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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. 9 — March 6, 2015
Lawmakers Introduce More Climate Change, Energy Bills As Hearings Near
State lawmakers have introduced dozens more climate change and energy bills for consideration in the 2015-16
legislative session, with the state’s greenhouse gas (GHG) and clean power mandates taking center stage as key policy
committees gear up to hold their first hearings of the year.
Many of the new bills — which aim to dramatically impact state GHG, energy, air, waste and water policies and
programs — were submitted just prior to the Feb. 27 deadline for introducing legislation.
One of the most noteworthy measures introduced last week is AB 1288 (Assembly Speaker Toni Atkins, D-San
Diego), which authorizes the California Air Resources Board (ARB) to continue operating its GHG cap-and-trade
program beyond 2020. Current law, AB 32 of 2006, only authorizes the board to operate a cap-and-trade program
continued on page 4
WRCB To Expand Water Conservation Rules, May Eye More ‘Drastic Actions’
State water board chief Felicia Marcus told lawmakers this week that the board will soon extend and expand
emergency regulations requiring urban water agencies to implement water conservation programs, and may consider “more
drastic” actions in the coming months should the rules prove an inadequate response to the state’s ongoing drought.
Marcus, chairwoman of the Water Resources Control Board, made her comments during a March 4 hearing of the
Assembly budget subcommittee for resources and transportation.
A state water board source said after the hearing that some of the more “drastic” measures on the table would target
regions that use significantly larger quantities of water, such as new requirements for utilities to fix leaks and to implement higher rates on customers.
continued on page 6
New ARB Guidance On GHG Offset Validity Draws Tepid Industry Response
Carbon credit trading professionals are unsatisfied with a new state air board guidance that aims to further explain
the board’s rules governing conformance and invalidation of greenhouse gas (GHG) offset credits under the cap-andtrade program, saying many key questions regarding the suspension of credits and timelines for investigations remain
either unclear or open to interpretation.
A source with the International Emissions Trading Association (IETA), a group that had pushed the board to craft
the guidance, says “outstanding concerns and lack of clarity still remain” even after the board quietly posted the guide
on its website late last month.
The California Air Resources Board (ARB) developed the guidance in response to calls from IETA and others who
continued on page 8
OEHHA’s Perchlorate Goal Spurs Industry To Eye Fight Over Cleanup Limit
An aerospace trade organization is vowing a fight with California over its pending development of an enforceable
cleanup standard for perchlorate, which the state will develop after its health hazard office last week finally adopted a
drinking water public health goal (PHG) for the chemical four years after proposing it.
The industry representatives argue that the 1 part per billion (ppb) PHG for perchlorate is far too low, or stringent,
and threatens to severely restrict water supplies at a time when California is experiencing one of its worst droughts.
But environmentalists, who are frustrated that it took the state four years to finalize the PHG, will be pressing for an
equally stringent cleanup standard based on the new PHG.
The Water Resources Control Board for the first time will be developing an updated maximum contaminant level
continued on next page
INSIDE
AIR QUALITY: ARB Poised To Release New Plan Relaxing ZEV Rule For Medium-Size Firms ..3
LITIGATION: Trucking Group Plans Supreme Court Appeal Of Suit Over ARB Diesel Rule ........ 5
FEDERAL: PG&E Stresses Need For EPA To Change Treatment Of EVs Under ESPS ..............7
CLIMATE: EPA Considers ‘Fallback Options’ For Dropping CCS From Power Plant NSPS .......12
(MCL) for perchlorate, after the Brown administration and lawmakers last year transferred all drinking water regulatory
programs to the board from the Department of Public Health.
WRCB must use the PHG as a starting point when setting the new MCL, which serves as the state’s cleanup standard,
but also consider economic impacts and technological feasibility. The current MCL for perchlorate is 6-ppb.
“Given the impacts the drought is already having on water supplies and costs, the people of California should expect
the regulators to carefully weigh the merits of a new MCL that science clearly shows will offer no public health benefit
against the real costs of making scarce water supplies more expensive and less available,” says a source with the Perchlorate Information Bureau, which is supported by Aerojet Rocketdyne, American Pacific Corporation, ATK and Lockheed
Martin.
The Office of Environmental Health Hazard Assessment last week finalized its 1-ppb PHG for perchlorate in
drinking water, four years after initially proposing the standard and two years after announcing a second comment period
on the level. The new PHG replaces a 6-ppb standard that was set in 2004, according to OEHHA.
“The updated PHG is lower than the previous goal because it incorporates new research about the effects of perchlorate on infants,” OEHHA states in a Feb. 27 announcement. “Like the previous PHG, the updated PHG takes into account
exposure from all sources of perchlorate including food. The lowering of the PHG does not suggest any food is unsafe or
that the public should change its dietary habits.”
Studies conducted by OEHHA scientists and others have revealed that perchlorate can harm the health of infants at
lower levels than the levels that are harmful to healthy adults, the announcement says.
Perchlorate is a chemical that can occur naturally in the environment and also may be released by fireworks, improper handling or disposal of rocket fuel, and various industrial processes, OEHHA says. Perchlorate is known to block
the thyroid’s ability to take in and process iodide, which is a nutrient essential to brain development, growth, heart
function, and other systems. Relevant documents are available on InsideEPA.com. See below for details. (Doc ID:
179430)
PHGs are set solely on the basis of health protection and are not a line between a “safe” level and a “dangerous”
level of a contaminant, OEHHA adds. State law requires that each MCL must be set as close to the corresponding PHG as
is economically and technologically feasible.
Following release of the PHG, focus now shifts to WRCB, which is required to develop a new MCL for perchlorate.
“This is the board’s first time to oversee this process, so Californian’s should expect them to be very thorough,” the
industry source says.
The industry organization argues that OEHHA relied on “untested and unsupportable assumptions and methodologies
to support” its 1-ppb PHG, the source says. “As one example, the agency assumes a 95th percentile one-month-old infant
would consume 280 percent of their blood volume in drinking water every day. This is the equivalent of the average adult
consuming nearly four gallons of tap water daily.”
Secondly, the PHG document “misrepresents the weight-of-evidence for perchlorate health to support its conclusions,” the source says. “OEHHA uses five studies as the foundation of its assessment, four of which are presented with
calculations by OEHHA, not the actual study authors. In contrast, several peer-reviewed studies that do not support
OEHHA’s conclusions are noticeably excluded by OEHHA.”
Apart from the science, the industry representatives argue that the 1-ppb PHG could lead to an MCL that prevents
safe water from being used by municipalities, farms and other key stakeholders. The new PHG “creates new impediments
to access to reliable water supplies, contrary to the governor’s plans for statewide drought relief, without valid scientific
rationale,” a Feb. 27 press release by the industry group says.
“By lowering the PHG, OEHHA sends the message that water supplies considered safe yesterday are no longer safe
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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EPA, Industries Attack Plan For Renewables Development In California Desert (179428)
California Guidance On GHG Offsets Fails To Satisfy Industry (179429)
California Adopts Strict Perchlorate Drinking Water Goal (179430)
Circuit Court Rejects Truckers’ Challenge Of California Diesel Rule (179431)
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 - March 6, 2015
today — a message that is completely at odds with the preponderance of scientific evidence,” the group asserts. “As a
precautionary measure, water purveyors are likely to take wells offline that currently meet the state standard of 6 ppb, but
may have perchlorate levels higher than” the new PHG.
“At a time when state resources — including its water supply — are scarce, we cannot afford to have regulatory
decisions based on anything other the best available science,” the group adds. “To do otherwise puts water supplies at
unnecessary risk without offering any public health benefit.”
Environmentalists, on the other hand, will be pushing WRCB to set a new MCL of 1 ppb or lower, arguing that the
current 6-ppb MCL is inadequate to ensure safe drinking water.
Clean Water Action, for example, opposed the 6-ppb MCL when it was promulgated in 2004 “because we felt it
would let quite a few responsible parties off the hook since levels [at contaminated sites] were just below that level,” says
a source with the group. “At the time, we actually wanted to see an MCL of 1 ppb or less, but that was not possible given
the PHG of 6 ppb. Hopefully this can be revisited in the future.”
ARB Poised To Release New Plan Relaxing ZEV Rule For Medium-Size Firms
State air board officials are poised to release a revised draft proposal to ease requirements under their zero-emission
vehicle (ZEV) mandate applying to several medium-size auto companies, according to sources, opening the door to a new
debate on how quickly several manufacturers would have to attain the program’s production targets.
The regulatory revisions follow a controversial decision by the board last fall to shelve a previous proposal after
agreeing with environmentalists that it overly weakened requirements on the automakers.
The changes to California’s ZEV regulation have direct impacts across the country, as nine other states have adopted
the rules. Under Section 177 of the Clean Air Act, U.S. EPA allows states to adopt California’s vehicle emission standards. There are currently nine Section 177 states that have adopted California’s vehicle rules: Connecticut, Maine,
Maryland, Massachusetts, New Jersey, New York, Oregon, Rhode Island and Vermont.
The ZEV regulation is a key part of California’s strategy to reduce greenhouse gas (GHG) emissions to 1990 levels
by the end of 2020, as well as to achieve its grander goal of cutting GHGs 80 percent by 2050.
In October last year, the California Air Resources Board (ARB) shelved a staff proposal to relax the ZEV mandate
for five companies that are currently defined under the regulation as intermediate volume manufacturers (IVMs) —
Jaguar Land Rover, Mazda, Mitsubishi, Subaru and Volvo. The rule changes affect requirements involving 2018-2025
model-year vehicles.
Several of these companies are expected to move into the large volume manufacturer (LVM) category over the next
few years, which would require production of the larger number of ZEVs that large auto companies are required to
produce and in a much shorter time than IVMs.
ARB Chairwoman Mary Nichols said at last year’s board meeting that the staff proposal went too far in providing the
auto companies with relief under the rule. “In my mind, the fairness to these manufacturers does not outweigh the
purposes of the program, which is to get the vehicles on the road,” Nichols said during the Oct. 23 meeting. “So I’m not
willing to support the proposal staff has put before us.”
Nichols directed ARB staff to return to the board with a modified proposal. An ARB spokesman said last year that
the new plan may not be considered by the board until the summer of 2015 (Inside Cal/EPA, Oct. 31).
A source close to the issue says this week that ARB staff may “circulate” the revised regulatory proposal within a
week. The board may consider the new proposal at its May meeting, the source says.
A second source closely following the proposal says the revised draft may maintain the original number of ZEVs
required to be sold by the medium-size companies, but offer “greater flexibility” to reach the goals.
An ARB spokesman this week did not return a request for comment.
Environmentalists charged at last year’s board meeting that the previous staff proposal would have reduced the
number of ZEVs the companies are required to produce through 2025 by nearly 60 percent.
Under that proposal, the IVMs would have seen a reduction in the amount of ZEV credit they must amass by certain
years. IVMs can also meet their entire ZEV obligations with credits for “transitional” ZEVs, such as plug-in hybrid
electric vehicles, under the plan.
Several of the IVMs are on track over the next three years to cross ARB’s threshold for becoming LVMs, defined as
selling more than 20,000 vehicles annually in the state. This definition was changed from 60,000 vehicles under ARB’s
umbrella advanced clean cars regulation adopted in 2012.
Fearing compliance burdens, the companies sought relief under the ZEV mandate. In July 2014, ARB proposed
several modifications to its requirements to address the concerns. These include changing the definition of an LVM by
adding a second test specifying that a company’s average global revenue over the prior three fiscal years is in excess of
$40 billion, which would be in effect until the 2018-19 fiscal year.
This is intended to allow some of the companies to remain defined as IVMs, which lessens their compliance obligations to sell certain numbers of ZEVs each year. This test would expire in 2020, resulting in manufacturers with sales over
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20,000 being required to produce ZEVs by 2025, according to ARB’s previous proposal.
Staff also proposed to provide IVMs with more lead time to produce ZEVs for sale. Currently the lead time for a
manufacturer is three sets of three-year averages of the number of vehicles the company sells annually. The staff proposed
to add two additional sets of averages. Once a company sells over 20,000 vehicles per year over that span, it must begin
producing ZEVs for sale the following year, according to the previous proposal. It also would have provided companies
with five to seven years of lead time, staff said during last year’s meeting.
ARB staff had also proposed to ease how companies can pool compliance in other states that have adopted the
California ZEV regulation. Under existing rules, companies must deliver ZEVs to the other states prior to 2018 to earn
the flexibility to pool compliance and to earn a reduced transitional ZEV requirement. Under the previously proposed
modifications, IVMs would not be required to deliver ZEVs in these states in 2016 and 2017, and would be given two
additional years to deliver the vehicles to these states.
And in perhaps the most controversial proposed change from last year’s proposal, ARB staff wanted to adjust
ZEV credit-deficit provisions to provide all manufacturers three years to make up deficits instead of one, beginning
in 2018.
But Nichols and several other board members charged that the proposal went too far to relax the regulation. Nichols
told staff to rewrite the proposal to maintain some flexibility for the auto companies to comply but ensure that it “does not
result in any significant, measurable loss of momentum or numbers of vehicles that meet our requirements.”
However, other ARB board members — including Sandra Berg and Ron Roberts — disagreed with Nichols, saying
they felt the staff plan represented a fair and equitable solution. Berg said that according to the current rule, the IVMs in
some cases would be hit with the scenario that 31 percent of the vehicles they sell in 2025 would have to be ZEVs. “I
think it is a fairness issue,” she said at last year’s board meeting. And while the large vehicle manufacturers have had
many years to gear up to comply with the ZEV requirements, in part by offering for sale many more models of ZEVs, the
IVMs have had very little time to prepare, she said.
Matt Solomon, transportation program manager for Northeast States for Coordinated Air Use Management, an
association of state environmental agencies in the Northeast that includes states that have adopted ARB’s ZEV regulation,
said during last year’s meeting that the group supported the previous staff proposal “with some reservation,” arguing that
the provisions would have corrected an “imbalance” in what the IVMs are required to produce compared with large
companies, which was created by amendments made to the regulation in 2012.
New Bills Target Oil, Gas Drilling . . . begins on page one
through 2020. Extending the cap-and-trade program — along with several other major GHG programs — is considered
by supporters as crucial to enabling California to reach its long-term GHG targets.
AB 1288 joins several other major climate change-related bills that were introduced recently, such as SB 32 by Sen.
Fran Pavley (D-Agoura Hills), which requires ARB to approve a GHG emissions limit for 2050 that is 80 percent below
1990 levels. Pavley’s bill also authorizes ARB to approve interim GHG emission targets to be achieved by 2030 and
2040.
And SB 350, the centerpiece of a legislative package introduced last month by top state senators, implements the
governor’s goals of increasing renewable energy procurement from 33 percent in 2020 to 50 percent by 2030, reducing
petroleum use 50 percent by 2030 and doubling building energy efficiency by 2030 (Inside Cal/EPA, Feb. 13).
Prominent new energy sector bills introduced last week include AB 645 (Assemblymen Das Williams, D-Santa
Barbara, and Anthony Rendon, D-Lakewood), which would expand the state’s renewable portfolio standard (RPS) by
requiring that all utilities ensure that 50 percent of the power they supply to customers comes from renewables sources by
the end of 2030; and AB 1094 (Williams), which requires the California Energy Commission (CEC) to conduct an
analysis of electricity consumption by plug-in equipment and set statewide targets for GHGs emitted by the generation of
electricity consumed by plug-in equipment.
Several major bills to bolster clean fuels and vehicles were also introduced. For example, AB 1176 (Assemblyman
Henry Perea, D-Fresno) would establish a new “Advanced Low-Carbon Diesel Fuels Access Program” at ARB, to reduce
GHG emissions from diesel vehicles by providing capital assistance to build fueling infrastructure. The bill would require
that $35 million from the state’s GHG auction revenue be used to fund the program.
ARB and CEC are also required by the bill to allocate at least half the money from their respective funding programs
for alternative fuels and vehicles on projects located in “disadvantaged communities.”
New energy sector bills include AB 1332 (Assemblyman Bill Quirk, D-Hayward), which requires ARB under
the state’s cap-and-trade program to create a GHG offset protocol for renewable energy projects that are able to ramp up
or down during peak energy demand periods.
Another measure seeking to reduce GHG emissions from the energy sector is SB 687 (Sen. Benjamin Allen, DRedondo Beach) which requires ARB, by June 30, 2016, to adopt a renewable gas standard requiring all gas sellers to
provide specified percentages of renewable gas to retail end-use customers. ARB would also be required, by 2017, to
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analyze the lifecycle GHG emissions and reductions for different biogas types and end-uses, according to the measure.
AB 1330 (Assemblyman Richard Bloom, D-Santa Monica) would enact the Energy Efficiency Resource Standard
Act, which would require both investor-owned and municipal utilities to establish energy efficiency resource standards.
The bill requires the California Public Utilities Commission (CPUC) to require that Pacific Gas & Electric Co., Southern
California Edison Co., and San Diego Gas & Electric Co. jointly achieve a reduction in “non-emergency, event-based
demand response of 7 percent by 2020 and 10 percent by 2025, as measured by the sum of their peak demands,” the bill
says.
At least 25 percent of a utility’s energy savings must come from disadvantaged communities identified by Cal/EPA,
AB 1330 also says. Each utility must also file with CEC an annual analysis of the energy savings achieved during the
prior year, divided by the energy consumption in the immediately preceding year, according to the measure.
Several bills also aim to crack down harder on hydraulic fracturing and other oil and gas drilling activities.
For example, SB 545 (Sen. Hannah-Beth Jackson, D-Santa Barbara) requires an owner or operator of a well to file an
application to state oil and gas regulators for approval to drill, and would prohibit any drilling until written approval is
given state regulators. This considerably tightens existing law, which deems such applications approved if state regulators
fail to respond in writing within 10 working days of receipt of the application.
In addition, SB 545 would tighten rules allowing well operators to maintain confidential records of certain wells,
including by shortening the time such records could remain under wraps. “The bill would require that the confidential
period for an offshore well not exceed three years from the cessation of drilling operations and would authorize the
supervisor to extend the period of confidentiality for confidential wells for only six months, upon receiving a written
request documenting extenuating circumstances,” the measure states.
Another bill setting tougher standards on well activities is AB 1501 (Rendon), which requires state air districts to
establish a methane emission standard for well stimulation treatments, such as fracking, and to issue permits to owners or
operators to enforce that standard.
AB 1501 would also require the methane emission standard to include requirements on the owner or operator to
monitor the well stimulation treatment for methane leaks. ARB or the air districts would also be required to install
monitoring stations near any site approved for well stimulation treatments, according to the bill.
Companies would be prohibited from fracking or conducting other well stimulation treatments on wells following an
earthquake of magnitude 2.0 or higher on a well that is within a radius of an undetermined distance from the epicenter of
the earthquake until state regulators complete an evaluation and are satisfied that the treatment will not create a heightened risk of seismic activity, according to AB 1490 (Rendon). The measure also prohibits wastewater disposal wells and
all well stimulation treatments within 10 miles of a recently active fault.
Trucking Group Plans Supreme Court Appeal Of Suit Over ARB Diesel Rule
A group representing California construction trucking companies says it will petition the U.S. Supreme Court to
overturn an appellate ruling that upheld the state air board’s controversial diesel truck and bus emissions regulation on
procedural grounds, with industry claiming the rule is clearly preempted by federal statute.
A federal district court says the lawsuit failed because it seeks to block the California Air Resources Board (ARB)
from implementing the rule, rather than challenging U.S. EPA’s approval of a Clean Air Act state implementation plan
(SIP) that included the regulation — and a federal appeals court recently backed the district court’s decision. But the
truckers plan to tell the high court that even if the rule is allowed under the air law, it is barred under a separate federal
statute.
In the case, California Dump Truck Owners Association v. Mary Nichols, ARB, the trucking group alleges that ARB’s
truck and bus regulation to lower diesel exhaust emissions — which was adopted in 2008 and amended several times over
the ensuing several years — is preempted by the Federal Aviation Administration Authorization Act (FAAAA).
The act prohibits states from enacting regulations “related to a price, route, or service of any motor carrier . . . with
respect to the transportation of property.” The truck group, now known as the California Construction Trucking Association, alleges that its motor carrier members would have to increase prices and alter their routes and services to offset the
costs of complying with the ARB regulation.
The Supreme Court, if it accepts the appeal, will have to analyze how to resolve the fact that two controlling federal
statutes — the Clean Air Act and the FAAAA — are “in conflict,” says a source with the industry group. While ARB’s
rule may be allowable under the Clean Air Act, it violates the FAAAA, “and the courts need to resolve that,” the source
says.
ARB’s regulation generally requires heavy-duty diesel trucks to be upgraded with pollution filters and loweremission engines over certain time periods.
The trucking group filed its lawsuit against ARB in April 2011 in U.S. District Court for the Eastern District of
California, seeking to enjoin ARB from enforcing the regulation.
Several months later, EPA approved California’s SIP for achieving federal air quality standards, which included the
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disputed truck and bus regulation.
As a result, the federal district court in late 2012 dismissed the suit, finding that it no longer had jurisdiction under
the Clean Air Act because EPA would be the rightful target of such litigation through a suit contesting the SIP approval,
and that such a challenge would need to be filed in a federal court of appeals.
The trucking group then appealed the district court’s ruling on procedural grounds to the U.S. Court of Appeals for
the 9th Circuit, arguing that the judge was in error.
But a three-person panel of the 9th Circuit in a March 3 ruling agreed with the district court. “The panel affirmed the
district court’s holding that [EPA’s] approval of the regulation as part of California’s [SIP] divested the district court of
jurisdiction under . . . the Clean Air Act,” the ruling states.
“The panel concluded that the suit, as a practical matter, challenged the [SIP] itself. Because the court of appeals has
exclusive jurisdiction over such challenges pursuant to” the Clean Air Act, “the district court lacked jurisdiction,” says the
ruling. The ruling is available on InsideEPA.com. See page 2 for details. (Doc. ID: 179431)
However, representatives of the trucking group argue this week that legal maneuvers by attorneys with the state
and the Natural Resources Defense Council (NRDC), which intervened on behalf of ARB, thwarted proper judicial
review of the case over the past few years.
“At virtually every step of the way, well-funded environmental groups united with ARB delayed the case and
prevented the courts from hearing the merits of our federal preemption argument,” the group says in a March 4 press
release. “Our argument is simple: Congress enacted a law [the FAAAA] to prevent states from regulating the trucking
industry, and the ARB rule does exactly what Congress has prohibited.”
More disappointing “is the fact that our lawsuit never directly challenged the federal Clean Air Act” or EPA’s
adoption of California’s SIP, the group says. “At the time we sued ARB, the agency was acting under state law —
not federal law as claimed by the NRDC. Once [EPA] approved the SIP, the NRDC waited nearly two months to
inform the court of that fact. When the issue of the Clean Air Act and the SIP was injected into the case, the court
subsequently concluded that a 60-day procedural clock started ticking in which to file a direct petition to the” 9th
Circuit challenging adoption of ARB’s regulations into the SIP and approved by the EPA, “essentially ‘federalizing’
a state regulation.”
Arguing that ARB regulations are EPA regulations “runs counter to the Clean Air Act, which does not give EPA
regulatory authority over in-use equipment,” the group adds.
The industry group has 90 days from the 9th Circuit’s ruling to appeal the case to the Supreme Court. The organization will also simultaneously petition the 9th Circuit for an en banc review of the three-judge panel’s decision, says a
source with the group. However, that request is expected to be denied, the source says
Meanwhile, NRDC representatives argue in a March 4 press release that the 9th Circuit’s decision means that “1
million old, heavy-duty diesel vehicles operating throughout California can continue to be updated to clean up their
pollution.”
WRCB Eyes Rate Hikes To Conserve Water . . . begins on page one
Assemblyman Das Williams (D-Santa Barbara), a member of the panel, asked Marcus what additional conservation measures WRCB is planning in light of new data showing conservation rates in California plummeted in
January 2015 compared with January 2013, after reaching a December 2014 rate that was 22 percent higher than
December 2013.
Marcus said she believes it is likely that residents began using more water for landscaping after the state was hit with
heavy rains in December, “and thought the drought was over.”
WRCB and other government officials are “going to have to redouble our efforts” to convince citizens to significantly lower their water usage, Marcus said.
WRCB likely will update and extend the water conservation emergency regulations at its March 17 board meeting,
Marcus said, with a draft proposal scheduled to be released March 6. The current emergency regulations expire 270 days
after adoption, or April 25, which is prompting the board to extend and expand the rules for another 270 days, the board
source says.
Some of the additional provisions the board will consider for adoption in the emergency rules are requirements on
hotels, motels and restaurants, such as giving customers the ability to specify whether they do not wish to have their
towels or linens washed or for restaurants not to serve water unless requested.
And if there is measurable rainfall in a given location, the emergency rules may specify that there should be no
irrigation during and after the rainfall for at least 24 or 48 hours, the source says.
Marcus said during this week’s legislative hearing that the board may also amend the emergency regulations to
provide more clarity on the number of days people should be watering their yards, and possibly to provide new watering
limits for “outdoor ornamental landscaping.”
Board officials are also “looking at ways to tune up” mandatory minimum penalties for urban water agencies to
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assess for violations of water conservation rules, she said.
In addition to the emergency rules, the board may consider “more drastic actions” in a month or two, Marcus added.
The WRCB source says these actions could include additional requirements for certain regions of the state where
water suppliers have “consistently high usage.” For example, the state board could require that these agencies take actions
to fix leaks on their systems, or direct the agencies to hike rates on customers, with increasingly higher charges for
customers using very large amounts of water.
The source says that northern San Diego County, the Palm Desert area and parts of the Central Valley are examples
of regions that use large quantities of water.
Last summer, WRCB adopted the emergency water conservation regulations, which took effect on July 28, in
response to an April 25 executive order by Gov. Jerry Brown (D) calling on the state to “redouble state drought actions,”
according to a WRCB background paper. Among other things, the order directed WRCB to adopt emergency regulations
“to ensure that urban water suppliers implement drought response plans to limit outdoor irrigation and other wasteful
water practices,” the paper says.
The current emergency water conservation regulation includes prohibitions on certain water uses and requires larger
urban water suppliers to activate “water shortage contingency plans” to a level where outdoor irrigation restrictions are
mandatory. In communities where no water shortage contingency plan exists, the regulation requires that water suppliers
either limit outdoor irrigation to twice a week or implement other comparable conservation actions, the paper says.
Finally, large urban water suppliers must report water use on a monthly basis to track progress.
Williams also questioned Marcus about the status of multi-million-dollar projects to increase recycled water use
statewide, which were spurred in part by separate WRCB regulations adopted last year in response to the governor’s
drought executive order that aim to streamline permitting for such projects.
Marcus responded that the board has a “long history” of quickly funding projects that are “ready to go,” but did not
provide any details about the status of new projects whose developers have submitted applications for funding in response to the special rules adopted last year. She indicated that a substantial amount of activity on recycled water projects
is likely to happen in 2016.
WRCB defines recycled water as water which, as a result of treatment of waste, is suitable for a direct beneficial use
or a controlled use that would not otherwise occur.
Environmentalists last year charged the new WRCB permit for recycled water projects appears to have loopholes that
could threaten water quality.
WRCB is also in the midst of enforcing controversial emergency drought orders forcing water rights holders in the
Central Valley to curtail water diversions for farming and related uses, which some experts believe could trigger lawsuits
against the board.
PG&E Stresses Need For EPA To Change Treatment Of EVs Under ESPS
Pacific Gas & Electric Co. (PG&E) officials are calling for U.S. EPA to change its treatment of electric vehicles
(EVs) under the agency’s proposed greenhouse gas (GHG) regulation on existing power plants, agreeing with other critics
that the additional GHGs created by electricity generation needed to power EVs is more than offset by GHG reductions
achieved by replacing vehicles that run on fossil fuels.
Ray Williams, PG&E’s director for long-term energy policy, told a Feb. 25 seminar in Washington, DC, that a
lack of discussion in EPA’s proposed power plant GHG existing source performance standards (ESPS) regarding
increased electricity demand for EVs is an “issue I’m sure has some legal hurdles” and “one we’d like to see
addressed.”
Williams’ comments — during a Feb. 25 seminar on California’s GHG cap-and-trade program hosted by the economic think tank Resources for the Future (RFF) — add to volumes of similar sentiment expressed by EV advocates,
utilities and environmentalists, who have charged in written comments on the ESPS and in other venues that the ESPS
does not allow states to use GHG reductions from EV programs to comply with the regulation and may even discourage
EV use because they will increase electricity demand and related GHG emissions.
The issue is a special concern in California, which already has the largest EV infrastructure in the nation and is
planning a significant expansion. For example, Gov. Jerry Brown (D) recently called for the state to reduce petroleum use
50 percent by 2030.
EPA’s ESPS sets rate-based GHG emissions targets for each state based on four compliance strategies or building
blocks — improved efficiency at coal plants, increased dispatch of natural gas generation and greater use of renewable
energy and energy efficiency.
The proposed rule requires states to meet their targets by 2030, though the measure also proposes interim goals.
California must reduce its emissions rate from 698 pounds (lbs) of carbon dioxide (CO2) per megawatt hour (CO2/MWh)
to 537 lbs/MWh by 2030. Its interim goal, which is based on the average of years 2020-2029, is 556 lbs CO2/MWh.
While the targets are set based on the blocks, EPA has said that states have flexibility to use a wide variety of
INSIDE Cal/EPA - www.InsideEPA.com - March 6, 2015
7
approaches to demonstrate their compliance.
The agency has also said that states can convert their rate-based targets into equivalent mass-based targets, an
approach that many say is easier, and less costly, to implement than rate-based measures.
But EV and clean-energy advocates are urging EPA to revise its proposed ESPS to account for reductions in total
carbon emissions that EVs create on a net basis through reduced petroleum consumption. Many advocates add that net
reduction in carbon emissions due to EV adoption will increase over time as electricity generation is decarbonized.
EPA officials to this point have maintained that the reduction of transportation GHGs are outside the scope of the
ESPS. EPA sought comment on the potential electric storage benefits of EVs and the extent to which it could reduce the
need for new fossil-fired generation, or provide low-carbon electricity.
EV advocates, however, say that using EVs as a form of grid storage is not a commonly available feature among
models sold in the United States, and is not possible without substantial modifications to the vehicle.
A California-based attorney explains that the fourth “building block” under EPA’s proposed regulation —
allowing states to cite GHG emission reductions from demand-side management and energy efficiency programs — fails
to include a credit for EVs.
“This is particularly a problem in states that choose a mass-based compliance plan,” rather than the rate-based
approach upon which the EPA regulation is based, the source says. EPA’s final guidelines for complying with the regulation “should assure states and electric utilities that increased transportation electrification — and the concomitant
reduction in emissions from other sectors — will not cause a state to be out of compliance with its goal,” the attorney
says.
Regarding the potential legal vulnerability of EPA’s currently proposed regulation, “one could certainly make a case
that it would be arbitrary and capricious not to take into account the above factors such that a state that is reducing GHG
emissions is actually penalized for doing so,” the attorney says.
The source points to a 2007 study jointly conducted by the Electric Power Research Institute and the Natural
Resources Defense Council finding that for nine different scenarios for the year 2050 with varying levels of EV market
penetration, GHG reductions ranged from 163 million to 612 million metric tons.
“If EPA ignores this information, it would effectively be treating a state with a large commitment to electric vehicles
more harshly than a state that made no commitment, even though the former would be doing a better job of reducing
GHG emissions,” the attorney adds. “It would make sense that California and its utilities would be particularly concerned
with this issue because of the state’s commitment to electric vehicles.”
But a PG&E spokesman says this week that EPA could also face legal challenges if it does include an EV credit
under the regulation, because the agency may be prohibited by the Clean Air Act from regulating GHG emission sources
that are “outside the fenceline” of a traditional power plant or other industrial facility.
“The Clean Air Act has traditionally been a source-based regulation, with compliance on the facility and the emissions of the facility,” the spokesman says. “This is generally referred to as ‘inside the fence line.’”
EPA’s fourth building block encompassing demand-side management and energy efficiency programs represents
emissions that are outside the fenceline, the source notes. “For some, the reliance on ‘outside-the-fence line’
solutions may cause concerns. To build electricity as a transportation fuel into the rule may add, incrementally, to
this concern.”
Many experts have also argued that states would have to switch to a mass-based equivalent standard under the EPA
rule to accommodate GHG emission increases resulting from the electrification of the transportation sector.
However, a second California-based attorney closely following the issue disagrees, calling it a red herring.
Critics Say GHG Offset Guide Raises New Questions . . . begins on page one
were concerned about a lack of certainty following the board’s investigation and invalidation of tens of thousands of
GHG offset credits generated at a Clean Harbors, Inc., facility in Arkansas.
ARB’s GHG offset program generally 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 ozone-depleting substances (ODS) that contribute to global warming.
Such credits can be sold to help emitting entities comply with the state’s GHG cap-and-trade 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 GHG cap-and-trade program.
ARB’s rules and policies governing GHG offset credits came under an international spotlight last year when the
board launched an investigation into whether to invalidate 4.3 million offset credits, worth more than $40 million,
generated through the destruction of ODS at the Arkansas facility.
The board launched the investigation because the facility had violated its federal waste disposal permit, a violation of
the board’s protocol.
Ultimately, ARB invalidated only 88,955 of the credits being investigated, concluding that these were generated
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during a narrow window when the destruction facility violated its waste permit (Inside Cal/EPA, Nov. 21).
However, IETA and many credit trading firms expressed their frustration last year with ARB’s investigatory process.
For example, these companies had expected ARB to make an announcement about the investigation results by July 23,
2014, which was approximately 30 days after affected companies submitted comment letters to board officials about the
matter.
This timeline appeared to be spelled out in ARB’s rules governing investigations, the industry critics said.
But ARB did not make a final decision in the matter until November. And an ARB spokesman said last year that the
board “has discretion on when the 30-day period starts, and at this point we are still gathering information, so it has not
yet begun.”
In addition, industry groups — led by IETA — pressed ARB to further clarify whether and when a GHG offset credit
could be invalidated due to possible noncompliance with local, state or federal rules.
In response to these concerns, ARB late last month quietly posted a new guidance document on its website,
“California Air Resources Board Offset Credit Regulatory Conformance and Invalidation Guidance.” The document aims
to “provide additional information on the regulatory conformance requirements that must be demonstrated prior to the
issuance of ARB offset credits, including the role of offset verification bodies in reviewing regulatory conformance.”
The document also provides “additional information on the scope of activities that are subject to review by the
executive officer as part of any offset investigation that may lead to invalidation of ARB offset credits.” The document is
available on InsideEPA.com. See page 2 for details.
But industry sources say they still have further questions. For example, while ARB’s guidance “now makes it clear
that California’s regulation gives ARB the authority to suspend all affected [credits] as soon as the investigation is
announced and before final determination . . . many questions and requests for added clarification from ARB still remain
on this issue,” the IETA source says.
The guidance document also now clearly states that ARB’s 30-day final determination phase is not required to begin
after a 25-day information-gathering phase, as many companies had previously assumed, the source says. “Thus, concern
still remains about the indefiniteness of the time frame of future investigations, during which affected credits will remain
frozen.”
In addition, while it helps that ARB’s document further clarifies the scope of what must be reviewed and what should
be considered for regulatory compliance regarding the integrity of credits and project activities, it does not help clarify
what is “material” in terms of compliance issues, the source says. For instance, there is “still no clarity or determination
that an administrative or minor compliance issue,” such as missing a paperwork deadline for project equipment permit,
would be considered a potential basis for invalidation.
“We were certainly hoping for more — and IETA will be encouraging ARB to further address persistent questions on
regulatory conformance and invalidation in future guidance,” or even a frequently asked questions document, the source
adds.
Last year, IETA urged ARB to revise its individual GHG offset protocols to clarify that only the activities in an offset
project area designated to increase the removal of GHG emissions from the atmosphere or reduce or prevent emissions
could potentially lead to an invalidation; clarify that an environmental violation unrelated to the offset project activity is
not grounds for a violation and that only “fully adjudicated” violations that directly affect a certain number of credits can
result in potential invalidation; and specify that only credits arising during a period of actual violation can be subject to
invalidation, rather than all credits arising during the entire reporting period (Inside Cal/EPA, Dec. 26).
An industry attorney closely following the issue adds that the guidance document raises new questions. For example,
one big question spurred by the Clean Harbors investigation is “whether the regulation can be interpreted so that only
those offsets produced after some notice of a violation has been received will be subject to invalidation,” the source says.
“By only invalidating the offsets that were sold after receipt of an EPA inspection report — and prior to the time the final
tanker truck of brine left the site — the Clean Harbors determination suggests just as much; but ARB was very careful not
to set out any hard and fast rule there.”
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INSIDE Cal/EPA - www.InsideEPA.com - March 6, 2015
9
Agencies Under Strong Press To Redo Desert Renewable Power Siting Plan
Wind and solar power companies, U.S. EPA and a number of other key stakeholder groups are all calling on state and
federal officials to substantially revise — if not overhaul — a revised draft plan to expedite and manage how renewable
energy projects are sited and permitted in California’s southeastern desert region.
The dominant theme from wind and solar power industry organizations is that the plan severely and unfairly restricts
areas for projects, while EPA raises concerns that the plan has not adequately reviewed various environmental impacts —
including greenhouse gas (GHG) emissions and climate change effects — and focuses too heavily on large-scale solar
plants in the region.
Meanwhile, some environmentalists and land conservationists fear the plan could fail to adequately mitigate significant impacts to threatened species and the environment, and may contain loopholes allowing developers to build projects
on areas designated as off-limits.
At issue is the draft Desert Renewable Energy Conservation Plan (DRECP) and accompanying environmental impact
analyses, which were released for public comment last September by the California Energy Commission (CEC), California Department of Fish & Game, the U.S. Bureau of Land Management, and the U.S. Fish & Wildlife Service (FWS).
The DRECP maps out preferred areas to develop renewable power in the desert regions and adjacent lands of seven
California counties — Imperial, Inyo, Kern, Los Angeles, Riverside, San Bernardino and San Diego. The plan also
includes mitigation and variance areas.
The plan’s alternatives all aim to establish approximately 20,000 megawatts (MW) of renewable power development
in the area. Depending on the various alternatives proposed in the plan, solar power would make up roughly 12,00014,000 MW and wind would fall in the 4,000-6,000 MW range.
The plan is considered critical for developing renewable power in California while protecting the environment, and
outlines how to streamline wind, solar and geothermal power permitting. It is also designed to help utilities meet the
state’s renewable portfolio standard, which requires that 33 percent of the electricity supplied to customers come from
renewable sources by the end of 2020.
Accompanying the plan is an environmental impact report (EIR)/environmental impact statement (EIS), which aims
to ensure compliance with the California Environmental Quality Act (CEQA) and National Environmental Policy Act
(NEPA), among other state and federal laws that require agencies to assess the potential adverse environmental impacts of
their actions, and to take steps to mitigate any such impacts.
The EIR/EIS covers a “preferred alternative” plan and a “range of alternatives” that are included in the revised draft
plan, sources say.
EPA, in Feb. 23 written comments to the state and federal agencies developing the DRECP, criticizes the plan for
threatening to cause substantial environmental impacts from scaling up large renewable generation projects in sensitive
areas. The agency’s comments suggest that the plan should be reconsidered because it focuses too heavily on utility-scale
solar projects, and that it should instead encourage much more distributed generation technologies — such as rooftop
solar and energy storage — that are increasingly available and dropping in price.
EPA urges the agencies to revise the plan to address several changes since the plan was compiled. First, EPA notes
that the “drop in distributed solar photovoltaic (PV) system prices . . . has been dramatic” since officials began developing the conservation plan. Also, “the rapid deployment of energy storage could prove even more disruptive” because it
could allow for greater amounts of distributed generation onto the grid.
The comments point to California legislation requiring at least 1,325 MW of storage from the state’s three main
investor-owned utilities by 2020, as well as a recent “road map” for deploying such storage on the grid.
While EPA says that Gov. Jerry Brown’s (D) recent pledge to boost the state’s renewable portfolio standard to 50
percent by 2030 “could lead to renewed interest in developing utility-scale renewable energy projects” in the plan’s study
area, it should be noted “that many of the projects in the proposed Plan Area that have completed construction relied, to
varying degrees, on federal loan guarantees or tax credits,” which likely will be reduced in the coming years. “For this
reason, the financial viability of future utility-scale renewable energy projects in the Plan Area is far from certain,” EPA
adds. Relevant documents are available on InsideEPA.com. See page 2 for details. (Doc. ID: 179428)
The agency urges federal and state officials to reconsider those market and policy factors and re-evaluate how much
renewable generation should be deployed in the plan area by 2040, and to conduct periodic reviews every two to five
years to account for changing market conditions and policies.
EPA in its comments on the California plan notes that it, along with environmental groups, had earlier raised concerns about environmental impacts associated with the projects, but that the agencies had created a “more considered,
integrated framework for proposing, siting, and thoughtfully constructing” the projects.
Even so, EPA asks for further analysis of water and air impacts, effects on protected or sensitive lands, as well as a
review of threats to birds from utility-scale solar projects.
EPA also suggests the DRECP authors to assess how the effort would facilitate California’s compliance with EPA’s
GHG rule for existing power plants. Officials should discuss in the final EIS how the plan “would further the goals of the
Clean Power Plan and fit into the State of California’s implementation of that Plan, to the extent that the State’s imple-
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INSIDE Cal/EPA - www.InsideEPA.com - March 6, 2015
mentation plans are known.”
A wind power industry source agrees with many of EPA’s positions — including that large-scale solar projects should
be discouraged in favor of smaller PV plants — and believes DRECP officials should completely rewrite the plan.
“That argument does not directly translate to needing more wind in the desert, but I believe that the further analyses
that they (and we) call for would show that we are going to need more wind energy in the desert, and that the impacts would be
acceptable, particularly in view of the imperative of addressing climate change at reasonable cost,” the source says.
“I would expect that the EPA’s comments, along with those of many . . . counties, the wind and solar industries, and
many of the environmental NGOs, would cause the DRECP agencies to seriously rethink the draft plan,” the source adds.
Solar power industry representatives are also calling for a complete overhaul of the plan, charging it needlessly
restricts areas to develop.
The DRECP “threatens to undermine the agencies’ support for renewable energy development,” states the LargeScale Solar Association, in its Feb. 23 written comments to the state and federal agencies. The plan “largely focuses on
where and how to conserve resources and artificially limits renewable energy development to a fraction of the plan area,
where significant, unconsidered questions about the feasibility of development, apart from biological resource conflict
concerns, loom large.”
Despite the fact that the DRECP has been in development for six years, the solar power group calls on the state and
federal officials to take more time to finalize the plan. When “the future of land use for 22.5 million acres is about to be
written, it is extremely important to get the programs right,” the comments state.
If the agencies intend to make a final decision on the plan in the immediate future, the solar industry group calls on
leaders to select the “no further action” alternative in the EIR/EIS, which would have the effect of leaving current
planning policies and rules in place.
A CEC spokeswoman responds this week that “we’re still docketing, posting and reviewing comments and will let
you know when we have an update on next steps” for the plan.
EPA Defends CCS Technologies . . . continued from page 12
that new coal plants sequester their CO2. If that happens, environmentalists would “be up in arms,” the source warns.
Possible substitute mandates — including for IGCC or USCPC without CCS — would result in plants that “emit an
awful lot of carbon. CCS can get you to zero,” the source adds.
The source acknowledges that DOE Secretary Ernest Moniz has been talking up USCPC plants in recent congressional testimony, rather than the IGCC demonstration plants. “They’re backing away from that a bit. But that doesn’t
mean they’re leaving a whole technology on the cutting room floor.”
In fact, Moniz in recent testimony has stressed that a USCPC plant with partial CCS can achieve the standard set by
the NSPS. For example, Moniz at a Feb. 25 House science committee hearing downplayed the regulatory burden from
EPA’s rule for new power plants, noting that it only requires partial carbon capture. And he suggested there is confusion
in public debate between DOE-funded CCS projects — which push the envelope on the technology with high rates of
carbon capture — and the less-ambitious goals in EPA’s regulation.
“If you look at the proposed EPA 111(b) rule for new coal plants, if you build an ultra-super critical plant, a very high
efficiency plant, which exists, the EPA proposed rule requires only 30 percent capture,” Moniz said.
He added in a Feb. 11 exchange with Rep. Ed Whitfield (R-KY), chair of an energy committee panel, that despite
problems with some of the demonstration projects, the CCS technology is proven. He also stressed the viability of a
USCPC plant, and offered to discuss the technology more with Whitfield, who is suggesting he will introduce legislation
to require EPA to change the NSPS so that a USCPC plant without CCS could comply.
Meanwhile, McCarthy in a Feb. 25 exchange with Rep. Tim Murphy (R-PA), chair of another House energy panel,
acknowledged that the demonstration projects are faltering but also strongly defended CCS’ viability.
Murphy asked her if the agency was considering withdrawing the NSPS due to legal questions and the expense of
CCS, which he said could “bankrupt” a company. In response, McCarthy said the agency is “very confident that use of
CCS technology at the levels we’re proposing will be a viable option.”
However, she also stressed that the questions Murphy was raising were based “on a proposal, not a final” rule, and
she noted the agency would look at all the comments it received — many of which asked it to drop the CCS mandate.
EPA’s proposal — issued in September 2013 though not promulgated in the Federal Register until January 2014 —
includes particularly strong language on why CCS is BSER, rather than a specific coal-fired technology such as super
critical pulverized coal (SCPC), USCPC or IGCC, which the proposal notes emit CO2 at high rates.
“Emission reductions in the amount that would result from an emission standard based on SCPC/USCPC or even
IGCC as the BSER would not be consistent with the purpose of [air act] section 111 to achieve ‘as much [emission
reduction] as practicable’. . . . [I]dentifying CCS partial capture as the BSER would provide for significantly greater
emissions reductions,” the proposal says.
The final rule is slated to be promulgated this summer, alongside EPA’s rules for existing and modified plants.
— Dawn Reeves
INSIDE Cal/EPA - www.InsideEPA.com - March 6, 2015
11
EPA Considers ‘Fallback Options’ For Dropping CCS From Power Plant NSPS
U.S. EPA is analyzing scenarios that would drop its contentious carbon capture and sequestration (CCS) mandate for
new coal-fired power plants under its proposed greenhouse gas (GHG) standards for new power plants, amid growing
agency concern that the rule is legally vulnerable because the technology may not be “adequately demonstrated” as the
Clean Air Act requires since most of the demonstration projects cited in the proposal are stymied.
However, one informed source stresses that the agency has made no decision on whether to walk away from the heart
of the new source performance standards (NSPS), but says a decision — one way or the other — will need to be made
soon. The source says it remains unclear how EPA decision makers would respond to a final NSPS that does not require
partial CCS for coal plants as the agency’s proposal does, and that it is also unclear whether the decision will be made by
EPA or the White House.
“This is a big political question,” the source says. “I just don’t know whether they’re prepared to live with [the] criticism.”
The source says EPA staff have analyzed “fallback options” including ultra super critical pulverized coal (USCPC)
and integrated gasification combined-cycle (IGCC) plant without CCS. “IGCC gets you to a lower number than ultra
super critical but none of them get you to the number that they were at with mandatory CCS,” the source says. “How the
policy makers feel about moving to that option, I have no idea.”
An EPA spokeswoman declined to answer questions about whether agency staff has analyzed scenarios for finalizing
the rule without CCS, only responding, “We are working to finalize the rule by this summer.” But EPA Administrator
Gina McCarthy earlier this week strongly defended the agency’s proposal before House lawmakers, saying she is “very
confident” the technology can be used at the levels the agency is proposing.
EPA’s proposed NSPS sets an emissions rate for new coal plants of 1,100 pounds of carbon dioxide (CO2) per
megawatt hour (lbs CO2/MWh), which it notes can be achieved only by partial CCS. The rate of an IGCC plant without
CCS is about 1,450 lbs CO2/MWh while a USCPC plant emits around 1,700 lbs CO2/MWh.
One industry source says backing away from the CCS mandate is “not an attractive option because [the White House
appears to be] all in for CCS. . . . What I’ve heard would lead me to believe that right now the administration is not ready
to move from CCS for policy reasons,” despite the acknowledged legal vulnerabilities.
The proposal identifies CCS as the best system of emission reduction (BSER) in particularly strong language that
EPA would likely find difficult to walk back in a final rule. The industry source believes the agency would have to
supplement its proposal before being able to finalize an NSPS without CCS.
If the agency does drop the CCS mandate, that could ease some of the legal uncertainties associated with the rule. In
addition to questions about whether CCS is adequately demonstrated, the air law also requires EPA to have a final NSPS
under section 111(b) in place before it can finalize its proposed existing source performance standards under section
111(d), and some sources suggest the agency might be willing to sacrifice some of the stringency in the NSPS in order to
help preserve the ESPS.
EPA also faces a restriction in a 2005 energy law from relying “solely” on projects that receive Department of Energy
(DOE) funding as the basis for new requirements. The agency says its rule is not based solely on those projects, though
that issue is being teed up for litigation.
The informed source says dropping CCS would make legal battles over the NSPS “much less contentious” while not
having much of a market impact now “because nobody’s really building coal. So I think it probably doesn’t change what
people are building, which is primarily combined-cycle natural gas.” But “if we see a dramatic change in gas prices . . .
that would allow for more diverse choices” in the future.
EPA is under growing pressure from some in Congress to drop the CCS mandate. The agency has faced heated GOP
criticism in recent hearings over the fact that DOE-funded advanced CCS demonstration projects, projects that EPA cited
to justify it proposal, are faltering, further undermining the rule.
For example, the Kemper CCS project in Mississippi is facing significant construction delays and massive cost
overruns, prompting agency officials to shift focus from that project to a Canadian one that recently began operations.
However, the relatively small 110-MW Boundary Dam project is a retrofit, rather than a new plant, and, as critics point
out, is not a domestic example.
But Boundary Dam is an example of a non-IGCC CCS project, which could be important because it relies on postcombustion carbon capture rather than pre-combustion carbon capture. The post-combustion technology shows that it is
possible to use CCS technology for the existing fleet, which typically burns coal in a conventional manner without
gasification.
Also, DOE last month pulled the plug on its contribution to the $1 billion FutureGen CCS project. And while EPA
and DOE officials stressed that was solely a funding decision unrelated to the state of CCS technology, sources warned
the project’s demise would legally undermine EPA’s CCS justification.
One CCS proponent says it would be “very good news and very prudent” for EPA to drop the CCS requirement from the
NSPS. “That is an approach that would allow the technology to continue to develop while not imposing an effective mandate.”
However, one environmentalist questions how the agency can consider dropping the heart of its proposal: to ensure
continued on page 11
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