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Inside Cal/EPA
An exclusive weekly report on environmental legislation, regulation and litigation
from the publishers of Inside EPA
Vol. 26, No. 6 — February 13, 2015
California Senators Unveil Bills To Create Post-2020 Climate Program
Top California state senators Feb. 10 unveiled a package of bills intended to extend the state’s current climate and
clean energy programs beyond their current 2020 expiration, including measures that seek to set greenhouse gas (GHG)
targets through 2050 and others that would codify Gov. Jerry Brown’s (D) plans for increases in renewable energy and
reductions in oil use.
But many of the legislation’s key provisions are likely to face significant debate in the coming legislative session.
For example, the California Air Resources Board (ARB) has indicated it prefers legislation allowing it to set its own
mid-term GHG targets for 2030 and 2040 rather than having lawmakers set the goals in statute.
Similarly, the legislation setting new renewable energy targets is expected to face significant debate over whether
continued on page 4
Environmentalists Urge EPA To Strengthen California’s UIC Program Overhaul
Environmentalists are urging U.S. EPA to strengthen the state’s plan to overhaul its oil and gas underground
injection control (UIC) program to comply with federal rules, arguing it ignores hundreds of wastewater disposal wells,
lacks adequate public input on what wells should be exempt, and fails to shutter hundreds of potentially contaminated
wells.
But state officials contend that the multi-pronged compliance plan is comprehensive and fully protective of water
supplies, and that environmentalists continue to grossly overstate the actual number of disposal wells that are potential
sources of contamination to useable, or “beneficial,” underground water.
Meanwhile, oil and gas industry representatives who generally support the plan are nonetheless raising early
continued on page 6
WRCB Chief Details Prop. 1 Budget Plans But Calls For Additional Funding
State water board chief Felicia Marcus this week provided lawmakers with an outline of how the board intends to
spend more than $2 billion from 2014’s Proposition 1 on funding water projects, including efforts to bolster drinking
water supplies and better manage wastewater — but warned that more money will be vital to solve California’s numerous water problems, including boosting supplies and building necessary infrastructure.
Marcus made her comments during a Feb. 10 informational hearing by the Assembly Water, Parks & Wildlife
Committee on Prop. 1, the “Water Bond” approved last year by voters that provides $7.5 billion in general obligation
bond funding for various water-related projects and programs.
The proposition specifies that the money be spent in the following manner: $520 million on clean drinking water;
continued on page 8
CEC Finds GHG Cap Hiking Fuel Prices But Advisors See No ‘Red Flags’
State energy officials are estimating that the inclusion of transportation fuels under the greenhouse gas (GHG) capand-trade program since Jan. 1 has caused prices in California to rise more than they have in neighboring states that do
not have a carbon pricing policy but members of a state advisory panel say the estimates raise no “red flags.”
Gordon Schremp, senior fuels analyst for the California Energy Commission (CEC), told members of a special state
petroleum market advisory panel Feb. 10 that various data collected since Jan. 1 show that the GHG cap appears to have
caused gasoline prices to be about 10 cents higher and diesel prices to be about 13 cents higher than if the policy was
not in effect.
The data include price comparisons between California and neighboring states such as Washington, Arizona,
continued on next page
INSIDE
AIR QUALITY: Lawmaker Seeks To Fix Solar, Carpool Programs After Audit Faults Data ...........3
ENERGY: Bill Would Tighten Power Plant GHG Standard, Extend It To Peaking Units ................7
CEQA: State Fracking Environmental Review Faces Suit For Lack Of CEQA ‘Project’ ................9
LITIGATION: California, Other States, Environmentalists Defend EPA In Climate ESPS Suit ....12
Oregon, Nevada, as well as states with comparable fuel types such as Texas and Illinois. The estimates also include the
assumption that a ton of GHG credit under the cap-and-trade program costs $11.80, according to the presentation. The
presentation is available on InsideEPA.com. See below for details. (Doc. ID: 178853)
The difference is on the high end of what state officials estimated would likely happen under normal market conditions. The California Air Resources Board (ARB), which administers and enforces the state’s cap-and-trade program, has
estimated that the inclusion of fuels under the GHG cap should not cause gas prices to rise by more than 10 cents per
gallon.
But oil industry representatives have warned that the GHG policy could cause gas prices to rise by between 15 and
75 cents per gallon.
Members of the market advisory panel this week said the price data raise no “red flags” that the policy is having a
significant economic impact or that the oil industry is using the GHG program to manipulate prices, as some Democratic
lawmakers and consumer advocacy groups have feared and have called on state officials to be watchful for.
“I don’t see any red flags yet to show there’s anything to cause us to have significant alarm that we have a real
problem,” said James Sweeney, director of the Stanford University Precourt Energy Efficiency Center and chairman of
the state’s Petroleum Market Advisory Committee, during a Feb. 10 meeting. “Maybe we will see something in the next
six months or year” that could be problematic, he added.
Severin Borenstein, a professor at the Haas School of Business Economic Analysis and Policy Group at the University of California-Berkeley and a member of the panel, agreed, saying that the data are so limited at this point that it is
merely a rough estimate of what has happened thus far under the policy.
“I just don’t want reporters to walk away saying that, sure enough, we know exactly what’s happened,” Borenstein
said. It’s fairer to say that officials have a vague inclination to know what’s happening, he added.
Nevertheless, members of the panel agreed to seek more resources and time to delve further into the question around
the extent to which the GHG cap policy will cause California fuel prices to rise.
Borenstein said the panel should not investigate merely in response to individual events that may contribute to fuel
price spikes — such as a refinery closure or accident — but perhaps more importantly if prices rise significantly over the
course of a year, for example.
Last month, a group of top Democrats in the state Senate pressed Attorney General Kamala Harris (D) to
closely monitor gas prices for possible market manipulation, charging that the oil industry may seek to hike prices in
order to falsely claim that the increases are due to the GHG cap. These concerns were first raised the previous month by
the Consumers Union in a letter to the advisory committee (Inside Cal/EPA, Jan. 16).
Industry representatives last month downplayed the need for any monitoring. “Individuals who have suggested the
petroleum industry be investigated or monitored in connection with retail fuel prices apparently have not been watching
the retail gasoline and diesel markets in California,” said Catherine Reheis-Boyd, president of the Western States Petroleum Association, in a written statement. “During the period in which the cap-and-trade program was being expanded to
fuels, retail prices for transportation fuels declined dramatically — hardly an outcome that would suggest investigation is
warranted.”
In addition, Reheis-Boyd noted that over the past several decades, “the petroleum industry on the West Coast has
been investigated by government agencies dozens of times and has never been found to have acted unlawfully in regards
to gasoline and diesel price movements. We are confident any new investigation will reach the same conclusion.”
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 Agency Submits Plan To Comply With EPA UIC Program (178851)
„
California Audit Finds Solar, Carpool Programs Lack Accountability (178852)
„
California Officials Estimate 10-Cent Higher Gas Price Due To GHG Cap Impact (178853)
„
California Legislative Panel Outlines State Water Bond Funding (178854)
„
California Lawmakers Introduce Bills For Post-2020 Climate, Energy Programs (178855)
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.
2
INSIDE Cal/EPA - www.InsideEPA.com - February 13, 2015
Lawmaker Seeks To Fix Solar, Carpool Programs After Audit Faults Data
A state assemblyman says he will soon author legislation to require more accountability in how agencies implement
solar power subsidy and clean car decal programs after an audit released this week faulted administrators for failing to
determine whether the programs are improving air quality or benefiting low-income residents.
Assemblyman Gary Gray (D-Merced), who requested the audits last year, told Inside Cal/EPA in an interview that he
likely will author legislation soon to direct state agencies to provide much more specificity about how the programs could
benefit disadvantaged communities, in addition to providing more accountability in general.
The audit findings are contained in a report released Feb. 10 by the California State Auditor — “California’s Alternative Energy and Efficiency Initiatives.” The audit is available on InsideEPA.com. See page 2 for details. (Doc. ID:
178852)
The document found that while California’s eight-year-old solar power subsidy program is on track to meet its goals
for total megawatt (MW) installations by 2016, state administrators are failing to determine whether the initiative has led
to any pollution reductions. In addition, the audit found that the program, which funds both residential and non-residential
projects, will fall far short of its goal for installing solar thermal water-heating systems by 2017.
Data about air pollution impacts are also lacking under the California Air Resources Board’s (ARB) vehicle decal
program that allows certain low-emission vehicles to travel in carpool lanes with just one occupant, the audit finds.
And both programs have failed to compile adequate demographic information about who is benefiting, which is a key
data point for some lawmakers.
The audit was requested last year through the Joint Legislative Audit Committee by Gray, who was chairman of the
panel at that time.
Gray said last year that in addition to determining whether the programs are achieving their goals, he wanted the
audit to uncover the extent to which the programs are being used by residents who are not affluent, considering that costs
of solar power technologies have dropped in recent years.
“I want to ensure the programs are benefiting all Californians and not just those who would have put solar on their
own homes or bought a specific type of car even without any incentive in place,” Gray said during last year’s committee
hearing.
In this respect, the audit finds that “although both programs track geographic information on participants, neither
collects demographic data. Specific to the solar initiative, we found participation to be dispersed geographically throughout the state; however, the limited demographic data that exists shows that participants in the solar initiative tend to be
older, wealthier, and have received more education than most Californians.”
Given “the high up-front costs of installing solar energy systems, it is not surprising that the demographic group
participating in the solar initiative would fit this profile,” the report adds. “Financing such an investment, even after
taking advantage of the solar initiative incentive and federal tax credit, is probably difficult for those with lower-thanaverage incomes.”
As for the carpool decal program, participants “largely reside in the counties that have freeways with carpool
lanes, such as Los Angeles and Santa Clara,” the audit states. “With respect to the decal program, a recent consumer
survey for a related incentive program for clean air vehicles found that although the ages of respondents are somewhat
evenly distributed, most respondents were male and earned $100,000 or more per year.”
Gray says this week that he will consider authoring legislation to implement some of the audit’s recommendations to
improve the programs, as well as to ensure that the intended benefits of “these extraordinarily expensive programs are
focused and accountable. We’ve spent $2.5 billion on the California Solar Initiative and there appears to be no real
oversight or mechanisms in place to see what the benefits are, or that those have gone to areas where they are most
needed.”
Although the audit finds that participation in the vehicle decal program continues to grow, ARB “needs to measure
the decal program’s effect on air quality,” and the Department of Motor Vehicles “needs to conduct periodic cost analyses
to ensure that decal fees cover all program costs.”
The solar installation program also fails to adequately assess air quality impacts, despite a 2010 consultant’s study on
the topic. “Although reductions in pollution emissions are a benefit in and of themselves, the consultant’s study does not
put those reductions in the context of the state’s overall emissions, nor does it show how those reductions have resulted in
measurable benefits to the state, such as cleaner air or fewer health problems,” the audit states.
The California Solar Initiative, created by 2006 legislation, consists of five programs and $2.6 billion in subsidies to
encourage the installation of solar energy systems on residential and nonresidential buildings. The state is on track to
attain one of the central goals of the program — to install 1,940 MW of solar power by 2016, the audit finds. The
program is funded by a surcharge on all customers of the state’s major investor-owned utilities.
The average size of a residential solar energy system installed under the program is about 5 kilowatts, and costs
about $25,350 per residence to install, if purchased, the audit explains. At an October 2014 solar initiative incentive level
of $200 per kilowatt, the participant receives an incentive of $1,000 to offset the installation cost. By taking the Federal
INSIDE Cal/EPA - www.InsideEPA.com - February 13, 2015
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Residential Renewable Energy tax credit, the participant may also claim on his or her federal income taxes up to 30
percent of the solar energy system installation costs less the solar initiative incentive, or about $7,305 for the average
installation, according to the report. Therefore, the net cost of installing a solar energy system is approximately $17,045
as of October 2014.
Another piece of the program — the California Solar Initiative Thermal Program — that provides incentives for
installing solar water-heating systems will not meet its 2017 goal, according to the audit. The initiative has provided or
reserved a total of $37.5 million in incentives for the heaters, representing only 12.3 percent of the program’s $305.8million incentive budget, the audit says.
The state auditor recommends that because the thermal program has not been successful in meeting the goals outlined
in state law, the Legislature should consider whether it wants to continue authorizing the collection of ratepayers’ money
to fund the program, the report says.
To show how air pollution emissions reductions related to the solar initiative benefit the state, the California Public
Utilities Commission (CPUC) should include in future reports the measurable benefits of those reductions, the audit also
recommends.
In a Jan. 22 response letter to the audit, CPUC Executive Director Timothy Sullivan says in part that prior program
evaluation reports have estimated the total quantity of greenhouse gas and air pollutant emission reductions from the
installation of solar photovoltaic systems, in tons or pounds.
Implementing the auditor’s recommendation will require close CPUC coordination with ARB “and the development of a
clear methodology to translate emission reductions into benefit calculations supported by both agencies,” Sullivan adds.
Regarding the vehicle decal program, the audit recommends that the Legislature should require ARB to research
whether there is a relationship between decal usage and a change in the state’s air quality. To ensure that the decal fee is
sufficient to reimburse program costs, DMV should periodically perform a full cost analysis of the decal program and
update the fee accordingly, the audit adds.
ARB did not submit a response letter to the audit.
‘Robust Debate’ Expected Over Climate Bills . . . begins on page one
the targets are achievable and how to allow utilities to meet them.
A coalition of business groups also cautioned lawmakers to proceed carefully as they craft California’s “Second
Generation” climate program.
“Businesses and consumers are now paying increasingly higher bills for our current climate change policies,”
Californians for Affordable and Reliable Energy (CARE) said in a statement. “While we support the current goals, we
have major concerns that the next generation of legislative and regulatory mandates allow businesses and energy providers the flexibility to determine the most cost effective way to meet climate change goals,” said Rob Lapsley, chairman of
the CARE coalition and president of the California Business Roundtable.
“Overly prescriptive policies should be avoided as we do not know what technology or economic conditions will
exist in 2030 or 2050.”
But key Senate staffers suggested they are planning to use the legislation as a starting point for any debate and vowed
to address the industry concerns.
Kip Lipper, a top adviser to Senate President Pro Tem Kevin de Leon (D-Los Angeles), said during a Feb. 10
conference call with reporters that he expects SB 350, the senator’s new bill setting 2030 renewable energy and oil use
targets, to be used as the “beginning of the conversation and dialogue with utilities.”
“We also want to have conversations with folks who are worried about flexibility, to see if we can find additional”
options to determine if the standard is achievable, Lipper said.
While most states are still struggling to craft climate programs to comply with 2020 and 2030 deadlines in U.S.
EPA’s proposed GHG rules for existing power plants, California policymakers are now preparing to develop a new
second generation climate program beyond 2020 targets that were set in the 2006 global warming law, AB 32.
In addition to requiring GHG reductions to 1990 levels by 2020, the state has also created a broad GHG cap-andtrade program, which this year began regulating transportation fuels; a low-carbon fuel standard; clean car programs;
aggressive renewable energy and energy efficiency targets; among other rules.
Some of the post-2020 legislation has already been introduced. Sen. Fran Pavley (D-Agoura Hills), who as an
assemblywoman authored AB 32, late last year introduced SB 32, a bill that requires ARB to approve a GHG emissions
limit for 2050 that is 80 percent below 1990 levels.
ARB is also authorized by the bill to approve interim GHG emission targets to be achieved by 2030 and 2040. Some
lawmakers have introduced legislation to set those interim limits, opposing the position that ARB should do it
administratively.
‘Golden Gate Standards’
SB 350, the centerpiece bill of the legislation introduced this week by de Leon and Sen. Mark Leno (D-San
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Francisco), implements the governor’s “Golden Gate Standards,” dubbed the “50-50-50 benchmarks.” First detailed
in Brown’s inauguration speech last month, the plan seeks to increase renewable energy procurement from 33
percent in 2020 to 50 percent by 2030, reduce petroleum use 50 percent by 2030 and double building energy
efficiency by 2030.
The bill “makes these standards permanent, trackable and enforceable by enacting them into law and building on the
accountability mechanisms already in existence to ensure they are fully implemented,” states a background paper on the
legislation. “Each of these standards are added to existing clean air, clean energy, and climate related statutes that have
been implemented for years.” Relevant documents are available on InsideEPA.com. See page 2 for details. (Doc. ID:
178855)
The bill would increase the state’s current renewable portfolio standard (RPS) from 33 percent by 2020, to 50
percent by 2030. The standard will be implemented by the California Public Utilities Commission (CPUC) for the
private, investor-owned utilities and by the California Energy Commission (CEC) for municipal utilities, following
current law.
“Each utility submits a procurement plan showing it will purchase clean energy to displace other non-renewable
resources,” the paper states. “Each state agency then reviews the plan, ensures it complies with the law and approves the
plan.”
In a separate CEC background paper, the renewables target can be reached in several ways, including: a new utility
procurement requirement that focuses on optimizing clean energy technologies, efficiency and demand management
programs according to costs and system benefits; a new procurement requirement to increase renewables beyond 33
percent, including allowing for rooftop solar and better coordination with Western states and Baja California to maximize
renewable energy production and better balance production with demand; and a clean energy standard requiring reductions in GHG emissions of electricity sold in California based upon the loading order.
Lipper, the de Leon adviser, said during the conference call that he expects extensive discussions in the coming
months about how utilities would go about meeting the 50 percent renewables standard, adding that current law already
provides a significant amount of flexibility.
The 50 percent reduction in petroleum use also will be implemented using existing laws and financial resources, with
a plan being developed by ARB. Under current law, ARB must reduce pollution in order to achieve state and federal
ambient air standards. Current law requires the board to adopt standards for vehicles and fuels to achieve clean air, the
legislation background paper says. “This measure simply ensures those actions will achieve a 50 percent reduction in
petroleum by 2030.”
ARB says that production, refining and use of petroleum accounts for nearly half of GHG emissions, 80 percent of
smog-forming pollution, and over 95 percent of cancer-causing diesel particulate matter, the paper says. ARB also notes
that oil dependence costs the state $33 billion-$55 billion annually, “and that reducing petroleum use and improving
vehicle efficiency will cut costs and improve California’s economic productivity and competitiveness.”
ARB Analysis
The paper points to an ARB analysis showing one pathway toward the goal could include reducing growth in vehiclemiles traveled to 4 percent; increasing on-road fuel efficiency of cars to 35 miles per gallon (mpg) and heavy-duty trucks
to 7 mpg; and at least doubling the use of alternative fuels such as biofuels, electricity, hydrogen, and renewable natural
gas.
SB 350 creates the new target and authorizes ARB to write regulations to meet the target, Lipper said during the
press conference call.
Lipper said that SB 350 will “clearly” trigger a “robust debate” about whether the 50 percent reduction in
petroleum use can be met and how. “We think ARB has a number of tools in the toolbox” to move toward meeting
the goal, he said.
For example, ARB has the ability to adopt specifications for fuel, efficiency standards for cars and, along with other
agencies, the authority and funding to promote less traffic and less pollution through more compact development under
the 2008 state law, SB 375, Lipper said.
SB 350’s call for a 50 percent increase in energy efficiency in buildings will be done through the use of existing
energy efficiency retrofit funding and regulatory tools already available to state energy agencies under existing law, the
paper says. The bill also requires state energy agencies to plan for and implement those programs in a manner that
achieves the energy efficiency target.
The paper notes that California under current law has energy efficiency standards for new buildings and appliances,
but that “implementation challenges include the lack of enforcement mechanisms and accountability.”
SB 350 “gives energy agencies the authority to review and revise our state’s energy efficiency programs to marshal
the funds and regulatory actions necessary to reach this target.”
Another measure in the Senate leaders’ clean energy and climate change package unveiled this week is SB 185 by de
Leon, which would require the state’s two largest public employee pension funds to divest from companies involved in
coal mining and combustion. Specifically, the funds over the next 18 months would have to divest from companies with
INSIDE Cal/EPA - www.InsideEPA.com - February 13, 2015
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50 percent or more of their facilities involved in the mining or the burning of coal, Lipper said.
The other bill included in the package is SB 189 by Sen. Ben Hueso (D-San Diego), which would create a new
Senate Committee on Maximizing Jobs and Economic Growth. The panel would “advise and inform state clean
energy and climate actions that ensure maximum job creation and economic benefits to all Californians,” the paper
says.
Quality Of Water Central In UIC Debate . . . begins on page one
concerns that the state agencies are not providing enough time to complete the new regulations and other elements of the
compliance strategy, potentially meaning that companies could be forced to close wells or reduce production.
Last year, EPA required state agencies to submit by Feb. 6 a plan to address the results of a 2011 EPA audit and
2012 review of the UIC rules, which found numerous deficiencies with the state’s program, including that officials
may have allowed drillers to inject wastewater into “non-exempt aquifers,” potentially posing a threat to valuable
drinking water supplies in violation of the Safe Drinking Water Act (SDWA) and EPA’s rules (Inside Cal/EPA, Jan.
16).
In their Feb. 6 response, officials with the Water Resources Control Board and Department of Conservation’s
Division of Oil, Gas & Geothermal Resources (DOGGR) told EPA Region IX that they plan to bring the program into
compliance with federal requirements, including via the development of a suite of new rules, a phaseout of wastewater
disposal wells that are considered a threat to drinking water supplies, and the elimination of permits for wells that cannot
qualify for exemptions from the UIC program. The plan is available on InsideEPA.com. See page 2 for details. (Doc. ID:
178851)
The WRCB-DOGGR compliance plan in part will use a combination of administrative mechanisms to ensure
that existing and new injection into non-exempt aquifers and 11 aquifers that have historically been treated as exempt “is
either phased out or covered by an aquifer exemption, and that any threats to drinking water or other beneficial uses of
water are urgently addressed,” the plan states.
DOGGR will advance a rulemaking to “codify a wind-down schedule that provides transparency to the regulated
community and the public at large,” the letter states. The schedule will provide for the phased elimination of new and
existing injection into aquifers that have not been approved as exempt by EPA by Feb. 15, 2017.
New injection “will be allowed only if strict criteria are met, and, like existing injection, will have to cease if no new
exemption has been timely obtained,” the letter adds.
DOGGR, in consultation with WRCB, “will issue administrative orders to address specific circumstances where
injection poses a threat to drinking water or other beneficial uses of water.”
The state agencies will also review roughly 2,500 wells that have potentially been injecting into non-exempt
“underground sources of drinking water” (USDW) zones, in addition to the 11 aquifers that have been identified as
“historically been treated as exempt,” according to the plan.
Of the total, 532 are water disposal wells and 2,021 are enhanced oil recovery (EOR) wells, where processes such as
steam flood, cyclic steam, water flood, and natural gas injection are used to increase the extraction of oil. The EOR wells
are separated into categories: those that inject into areas with total dissolved solids (TDS) less than 3,000 micrograms per
liter (mg/l) — 503; those with TDS between 3,000 and 10,000 mg/l — 1,327; and those for which the TDS is under
review — 157.
The standard water disposal wells are similarly separated into categories: those with TDS less than 3,000 mg/l (176);
TDS between 3,000 and 10,000 mg/l (282); and those where the TDS is under review (32), the plan says.
The TDS is critical in terms of defining whether water in an aquifer is potentially useable as drinking water or other
beneficial purposes, such as irrigating crops.
State officials and oil industry representatives generally indicate that aquifers with TDS more than 3,000 mg/l contain
water that is not beneficial or useable for drinking, unless it is treated.
Environmentalists, on the other hand, cite EPA’s definition under the SDWA that water in aquifers with TDS of less
than 10,000 mg/l can be treated and used for beneficial uses.
Andrew Grinberg, oil and gas program manager for Clean Water Action, asserts that the state agencies have identified “over 2,000 wells that may be impacting drinking water, yet regulators continue to allow injection into groundwater
that should be protected by law,” according to a Feb. 9 press release. “This is a massive failure to implement the SDWA
and EPA should intervene immediately due to the lack of state enforcement.”
But during a Feb. 9 conference phone call with reporters, DOGGR chief Steve Bohlen said the environmentalists continue to exaggerate the number of injection wells that could potentially contaminate supplies of drinking
water.
For example, he said the 2,021 EOR wells are injecting into formations that contain significant amounts of oil.
“When water has oil in it, we tend to not want to drink it,” Bohlen said.
So that leaves 532 wells at issue, which are the Class II UIC water disposal wells, he said. Out of that number, about
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INSIDE Cal/EPA - www.InsideEPA.com - February 13, 2015
109 are idle, he said. There are 87 active wells in the so-called 11 aquifers whose exemption from the SDWA has been
“confused,” Bohlen said.
“We think the documents show, in fact, that they were exempted by EPA. But legislation does allow for aquifers
to be revisited to consider their exemption status.” The state agencies have agreed to revisit the status with EPA, he
said.
Further, Bohlen claimed that wells disposing Class II fluids, or produced water from oil wells, into aquifers that are
sub-3,000 TDS “are not pristine,” but do contain water of a high quality. “But the water would need to undergo some
considerable treatment to be actual drinking water,” or water defined as useable for beneficial uses, he said. Some of this
water contains high boron and arsenic levels and is not potable, he added.
An environmentalist points out that an EOR well still needs an EPA-approved exemption from the UIC
program to operate. “They can get an exemption based on the presence of hydrocarbons, but until EPA makes that
determination, if the salinity of the zone is below 10,000 TDS, it is still an ‘underground source of drinking water’ as
defined by EPA,” the source says.
The environmentalist acknowledges, however, that “it is true that those wells are probably less likely to impact
drinking water sources than the disposal wells located in high quality aquifers.”
Meanwhile, oil industry representatives are generally supportive of the plan and point out that there has been no
contamination of water supply wells by oil and gas injection activities. However, the industry is concerned that some of
the tasks the state agencies are undertaking may take longer than projected.
“The timelines to address production in non-exempt aquifers are aggressive and we continue to be concerned that
DOGGR and WRCB may not be able to meet them,” states the Western States Petroleum Association (WSPA), in a Feb. 9
press release. “If they are not met, operators would be put in the untenable situation of having to shut in wells or reduce
production.”
In addition, the state agencies indicate they will begin the process of developing regulations in April 2015 to effectuate the “wind down” of production in these aquifers, WSPA points out. “However, the response is unclear if this will be a
standard rulemaking. Additional clarity on the rulemaking process would be much appreciated California energy producers.”
An EPA Region IX spokesman says this week that the agency has received a copy of the state’s program compliance
plan and “will review it over the next few weeks. EPA will then work with the state to ensure that the plan contains
actions that will bring their program into compliance with” the SDWA.
Bohlen said during the press conference call that he “believes” EPA will approve the state’s compliance plan and not
seek further actions or intervene to close wells or otherwise step up enforcement, noting that the agencies have had
numerous discussions in recent months about setting a satisfactory path forward.
Bill Would Tighten Power Plant GHG Standard, Extend It To Peaking Units
A bill introduced this week by a leading senator proposes to overhaul the state’s greenhouse gas (GHG) emissions
performance standard (EPS) for base-load power plants by tightening the standard and extending it to all “secondary
generation” power plants, such as “peaker” units that are generally operated in short spans during times of high electricity
demand.
The bill, SB 180 by Sen. Hannah-Beth Jackson (D-Santa Barbara), is likely to spark lively debate in the coming
months and could be strongly opposed by both municipal and investor-owned utilities.
The current EPS, enacted in 2006 by SB 1368, requires state energy regulatory agencies to limit long-term investments in base-load generation by state utilities to power plants that meet the EPS, which is set at 1,100 pounds of carbon
dioxide (CO2) per megawatt-hour (Mwh).
The EPS is intended to encourage development of power plants that minimize GHG emissions and to phase out
utility reliance on out-of-state coal-fired power. While long-term contracts that had already been signed by utilities for
coal-fired power before the enactment of the EPS are allowed to be fulfilled, “investments” by the utilities in those plants
in the following years are subject to the EPS.
Introduced Feb. 9, SB 180 proposes to replace, on July 1, 2017, the current GHG EPS for base-load generation with
a GHG EPS for “primary generation and secondary generation.” The initial EPS for primary generation must “establish a
rate of emissions of GHGs that is 80 percent lower than the permissible rate of emissions of GHGs for base-load generation in effect as of Jan. 1, 2015,” the bill adds. And the commissions must update their respective EPS levels every five
years based on new technology.
Specifically, the California Energy Commission (CEC) by June 30, 2017, is required to establish a GHG EPS for all
primary generation of local publicly owned electric utilities, and a separate standard for secondary generation. CEC is
required to consult with the California Air Resources Board (ARB) to develop the two new EPS.
Secondary generation is defined in the bill as “electricity generation from a power plant that is designed and intended
to provide electricity at an annualized plant capacity factor of less than 15 percent and at least 2 percent.” SB 180
INSIDE Cal/EPA - www.InsideEPA.com - February 13, 2015
7
requires the California Public Utilities Commission (CPUC) to undertake the same rulemaking by the same schedule to
establish two new EPS for “load-serving entities,” mainly investor-owned utilities.
SB 180 requires that the GHG EPS for primary generation and secondary generation be established at the lowest
level that CEC and CPUC “determine to be technologically feasible without putting reliability of the electrical grid and of
electric service at risk,” the bill states.
The bill is raising significant initial concerns among representatives of municipal utilities.
“This appears to be a command-and-control measure that’s kind of creating new mechanisms for the reduction of
both base-load and peaker plant emissions . . . on top of already a [GHG] cap-and-trade system” in the state, says one
utility source.
The provision calling for the GHG EPS for primary base-load power to be 80 percent lower than what is in effect
now is particularly troubling, the source says, because it appears Jackson is misinformed about what types of technologies
are available to cut emissions.
“The words in print suggest that for both peaker and base-load power . . . when we retool it, we would have to retool
to such a degree of efficiency that is nonexistent now,” the source adds. Even if the requirements are phased in, meeting
such a standard would “cost a ton of money,” on top of the fact that “we have a cap-and-trade program that already
requires emissions to be reduced.”
A spokeswoman for Jackson declined to comment further on the bill, noting that staff is working on a fact sheet for
the measure that is expected to be circulated soon.
WRCB Details Water Bond Funding . . . begins on page one
$1.5 billion on protecting rivers, lakes, streams, coastal waters and watersheds; $810 million on regional water security,
climate and drought preparedness; $2.7 billion on statewide water system storage; $725 million on water recycling;
$900 million on groundwater sustainability; and $395 million on flood management, according to a committee
background paper for the hearing. Relevant documents are available on InsideEPA.com. See page 2 for details.
(Doc. ID: 178854)
The Water Resources Control Board is responsible for allocating about $2.1 billion of the total provided by Prop. 1.
Marcus explained that the board will spend the money as follows: $260 million for safe and affordable drinking water
projects targeted at small, disadvantaged communities; $260 million for wastewater treatment projects targeted at small,
disadvantaged communities; $625 million for recycled water projects; $200 million for “multiple-benefit” stormwater
projects; and $800 million to prevent or clean up contaminated groundwater.
“We are going to be able to help a lot of people, in ways that we have not had the tools to do so before,” Marcus told
the legislative committee. The projects will help “a lot of people in the real world and real problems that we’re going to
see solved or at least made more bearable in communities across the state.”
However, only a fraction of the total Prop. 1 funding for WRCB is proposed to be spent during the 2015-16 fiscal
year, according to the Brown administration budget plan released last month.
According to the committee background paper, WRCB is proposed to receive $66.3 million for wastewater treatment; $69.2 million for safe drinking water in small disadvantaged communities; $600,000 for stormwater management;
$131.7 million for water recycling and treatment technology projects; and $600,000 on groundwater contamination
cleanup.
WRCB will use existing spending guidelines, criteria and programs to disburse the funding for the drinking water,
wastewater and recycled water projects, with the board planning to release draft funding guidelines in March and finalize
them by July 1, Marcus told the lawmakers.
But for the stormwater and groundwater cleanup funding programs, “we’re going to need more time to work
with the stakeholders to develop program guidelines and criteria,” Marcus said, adding that the proposed 2015-16
fiscal year budget contains new funding for additional staffers, with the intent to allocate Prop. 1 funding in the
2016-17 fiscal year.
While Marcus said the Prop. 1 funding is considerable and critical, she said much more money will be needed to
address the state’s numerous water-related problems.
“The overall investment needs for water infrastructure in California are enormous,” she said. “So the challenge for us
is going to be how do we leverage these bond funds to get the most done with each dollar. We still have a huge
affordability issue for small, disadvantaged communities when it comes to dealing with operations and maintenance, and
we’re going to need some kind of new funding source if we want to tackle that issue.”
8
INSIDE Cal/EPA - www.InsideEPA.com - February 13, 2015
State Fracking Environmental Review Faces Suit For Lack Of CEQA ‘Project’
California’s sweeping environmental review of hydraulic fracturing and other oil and gas well stimulation projects in
the state faces a potential suit from environmental groups who argue that the review lacks a defined “project” for analysis
as required by the California Environmental Quality Act (CEQA), according to informed sources.
How the state regulates fracking and other well stimulation treatments is being closely followed by numerous
stakeholders around the country, in part because the state is home to the Monterey Shale formation, which experts say
holds billion of barrels of potentially recoverable oil, and because the state is implementing first-time rules for acidization
and other well stimulation treatments in addition to regulating the fracking process.
The state’s Division of Oil, Gas & Geothermal Resources (DOGGR) Jan. 14 released its draft CEQA environmental
impact report (EIR) for well stimulation treatments in California, which was required by SB 4, the 2013 state law requiring sweeping first-time fracking rules, including requirements for specific permits and groundwater management plans.
The department held public hearings on the draft EIR this week in Ventura and Los Angeles, and plans to hold
additional hearings in Oakland, Sacramento, Bakersfield and Salinas.
The draft EIR finds that “most of the significant environmental impacts identified can be reduced to the level of
‘less-than-significant,’ including potential impacts to groundwater and surface water, as well as the threat of seismic
activity,” said Steven Bohlen, the state’s oil and gas supervisor, in a Jan. 14 press release.
With the SB 4 regulations and mitigation measures proposed in the EIR, DOGGR is “confident well stimulation
treatment activities can continue in California without the kind of environmental problems that have plagued well
stimulation treatment in other states with lesser levels of environmental protection,” Bohlen also said.
But an attorney representing environmental groups that oppose fracking says this week that the EIR does not analyze
a specific regulatory agency decision or a specific “project,” as required by CEQA. DOGGR officials are “just kind of
analyzing well stimulation treatment as an informational document, or informational exercise without an actual project,
and that’s not consistent with CEQA,” the source argues.
Environmental groups are likely to argue in any forthcoming lawsuit challenging the EIR that the actual project is the
approval of fracking and other well stimulation treatments, and that DOGGR or other state agencies have never officially
approved such a project under CEQA, the source says.
Further, simply because the state enacted SB 4 and DOGGR has approved new fracking regulations, the “law of
CEQA” has not changed, and the state is responsible for preparing and certifying an EIR for a project, the attorney says.
It appears that state officials are indicating that the SB 4 regulations make up the “project” being assessed by the
draft EIR, “but they’re not the project,” the source claims. This “provides a really unclear project description, and you
don’t know what the decision is. The way CEQA works is you need to have a decision to approve or disapprove, and your
EIR analyzes the impacts of that decision.”
Bohlen, during a Feb. 11 oversight hearing on the SB 4 regulations by the Senate Natural Resources & Water
Committee, explained that the draft document is a “programmatic” EIR, “so it considers the entire program statewide and
it covers what the impact is of this entire program on the state. It doesn’t get down into specific projects.” There will be
additional CEQA reviews required for individual projects in terms of local area conditions that have to be “evaluated and
adjudicated,” he added.
The draft EIR also considers different paths forward, including an analysis of a scenario where the state would not
allow fracking going forward, or only allow it within existing oil and gas reservoirs, Bohlen told the panel. One of the
most important conclusions of the EIR is that the “smallest environmental footprint” would be to allow fracking in the
state subject to the new SB 4 regulations.
This option is the most environmentally protective because not allowing fracking in California would force fuel
providers to import more oil from other locations, which would have greater potential environmental consequences from
the transportation of the fuel by rail or tanker, Bohlen said. But environmentalists have challenged this conclusion.
Environmentalists have also criticized the draft EIR as premature because a separate scientific study on fracking
impacts required by SB 4 will not be completed until July. July 1 marks the day when California’s landmark final regulations on fracking and other well stimulation treatments take effect.
That report is being drafted by the California Council on Science and Technology (CCST), which last month released
the first volume of the effort, “Well Stimulation Technologies and their Past, Present, and Potential Future Use in California” (Inside Cal/EPA, Jan. 23).
The Volume I document “provides the factual basis describing well stimulation technologies, how and where operators deploy these technologies for oil and gas production in California, and where they might enable production in the
future,” according to the report.
Volume II will discuss “how well stimulation affects water, the atmosphere, seismic activity, wildlife and vegetation,
traffic, light and noise levels; it will also explore human health hazards, and identify data gaps and alternative practices,”
according to CCST. And Volume III “presents case studies to assess environmental issues and qualitative risks for specific
geographic regions.”
Those two volumes will not be released until July, the same month DOC is scheduled to finalize its fracking rules.
INSIDE Cal/EPA - www.InsideEPA.com - February 13, 2015
9
EPA Official Again Signals Eased ESPS Targets But Touts Fund To Do ‘More’
U.S. EPA’s top air official Janet McCabe is again signaling the agency is likely to ease controversial interim greenhouse gas (GHG) reduction targets in its proposed GHG rule for existing power plants, but says President Obama’s proposed
$4 billion climate fund for fiscal year 2016 will help achieve emissions cuts beyond whatever is required in the rule.
“However [the guidelines] end up being finalized, in terms of the goals that EPA sets, the time frame that we set,
there’s more that can be done,” McCabe said during a Feb. 5 meeting of the National Association of State Energy
Officials (NASEO) in Washington, D.C.
Her comments provide an early indication that the administration may seek to use the proposed $4 billion incentive
fund for states that go beyond their GHG targets as a way to address concerns that may result if or when EPA softens the
proposed rule’s interim emissions targets, which are shaping up as a premiere dispute between utility officials and
environmentalists.
EPA officials also remain open to accepting proposals to create smaller “modular” agreements between states to
comply with the rule, a tack that California officials have shown great interest in pursuing, she said.
Under the proposed existing source performance standards (ESPS), EPA set interim targets that must be met on an
average basis between 2020 and 2029 before states must meet a final 2030 limit. But many critics charge that the interim
targets are too steep, making it difficult to comply. Many have urged the agency to eliminate the interim targets and allow
states to only meet much more achievable 2030 targets.
But environmentalists strongly oppose this approach, saying it will not result in adequate emissions reductions and
would allow cumulative emissions to increase relative to the proposed ESPS.
In her comments to the NASEO meeting, McCabe reiterated the agency’s desire to create a smooth “glide path” and
to avoid electric grid reliability issues when finalizing its GHG standards.
She said the agency is looking “very, very closely” at the issue, adding that the administration’s request in its fiscal
year 2016 budget for the $4 billion fund reflects that the rule would set a floor for carbon reductions in the power sector.
McCabe cited the interim targets as the issue EPA heard about the most in formal comments and meetings.
The agency has heard “concerns that the interim goals that we set required some states to do almost as much as they
need to do in 2030, by 2020,” she said.
“The idea [in setting the interim limits] was we wanted to make sure that progress was being made, but we recognize
that a lot of these [compliance strategies] do take a lot of time to put in place,” she said. “So the idea of a glide path was
to provide a glide path. We’re certainly looking at this very, very closely.”
She added that some groups have noted potential grid reliability concerns tied to steep reductions early in the ESPS
compliance period. Many of those concerns are “hooked in large part to how quickly reductions would have to happen,”
she said. “The president’s very clear direction to us is that reliability is an issue of first order in finalizing this rule, and
we are committed to that.”
EPA has earlier hinted that it could soften the interim goals, offering two ways to do so in an October notice of data
availability. McCabe also mentioned that notice in an EPA blog post pushing back on the notion that the ESPS would
threaten reliability.
Those signals could reassure utilities that EPA will ultimately soften the interim targets to make it easier for states to
achieve their final 2030 limits, though they could spark concern among environmentalists that the rule’s collective GHG
reductions could be undermined.
Robert Sussman, a consultant and former EPA senior policy counsel, earlier said that he expects EPA to soften the
interim targets somewhat, but that stakeholders have “persuasively argued” that EPA’s renewable energy assumptions can
be increased and there is room for a greater increase in natural gas use.
That means the 2030 targets “are certainly not going to be any less stringent than they are in the proposal, and they
may even be a little more stringent,” he said.
Similarly, the Center for Climate and Energy Solutions (C2ES) in Dec. 1 comments to EPA supported a proposed
change to phase-in targets associated with greater gas use — which would have the effect of softening the interim limits
— but said “we are not suggesting that any change to this effect should loosen the 2030 targets or the cumulative effect of
the Proposal over the course of the next decade.”
C2ES added: “If the interim targets are loosened, we recommend that EPA consider ways to tighten the final targets
such that there is no net increase in cumulative emissions between 2020 and 2030 relative to the Proposal.”
In addition to her comments on the interim targets, McCabe said the agency likely will bless “modular” multi-state
plans that only cooperate on certain issues, such as renewable energy and energy efficiency, and that EPA would issue
guidance on how to evaluate end-use efficiency gains when the ESPS is finalized in mid summer.
EPA’s air chief told the NASEO conference that while states are interested in broad regional compliance plans,
“many states feel like that’s a very big undertaking, to do something that’s very formal,” given that multiple state agencies
and governors would have to reach agreement.
But she said several states have asked “whether we would be open to sort of partial multi-state agreements.”
That approach has been prominently championed by California, which has suggested cooperating with other Western
10
INSIDE Cal/EPA - www.InsideEPA.com - February 13, 2015
states on issues such as renewable generation or efficiency — perhaps through tradable credits — while maintaining
separate state compliance plans and targets.
“Our reaction all along has been we’re open to anything in that regard — as long as we can all follow the strands of
spaghetti when we’re ultimately trying to figure out where reductions have happened and whether states are being able to
successfully implement their plan,” McCabe said.
A group of 10 Western states previously endorsed the concept of using such “modular” agreements for compliance,
and called on EPA to support the approach while not specifically committing to using those agreements in final compliance plans.
During a Jan. 29 event at the Bipartisan Policy Center, Arizona Department of Environmental Quality Director Henry
Darwin said he doesn’t believe “there’s enough time to develop multi-state plans, but I do think we need to do multi-state
collaboration.” He specifically cited the option of trading renewable energy credits, and said states and utilities should
work together to develop a system for such credits.
McCabe at the NASEO event also noted there is “a lot of interest in EPA helping to clarify and set a baseline for
what’s expected for credible” evaluation, monitoring and verification programs for energy-efficiency.
Such verification programs will be needed to help states track how much avoided generation — and thus GHG
emissions — they can take credit for in state plans due to efficiency programs, especially for states using rate-based
targets. “We understand this is absolutely essential foundational information,” McCabe said. “We are committed to
having something out around the time of the final rule on that.” — Lee Logan
OMB May Accelerate WQS Rule Review Ahead Of CWA Jurisdiction Policy
State officials say the White House is pushing to finish pre-publication review of U.S. EPA’s long-awaited final rule
for how states should craft water quality standards (WQS) before it begins review of a final rule to define Clean Water
Act (CWA) jurisdiction, fearing a lack of resources to process two highly controversial water rules at the same time.
A state source says the administration is seeking to avoid simultaneous review of the two regulations, out of concern
that if the White House Office of Management & Budget (OMB) takes up the CWA jurisdiction rule before completing its
work on the WQS policy, one of the regulations will be sidelined due to the limited resources.
To achieve that goal, the water standards rule would likely have to clear OMB by early spring — or the administration would need to delay submitting its jurisdiction regulation for White House review.
“The concern is that the water quality standards rule has no legal deadline. And if it ends up getting behind the
[jurisdiction] rule it just may never come out, because OMB will be overwhelmed with the review process,” the source
says.
The final WQS rule, which EPA sent for OMB review Jan. 8, will update federal regulations governing a wide range
of state water policies required by the CWA, including antidegradation requirements, procedures for allowing variances
from strict WQS, restrictions on waterbodies’ designated uses and the conditions under which EPA will promulgate
federal standards when it determines a state’s rules to be “inadequate.”
The agency is under no statutory or court-enforced deadline to take final action on the WQS rule. But if the administration is determined to release the final rule before addressing CWA jurisdiction it would likely require review to
conclude before the end of winter in order to fit with the timeline EPA has set out for that rule, as EPA Administrator Gina
McCarthy has pledged to finalize the CWA jurisdiction rule in the spring.
EPA and the Army Corps of Engineers, which are jointly developing the jurisdiction rule, had earlier set a selfimposed deadline of April for final action, but at a Feb. 4 joint hearing of the House Transportation & Infrastructure
Committee (T&I) and the Senate Environment & Public Works Committee (EPW), McCarthy said that because of the
volume of comments submitted on the proposal, regulators may miss that target.
“Certainly this spring, but we’re not giving a specific time frame. We’ll take the time to go through the comments,”
she said in response to a question from Rep. Bob Gibbs (R-OH) on the agencies’ timeframe. Spring formally begins in
March and ends in June.
Since OMB review normally lasts approximately 90 days — though in some cases it can take more or less time —
the WQS rule could be released from review no later than the end of March in order to create an adequate buffer for the
jurisdiction rule to be released before summer.
EPA has given little indication of how the rule it eventually releases might differ from the proposal issued in September 2013. That version of the rule drew push-back from both industry groups and environmentalists, suggesting litigation
over the final rule if it is similar to the proposal.
But the state source says the agency appears to be focusing more on states’ comments — which were critical of some
parts of the rule but stopped short of threatening legal action — than on those from other stakeholders.
“Because it’s a state-run program, my understanding is that the Office of Water took the state comments very seriously. They had a working group of states during the comment period to try and hash out some of the concerns when the
agency was free to talk,” the source says. — David LaRoss
INSIDE Cal/EPA - www.InsideEPA.com - February 13, 2015
11
California, Other States, Environmentalists Defend EPA In Climate ESPS Suit
States, including California, and environmentalists are urging a key federal appellate court to dismiss a suit from a
group of 12 other states targeting U.S. EPA’s greenhouse gas (GHG) rule for existing power plants, with the states
supporting the rule arguing that the challenge is “jurisdictionally deficient on numerous grounds,” and that the underlying
argument also lacks merit.
The states’ Feb. 10 brief, filed in West Virginia, et al. v. EPA, which is pending in the U.S. Court of Appeals for the
District of Columbia Circuit, echoes many of the arguments EPA made to dismiss the suit, which seeks to scrap the GHG
proposal by targeting a lapsed 2012 settlement agreement between EPA and the group of states led by New York that was
driving development of the rule.
Additionally, three national environmental groups in a separate Feb. 10 brief warn that a finding in favor of West
Virginia would have “radically disruptive consequences” by opening up a wide gap in the Clean Air Act in which EPA
could not regulate non-hazardous air pollutants from scores of source categories.
Regarding what it sees as procedural flaws, New York says the other group of states lack standing to file the suit
because they were not parties to the agreement. The states also missed a 60-day deadline to file the claim after the
agreement was finalized in April 2012, the brief adds. New York is joined in the brief by California, Connecticut, Delaware, Maine, Massachusetts, New Mexico, Oregon, Rhode Island, Vermont, Washington, the District of Columbia and
New York City.
The suit — one of three challenging EPA’s proposed existing source performance standards (ESPS) — centers on a
thorny legal argument of whether the agency has underlying authority to issue its proposed rule for power plants under
section 111(d) of the Clean Air Act.
West Virginia and other critics say a “literal” reading of the statute prohibits regulation because the section bars
regulation of sources already regulated under section 112 of the law. Power plants are subject to the mercury and air
toxics standards, which was finalized in 2012.
“Under Petitioners’ theory, EPA lost its ability to regulate carbon dioxide from existing power plants under section
111(d) on February 16, 2012, when it promulgated emission standards for hazardous air pollutants from power plants
under section 112,” New York says in its brief, adding that the settlement agreement at issue was finalized two months
later. “Yet Petitioners did not file this action until August 2014, more than two years later.”
The issue is complicated by the fact that the House and Senate passed two different versions of section 111(d) that
were both enacted when the 1990 Clean Air Act amendments were signed into law. The Senate version would explicitly
allow EPA’s ESPS. The House amendment could be read as barring the rule because its “112 exclusion” is focused on
source categories, not pollutants.
But New York argues the House amendment alone could preserve EPA’s authority when “properly read in light of
statutory purpose, structure and legislative history.”
“Petitioners’ argument is based solely on the House amendment. But their reading of that amendment is not compelled, and thus they cannot show that EPA’s proposed reading of the provision is impermissible,” the brief says, citing
the Supreme Court’s Chevron precedent granting deference to agencies’ reasonable interpretations of ambiguous statutes.
The brief says the existence of the Senate amendment provides further evidence that EPA has the authority for its
ESPS, arguing that the amendment cannot be dismissed and that EPA has offered a reasonable interpretation that gives
weight to both amendments.
The environmental groups focus on the merits of West Virginia’s claim, arguing that the House amendment when read
in context “is most naturally read to preserve EPA’s authority under section 111(d) to regulate ‘any existing source for any
air pollutant’ that is not regulated under the” national ambient air quality standards or hazardous air pollutant programs.
They add that the term “regulated” must be read in context, arguing that “EPA could reasonably conclude that
existing sources of CO2 are not ‘regulated under section 112’ because they are not subject to controls with respect to their
CO2 emissions.”
The environmentalist brief is joined by Natural Resources Defense Council, Environmental Defense Fund and the
Sierra Club.
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INSIDE Cal/EPA - www.InsideEPA.com - February 13, 2015