Energy & Environmental Law Blog

Energy & Environmental Law Blog

Analyzing the critical energy and environmental issues of the day

Proposed California Bill to Cap Coal-Generated Electricity and Eliminate Coal-Dependency by 2026

Posted in California

On January 4, 2017, at the start of this year’s legislative session, Assemblymember Marc Levine of Marin County introduced Assembly Bill (AB) 79, which is intended to cap the amount of coal-generated electricity used in California. Under the current version of AB 79, a maximum of 6 percent of electricity consumed in California could be coal-generated by 2018 and a maximum of 3 percent by 2024.  The bill would eliminate the use of coal-generated electricity from California entirely by 2026.

Although not obvious on its face, AB 79 addresses a non-issue in California, because the amount of coal-generated electricity is already almost non-existent. The California Energy Commission has estimated that coal-fired generation is set to decrease to zero by 2026.  As of 2014, the California Energy Commission estimated that California imported coal from only four out-of-state coal-fired facilities.  And by the end of 2016, coal-fired generators accounted for less than 6 percent of the energy used to power California, with about 97 percent of this coal-related energy generated by power plants located outside California.

So why the need for AB 79?

AB 79 has been introduced at a time when many Californians are uncertain whether national policies and trends under the incoming Trump administration – which plans to encourage more coal production and use nationally – could negatively impact California’s progress to address climate change.  Accordingly, the intent of AB 79 may be symbolic; it would codify into law California’s commitment to address climate change by eliminating coal-generated energy sources entirely from the grid.  Importantly, the bill would also prohibit all load-serving entities and local publicly owned electric utilities from entering into any financial commitment to procure coal-fired electricity after 2026.

So while the bill does not mark a change in California’s policies with respect to coal-fired power, it does serve to solidify those policies. AB 79 would serve as statutory protection against any future temptation to revert to polluting sources of energy during times of unexpected service interruptions or unprecedented electric demand that may occur with the expansion of the electric vehicles and the electric transportation industry.  And most notably, it is a step toward protecting California’s climate change progress from any national changes in energy policy.

EPA Proposes Ban on Common Degreasing Chemical TCE

Posted in EPA

Yesterday, EPA announced its first proposed ban of a new chemical under the amended TSCA (Frank R. Lautenberg Act, Pub. L. No. 114-182 (2016)), which, among other changes, mandated  EPA risk assessments of all high-priority substances including chemicals already in commerce. Today’s proposed rule would ban trichloroethylene (“TCE”) for use in dry cleaning and aerosol spray degreasers for both commercial and consumer use by prohibiting its manufacture, processing and distribution. TCE has been commonly used in various degreasers since 1925.

As we previously blogged about (EPA Prioritizes Asbestos for Review Under Newly Revised TSCA and New Amendments To TSCA Invigorate Chemical Regulatory Regime And Empower EPA), under the amended TSCA if a chemical is found to present an “unreasonable risk” to human health or the environment, EPA must take regulatory action within two years to address the identified risks. The rule announced yesterday represents the first time in over 20 years that EPA has proposed restricting a chemical substance under TSCA. The proposed ban is based on a pre-amendment 2014 analysis from EPA which found that TCE posed significant risks to workers. Given that the study had already been performed in 2014, this ban was “easy low hanging fruit” for EPA to implement.

We should expect more bans on previously-studied chemicals in the near future.

EPA Prioritizes Asbestos for Review Under Newly Revised TSCA

Posted in EPA

Yesterday, EPA announced the first ten chemicals to be evaluated for their potential risk to human health and the environment under the new Toxic Substances Control Act as amended by the Frank R. Launtenberg Chemical Safety for the 21st Century Act (the “Act”).  As we previously reported, the Act amended TSCA on June 22, 2016, which is the first significant TSCA overhaul since its 1976 enactment. The Act specifically requires EPA to evaluate all chemicals in active commerce.  The first ten chemicals selected for evaluation are:

  • 1,4-Dioxane
  • 1-Bromopropane
  • Asbestos
  • Carbon Tetrachloride
  • Cyclic Aliphatic Bromide Cluster
  • N-methylpyrrolidone
  • Pigment Violet 29 Anthra [2,19-def:6,5,10-d’e’f] diisoquinoline-1,3,8,10(2H, 9H)-tetrone
  • Trichloroethylene (commonly known as TCE)
  • Tetrachloroethylene (also known as PCE, perchloroethylene or “Perc”)

EPA selected the first chemicals for evaluation from 90 chemicals previously listed on the 2014 Update to the TSCA Work Plan, with consideration given to recommendations from the public, industry, environmental groups and members of Congress. Over the next three years, EPA will analyze whether the chemicals present an “unreasonable risk to humans and the environment,” and a subsequent two years to mitigate any such risk through new regulations.

Asbestos is unique to the list in that it is not a chemical but a naturally occurring mineral that is present in varying forms with distinct characteristics. The use of asbestos in building materials was curbed in the 1980s, but concerns have continued to be raised by organizations like OSHA as to health risks posed by its ongoing use in other products.  However, a 1989 EPA rule banning most asbestos-containing products was overturned by the Fifth Circuit Court of Appeals in 1991.  Since then, although some uses of asbestos are federally banned, and testing is required in certain circumstances, asbestos regulation has been incomplete and somewhat arbitrary (for example in specifying one percent as a demarcation for materials to be regulated).  EPA’s selection of asbestos for priority evaluation may signal its intention to use its new TSCA authority to revisit the prior ban or more carefully evaluate the specific forms of asbestos most likely to pose an unreasonable risk to human health.

FERC Proposes New Market Rules to Better Integrate Energy Storage and Distributed Resources into Organized Markets

Posted in FERC

On November 17, 2016, the Federal Energy Regulatory Commission (“FERC”) issued a Notice of Proposed Rulemaking seeking comments on its proposal to remove barriers to the participation of electric storage resources and distributed energy resource aggregators in the organized wholesale electric markets. If successful, these new rules could unlock huge new market opportunities for distributed energy resources (e.g., rooftop solar, batteries, and smart energy-management software), which could rapidly increase their deployment throughout much of the country.  While the California Independent System Operator already has specific tariff rules allowing for participation of distributed energy resources, other organized wholesale electric markets currently have rules that impede the entrance of these resources into their respective market.

FERC seeks to require each Independent System Operator (“ISO”) and Regional Transmission Organization (“RTO”) to revise its tariff to: (1) establish market rules, i.e. “participation models”, that recognize the operational characteristics of storage devices but accommodate their participation in the wholesale electric markets; and (2) define distributed energy resource “aggregators” as a type of market participant that can participate in wholesale markets by grouping together individual distributed energy devices.

FERC acknowledges that existing tariffs were developed at a time when traditional generation resources (e.g., large coal and natural gas powered facilities) were the predominant market participants.  As a result, traditional generator “participation models” found in the various ISO/RTOs were not designed with the unique characteristics of energy storage resources in mind.

The new ruling seeks to remove barriers in current ISO/RTO market rules (e.g., minimum size requirements and operational performance requirements) that prevent small distributed energy resources from participating in wholesale markets.  In particular, each ISO/RTO would need to develop new participation models to achieve the following:

  • ensure that electric storage resources are eligible to provide all capacity, energy and ancillary services that they are technically capable of providing in the organized wholesale electric markets.
  • incorporate bidding parameters that reflect and account for the physical and operational characteristics of electric storage resources.
  • ensure that electric storage resources can be dispatched and can set the wholesale market clearing price as both wholesale sellers and buyers.
  • establish a minimum size requirement for participation in the organized wholesale electric markets that does not exceed 100 kilowatts.
  • specify that the sale of energy from the organized wholesale electric markets to an electric storage resource that the resource then resells back to those markets must be at the wholesale locational marginal price.

FERC also proposes to require each ISO/RTO to revise its tariff to allow distributed energy resource aggregators to sell capacity, energy, and ancillary services in organized markets. In other words, each ISO/RTO will need to modify its market rules to define distributed energy resource aggregators as eligible market participants under the participation model that best fits the physical and operational characteristics of such distributed resources.

FERC is focusing on aggregators because individual distributed energy resources could, even with new market rules, face physical and/or financial barriers to entry. For example, even with new market rules, a home with rooftop solar may be too small to participate individually or could face significant transactional costs that would outweigh the benefits of participating in wholesale electric markets.

The new ISO/RTO market rules allowing energy resource aggregators to participate directly in the organized wholesale electric markets must include the following:

  • eligibility to participate in the organized wholesale electric markets through a distributed energy resource aggregator;
  • locational requirements for distributed energy resource aggregations;
  • distribution factors and bidding parameters for distributed energy resource aggregations;
  • information and data requirements for distributed energy resource aggregations;
  • modifications to the list of resources in a distributed energy resource aggregation;
  • metering and telemetry system requirements for distributed energy resource aggregations;
  • coordination between the ISO/RTO, the distributed energy resource aggregator, and the distribution utility; and
  • market participation agreements for distributed energy resource aggregators.

FERC has proposed significant limitations on aggregators by authorizing ISO/RTOs to limit the participation of aggregators that are already receiving compensation for the same services as part of another program. In other words, ISO/RTOs will have the ability to prevent aggregators from “double dipping” by receiving compensation for other services such as net metering or demand response in addition to participating in electric wholesale markets.  Lastly, FERC seeks comment on its proposal to require distributed energy resource aggregations to meet the minimum size requirements of the participation model that they use to participate in the organized wholesale electric markets.

Comments on FERC ruling will be due in late-January 2017, 60 days after publication of the NOPR in the Federal Register.  It will be particularly interesting to track the outcome of this FERC ruling given its timing with the Presidential inauguration.  Two of the five FERC commissioner seats are currently open, and it is not clear whether President-elect Trump will nominate individuals who share FERC’s current desire to accelerate the adoption of distributed energy resources throughout the country.

Does Trump Election Boost Children’s Climate Crusade?

Posted in Climate Change

As reported here, Oregon is among a group of states in which groups of school age plaintiffs are suing to force the government to do more about climate change.  On November 10, U. S. District Judge Ann Aiken adopted the magistrate judge’s April Findings and Recommendations in Juliana et al. v. United States to deny the government’s motion to dismiss.

Plaintiffs seek a declaration that U. S. policies and actions have substantially contributed to climate change—even though the government was aware of the climate consequences—and an injunction to reduce greenhouse gas emissions. Plaintiffs allege that the government’s failures violate plaintiffs’ substantive due process rights and violate the government’s public trust obligations.

The judge found that plaintiffs have presented facts sufficient to state a cause of action, stressing that the context of her ruling is a motion to dismiss in which she must assume the truth of the pleadings. In her 54-page opinion, Judge Aiken recognizes and embraces that this case breaks new ground, concluding:  “Federal courts too often have been cautious and overly deferential in the arena of environmental law, and the world has suffered for it.”

In my earlier post, I suggested that the case is not likely to succeed, as climate change is so complex, diffuse and political a problem as to render the case nonjusticiable. Although Judge Aiken was undeterred by these considerations, I still believe that to be true.  Still, did the election of Donald Trump give new impetus to the case?

The president-elect believes human-induced climate change is a hoax perpetrated by the Chinese, has pledged to walk from the Paris Accords and to undo the Obama Administration’s executive orders and rulemakings to curtail greenhouse gas emissions, and has chosen climate change skeptic Myron Ebell to head his EPA transition team. This, combined with a solidly Republican Congress with no inclination to address climate change, makes it pretty clear that the only action we can expect by the federal government is to roll back any forward progress made over the past eight years.

It seems the case to force action is more difficult where the government is appearing to grapple with climate change, as Obama attempted to do despite congressional hostility. Could it make a difference in this case that the government not only takes no action, but denies the overwhelming scientific evidence of rising global temperatures resulting from GHG emissions?  Could the election create a sense of urgency that a court may feel the need to address?  Maybe, but this still strikes me as tough case to sustain.

A more likely result of the election is to see some states pushing harder for some kind of carbon pricing, like a cap and trade program or a carbon tax. Washington State voters just rejected a carbon tax initiative, but the issue is far from dead there.  California has a cap and trade system, and Oregon is expected to take up the issue in next year’s legislative session.  Local environmentalists think the chances of a successful local climate initiative are high.  The election results very likely improve those chances, at least on the West Coast, and perhaps in other regions convinced of the need to act.

The (much!) Higher Cost of Non-Compliance: Federal Civil Penalties Increase

Posted in EPA, Federal

EPA has released an interim final rule with penalty adjustments mandated by a new law (“Interim Rule” or “Rule”). Most importantly, the “catch up” adjustments under the Interim Rule carry quite a wallop for those subject to any of a wide variety of violations (rule available here). For example, the maximum daily penalty for violating the Resource Conservation and Recovery Act (RCRA), which governs treatment, storage and disposal of hazardous waste, was originally $25,000 previously adjusted for inflation to $37,500. But under the Interim Rule’s new increases, EPA can now seek a maximum of $70,117 per day of violation. As it stands today, the Rule applies to penalties arising from violations occurring after November 2, 2015 where penalties are assessed after August 1, 2016. And it is not just EPA hiking the penalties, as we mention at the end of this article, other federal agencies are doing the same.

Why this is Happening – the Legislative Background

In 2015, Congress passed the Federal Civil Penalties Inflation Adjustment Act Improvements Act of 2015 (the Act), which required federal agencies to adjust maximum civil monetary penalties (CMP) to account for inflation. Section 701 of the Act mandated two adjustments

  • First, the Act required an initial “catch-up” adjustment, capped at 150% of the value of each CMP, as of November 2015. Agencies published notice of their “catch-up” adjustments in the form of interim final rules by or before July 1, 2016; and
  • Second, beginning January 15, 2017, agencies must adjust CMPs annually instead of every four years as they previously did. The Act also removed “notice and comment” rulemaking requirements. Instead, agencies will follow annual guidance from the Office of Management and Budget (OMB) on calculating CMP adjustments.

EPA’s Interim Final Rule

Table 2 of the EPA’s Interim Rule identifies over 65 maximum penalty increases across the environmental statutes the agency enforces. Amounts vary, but the Clean Air Act saw the largest hike. In 2014, an operator’s failure to comply with a major stationary source permit could yield a $37,500 maximum penalty. Today, that same violation could result in a maximum penalty of $93,750 per day per violation. Other examples include:

  • Clean Water Act – maximum penalties for violations of an effluent limit increased from $37,500 to $51,570 per day per violation.
  • Emergency Planning and Community Right-to-Know Act (EPCRA) and the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) – maximum penalties for failure to comply with release reporting requirements increased from $37,500 to $53,907 per day per violation.
  • Federal Insecticide, Fungicide, and Rodenticide Act (FIFRA) – maximum civil penalties for violations increased from $7,500 to $18,750 per violation.

The increases apply to civil penalties assessed after August 1, 2016 whose associated violations occurred after November 2, 2015. Violations occurring on or before November 2, 2015, as well as assessments made prior to August 1, 2016, will continue to be subject to the civil penalty amounts previously in effect.

EPA will continue to weigh fact-specific considerations, including the seriousness of the violation, the violator’s good-faith efforts to comply, economic benefit gained by the violator as a result of noncompliance, and a violator’s ability to pay, when determining the appropriate penalty, up to the new maximum.

Civil Maximum Penalties Increase Across Federal Agencies

The Act applies to federal agencies across the board. Therefore, Final Interim Rules published during the summer of 2016 increased CMPs from enforcement agencies including the Federal Trade Commission (FTC), Consumer Financial Protection Bureau (CFPB), Securities and Exchange Commission (SEC), Department of Energy (DOE), Federal Energy Regulatory Commission (FERC), Department of Transportation (DOT), the Federal Aviation Administration (FAA) and many others.

What does this mean for businesses?

Businesses should look to invest in compliance assessments and be proactive in implementing corrective actions because the cost of non-compliance just went up and will continue to do so each year.

Davis Wright Tremaine LLP’s Environmental Partners to Discuss the Resource Conservation and Recovery Act During American Bar Association Webinar 10.20.16

Posted in California, Environmental Quality

Davis Wright Tremaine LLP partners Kerry Shea and Larry Burke to join the American Bar Association webinar on the Resource Conservation and Recovery Act, along with Hope Schmeltzer, Assistant Regional Counsel at the U.S. Environmental Protection Agency, and Thomas Fusillo, Managing Principal at Ramboll Environ.

This webinar will address the management of hazardous waste, solid waste, and universal waste, respectively. Panelists will also discuss the legal requirements of determining whether material is a waste, and then the proper steps to characterize, handle, store and dispose of such waste. The law will be presented in a step-by-step process guiding the participants through the life span of the waste: (1) identifying waste streams; (2) determining if the material is waste; and (3) characterizing the waste as “hazardous” or not.

The webinar will take place on October 20, 2016, from 10:00 a.m. – 11:30 a.m. PT. To join, please register here.

Pennsylvania Federal Court Decides a Novel CERCLA Issue: When Is the Current Owner Not the Current Owner?

Posted in CERCLA

The U.S. District Court for the Eastern District of Pennsylvania issued a decision on an aspect of CERCLA for which it found almost no prior court precedent – the temporal aspect of the term “current owner or operator” – holding that the current owners at the time of suit were not liable for response costs incurred before they took title to the facility. Commonwealth of Pennsylvania, Department of Environmental Protection v. Trainer Custom Chemical LLC, et al.

The Pennsylvania Department of Environmental Protection (PaDEP) had filed suit against a company and its two owners for recovery of cleanup costs expended by the State in addressing a facility owned by the company. The cleanup had commenced when the facility was owned by another company, and virtually all of the costs for which reimbursement was sought related to electrical power paid for by the PaDEP, which the prior owner of the property had failed to pay. Those costs were incurred more than three years before the defendants (i.e., the current owners) purchased the site. The court held that the defendants were not liable for response costs incurred prior to their purchase of the property – that CERCLA intended that the “current owner or operator” was the owner or operator at the time the response costs were incurred, not the owner or operator at the time the suit was filed.

In its ruling, the court noted that it had found no cases directly on point in the Third Circuit, but that the Ninth Circuit had addressed the issue in California DTSC v. Hearthside Residential Corporation. The Ninth Circuit opinion itself noted the lack of any controlling precedent on the issue, but concluded that using the date of response costs to identify a current owner was consistent with the statute of limitations, which begins with the incurrence of costs, and the intent to foster early settlement. The Pennsylvania court agreed that the Ninth Circuit analysis made “common sense” and reasoned that, while CERCLA is a broad statute, “strict liability is not limitless liability.”

That last point is one that countless sophisticated defendants have tried to make in CERCLA actions. And while the defendants in this case may not have been sophisticated in some of their arguments, they convinced the District Court on the issue central to their monetary liability. Alas, they may now have to also convince the Third Circuit Court of Appeals, as the PaDEP has requested certification for an interlocutory appeal.

FERC Seeks Comments on Potential Changes to Review of Mergers and Acquisitions

Posted in Federal, FERC

The Federal Energy Regulatory Commission (“FERC” or “Commission”) has asked for comments on procedures established for its review of mergers and acquisitions pursuant to section 203 of the Federal Power Act (“FPA”). In a Notice of Inquiry (“NOI”) issued on September 22, 2016, the Commission explained that it is seeking to “harmonize” its analysis of its 203 transactions with its market-based rate analysis under section 205 of the FPA.

Among other things, the FERC regulations do not require a utility seeking to engage in a transaction for which its authorization is required under Section 203 of the FPA to submit a horizontal Competitive Analysis Screen if pre-merger business transactions between the merging entities are shown to be non-existent or de minimis. Currently, FERC accepts representations from an applicant that the proposed transaction’s effect on horizontal competition is de minimis if the combined share of post-transaction installed capacity in the relevant geographic market will be relatively small or if the increase in an applicant’s post-transaction installed capacity is relatively small. However, the FERC is considering the development of a more precise definition or test of what is de minimis in determining when a full Competitive Analysis Screen is unnecessary. Accordingly, the NOI seeks comment on whether a bright line market share threshold should be established to determine whether a transaction’s impact can be determined to be de minimis and, if so, how that threshold should be calculated. The NOI also asks for comments on how FERC should analyze so called “serial de minimis” transactions in which an entity makes incremental acquisitions of generating capacity that cumulatively could lead to market power, but where no individual transaction raises a competitive concern.

In addition, the Commission has asked for comments on the potential benefits of expanding FERC’s section 203 analysis to include both a pivotal supplier screen and a market share analysis, similar to the preliminary screens used to evaluate requests for market-based rate authorization, to assess whether the merged entity would have the potential ability to exercise horizontal market power after the transaction has been consummated. The FERC has also asked for comments on whether, if it does so, the pivotal supplier analysis and the market share analysis used to evaluate mergers under section 203 of the FPA should be different from the pivotal supplier screen and the market share analysis used to evaluate market-based rate applications under section 205 of the FPA.

The NOI also addresses the Commission’s potential modification on how it accounts for control of capacity under long-term power purchase agreements (“PPAs”) in its horizontal market power analysis. Currently, if a purchasing applicant entered into a long-term firm PPA to acquire the output of a generating facility, the Commission has generally considered the generation capacity of that facility to be attributed to the purchasing utility’s pre-acquisition market share. If the entity is proposing to acquire ownership of that generating facility, such transactions would be considered to have no adverse effect on competition because there would be no change in the amount of generating capacity controlled by the acquiring entity. However, FERC is concerned about changes in market concentration after the PPA has expired and seeks comments on whether it should use “alternative methodologies” in its review of a section 203 application to account for the capacity associated with long-term firm PPAs in order to increase the accuracy of its market power analyses. For example, the Commission is considering whether to require the applicant to submit a delivered price test analysis showing certain HHI impacts and/or requiring applicants to submit a detailed explanation as to why the PPA’s capacity should be attributed to the purchaser.

Lastly, the NOI asks for comments on whether applicants should submit consultant reports that are prepared for submission to the Department of Justice and/or the Federal Trade Commission. The Commission believes that such documents could be “useful” for additional information such as the relevant geographic market definition or anticipated unit retirements. The Commission has also inquired about potential changes to its regulations governing the grant of blanket authorization for certain types of transactions under section 203 of the FPA.

The NOI is set forth in Modifidcations to Commission Requirements for Review of Transactions under Section 203 of the Federal Power Act and Market-Based Rate Applications under Section 205 of the Federal Power Act, Docket No. RM16-21-000, 156 FERC ¶ 61,214 (2016). Comments on the NOI are due 60 days from the date of publication of the NOI in the Federal Register.

Senate Approves $4.9 Billion for Drinking Water

Posted in Federal, Water Law

Congress in recent years has not really been in the business of solving core public welfare problems like safe drinking water.  Today the Senate, however, has taken a major step forward by passing the 2016 Water Resources and Development Act, S. 2848.  WRDA bills are the annual appropriations bills to shore up the nation’s water service infrastructure.  The Senate bill would provide $9.4 billion for water projects, hydrology and flood control, including $4.9 billion to address aging municipal water systems.

By and large, Americans take for granted that their municipal water supply systems deliver abundant, wholesome and safe drinking water.  Water borne illnesses are rare in this country, and the professionals I know that operate these systems take their jobs seriously and feel the weight of the responsibility.  And yet, there are colossal failures putting public health at risk—like Flint.

The Flint debacle reflects a complete absence of professional water management.  The problem there was a change in water supply, and the failure to add commonly available corrosion inhibiting chemicals to the water to prevent lead pipelines from leaching lead into Flint homes.  What should have been an inexpensive operational measure became a billion dollar pipe replacement project.  And that figure doesn’t include the long-term costs to address health effects of drinking the water, not to mention the cost of a different kind of corrosion, that of the public trust.

But even well-managed municipal water systems, including those that tout the high quality of the supply, can have serious lead problems.   My town of Portland, Oregon, has one of the purest water sources in the country, the Bull Run water shed on Mt. Hood.  The water is so soft, however, that it has a corrosive effect.  Luckily, Portland doesn’t have lead service pipes like Flint, but many older homes have lead solder in their plumbing, resulting in Portland exceeding lead drinking water standards in high risk households and schools.

The Portland Water Bureau is taking steps to address the lead problem, like raising the pH level in the water to minimize lead leaching.  But Portland’s water rates are among the highest in the country, and the cost of maintaining safe water supplies is only going up.  There is a practical limit to how high water rates can go, and communities with fewer resources than Portland struggle to keep up.

This is where the federal government is supposed to step in, to address problems that exceed local capacities to protect the public.  Although a little late in coming, S. 2848 is a mostly bipartisan bill, which if enacted could move the needle in the right direction.  Let’s hope this bill gets through the House and to the President for signing without further delay.

California’s New Climate Change Law Tempered by Uncertainty About Its Cap and Trade Program

Posted in California, Cap and Trade, Climate Change

California Governor Jerry Brown signed Senate Bill 32 last week codifying into law his office’s emission reduction goal of cutting greenhouse gas emissions to 40% below the 1990 level by 2030. By signing this bill, Governor Brown made his prior Executive Order B-30-15 part of California’s overall climate change law by adding a new section to the California Global Warming Solutions Act of 2006 (See California Health & Safety Code § 38566).  As before, the California Air Resource Board (“CARB”) is the state agency charged with ensuring that the new greenhouse gas emission reduction goal is met.

Senate Bill 32 is accompanied by a companion bill, Assembly Bill 197, which passed in late August (though language in each bill prevented either from reaching the governor’s desk without the passage of the other).  As codified, Assembly Bill 197 adds two members of the Legislature to the CARB Board as ex-officio, nonvoting members and creates staggered six-year terms for the voting members of the CARB Board.  It also creates the Joint Legislative Committee on Climate Change Policies to provide oversight for state programs, policies, and investments related to climate change.

Notably, neither bill extends California’s current Cap and Trade program past 2020.  The Cap and Trade program is a preeminent piece of the state’s overall Greenhouse Gas reduction program but it faces an uncertain future. Ongoing litigation challenging CARB’s authority to raise revenue through the program’s auctions of greenhouse gas allowances remains active at various trial and appellate court levels.

The state Cap and Trade program’s uncertainty could place a significant restraint on the effectiveness and viability of Senate Bill 32’s new emission reduction goal. All eyes are turning toward the Legislature in 2017 for a definitive sign that California will continue its Cap and Trade program past 2020.  Despite this uncertainty, California moves forward full steam ahead — the law of the land now requires a 40% reduction below 1990 levels of greenhouse gas emissions by the year 2030.

CPUC Hosts Workshop for New Safety Intervenor

Posted in California, Electric Power, Federal, Rulemakings

Earlier in 2016, the California Public Utilities Commission (CPUC) received approval from the Legislature to establish its own Office of Safety Advocates (OSA) as an effort to expand the participation of safety related intervenors in relevant CPUC proceedings.  This month, the CPUC is hosting a workshop to: (i) allow stakeholders to brainstorm an effective way to establish the OSA, and (ii) discuss opportunities and challenges surrounding the potential participation of OSA in relevant CPUC proceedings. The workshop will be held on September 15, 2016, 1-4:30pm, at the CPUC Courtyard Room, 505 Van Ness Ave., San Francisco, CA.

CPUC Cracks Down on Secrecy of Utility Data

Posted in California, Electric Power, Federal, Rulemakings


For California utilities, ensuring their information stays confidential just got harder. On August 25, 2016, the California Public Utilities Commission issued a decision updating the process for submitting potentially confidential documents to the Commission. The Commission intended for this process to ensure consistency across industries and to expedite Commission review of California Public Records Act requests.

On balance, the new process shifts the burden for preserving confidential documents to the utilities. In the past, utilities would submit data to the Commission either with a marking to show it was confidential, or with the unspoken agreement with Commission staff that certain types of documents were confidential even without a marking. In light of this new decision, utilities now have to mark all documents, specify the reason it’s confidential, and, depending on whether the document is submitted within or outside of a formal proceeding, file a motion or declaration certifying the confidentiality of the documents. Further, if only certain information in a document is confidential, utilities must designate as confidential only that information rather than the entire document.

Moreover, the Commission has “greased the wheels” for handing Public Records Act request, and releasing utility data. The Commission has delegated authority for reviewing requests for confidential treatment of documents to the Commission’s Legal Division, rather than requiring the Commission itself to review and issue and an order regarding the release of potentially confidential information.

While this decision presents a significant challenge for many utilities, this shift in Commission policy is not entirely surprising. In the wake of the San Bruno gas pipeline explosion in 2010, public outcry and litigation cropped up over the Commission’s Public Records Act request process. While trying to balance the requirements of the Public Records Act and its statutory duty to preserve confidential utility data, under Public Utilities Code§ 583, the Commission has seemingly responded to pressure from the public, and shifted towards the Public Records Act side of the scale.

This decision was an interim decision, and the proceeding remains open for further refinement and improvement of the Commission’s processes (e.g. updating General Order 66-C).

“The War Is Over”: Assemblymember Gatto Introduces Bill to Memorialize CPUC Reform Package

Posted in California, Renewables

At an August 11th conference organized by the Advanced Energy Economy, Assemblymember Mike Gatto (D-Los Angeles), Chair of the Utilities and Commerce Committee, and California Public Utilities Commission (“CPUC”) President Michael Picker participated in a panel discussion on CPUC reform efforts.

Gatto declared that “the war is over,” referencing the sparring between the Legislature and CPUC over agency reforms in the wake of numerous CPUC controversies, including improper ex parte communications between regulators and utility executives surrounding the shuttered San Onofre nuclear power plant, the San Bruno gas pipeline explosion, and the Aliso Canyon gas leak.

Gatto explained that utilities are at the forefront of people’s minds at an unusual level, which has motivated the  lawmakers’ reform efforts.  And not just energy utilities — Gatto explained that he received more emails from the public about the Frontier Communications/Verizon merger than both the San Bruno and Aliso Canyon disasters combined.  By having a substantive CPUC reform package, Gatto explained that the Legislature can “hold its head high” and let constituents know that it has heard them and has produced legislation that will move the ball forward.

Gatto acknowledged, however, that reform efforts have been a “distraction” to the CPUC and stated that the time had come to move away from CPUC reform efforts to enable the CPUC to “get back to work” and focus on what it needs to be doing — ensuring that customers have safe, reliable utility service at reasonable rates, protecting against fraud, and promoting the health of California’s economy.

CPUC Reform Package

The day before the panel event, Gatto had released bill language for AB 2903, which is part of a sweeping package of reforms announced in June by Governor Brown, Assembly member Gatto, and Senators Jerry Hill (D-San Mateo) and Mark Leno (D-San Francisco).  As the primary vehicle for reforms, AB 2903 makes changes to CPUC governance, accountability, transparency, and oversight and safety.  (AB 2903, along with the three other bills comprising the reform package will be examined in a subsequent blog post.)  Gatto remarked that he doesn’t think any of the reform measures should be difficult for the CPUC to implement.

President Picker, who was asked by Governor Brown to “fix the CPUC,” expressed support for Gatto’s and the Legislature’s efforts, which he believes are helping to advance this objective.  While the concept of CPUC reform has long been discussed, the challenge from Picker’s perspective is that “no one sees the same thing” when it comes to differing notions of reform.

For example, one major sticking point is the process by which the CPUC conducts rulemakings.  The existing process is quite formal, requiring parties to obtain permission to participate and commit to participating in a range of activities across time, such as entering evidence into the record and submitting to cross-examination.  Picker has heard from some who are calling for a more fluid process similar to conventional notice-and-comment rulemakings that may be more accessible to the public.  Others have asked Picker to champion an even more formal process that restricts access to decisionmakers.  Picker believes the reform package has focused on finding ways to modernize the rulemaking process to give more people an opportunity to participate.

As another example, Picker pointed to the perception by many that the CPUC is too cozy with the utilities it regulates. He believes that a bigger problem is the CPUC’s failure to work well with other state agencies, and supports the legislative reform effort to increase inter-agency coordination and information sharing.

FERC Requires New England Generators to Reveal How Bids Formulated

Posted in Electric Power, FERC

On August 8, 2016, the Federal Energy Regulatory Commission (FERC) issued its order on remand from the D.C. Circuit on FERC’s approval of ISO New England’s (ISO-NE) 2013-14 winter reliability program, results, and rates. (TransCanada Power Marketing Ltd v. FERC, No. 14-1103). In a ruling that could have a significant impact on the rates that were charged, as well as the rules that will be applied to subsequent winter reliability programs in the region, FERC required generators to disclose how they formulated their winter reliability program bids.

ISO-NE adopted its winter reliability program to help assure reliability during periods of stressed system conditions by providing compensation to oil-fired and dual-fuel generators, as well as demand response resources, agreeing to provide oil inventory service or demand response for the duration of the program.  Resources were selected through a bidding process and were compensated based on their prices “as-bid,” rather than by using a uniform market clearing price.  Although ISO-NE’s estimated cost for the program was $16-$43 million, it ended up costing $78.8 million.  The court found that without evidence regarding how much of that cost was attributable to profit and mark-up, FERC could not make a reasoned determination as to the justness and reasonableness of the rates charged.

In its order on remand, FERC directs ISO-NE to obtain from each bidder the basis for its bid, including the process it used to formulate the bid.  FERC further requires that, within 120 days, ISO-NE make a compliance filing consisting of: (1) a compilation of this bidder information; (2) an analysis of the bidder information by ISO-NE’s Independent Market Monitor (IMM), including the IMM’s conclusions as to the competitiveness of the program and the exercise of market power; and (3) ISO-NE’s recommendation as to the reasonableness of the bids that were accepted.

Because the information to be obtained from bidders is commercially sensitive, ISO-NE can be expected to seek privileged treatment when it makes its filing.  Nonetheless, the New England generators who bid should weigh their disclosure obligations carefully.  The story their submissions tell could impact not just the compensation they have been paid under this program, but the rules for winter reliability programs going forward.