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Inside Cal/EPA
An exclusive weekly report on environmental legislation, regulation and litigation
from the publishers of Inside EPA
Vol. 25, No. 43 — October 24, 2014
ARB Faces Likely Legal Challenge Over Revocation Of GHG Offset Credits
California’s Air Resources Board (ARB) is facing strong criticisms, as well as a likely legal challenge, over its
investigation into the validity of millions of greenhouse gas (GHG)-offset credits for ozone-depleting substances (ODS)
and its proposed decision to revoke hundreds of thousands of already-issued credits, according to recent comments.
Clean Harbors, Inc., the company that generated the revoked credits, is charging that the board made factual and
legal errors during the probe, exceeded its authority under the 2006 GHG law AB 32 and acted in an “arbitrary and
capricious” manner by concluding that some of the credits should be invalidated.
“Clean Harbors believes that ARB has made significant errors of fact and law in its analysis, failed to adequately
consider all relevant information, and failed to demonstrate an adequate legal basis for its preliminary determination,”
continued on page 6
Science Panel Seeks More Specifics In DTSC Green Chemistry Priority Plan
Industry and academic members of a toxics department science panel overseeing the implementation of the state’s
green chemistry program are recommending the agency improve its three-year draft plan for prioritizing consumer
products under the regulation, in part by providing more specificity about products likely to be targeted.
Panel members representing chemical companies are also suggesting that the Department of Toxic Substances
Control narrow the plan, while those with academic institutions and environmental groups said the document should
place more weight on chemicals with significant exposures to workers and other sensitive groups.
DTSC’s draft “2015-2017 Priority Product Work Plan” is designed for identifying priority products from seven
categories of goods over the next three years. The categories are: beauty/personal care/hygiene; clothing; building
continued on page 8
Energy Group Seeks To Mesh California’s Multi-Sector GHG Plan With ESPS
An energy trading group representing western power companies and major financial institutions is warning that
California risks non-compliance with U.S. EPA’s greenhouse gas (GHG) rule for existing utilities if the state does not
adequately account for the multi-sector nature of its cap-and-trade program in any implementation plan.
In an Oct. 15 letter to the California Air Resources Board (ARB), the Western Power Trading Forum (WPTF) said
that California’s compliance plan will be more complicated than that for the nine Northeast and Mid-Atlantic states in
the Regional Greenhouse Gas Initiative (RGGI), whose program focuses only on power sector emissions.
“Because the scope of the RGGI program is electricity sector only, it will be fairly straightforward to fit the RGGI
program into the [EPA rule’s] framework,” the group says. “In contrast, fitting the California program into the [rule’s]
continued on page 10
Industry Appeal Details Case California GHG Auctions Are Illegal Taxes
Attorneys representing multiple industries are detailing extensive arguments in a California appellate court that the
state’s greenhouse gas (GHG) allowance auctions are illegal taxes and must be halted, filing opening briefs Oct. 17 in a
case that threatens to scrap the landmark climate program.
The arguments laid out in the briefs by the Pacific Legal Foundation (PLF) and California Chamber of Commerce
on behalf of multiple companies focus on two primary issues in which the trial court judge allegedly erred by ruling last
year that the allowance auctions are not illegal taxes under the California Constitution and that the auctions are authorized by AB 32, the state’s 2006 global warming solutions law. PLF, which advocates for property rights and limited
government, is representing a group of companies in the trucking, oil and construction sectors.
continued on next page
INSIDE
FUELS: Revised Draft ARB Biodiesel Rules Draw New Industry Criticism, Concern .................... 3
AIR QUALITY: Environmentalists Tout Revocation Of Crude-By-Rail Permit ................................ 5
LITIGATION: Legal Filing Reignites Dispute Over BLM Fracking Reviews, Leases .....................9
ENERGY: ARB Urges EPA To Ease GHG Limits For Gas Plants Tied To Renewables............... 12
The case, Morning Star Packing Co., et al., v. California Air Resources Board (ARB) in the Court of Appeal of the
State of California Third Appellate District, is being closely watched by numerous stakeholders around the country
because it could halt the state’s landmark GHG trading program, which generates billions of dollars annually in state
revenue. The case has been consolidated with California Chamber of Commerce, et al. v. ARB, et al. Attorneys for the
Chamber also filed an opening brief Oct. 17 in the case that is very similar to the PLF brief.
The appeal challenges a November 2013 ruling by Judge Timothy Frawley of Sacramento County Superior Court
that the sale at auction of GHG allowances by the state to regulated entities represents a regulatory fee and not a tax that
failed to receive a two-thirds vote of the Legislature, as alleged by the plaintiffs. The ruling also found that ARB has the
authority to hold GHG allowance auctions under AB 32.
But PLF attorneys, in their Oct. 17 opening brief in the appeal, argue that Frawley made numerous errors in his ruling
that the auctions are not taxes under the state’s Proposition 13, including that ARB did not have a “predominantly
revenue-generating purpose in raising the billions” of dollars through the auctions; that bidders pay market prices for
emission allowances; that payments for the emissions allowances are voluntary; and that the auction revenues cannot be
used for general government purposes.
For example, PLF claims that Frawley failed to address Prop. 13’s burdens of proof or standards of review for
whether the auctions are taxes as laid out by the state Supreme Court’s 1997 ruling in Sinclair Paint Co. v. State Board of
Equalization. In that ruling, the court determined in part that there are several types of charges that should not be considered to be taxes, including “regulatory fees.” This would be the case when there is a causal connection between the
product regulated and its adverse effects; the money raised was limited to the reasonable cost of mitigating the adverse
effect; and there is a reasonable relationship between the allocation of costs among payors and the burdens imposed by
the payor, according to a California university summary.
In contrast, both the state Legislature and ARB have recognized the auction revenues as being subject to the Sinclair
test, PLF says in the brief.
“Giving short shrift to Sinclair Paint, the lower court opines that the enormous sums to be generated by the auctions
are mere ‘byproducts’ of the regulatory program to curb carbon dioxide emissions and revenue generation is not the
‘primary purpose’ for the auctions,” the PLF brief states. “But neither Sinclair Paint nor its progeny suggest that, where
the revenue generation is a ‘byproduct’ of a regulatory program, the Sinclair Paint standards are inapplicable. . . . Calling
the auction revenues a ‘byproduct’ of the regulation does not make then any less of a tax.” Relevant documents are
available on InsideEPA.com. See below for details.
Under Prop. 13, any charges that serve to “increase revenues” for the state should be considered taxes subject to a
two-thirds vote of approval by the state Legislature, PLF argues, which AB 32 did not receive when it passed in 2006.
Frawley also erred in citing a case involving Proposition 26, a 2010 initiative that amended Prop. 13 to further clarify
fees and taxes, to argue that the GHG auctions are not taxes, PLF argues. “That case held that a county ordinance enacted
after the effective date of Prop. 26 requiring customers to pay 10 cents for each paper carryout bag provided by retail
stores was not a tax because the money was paid to the stores and was not remittable to any level of government,” PLF
explains. “By contrast here billions are going to the state government. Under these circumstances, the instant case sets up
‘a clear, substantial, and irreconcilable conflict’ between the auctions, on the one hand, and the California Constitution on
the other hand. . . . These are precisely the circumstances to which Sinclair Paint applies.”
PLF also rebuts the lower court’s ruling that because the auction bidders get something of value that may be traded,
auction revenues are not a tax, with the group arguing that value passes to a payor in many situations that have long been
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:
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California Revises Draft ‘Alternative Diesel’ Rules
Dispute Reemerges Over BLM Fracking EIS For California Drilling Leases
Industry Groups Detail Challenge To California GHG Credit Auctions
California Air District Revokes ‘Crude-By-Rail’ Permit
Companies Attack California GHG-Offset Credit Investigation
FERC Backs California Grid Flexibility Plan To Aid GHG Reduction Efforts
California Advances Green Chemistry Product Priority Plan
California Says EPA Rule For ‘Modified’ EGUs Should Mimic New Plant Standards
Western Power Traders Seek To Mesh California GHG Plan With ESPS
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 - October 24, 2014
recognized as taxes. “For example, when a consumer purchases any tangible thing, a sales tax is paid,” the brief states.
“The fact that the tangible item has value does not make the sales tax any less of a tax.”
Further, while financial firms may benefit if they trade allowances profitably, entities regulated under the program are
required to obtain emissions allowances in order to stay in business in California, PLF argues. “The only ‘benefit’ they
receive is the ability to continue doing what they have always been doing, but they will be required to do less of it and
pay for the ‘privilege.’”
In addition, PLF charges that the auctions fail the Sinclair test because they go well beyond collecting enough money
to pay for the costs of carrying out AB 32 programs, and because the revenue from the auctions has been used for
purposes not related to the program or GHG emission reductions, such as General Fund backup.
Frawley ruled in the 2013 decision that “the court is not persuaded that the amounts charged for allowances must be
closely linked to the payers’ burdens on the specific regulatory programs that will be funded by them. Rather, all that is
required is a reasonable relationship between the charges and the covered entities’ (collective) responsibility for the
harmful effects of GHG emissions. As the state’s largest sources of GHG emissions, the court is persuaded that a reasonable relationship exists.”
But PLF argues in the appeal that this argument fails under Sinclair Paint because ARB has made no findings in the
cap-and-trade regulation or elsewhere regarding “‘the estimated costs’” of addressing the issue of global warming, in or
outside of California, and no “‘total budgeted cost’” of dealing with global warming has been projected. ARB “has not
even estimated the extent to which California’s GHG emissions reductions, at whatever cost, may have any beneficial
effect on reducing global warming, thereby running afoul also of Sinclair Paint’s reasonable alignment requirement,” the
brief adds.
The other major argument in the appeal is that AB 32 did not authorize ARB to hold GHG allowance auctions.
Frawley ignored substantial amounts of relevant information about whether the state Legislature intended to authorize
such auctions, including statements by the Assembly speaker at the time and floor debate among lawmakers, PLF charges
in the brief. The Chamber brief expands on these arguments.
In addition, PLF contends the lower court erred when it said that if the Legislature had meant to exclude the sale of
allowances, it would have said so in AB 32. “But that turns the law on its head,” the brief says. “An administrative agency
may only do that which it is authorized to do by statute. . . . It would be a startling proposition if [ARB] could do anything not explicitly prohibited by AB 32.”
PLF is asking the appellate court to issue a writ of mandate enjoining ARB from conducting further GHG allowance
auctions and declare that the auctions violate the state constitution under Prop. 13 or Prop. 26, or that the auctions are
disallowed under AB 32.
Revised Draft ARB Biodiesel Rules Draw New Industry Criticism, Concerns
The California Air Resources Board’s (ARB) revised draft rules to establish new specifications for reducing emissions from biodiesel and renewable diesel fuel are prompting new criticism from the biofuels and oil sectors, including
concerns over whether some emissions can be mitigated and difficulties in meeting the rule’s 2018 compliance goal.
An official with the state’s fuel measuring and enforcement department is also warning that the new rules could spark
a marketing and labeling “nightmare” for retail fuel outlets based on how the proposal categorizes certain biodiesel
blends at different times of the year. The regulations will, once finalized, set requirements for biodiesel and renewable
diesel fuel with the goal of reducing emissions such as nitrogen oxides (NOx) from fuel combustion.
How California regulates biodiesel and renewable diesel is being closely tracked by numerous stakeholders, including engine makers, biofuel producers, the oil industry and environmentalists, in part because it may have significant
impacts on greenhouse gas (GHG) and other pollutant emission reductions, and will influence how companies comply
with the state’s low-carbon fuel standard (LCFS) and federal renewable fuel standard.
ARB officials this week unveiled the revised draft proposal for its “Alternative Diesel Fuel Regulation,” which aims
to incentivize the production of cleaner diesel while ensuring that pollutants such as NOx do not increase from greater use
of the fuels. The regulation, several variations of which have been in the works for more than four years, was previously
scheduled to be adopted by ARB last year.
The primary change to the latest proposed regulation is a new NOx mitigation strategy, based on recent studies
showing that 5 percent and 10 percent biodiesel blends (B5 and B10) with soy feedstocks cause a statistically significant
NOx emission increase from heavy-duty vehicles, compared with standard California ultra low-sulfur diesel fuel (Inside
Cal/EPA, July 18).
ARB is proposing that under certain conditions fuel producers take measures to mitigate NOx emissions from B5 and
B10 on a per-gallon basis when those emissions exceed a “safe harbor” level based on a significance threshold that has
not yet been defined in the proposal.
Biodiesel made from soy feedstocks is referred to as “low saturation” with a cetane number of below 56, while
biodiesel made from animal feedstocks is referred to as “high saturation” with a cetane number of 56 or higher, according
INSIDE Cal/EPA - www.InsideEPA.com - October 24, 2014
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to the proposal. ARB also intends to transition from a qualitative description of feedstocks, such as “animal” or “soy,” to
one based on a performance value, such as a cetane number or index.
ARB would establish significance thresholds of B5 for low saturation biodiesel, and B10 for high saturation
biodiesel to ensure NOx impacts associated with biodiesel use do not increase.
In addition, ARB staff is considering a B10 safe harbor level regardless of feedstock in the “low ozone season” from
November to April, according to the proposal. While higher NOx emissions are unlikely to result in “ozone episodes”
during the low-ozone season, preliminary analysis suggests the potential for secondary particulate matter (PM) formation
from increased NOx, the proposal says. Relevant documents are available on InsideEPA.com. See page 2 for details.
Possible strategies to mitigate NOx emissions include blending additives such as di-tert butyl peroxide (DTBP) into
the fuel, ARB notes.
As newer technology diesel engines (NTDEs) enter the market, the need for biodiesel mitigation will decrease, ARB
staff says. NTDE penetration is expected to be above 90 percent by 2023, “negating the need for NOx mitigation” under
the regulation, according to the proposal.
ARB plans to release draft regulatory language for the proposal in early November, a final staff report in December
and consider adoption of the plan at the board’s Feb. 19-20, 2015, board meeting. The regulation’s reporting provisions
would take effect Jan. 1, 2016, with the NOx mitigation requirements taking effect on Jan. 1, 2018, according to the latest
proposal. Staff says that the two-year lead-in is “necessary for industry to invest in necessary infrastructure, certify new
mitigation options, or change business practices to focus on exempt fleets.”
ARB staff notes in the proposal that, overall, biodiesel reduces direct PM, volatile organic compounds and GHGs.
Biodiesel producers and oil companies are, however, raising a host of concerns with the latest ARB plan. “My
personal opinion is that the regulations are overkill, and that the benefits of biodiesel far outweigh any negatives that may
occur for a very brief period of time while NTDEs are incorporated into California,” says one biodiesel industry source.
During an Oct. 20 ARB public workshop on the revised draft proposal, Russ Teall, representing Biodico and the
California Biodiesel Alliance, asked ARB staff whether it will be analyzing in its environmental review document for the
regulation the emissions impacts of not adopting the regulation at all, referred to as the “no action alternative” under the
California Environmental Quality Act (CEQA). He argued the regulation’s restrictions on biodiesel use will result in
higher criteria pollutant, air toxic and GHG emissions in the state.
“For every gallon of biodiesel that is not allowed in the marketplace you have a known increase in all those other
[emissions], and that should be included in the no-action alternative,” Teall said during this week’s workshop.
ARB declined to speculate on such a scenario, but noted that such a CEQA analysis would use the state’s currently
mandated ultra low-sulfur diesel fuel as a baseline for emissions calculations.
Shelby Neal, representing the National Biodiesel Board, echoed Teall’s concerns, saying that the PM reductions and
other benefits of biodiesel is “one point lost in this proceeding,” and that PM reductions are closely associated with
improving human health, especially children who are exposed to high PM levels in school zones.
Oil industry representatives at the recent meeting, meanwhile, raised concerns about the mitigation options and
the schedule for implementing the regulation.
Nick Economides, representing Chevron Corp., called the mitigation options proposed in the revised rule “weak, as
far as practicality for the regulated industry.”
Specifically, “we have told you from the beginning we have serious concerns about being able to use that individual,
specific additive option as it currently stands,” he said, apparently referring to DTBP.
He said that it is very difficult to estimate all the different impacts on cetane and pollutant emissions that will result
from blending different additives.
With regard to ARB’s proposed implementation schedule for the regulation, Economides indicated that two years
lead-time is insufficient based on the amount of testing fuel producers would have to carry out on biodiesel blends and
additives, in addition to building new facilities, tanks and storage devices.
“Even if we thought we had a ready-made, off-the-shelf mitigation alternative in the menu you presented, two years
would be aggressive,” he said. “In the absence of that, it is impossible.”
ARB’s proposed regulation could also create numerous challenges for retail sellers of biodiesel, in terms of how they
market and label different blends, according to comments made at this week’s meeting by Allan Morrison, an official with
the California Department of Food & Agriculture’s Division of Measurement Standards, which is in charge of enforcing
ARB’s rules at the pump.
He explained that B10 and B5 are two different products that require two different methods of labeling and advertising. ARB’s proposed regulation would change how these blends are categorized depending on the season they are sold, he
noted. This could result in an “enforcement nightmare and a marketing nightmare” that also would create a substantial
level of uncertainty and confusion in the marketplace among consumers, Morrison said. He suggested that ARB could
make tweaks to the proposal to avoid such a scenario.
ARB staff downplayed the likelihood of such a scenario, but committed to discussing the issue further with Morrison
and others.
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Advocates Tout Revocation Of Crude-By-Rail Permit As ‘Wake-Up’ Call
Environmentalists are hailing the Sacramento Metropolitan air district’s revocation of a permit allowing a company
to import crude oil by railroad and transfer it to trucks for delivery to a refinery, saying the action puts other local
agencies and industry on alert that “crude-by-rail” facilities will face much more scrutiny for their potential environmental and public safety impacts.
Environmental groups have made targeting crude-by-rail projects a high priority over the past year, arguing the
imports allow more flammable crude oil to be transported from the Midwest and Canada, posing a danger to the environment and the public for a host of reasons. For example, advocates say the imports increase emissions of air toxics and
greenhouse gases (GHGs) in low-income, minority areas; they necessitate more hydraulic fracturing and other well
stimulation treatments; and they perpetuate California’s reliance on dirty fossil fuels for transportation.
The Sacramento Metropolitan air district determined this week that a permit it approved earlier this year for
InterState Oil Co. to receive crude oil via rail car at its McClellan “transloading facility” and load it onto trucks for
delivery to a refinery in the Bay Area was “issued in error” because it failed to meet district best available control
technology (BACT) requirements, according to an Oct. 21 letter from the district to InterState Oil.
The company has agreed to “surrender” the permit, rather than force the district to petition its hearing board for
permit revocation, according to the letter. Relevant documents are available on InsideEPA.com. See page 2 for details.
The district was forced to review the permit after it was sued last month by Earthjustice on behalf of the Sierra Club,
which argued in part that the permit violated the California Environmental Quality Act (CEQA) because it did not include
a review of the project’s risks to public health and safety and that the district did not provide the public with a chance to
comment on the permit.
As a result of the revocation of the permit, Earthjustice is expected to drop the lawsuit, sources say.
“This is the first crude transport project that has been stopped dead in its tracks in California,” Earthjustice attorney
Suma Peesapati says in an Oct. 22 press release. “This is a victory for the health and safety of the people of Sacramento,
for communities along the path of the trucks hauling this dangerous product to the Bay Area, and for the refinery communities where the crude is eventually processed. It signals that industry and government may not benefit from a lack of
transparency and play dice with the lives of people who live along the paths of these dangerous oil trains.”
An Earthjustice source says it is highly unusual for an air district to revoke one of its permits, and the group wants
the Sacramento Metropolitan air district’s action to provide an example for other air districts and government agencies in
the state. “We hope it serves as a wake-up call to other agencies,” the source says.
InterState Oil will still be able to import and transport ethanol at its facility, as allowed by a previously issued permit,
the air district notes in its letter.
The company “will cease oil transloading as of Nov. 7, 2014,” but the official termination of the permit will not take
effect until Nov. 14 to account for any late railcar deliveries after Nov. 7, according to an Oct. 22 letter to the district
from the company’s attorney.
The attorney did not respond to a request for further comment.
Earthjustice has also filed several other lawsuits this year to stop crude-by-rail projects, including challenges to a
Bay Area air district permit and a Bakersfield County environmental impact review (Inside Cal/EPA, Oct. 17). The group
is currently appealing the challenge to the Bay Area permit, after a superior court judge ruled that the suit was filed too
late under CEQA’s statute of limitations provisions.
ARB Declines To Seek ‘Early Action’ Credit Under EPA Power Plant Rule
The state air board is rejecting a stepped-up call from oil and other industry groups for the state to seek maximum
“early action” credit for its past greenhouse gas (GHG) cuts under U.S. EPA’s proposed standards for existing power
plants, complicating a similar push from a host of other leading states and utilities.
By declining to seek credit for early GHG cuts under EPA’s utility existing source performance standards (ESPS),
California — the state that is widely seen as a leader on GHG mitigation issues — has removed significant heft from the
broader push by states and others to receive early action credits as EPA begins to weigh formal comments on the proposal
and craft the final rule by June 2015.
Multiple states ranging from Colorado to Maine to Texas have all urged EPA to provide greater recognition of their
previous efforts to reduce carbon emissions in the final rule, a move that if successful would ease state and industry
efforts to comply with the EPA’s emissions targets.
Officials from some of those states have been especially eager to ensure that states that have done relatively little to
reduce their emissions are not able to gain an advantage. For example, one Minnesota regulator has said the proposal
needs “more balance” due to relatively weaker targets in some coal-heavy states.
And Rep. Paul Tonko (D-NY) has asked whether the ESPS should require “more reductions from the states that have
historically done little, and therefore [ease] targets for states that have already been doing their part to address this
INSIDE Cal/EPA - www.InsideEPA.com - October 24, 2014
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national and global problem.”
But a spokesman for the California Air Resources Board (ARB) says the board believes “emissions should be
measured going forward,” an approach that would not include early action. “California’s previous efforts already put us in
a favorable position because those reductions translate into a reduced compliance obligation for the state,” the board
adds.
ARB also says the state “will continue to pursue the significant reductions the science requires from today’s levels,
and encourage EPA to do the same.”
The ESPS proposes to set state-specific GHG reduction goals to achieve by 2030 while giving regulators wide
latitude to craft strategies to meet their targets. California must reduce its emissions rate from 698 pounds of carbon
dioxide (CO2) per megawatt hour (lb/MWh) to 537 lb/MWh by 2030.
A September discussion paper from ARB was silent on the early action credit issue but said EPA’s proposed state
target is achievable and added that the goal could be met through existing state policies. ARB has also previously said it
will “over comply” with EPA’s rule.
The discussion paper also notes that EPA’s target does not fully account for the Golden State’s renewable policies,
asking, “what are the pros and cons to increasing the stringency of California’s target?”
The proposed portion of states’ targets tied to renewables is seen as the most explicit recognition of early action,
given that a handful of states have renewable generation that meets or exceeds EPA’s 2030 target, and several others,
including California, are close to the mark.
EPA is said to be leaning toward its proposed alternate approach to renewable targets, a move that likely would not
increase the overall stringency of the rule but could hike targets in some Midwest states while decreasing them in the
Southeast. Environmentalists are also pushing the agency to significantly strengthen the rule by using a more robust
calculation of states’ potential for renewable generation.
California’s stance comes as industry groups are stepping up their push for ARB to seek some form of early action
credit. A just-released white paper commissioned by the oil industry says board officials should do everything possible to
convince EPA to recognize California’s significant progress in GHG cuts under the state’s sweeping AB 32 cap-and-trade
regulatory programs (Inside Cal/EPA, Oct. 17).
And earlier this year, a group of attorneys representing a variety of California industries said they will push for early
action credit, arguing the proposal could penalize California companies by driving up compliance and energy costs
compared with neighboring states that have done very little to reduce GHG emissions (Inside Cal/EPA, July 4).
Lawyers Attack ARB GHG Credit Probe . . . begins on page one
attorneys for the company argue in their Oct. 17 comments.
“While Clean Harbors acknowledges that ARB is entitled to a level of discretion in the application of its own
regulations, ARB has exceeded its authority under AB 32, failed to follow appropriate procedures, and acted in an
arbitrary and capricious manner by issuing a preliminary determination that some of the credits should be invalidated.”
Relevant documents are available on InsideEPA.com. See page 2 for details.
In addition, numerous power companies, utilities and carbon credit development and trading firms from around the
country are attacking the board, urging the board to reverse its preliminary decision and instead overhaul its investigation
process, which they charged went on too long, lacked transparency and inappropriately concluded that the credits should
be invalidated.
At issue is the California Air Resources Board’s (ARB) decision to invalidate 231,154, or about 5 percent, of the 4.3
million credits that Clean Harbors had generated at its incineration facility in El Dorado, AR. The board revoked the
credits after concluding that the credits were fraudulently produced under the state’s ODS offset protocol while the
facility was not in compliance with provisions of its Resource Conservation & Recovery Act (RCRA) permit issued by
U.S. EPA. The credits have a value of roughly $43 million.
ARB’s offset program allows businesses to generate tradable credits for activities that result in GHG reductions, such
as forestry projects that increase carbon sequestration, and the destruction of chemical refrigerants and other ODS that
contribute to global warming. Such credits can be sold to help emitting entities comply with the state’s GHG cap-andtrade program, if they comply with ARB’s protocols. The use of offsets, which are generally less expensive than GHG
allowances sold at quarterly state auctions, is a key strategy to contain compliance costs under the state’s cap-and-trade
program.
Clean Harbors collects equipment and appliances that contain ODS such as foam blowing agents and refrigerants and
burn it in an incinerator. The emissions from the incinerator are processed through air pollution control equipment, which
produces a briny sludge that is removed from the equipment, according to an industry source. Clean Harbors was selling
this sludge as a product for use in other operations such as oil and gas hydraulic fracturing, the source said, but EPA
Region VI earlier this year determined that the sale of the sludge violated the facility’s RCRA permit.
ARB concluded that the RCRA violation meant the credits violated the offset protocol, which bars credits from being
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INSIDE Cal/EPA - www.InsideEPA.com - October 24, 2014
generated if the facility violates local, state or national, environmental and health and safety rules during the reporting
period for which the compliance offset credit was issued.
On Oct. 8, ARB Executive Officer Richard Corey issued a preliminary determination that 231,154, or about 5
percent, of the 4.3 million credits targeted in the probe should be invalidated because they were generated during a twoday period when the facility was out of compliance with the RCRA permit. ARB limited its action to credits that were
generated during a narrow window between the time the facility was officially notified by EPA that its ODS destruction
activities violated its RCRA permit and the time the company continued to violate its permit — one day later (Inside
Cal/EPA, Oct. 10).
As part of the proposed determination, ARB established a 10-day written comment period, which ended Oct. 17.
Clean Harbors used its comments to detail a possible litigation strategy, charging that “ARB has made significant
errors of fact and law in its analysis, failed to adequately consider all relevant information, and failed to demonstrate an
adequate legal basis for its preliminary determination,” attorneys for the company comment.
Like many of the other companies, Clean Harbors contends that ARB incorrectly concluded that the ODS are RCRA
hazardous wastes, and that the disposal of the waste is not connected to the destruction of the ODS. In addition, the Clean
Harbors attorneys argue that “ARB is incorrect that the opinions expressed in an EPA inspection report are conclusive
evidence that a violation of law has occurred,” and that “ARB failed to conduct its investigation in accordance with longestablished principles of administrative law, and has acted outside its legislative mandate.”
Many other commenters also provided strong criticisms, calling on Corey to reverse the proposed revocation
decision by validating the credits and taking actions to overhaul ARB’s investigation process.
Environmental Credit Corp. (ECC), whose lawyers describe the company as North America’s leading GHG offset
credit developer, said ARB’s preliminary determination will invalidate 142,199 of ODS offset credits generated by ECC,
the company’s Oct. 17 letter to Corey says.
“ECC is deeply concerned by the manner in which ARB conducted this investigation, including its seizure of the
offsets prior to final determination, ARB’s willingness to give conclusive weight to what are only allegations of RCRA
noncompliance, and ARB’s formalistic application of the ODS Protocol despite its recognition that ‘the offsets at issue
here are real, quantified, and verified,’” the letter states.
Even if the Clean Harbors facility was in violation of its RCRA permit on Feb. 2 and 3 (2012) due to its sale of brine
byproducts, the RCRA violation “simply does not bear on the validity of the offsets generated by the ECC Project
because it had been cured on February 3 hours before the ECC Project’s ODS destruction began,” the letter says.
Further, to the extent ARB’s preliminary determination rests on the proposition that the ODS destroyed at the Clean
Harbors facility are classified as listed hazardous wastes under RCRA, the board’s analysis is “critically flawed,” the
ECC attorneys add. “Used chlorofluorocarbons . . . simply are not listed hazardous wastes. The vast majority of ODS in
existence in the United States are used, and are not treated as hazardous wastes. It is absolutely essential to the ongoing
viability of ODS destruction projects — projects that significantly further the objectives of AB 32 —that ARB correct
this in its Final Determination.”
Carbon credit-trading organizations and companies, as well as oil industry representatives, are also strongly
objecting to ARB’s investigatory process and the precedent it could set.
The International Emissions Trading Association (IETA) complains in its Oct. 16 letter to Corey that the investigation “has taken far longer and lacks the transparency that many stakeholders first expected, following ARB’s initial
announcement” on May 29. “According to ARB’s initial review notice, it appeared that staff planned to deliver a final
determination within 30 days after its initial 25-day information gathering phase,” which ended on June 23.
But ARB later signaled its official interpretation of the rules was that the 30-day determination period is not stipulated to follow the 25-day information-gathering period, “but can instead be launched based on staff’s discretion,” IETA
says. Until the release of its preliminary determination on Oct. 8, “ARB did not signal when they intended to launch their
30-day final determination period for the review, which further added to the uncertainty and potentially affected market
participants’ ability to operate under clear and consistent timelines.”
The organization “is concerned about the precedent being set with the Clean Harbors’ review, and how the ad-hoc
approach to the review process will be undertaken by ARB in the future,” IETA adds. “ARB’s discretion in interpreting
regulatory language regarding the sequence and timing of its investigation further undermines the certainty needed for
markets to function effectively, and could potentially damage the ability of California’s program to meet its goals costeffectively.”
The Western States Petroleum Association charges that ARB’s removal of the ODS credits from regulated parties’
compliance accounts under the cap-and-trade program prior to the launch of the investigation was unauthorized. “While
we understand that offsets could be suspended for purposes of further investigating certain transactions, the removal of
offsets from the holding and compliance accounts for individual entities is an action that is not authorized under the capand-trade regulations, and which will further delay use of valid offsets for compliance purposes,” the group says in an
Oct. 17 comment letter.
An ARB spokesman says this week that the Oct. 17 comment deadline triggered a 30-day period for “executive
review of the case.” As a result, “sometime during or by the end of that period a final decision will be released.”
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Academics Suggest DTSC Consider Worker Exposure . . . begins on page one
products; household/office furniture/furnishings; cleaning products; office machinery consumable products; and fishing
and angling equipment. The plan was released in September (Inside Cal/EPA, Sept. 19).
DTSC in March announced the first three “priority products” and chemicals that it will initially target under the
program. The chemicals and products are: unreacted diisocyanates in spray polyurethane foam systems used in building
insulation; flame retardants Tris (1,3-dichloro-2-propyl) phosphate or “TDCPP” found in children’s foam-padded
sleeping products; and methylene chloride in paint and varnish strippers and surface cleaners.
The three-year draft work plan was discussed during an Oct. 20 meeting of DTSC’s Green Ribbon Science Panel that
advises the department on the implementation of the green chemistry program. DTSC officials said that they plan to
initiate a rulemaking to adopt a priority products list in early 2015, which will take about a year to finalize.
The rulemaking will include priority product “listing” language, supporting documents, an economic and fiscal
impact statement, an external scientific peer review and a review by the state’s Environmental Policy Council,
according to a DTSC presentation at a meeting this week. The presentation is available on InsideEPA.com. See
page 2 for details.
DTSC anticipates adopting revised three-year plans annually, incorporating new chemical products to the priority
list. The plans will identify between five and 10 priority products each of the next three years.
DTSC also plans to release a draft guide on conducting alternatives assessments in “early 2015,” according to the
presentation.
The department’s “safer consumer product alternatives,” or green chemistry regulations, officially went into effect
last October. The program is viewed by many experts as a possible national model for chemical policy reform and for
addressing potentially problematic chemicals in consumer products.
Under the regulations, DTSC will require manufacturers to study whether replacing chemicals of concern with
alternatives is feasible. This is known as the alternatives assessment process, considered a key part of the program. DTSC
also has the authority to ban certain chemicals found in products if it deems that action necessary.
During the science panel meeting, representatives of chemical companies such as S.C. Johnson & Son, Occidental Chemical Corp. and Procter & Gamble Co. raised concerns that the work plan’s proposed categories of consumer
products are too broad, covering too many types of goods, and that it would be more helpful if DTSC provided stakeholders more specificity about products that may be targeted earlier in the process.
For example, panel member Don Versteeg with Procter & Gamble noted that DTSC has already scaled back its
March proposal to investigate diisocyanates in spray polyurethane foam system and the other two product categories
based on industry feedback about the nature of those products.
“With the three-year work plan, you’ve started down that road again but are being careful to say that these chemicals
are not the ones we’re necessarily focusing on,” Versteeg said. “The suggestion is to be as clear as you can about what the
chemicals are and what the products are as early as possible to be helpful.”
Merely outlining a plan saying that dozens of chemicals and products are in the scope of the work plan is “not
tremendously helpful,” he added. “So the more specific you can be, the better it’s going to be and you’ll get that input
earlier and it will be focused input as opposed to generic input.”
Bill Carroll, representing Occidental, recommended that DTSC begin narrowing the scope of targeted products or
chemical combinations in products early in the processs, such as limiting the initial scope to 15 products if the desire is to
ultimately settle on five. This would help in part to satisfy DTSC’s objective of “sending signals to the marketplace,”
whereas the current process captures such a large swath of products that it is unclear if any signals are being sent, Carroll
said at this week’s meeting.
S.C. Johnson & Son representative Mike Caringello also raised concerns that certain companies could be repeatedly
targeted under the program depending on how DTSC prioritizes chemicals and products. For example, if DTSC “really
got on a roll” and started targeting 10 products per year for a limited number of categories, “are we going to start hitting
the same players over and over again?” he asked.
This scenario could potentially unfold in the cleaning products category where the same chemicals are used in
numerous, multipurpose products, Caringello said. This could disrupt a company’s efforts to comply with the program by
conducting alternatives assessments for chemicals and product reformulations, he added.
Meredith Williams, DTSC’s deputy director of the program, responded that Caringello raised an “excellent point”
and that department officials would think about the issue while considering revisions to the draft plan.
Meanwhile, panel members representing universities and environmental organizations generally called on
DTSC to maintain a broad scope for chemical product categories and to potentially enhance the list by considering
exposures to workers.
For example, Julie Schoenung, with the University of California-Davis, recommended that DTSC highly factor
chemical exposure to not only workers who handle finished consumer products but those who help manufacture the
chemicals that ultimately wind up in products. The current work plan is unclear on this topic and DTSC should revise the
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language to provide clarity and certainty, she said.
Megan Schwarzman, with the University of California-Berkeley, added that this is especially important for workers
who handle chemicals used in textile finishes, such as those in wrinkle-resistant clothes that contain significant levels of
formaldehyde. These workers are handling the chemicals before they are “treated” and “cured” for application to the
retail products and therefore are being subject to “potentially very high exposures,” she said.
DTSC should also include semi-volatile organic chemicals in its prioritization work plan to capture harmful chemicals that are carried on dust in indoor environments, Schwarzman said, noting that the current plan only includes full
volatile organic compounds.
Panel member Ken Geiser, with the University Massachusetts-Lowell, recommended that DTSC establish a new
category for children’s products, adding that DTSC could coordinate with officials in Washington state, which he said is
conducting significant amounts of chemical-review research in this area.
Several panel members representing both industry, universities and state agencies all questioned whether DTSC has
enough resources to carry out all of the tasks required under the green chemistry program, including those within the
priority products work plan.
But DTSC staffer Karl Palmer said the department will “manage it as best we can,” acknowledging that processing
five to 10 priority products a year is potentially “ambitious” and adding that building the new program will take a lot of
learning.
Legal Filing Reignites Dispute Over BLM Fracking Reviews, Oil Well Leases
A legal dispute between environmentalists and the Bureau of Land Management (BLM) over when the federal
agency will resume oil and gas drilling lease sales and complete an environmental impact review of hydraulic fracturing
in California has flared up again with a new BLM “status report” on the parties’ settlement agreement.
Resolution of the case is being closely watched by numerous parties around the country because it is expected to
inform how federal regulators assess fracking impacts before they conduct oil and gas lease sales throughout the United
States.
Attorneys with the Center for Biological Diversity (CBD) claim that BLM’s Oct. 16 status report reveals the agency
likely does not intend to resume oil and gas lease sales anywhere in the state until 2016 at the earliest, in order to complete a legally required environmental impact statement (EIS) on fracking that may occur on two disputed leases in the
central coastal area of California.
But BLM officials dispute this contention, maintaining that they still intend to resume lease sales next year in regions
outside the location of the disputed two leases. The area to be covered by the EIS is overseen by BLM’s Hollister Field
Office, which covers a swath of land from the San Francisco Bay Area south to Monterey County. Not included in the EIS
area is Kern County, where approximately 80 percent of oil drilling occurs in the state, BLM officials say.
At issue is a legal settlement for two related lawsuits, both named CBD and Sierra Club v. BLM, in the U.S. District
Court for the Northern District of California. The court ruled last year that BLM violated the National Environmental
Policy Act (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. The counties are within the Monterey Shale formation, which is estimated to contain billions of
barrels of oil, some of which could possibly be extracted by fracking.
The Oct. 16 BLM status report states in part that BLM last month awarded a contract for the preparation of a
“Resource Management Plan” amendment and EIS “to address oil and gas leasing and development on public lands and
federal mineral estate in the Hollister Field Office.” Project completion and issuance of a record of decision (ROD) is
tentatively scheduled for October 2016, the filing states. The filing is available on InsideEPA.com. See page 2 for details.
A CBD source says the BLM status report shows that “the federal government will likely not issue new leases to oil
companies for drilling and fracking on public land in Monterey County and across California for at least another two
years,” noting the October 2016 ROD completion date.
“Given BLM cannot lawfully issue any new leases until they complete the EIS process, this should mean the de facto
moratorium on leasing of public land in California to oil companies continues for another two years,” the CBD source
adds.
Brendan Cummings, CBD senior counsel, says in a written statement that it is a “huge relief to see California’s
beautiful public lands get two more years of protection from fracking pollution. . . . The fact that we’ve had no new
leasing for almost two years and won’t for two more gives us breathing space to push for a permanent ban on this toxic
technique.”
But a BLM spokesman says CBD’s interpretation of the status report is erroneous. “We won’t be leasing in the
Hollister Field Office [region] before completing the EIS, but are looking elsewhere for 2015 lease auctions,” the
spokesman says.
BLM officials recently made this point clear in response to CBD claims that the agency could not legally conduct oil
INSIDE Cal/EPA - www.InsideEPA.com - October 24, 2014
9
and gas lease sales anywhere in California until the EIS and ROD are finalized (Inside Cal/EPA, Sept. 5).
At that time, a CBD source said the group would again sue BLM if it conducts lease sales prior to the issuance of the
ROD. “While the lawsuit was only over Hollister leases, and technically they only need to do an EIS covering Hollister to
address those leases, BLM has no EIS for Kern [County] leases that addresses fracking,” the source argued. “Consequently, if they limit the new EIS to Hollister they will not have up-to-date and lawful NEPA coverage for leasing in Kern.
That said, BLM lost their case against us since they chose to ignore the law and common sense, so they may very well
decide to move forward with leasing in Kern in 2015. If they do, a court will likely put a halt to it.”
The settlement recently reached in CBD and Sierra Club v. BLM includes a stay of the suit while BLM carries out the
EIS and stipulates that environmentalists can return to the court for further relief if they are unsatisfied with BLM’s EIS.
One of the primary reasons BLM plans to resume lease sales in California next year is that an independent study the
bureau commissioned by the California Council on Science and Technology (CCST) found that fracking and other well
stimulation treatments to extract oil in the state pose a relatively low environmental risk (Inside Cal/EPA, Aug. 28).
The study, “Advanced Well Stimulation Technologies in California,” was commissioned by BLM in September 2013
in part as a result of the legal challenges against the agency’s approval of oil and gas well lease sales. The court challenges prompted BLM to suspend its oil and gas well lease sales beginning in December 2012, according to a BLM
spokeswoman.
Along with the release of the study, BLM in August announced a comprehensive strategy for the federal oil and gas
program in California, which incorporates information from the CCST study, provides the results from public scoping on
oil and gas development, and provides internal guidance for processing of applications for permits to drill and sundry
notices.
Jim Kenna, BLM’s California state director, said during an Aug. 28 press conference call that the study and BLM’s
new review strategy “allows us to do leasing again in California and Kern County.” While there will be a “lag time out
into 2015” to complete parcel and other reviews, “we do expect to resume leasing,” Kenna said.
In addition to the CCST report, BLM has issued internal guidance directing its field offices to request from oil and
gas operators the information California requires under its new regulations, according to the bureau.
CBD charged last month that the CCST study does not justify the bureau’s decision to soon resume oil and gas lease
sales in the state. In some cases the study reveals potentially dangerous impacts from fracking and at the same time the
review is so incomplete that BLM should wait for further information to be collected before making any determinations
about lease sales, CBD asserted.
Power Firms Back GHG Trading Under EPA Rule . . . begins on page one
framework is complicated by the fact that California’s program is multi-sector in scope, and is linked to a jurisdiction
(Quebec) that will not be subject to” EPA’s rule. The letter is available on InsideEPA.com. See page 2 for details.
To address this, the group is urging ARB to take steps to account for the difference between the state’s broader
approach and EPA’s narrower power sector measure.
Specifically, the group says the Golden State should model the emissions impact of its AB 32 cap-and-trade
program’s “carbon price” on utilities in conjunction with renewable energy mandates. The group adds that ARB should
preserve EPA’s proposed rate-based target to provide flexibility for additional generation.
It also said that ARB should ensure that EPA’s final rule better articulate the benefits of regional trading
programs and does not inhibit multi-sector trading if and when the agency crafts GHG rules for other industrial
sources.
The group says ARB’s comments on the rule “will carry significant weight with EPA” due to the Golden State being
widely seen as a leader on climate change issues. For example, ARB recent comments declining to seek “early action”
credit could complicate requests from other leading states and utilities for greater recognition of their past efforts to curb
GHGs (see separate story, px).
At issue in California’s program is the fact that it covers many sectors of the economy, and will include transportation
fuels in early 2015, allowing a regulated source to buy credits generated in other sectors.
An allowance bought by a power plant “does not necessitate an equivalent reduction in electricity sector emissions
elsewhere; rather the reduction in emissions might occur in a different sector,” WPTF says. “As a result, total electricity
sector emissions could rise, creating a risk of non-compliance with the state’s” target in the EPA rule.
Despite that concern, WPTF is challenging a new oil industry-funded white paper that claims California’s GHG capand-trade program is “fundamentally misaligned” with EPA’s proposed existing source performance standards (ESPS), in
terms of providing a workable compliance strategy (Inside Cal/EPA, Oct. 17, p1).
To the contrary, the group argues, California and other western states could devise regional plans based on economywide carbon credits that could be shown to meet and exceed EPA’s regulation.
The ESPS, crafted under Section 111(d) of the Clean Air Act, sets GHG-reduction requirements for each state to
achieve by 2030, using a 2012 baseline. California must reduce its emissions rate from 698 pounds of carbon dioxide
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(CO2) per megawatt hour (lb/MWh) to 537 lb/MWh by 2030.
New Modeling
To show how California’s multi-sector cap-and-trade program can be shown to fit into the ESPS framework, WPTF
says the state should model how the program’s “carbon price” on utilities, and the state’s renewable programs, will reduce
utility emissions.
The group notes that some analysts have suggested states must convert rate-based emissions limits established
under the ESPS to mass-based targets in order to implement mass-based emission trading programs. Other analysts
have also suggested that California would need to establish a separate electricity sector-only cap in order to comply
with the rule.
However, “WPTF believes that these assertions arise out of an incorrect assumption that a state’s emission cap under
its cap and trade program must match its 111(d) target,” the letter says. The group even argues that conversion from a
rate-based emission performance standard to a mass-based target will not help demonstrate compliance under a multisector cap.
WPTF argues California can implement its mass-based emissions program under a rate-based state target. “The state
would have a rate-based target under 111(d) and establish a separate mass-based cap for the emission trading program,”
the group says. Compliance by the state with its rate-based 111(d) target would be demonstrated “ex-post” by comparing
total statewide emissions from existing fossil generation in the state against total generation of these units, as adjusted by
renewable energy generation and avoided generation from energy efficiency savings,” the group says.
Compliance by covered entities under the emission trading program would be verified by comparing each entity’s
emissions to its surrendered compliance instruments, the group adds.
Beyond its request for a rate-based ESPS goal, WPTF says, “We believe that the carbon price created under the cap
and trade program, rather than the cap, can be used to demonstrate the state’s compliance pathway and that the imposition
of a carbon price on affected EGUs via the cap and trade program should be the basis for the state’s implementation
plan.”
Future EPA Rules
ARB should also ensure that the final EPA regulation “does not inhibit multi-sectoral emission trading” under state
compliance plans for future EPA rules, WPTF says.
The agency has so far proposed section 111(d) GHG regulations for existing power plants and issued an
advance notice of proposed rulemaking for GHG emissions from existing landfills, but officials indicated in the
agency’s fiscal year 2015 budget request that they are also reviewing several other industrial sectors for possible
GHG regulations, including pulp and paper facilities; iron and steel production, animal feeding operations; and
cement manufacturing.
The agency also indicated it was reviewing refineries for possible GHG rules but EPA Administrator Gina McCarthy
said late last month that expected “co-benefit” reductions of methane under the agency’s proposed air toxics rules for the
sector could capture enough GHGs to obviate the need for long-delayed new source performance standards (NSPS) for
the facilities.
While EPA’s statutory authority restricts the agency to regulating emissions on a sector-by-sector — rather than a
cross-sectoral — basis, that does not mean that EPA’s regulations “cannot accommodate state implementation plans that
regulate emissions across sectors,” WPTF argues.
Because California’s cap-and-trade program is currently the only multi-sector GHG emissions trading program in the
country, “it is incumbent on ARB to ensure that EPA’s final rule provides for, or at least does not inhibit, emissions
trading across sectors in the event that EPA does regulate additional GHG sources in the future. We believe that this
objective can be met by ensuring that EPA allows the carbon price under a cap and trade program to be used to demonstrate a compliance pathway.”
Under that scenario, WPTF says, if EPA later crafts a GHG rule for another sector regulated by California’s program,
the state could craft a compliance plan similar to the one it wrote for the power sector.
The western energy group also says that although the ESPS will encourage multi-state cooperation, “there will be
significant barriers to such cooperation even in states where regulators and stakeholder recognize the benefits.” The
group says ARB should urge EPA to “better articulate the benefits” of such plans when possible.
Even though EPA would give states up to three years to write a multi-state plan, the group says that time frame is
“still too tight and inflexible,” urging EPA to provide more time. Further, the group warns that the ESPS “provides no
means for a state that has initially chosen an individual implementation plan to pursue regional cooperation at a later
date,” arguing EPA should create that mechanism in the final rule.
The group also urges EPA to develop ways for states to form modular agreements that California is proposing for
specific aspects of a state plan. And it also encourages the agency to “clarify” interstate issues such as how renewables
and energy efficiency are accounted for.
Further, the group says EPA should provide technical assistance, including a model rule or establishment of a
regional target “upon request” of interested states.
INSIDE Cal/EPA - www.InsideEPA.com - October 24, 2014
11
ARB Urges EPA To Ease GHG Limits For Gas Plants Tied To Renewables
State air board officials are urging U.S. EPA to revise its proposed greenhouse gas (GHG) rule for “modified and
reconstructed” power plants to better accommodate natural gas units that serve as backup to renewable energy generation,
echoing calls from gas industry officials who are seeking similar revisions.
In Oct. 16 comments, the California Air Resources Board (ARB) reiterated calls it had made in its comments on
EPA’s proposed rule for new electric generating units (EGUs) where officials urged the federal agency to subcategorize
natural gas units by “functional type” rather than the size of the units — an approach that the state and many gas industry
officials are seeking to ease requirements for units that act as a backup for renewable energy generation. The letter is
available on InsideEPA.com. See page 2 for details.
“Expanding renewable resources is an essential element of California’s GHG reduction program,” ARB says. “As
California has rapidly added variable renewable resources, the incremental need for flexibility, which is critical for
maintaining grid reliability, has also increased,” the letter says.
California’s input on the draft EPA rules could have a significant influence on the final product considering that the
state is considered a forerunner in GHG-reduction policy and regulation, including an economy-wide cap-and-trade
program, and has the nation’s most stringent renewable portfolio standard.
In addition to its call on gas units, the board is also urging EPA to drop an exemption for units that operate
infrequently.
At issue is EPA’s proposed “Carbon Pollution Standards for Modified and Reconstructed Sources: Electric Utility
Generating Units,” which is being issued under section 111(b) of the Clean Air Act. The rule is one of three EPA is
advancing to reduce GHG emissions from new and existing power plants.
EPA has proposed the standards for modified and reconstructed sources as a legal backstop in the event its rule for
new sources, also issued under 111(b), is vacated because the agency must define EGUs as a source category under 111
(b) before it can regulate existing sources under 111(d).
As a result, if the agency’s new source performance standard (NSPS) is vacated, the modified source rule will also
define EGUs as a source category subject to regulation under 111(d).
The proposed EPA regulation for modified and reconstructed natural gas fired units currently subcategorizes EGUs
into large units — turbines with a heat input rating greater than 850 million Btu per hour (MMBtu/hr) — and small units
with a heat input rating less than or equal to 850 MMBtu/hr, ARB notes.
EPA is also proposing emission standards of 1,000 pounds of carbon dioxide per megawatt-hour (lb CO2/MWh) for
large units, and 1,100 lb CO2/MWh for small units.
But ARB and many gas industry officials say that the size-based approach is inappropriate for “load following” units that serve as backup for renewable generation, arguing that the plants cannot achieve the current proposed limit
because those facilities must ramp up and down quickly to fill in when renewable energy is unavailable, boosting emissions.
Instead, ARB is urging EPA to create a separate standard or “subcategory” for such units in the modified source rule
to account for their generation practices, echoing comments officials made in their May 8 letter regarding EPA’s proposed
NSPS.
“These size-based standards do not fully recognize the changes in the operation of natural gas-fired EGUs we
anticipate in California as part of its plan to de-carbonize the electricity sector,” the Oct. 16 letter states. “Further, they do
not reflect the emissions performance abilities for baseload and peaker facilities.”
EPA should “secure more focused and durable emissions reductions by continuing to investigate EGU performance
characteristics, and how those characteristics may shift in the regulated future, subcategorizing appropriately to reflect the
resulting range of operational modes.”
Natural gas-fired EGUs are increasingly operated to support and integrate increasing levels of renewable resources,
such as wind and solar, rather than solely as baseload or peaking resources, according to ARB. These flexible EGUs must
have the ability to sit idle or at very low levels of output while renewable resources are on-line, then quickly start and
rapidly ramp up as renewable resources come off the grid, such as when the sun sets or the wind dies down, ARB says in
the letter.
However, operating these EGUs as flexible resources results in reduced thermal efficiency, which in turn increases
GHG emissions from the individual units, ARB points out. But “by helping to integrate renewable resources, they reduce
overall GHG emissions from the electricity system.”
As a result, a more precise subcategorization approach is warranted to address this performance gap, ARB says,
primarily to properly recognize the characteristics of EGUs used for renewable power integration in California. As a
result, EPA should establish a separate standard for “load-following” natural-gas units, separate from base load units,
agreeing with EPA’s suggestion that it apply during periods “when electric sales are between 33 to 60 percent of the
potential electric output,” ARB says.
“This means that the adequately demonstrated emission performance level for new and modified or reconstructed
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EGUs functioning as base load units will be different than for load-following or peaker units,” ARB says in its comments.
Specifically, ARB asks EPA to adopt a rule with the following emissions performance standard provisions:
• Baseload EGUs (60 to 100 percent capacity factor) have a limit of 825 lbs CO2/MWh.
• Flexible EGUs (33 to 59 percent capacity factor) have a limit of 1,100 or 1,000 lbs CO2/MWh (based on size as
currently proposed).
• Peaker EGUs (less than 33 percent capacity factor) have an emissions factor that considers the variability in
operating conditions and need for peaking units.
In addition, ARB says EPA should “conduct further reviews and rulemakings as necessary, even after finalizing
standards on its current timeline, in order to continue to adapt the standards to ensure that any modified or reconstructed
EGUs are operated as efficiently as possible within the context of ever-evolving, lower carbon energy systems,” the Oct.
16 letter says.
In its May comments on the proposed GHG regulation for new power plants, which were included in the Oct. 16
comments for modified EGUs, ARB also urged EPA to rescind its proposal to exempt “low capacity factor combustion
units,” recommending the agency instead regulate them “as quickly as possible.” The exemption applies to single cycle
gas generators or other units that sell less than a third of their power to the grid, based on a three-year rolling average of
operating hours, according to the proposal.
“ARB believes that EPA should not provide an exemption for these types of units at all, as such an exemption would
not require any standards from what may be a significant body of new emissions sources,” ARB’s May comments state.
“Comprehensive new source GHG standards for all EGUs, regardless of operational type, are an important step towards
fulfilling the President’s mandate to employ EPA’s Clean Air Act authority fully, and will provide the strongest foundation
for pending regulations for existing plants.”
EPA’s proposed exemption is unlikely to serve these purposes, especially in the context of resources used for
renewables integration, to the extent they operate below any “exempt” threshold, ARB further argued. EPA should use the
subcategorization approach ARB recommends to develop “distinct standards for plants operating at low capacity factors.”
Order Allows Flexible Power Purchasing . . . continued from page 14
the expensive replacement systems.
“At the same time, the once-through-cooling retirements will reduce the number of existing resources that are
available to provide the flexibility necessary to manage the increased variability and maintain day-to-day reliability,”
CAISO says in its request to FERC.
But CAISO explains that given these problems, California will have an increased need for resources that can ramp up
and down quickly and start and shut down potentially multiple times per day.
Moreover, to efficiently operate the grid CAISO “needs measures to ensure that these flexible resources economically bid into the CAISO markets so the CAISO can optimally dispatch them,” the request adds. “Without load
serving entity procurement of flexible capacity resources and requirements that the resources economically bid such
capacity into the CAISO markets, at best the CAISO will face an increasing need for out-of-market exceptional
dispatches and backstop capacity procurement through the CAISO’s capacity procurement mechanism. At worst, the
CAISO may not have access to sufficient resources to address the significant operational challenges and maintain grid
reliability.”
The FERC order allows CAISO to revise tariff provisions “to remove a barrier for resources that have not
submitted prior bids to qualify as flexible capacity resources,” according to FERC. The order also directs CAISO to
submit an informational report, by Jan. 1, 2016, addressing, among other things, information about allocating
flexible resource adequacy capacity obligations and backstop costs, and the feasibility of allowing imports to
provide flexible capacity.
“While the proposal addresses CAISO’s immediate needs for flexible capacity, a more comprehensive framework is
under consideration including a multi-year forward resource adequacy mechanism and a market-based backstop procurement mechanism. These mechanisms are currently being assessed through California Public Utilities Commission and
CAISO stakeholder processes,” according to FERC.
The new CAISO flexible capacity methodology includes: a system-wide flexible capacity needs determination for the
following year; the calculation and allocation of the flexible capacity needs in each of three flexible capacity categories to
local regulatory authorities — local regulatory authorities are responsible for allocating flexible capacity procurement
obligations to their load serving entities; a month-ahead and year-ahead showing of flexible resource adequacy by load
serving entities and CAISO’s cumulative evaluation of these showings; a must-offer obligation requiring flexible capacity
resources to bid into the CAISO market; and an extension of CAISO’s authority under its capacity procurement mechanism to procure additional flexible capacity when there is a cumulative deficiency, and an allocation of backstop procurement costs to each load serving entity that failed to cure its deficiency, the FERC summary says.
INSIDE Cal/EPA - www.InsideEPA.com - October 24, 2014
13
FERC Backs California Grid Flexibility Plan To Aid GHG Reduction Efforts
The Federal Energy Regulatory Commission (FERC) has approved a proposal by California grid operators to
ease electricity purchasing rules to integrate more renewable power and distributed generation (DG) on the state’s
grid while ensuring system reliability — all of which are considered crucial to the state’s greenhouse gas (GHG)
reduction programs.
The regulators’ action could be a harbinger for other states that may be in a similar situation as California, where
renewable portfolio standard (RPS) and other GHG-reduction programs are forcing more renewables and distributed
generation power onto a grid system that faces technical, economic and reliability challenges.
It also suggests that the federal regulator may be willing to approve state plans needed to comply with EPA’s GHG
rules, despite concerns from some state critics that they face a dilemma over whether to comply with EPA’s climate rule
for utilities and risk violating FERC reliability mandates, or to adhere to FERC’s requirements but risk major penalties
with a climate plan that falls short of EPA’s rule.
FERC Oct. 16 approved a “Flexible Resource Adequacy Capacity Requirement Amendment” for an existing tariff
governing the California Independent System Operator (CAISO), which requested the order in August.
“CAISO in its filing states that its electric grid is undergoing significant operational challenges, driven by
California’s energy and environmental policy initiatives, including a renewable portfolio standard of 33 percent by 2020,
and various policies encouraging more reliance on distributed generation,” FERC states in an Oct. 16 summary of the
order.
“According to CAISO, managing the increased penetration of variable energy resources and distributed generation
has increased supply and net load variability and unpredictability, at a time when California’s once-through-cooling
[OTC] requirements will reduce the number of existing resources that are available to manage variability and maintain
reliability. Thus, CAISO’s need for flexible capacity is increasing.” Relevant documents are available on InsideEPA.com.
See page 2 for details.
California’s RPS, which requires that 33 percent of the electricity supplied to customers come from renewable
sources by 2020, is a cornerstone of the state’s strategy to reduce GHG emissions to 1990 levels by the end of 2020, a
mandate required by the 2006 global warming solutions law, AB 32.
Clean energy is also expected to play a key role in the state achieving a 2030 GHG-reduction target, which is
expected to be proposed by state officials next year.
But many utilities are struggling to deal with renewable and distributed generation because they do not know how
much retail generating capacity, especially for solar generation, is available so they are unable to reliably dispatch the
power. And, because they are variable resources, their generation is not reliable. Utilities are also struggling to create a
fee system for integrating the resources onto the grid.
Flexible Resources
California’s grid has already experienced some of the negative effects of new variable energy resources coming on
line, CAISO says. For example, on 22 days in March, the CAISO system experienced two significant “daily net load
ramps.” This demonstrates “a current need to have resources available that are capable of responding to multiple dispatches in a single day.”
CAISO explains in its Aug. 1 request for the FERC tariff amendment that managing a “greener grid, with an increased penetration of variable energy resources and distributed generation presents significant operational challenges to
grid reliability in the future.” The influx of large quantities of these resources “will increase supply and load variability
and unpredictability,” CAISO says.
The situation is further exacerbated by the state’s OTC water policy, which requires more than a dozen coastal
power plants to replace their cooling systems over the next decade in favor of technologies that do not have a
significant impact on marine life. State officials expect that many of these plants will simply close rather than install
continued on page 13
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INSIDE Cal/EPA - www.InsideEPA.com - October 24, 2014