analyst for the Environmental
Defense Fund (EDF), in a Feb. 25 blog.
Hsia-Kiung says that the fact that all the 2018 vintage allowances offered for sale were sold “once again reflects
confidence in the future strength of the market,” the blog says. “These companies are making financial investments that
are consistent with the belief that the market will be in existence well into the future, as was strongly signaled through the
governor’s and the Legislature’s prioritization of long-term emission reductions.”
Merrian Borgeson, senior scientist with the Natural Resources Defense Council, says in a Feb. 25 press release that
despite warnings by the oil industry over the past few years that the inclusion of fuels under the cap would cause fuel
prices to soar, “the sky did not fall. California’s carbon market continues to hum along as expected, with this auction’s
price right in line with previous auctions.”
However, energy market experts have said that it is unclear to what degree and when gasoline and diesel prices could
increase as a result of the cap-and-trade program expansion. Some have said that the industry had already built in the cost
of carbon into their prices to prepare for the program expansion, while others say companies could be forced to purchase
GHG allowances at much higher prices in the years to come, resulting in more dramatic hikes in fuel costs at the pump.
Court Backs ARB GHG Offset Rules . . . begins on page one
effect of reducing off-site emissions and, in California’s case, creating credits toward compliance requirements.
To date, ARB has adopted protocols for five GHG offset project types, which cover reductions in methane from coal
mines, methane from livestock, ozone-depleting substances from appliances, and two separate measures governing carbon
dioxide sequestration from urban forests and U.S. forests. ARB is also in the process of finalizing a protocol for reducing
methane from rice cultivation.
While offset credits represent GHG emission reductions achieved at off-site locations, they are purchased by entities
regulated under cap-and-trade programs to help meet their compliance obligations. This allows them a more flexible and
cheaper way to comply than merely trying to reduce emissions from their own facilities.
For example, under California’s program, many companies subject to the GHG requirements have purchased offset credits
generated by a facility in Arkansas that incinerates ozone-depleting substances that have a high global warming potential.
But the protocols have not been without controversy. For example, ARB late last year invalidated tens of thousands
of ODS credits from the Arkansas facility that were generated during a narrow window when the facility was in violation
of its federal waste disposal permit, which was at odds with the ARB protocol.
The invalidation drew charges from the credit generator that ARB acted unlawfully, though so far no lawsuit has been
filed over the issue. But ARB did say last year that it planned new guidance to clarify their invalidation rules in the face
of charges from credit developers and traders that the current provisions are unclear and hamper the industry.
ARB faced a different charge in the instant litigation where the plaintiffs, who were assisted by former U.S. EPA attorneys
Laurie Williams and Allan Zabel, argued that cap-and-trade programs in California and Europe cannot ensure that actions
governed by the offset protocols achieve “additional” reductions beyond what would be achieved by business as usual.
As a result, they argued that offsets are prohibited by AB 32, the state’s 2006 global warming solutions law that
authorized the cap-and-trade program.
But the appellate court agreed with the lower court ruling that ARB has constructed protocols in a manner that
satisfies AB 32 and does not illegally expand the board’s authority.
While OCE argues that ARB must “‘ensure that each and every reduction that generates an offset would not otherwise occur,’” the group “never articulates how a project operator could prove the GHG emission reduction would not otherwise occur or how the board could provide the assurance that appellant claims the statute demands,” the ruling states.
Instead, OCE “takes the rather . . . pedantic position that this part of the [law’s] additionality requirement speaks for
itself and expressly requires unequivocal proof that the emissions reduction would not otherwise occur,” the ruling says.
Although AB 32 “requires additionality in the context of a market-based compliance mechanism, it does not define the
word ‘additional.’ Nor does it define the term ‘otherwise would occur.’” The ruling is available on InsideEPA.com. See
page 2 for details. (Doc. ID: 179207)
However, AB 32 does define market-based compliance mechanism as including GHG “‘emissions exchanges,
banking, credits, and other transactions, governed by rules and protocols’ to be established by the board,” the court says.
“Within this authority, the board established rules and protocols which give sufficient meaning to the concept of
additionality so that the statutory requirement is capable of enforcement,” the decision adds. “By developing these rules
and protocols the board did not exceed its power, but rather exercised the legislative authority delegated to it by the
Legislature.”
OCE attorneys said at press time they were still reviewing the ruling. “Obviously we’re disappointed with the decision, but
in terms of any steps forward, we’ve got to read it and figure out what might be the next steps,” one source says.
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Suit Claims DOI Failing To Assess Impacts Of California Offshore Fracking
The Center for Biological Diversity (CBD) is ramping up its fight against oil and gas hydraulic fracturing by suing
the Department of the Interior (DOI), charging the agency is failing to adequately assess the environmental and ecological
impacts of the drilling practices prior to approving permits for companies to drill off the California coast.
The CBD lawsuit, filed Feb. 19 in U.S. District Court for the Central District of California, Western Division, names
DOI’s Bureau of Ocean Energy Management (BOEM) and Bureau of Safety & Environmental Enforcement (BSEE) as
defendants. The complaint is available on InsideEPA.com. See page 2 for details. (Doc. ID: 179214)
CBD attorneys claim the DOI agencies are violating the Outer Continental Shelf Lands Act, National Environmental
Policy Act (NEPA) and Coastal Zone Management Act when approving drilling permits that allow fracking off the
California coast.
“The bureaus have a pattern and practice of rubber-stamping permits to frack with no analysis of the environmental
impacts, no determination of whether such activities are consistent with the plans governing oil development and production in the Pacific Region or California’s Coastal Management Program, and no public involvement,” the lawsuit claims.
“The bureaus’ actions — or lack thereof — violate a myriad of laws.”
Offshore fracking raises “several significant environmental and public health concerns,” the complaint adds.
“The impacts associated with offshore fracking include the discharge of toxic wastewater, the emission of hazardous
air pollutants, increased risk of earthquakes and oil spills, and threats to a variety of marine species, such as
imperiled blue whales and sea otters. Nevertheless, the bureaus have permitted fracking in the Pacific Ocean on
numerous occasions.”
The court should issue an order declaring the bureaus to be in violation of the federal laws and prohibiting them from
issuing future permits allowing fracking unless and until the bureaus comply, CBD asserts in the suit.
BOEM officials “are not able to comment due to pending litigation,” a bureau spokeswoman responds this week.
CBD’s lawsuit follows letters it sent the federal agencies in October 2013 seeking to block fracking off the
state’s coast in federal waters and threatening to sue to force them to assess the potential adverse effects to the
marine environment.
In a separate action, CBD last year petitioned U.S. EPA to amend a Clean Water Act permit to halt the discharge of
waste from hydraulic fracking operations into federal waters off the southern California coastline.
CBD has also targeted onshore fracking with litigation against other federal agencies. Last year, CBD reached a legal
settlement with the Bureau of Land Management (BLM) in the U.S. District Court for the Northern District of California.
The court ruled in 2013 that BLM violated NEPA and the Administrative Procedure Act when it declined to assess
potential contamination from fracking in approving in late 2011 the sale of oil and gas leases on approximately 2,700
acres of federal land in Monterey and Fresno counties.
However, BLM has said recently that it plans to restart oil and gas lease sales this year in regions other than the area
of the two leases contested in the lawsuit. CBD claims the agency should complete a legally required environmental
impact statement on fracking before continuing lease sales in any part of the state.
Meanwhile, California regulators are also pressing federal agencies to tighten their regulation of offshore
fracking. Late last year, the California Coastal Commission sent a letter to DOI seeking more specificity and assurance
about how federal agencies will include the state in reviewing applications for offshore hydraulic fracturing permits, after
DOI last month sent a brief letter committing to some level of cooperation.
The commission’s efforts were triggered in early 2013 in part by the release of reports by CBD and other environmental organizations that showed dozens of offshore fracking events in recent years were not known to California
regulators and that toxic substances have been discharged into the ocean from the activities.
The commission also wrote a letter last May to EPA Region IX, asking the agency to establish new discharge limits
on certain chemicals used in fracking and to require additional testing and monitoring of discharges.
In response, the bureaus committed to more coordination with the state but noted that fracking on the Pacific OCS
occurs relatively infrequently, and that BSEE’s Pacific Region office had no pending applications to use fracking or other
well stimulation techniques.
Oil industry representatives say there is very little offshore fracking happening, companies are in compliance with all
applicable regulations and environmentalists are blowing the issue out of proportion.
Fracking and other well stimulation techniques “have been deployed in California without a negative impact on the
environment for over forty years, including offshore,” says an industry source this week.
Offshore oil and gas development in federal waters, “and especially discharges of drilling fluids,” are addressed in a
December 2013 general National Pollutant Discharge Elimination System (NPDES) permit for oil and gas exploration,
development, and production facilities offshore of California, the industry source says.
“The findings and protections in the permit are based on more than 25 years of chemical and aquatic testing of
different types of chemicals,” the source adds. “The regulations attached to the NPDES permit are comprehensive. No
discussion of this topic can be conducted without a complete understanding of the extensive nature of these permits and
the amount of chemical characterization that was completed to support them.”
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FERC Meeting Addresses Concerns Over ESPS’ Citizen Suits, Safety Valve
U.S. EPA’s acting air chief Janet McCabe is acknowledging concerns from state and federal officials that states could
face citizen suits seeking to enforce provisions of their plans to comply with the agency’s greenhouse gas (GHG) standards for existing power plants and is vowing to address the concerns and preserve states’ flexibility.
Speaking Feb. 19 at the Federal Energy Regulatory Commission’s (FERC) first-ever technical conference on the
implications of EPA’s existing source performance standards (ESPS), McCabe said she sees a “potential” for states to be
sued by third parties for their attempts to comply with the ESPS, where the states’ use of compliance flexibilities under
the rule could become subject to litigation.
“As a former state regulator, . . . I am extremely sensitive to this kind of issue and we tried to be extremely sensitive
to this kind of issue, and we tried to be extremely sensitive to that in the proposal [by] recognizing a potential tension
there,” McCabe said.
She added: “There are some things we can think about in the final rule to provide space for states to design plans that
wouldn’t necessarily bring every last bit into federal enforceability. We want to work very hard to find a way to be
responsive to those concerns.”
McCabe’s commitment was one of several areas where regulators and other participants in the conference appeared
to suggest ways to address concerns over the rule. For example, representatives of environmental, electricity and grid
groups agreed on the need for a relatively narrow reliability “safety valve” to address adverse grid reliability impacts,
though they differed on how such a mechanism should be structured.
Under the ESPS, EPA sets rate-based GHG emission targets for each state and then requires states to submit compliance plans detailing how they plan to attain the targets. Once approved by EPA, those compliance plans are enforceable
by third-party suits authorized by litigation rights contained in the Clean Air Act.
Given the enforcement option, critics of EPA’s rule fear that the ESPS will prompt a host of citizen suits that
will give environmentalists tremendous power to dictate energy supply policy for states. As a result, they fear the
suits will undermine the flexibility that EPA has vowed to provide states as they seek to comply with their GHG
targets.
“I think states are going to be reluctant to bring things into their plan that currently are sort of voluntary partnerships
with businesses. They want that to be discretionary,” Alexandra Dunn, executive director of the Environmental Council of
the States, a group that represents state environmental commissioners, told the FERC conference.
“If [the concept of federal enforceability] is interpreted too rigidly, we will see inflexible approaches to state plans. If
putting it in the plan makes it federally enforceable, that’s going to be a deterrent,” she said.
Dunn also cautioned that fossil fuel-fired power plants, which are most clearly subject to regulation under section
111(d) of the air act, could be forced to bear the brunt of emission reduction requirements in state compliance plans if
other “building block” strategies, such as increased use of natural gas and greater use of renewable energy and energy
efficiency, do not withstand legal scrutiny or do not deliver reductions.
“Do those plants end up at the end of the day having to sort of bear the shortfalls of the other building blocks not
delivering as projected? There is some risk there,” she said.
FERC Commissioner Tony Clark, one of the two Republicans on the commission, echoed Dunn’s concerns, warning
that many states believe if they include measures in compliance plans later be subject to suit, they are “effectively walking
into a buzz saw where their entire state plan can become subject to judicial fiat,” he said.
Clark said such suits are “the bane” of state government, adding that many utility regulators raised during the
winter meeting of the National Association of Regulatory Utility Commissioners (NARUC) in Washington, DC, held
earlier this week. State commissioners “feel there is a big target on their chest[s]” in being subject to “judicial fiat”
if someone, or some group, does not believe a state’s compliance strategy is adequate or underplays a particular
resource, he said.
For example, Kenneth Anderson, Jr, of Texas Public Utility Commission, speaking at the NARUC meeting, said
regulators are “very concerned with federal enforceability of state implementation plans, and particularly by third-party
plaintiffs that could bring suit in federal court.”
“We simply aren’t going to turn the keys to [the Texas grid] over to the Sierra Club in [a] federal lawsuit,” he
said, noting that environmentalists tend to be the largest litigants in cases regarding the Clean Air Act. “It just won’t
happen.”
Anderson said Texas “won’t do a plan if that’s the risk. We won’t turn our energy efficiency program over to the
Sierra Club or other environmental groups that really don’t have a clue about how energy markets work.” He explained
that the state may not write a compliance plan and let EPA implement a federal plan unless there is federal enforcement
litigation relief, while also questioning whether such relief is possible.
Given such concerns, Clark said EPA “has an interest in getting as many states willing to play ball as possible in
terms of setting up [state implementation plan (SIP)] or regional plans because there are a lot of things that states can
voluntarily put into a SIP that EPA can’t mandate as part of a federal implementation plan.” — John Siciliano
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