Energy & Environmental Law Blog

Energy & Environmental Law Blog

Analyzing the critical energy and environmental issues of the day

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.

State Water Board Cleans Up Its Water Quality Enforcement Policy

Posted in California, Rulemakings, Water Law

 On August 4, 2016, the California State Water Resources Board (State Water Board) issued a draft rule amending its 2010 Water Quality Enforcement Policy. The proposed amendments are intended to provide additional clarity, allow disadvantaged communities to receive assistance with compliance matters akin to that provided under the current policy to facilities serving small communities, and to establish a process for coordination within and among Regions to improve transparency, uniformity and fairness.  Written comments on the Draft Policy are due no later than September 13, 2016 at noon.

The Water Quality Enforcement Policy was promulgated in 2010, to provide a degree of uniformity in enforcement priorities and penalties among California’s nine Regional Water Quality Control Boards.  However, experience under the Policy indicated that problems of consistency continued, due to ambiguities and gaps in the language.  Accordingly, this new draft is largely an effort to provide more guidance and clarity.

The draft provides a definition of “fairness” that is based on eliminating any benefit received by the violator in comparison to voluntarily compliant entities, clarifies the definitions for various penalty factors, and expands the explanations of their application.  One example is that the treatment of “high volume” releases now includes a definition of “high volume” along with specific examples of its application.  With respect to other penalty calculations, the draft eliminates Class 3 (minor) violations because it was often conflated with Class 2 (moderate) violations, and discontinued the use of algorithms in the calculation of penalties.  The most notable substantive change is that unlike the 2010 policy, this draft is clear in not allowing the Board to recover attorney fees and costs associated with preparing for or attending a hearing.

The Notice for the proposed amendments states that the proposed penalty policy is not a significant alteration of the current methodology.  On review, that conclusion appears to be accurate.  The changes appear aimed at providing more certainty in the process, rather than on imposing new or greater burdens.  However, practitioners should look the changes over carefully, to see how they might impact their clients in dealings with their local Regional Board, and make comments as appropriate.

CARB Proposed Amendments to Extend the Cap-and-Trade Program Beyond 2020 Overshadow Significant Revisions to the Program Itself

Posted in California, Cap and Trade, Rulemakings

On August 2nd, the California Air Resources Board (CARB) formally released its Proposed Amendments to the California Cap-and-Trade Program.  CARB’s proposed amendments are meant to extend the program through 2030 and ensure continued emissions reductions through 2050.  Notably, the amendments are also intended to broaden the program through linkage with the Ontario program beginning in January 2018.  CARB is also attempting to better align California’s Cap-and-Trade Program with the Federal Clean Power Plan.

Extending the cap and trade program beyond 2020—which includes new emission caps, establishes future auctions, and allocates future allowances—was big news when it was announced nearly a month ago.  But CARB’s proposed changes to the program go even further.

CARB has proposed a number of adjustments/refinements to the program that may have significant impacts on a number of regulated industries and industry sectors.  These revisions did not create the same headlines because the proposed changes affect a myriad of industries in very different ways, and the potential “winners” and “losers” are not readily apparent given the complexity of the subject area.

For example, CARB is proposing to eliminate product-based benchmarks for the paper mill and roasted nuts and peanut butter manufacturing sectors, to revise product-based benchmarks for dairy product manufacturing, and to add product-based benchmarks for sulfuric acid regeneration (important for fertilizer production and petroleum refineries).  Each of these changes are significant, and companies in related industries will need to determine the specific positive or negative effect of the proposed revisions.

Another example of a possibly significant change is that CARB is proposing to directly allocate allowances to industrial covered entities to cover the carbon cost associated with their purchased electricity.  This would potentially eliminate the middleman (i.e., the electric utility), and will hopefully provide the effective transition assistance that has always intended for the California industrial sector.  Going forward, however, the question will be whether CARB can better and more efficiently allocate these allowances than the electric utilities across the State.

As one final example of a potentially significant change, CARB is proposing to change which entities and emissions are covered by the Cap-and-Trade Program.  CARB is proposing that waste-to-energy facilities that directly combust municipal solid waste should be exempt from the program for 2016-2017, while proposing that natural gas hydrogen fuel cells should no longer be exempt from the Cap-and-Trade Program.  The ramifications for each of these fledgling industries could be huge.

Industry participants will need to carefully analyze the proposed amendments to determine the potential impact of these changes on their sector.  Written comments are due on the proposed amendments are due by September 19.

Ninth Circuit Rejects Application of CERCLA to Aerial Emissions

Posted in CERCLA, Federal, Litigation

In the long-running saga of efforts by the State of Washington and the Confederated Tribes of the Colville Reservation to attach CERCLA liability to a smelter in British Columbia, the smelter owner, Teck Industries, won a significant ruling. In Pakootas v. Teck Cominco Metals, Ninth Circuit Court of Appeals rejected plaintiffs’ efforts to expand their claims beyond slag discharges to the Columbia River to include aerial emissions from the smelter’s smokestacks.

After finding liability for the slag discharges, the district court had allowed amendment of the initial complaint to include the emissions even though it initially denied the amendment as untimely. The court then certified its ruling on the emission issue for interlocutory appeal. On July 27, 2016, the Ninth Circuit reversed the district court ruling.

In a prior ruling in 2006, the Ninth Circuit had affirmed a denial of a motion to dismiss, holding that although the initial smelter discharges to the Columbia River occurred in Canada, contaminants in the slag moved downstream and were “re-released” in the US, meaning that application of CERCLA to the contamination in the US did not amount to trans-boundary application of U. S. law. Likewise, the Ninth Circuit’s refusal to extend that ruling to air emissions did not turn on questions of international law, although the Government of Canada did file an amicus brief raising sovereignty issues.

Instead, the opinion limited itself to the interpretation of “disposal” in the statute (where CERCLA simply says “’disposal shall have the meaning provided in [42 U.S.C. 6903]” (i.e., in RCRA). That approach is consistent with two prior Ninth Circuit rulings, including an en banc decision, in which the court read the language in CERCLA and RCRA to exclude aerial emissions from “disposal.”

This is unlikely to be the last word on the question. Apart from the transboundary issue, the imposition of CERCLA liability based on smokestack emissions at US facilities has not been unusual. And the court’s decision expressly states that the plaintiffs’ argument for a broader interpretation was “reasonable enough,” and on a blank slate, the panel might have found it persuasive.

The court also added a footnote regarding the effort by the U. S. to assert Skidmore deference, which, unlike Chevron deference based on an agency’s interpretation of a statute through regulations, is based on less formal agency interpretations in the course of applying a statute. In rejecting the U. S. effort, made in a post-argument filing, the court noted that it would have to not only consider the application of Skidmore deference, it would also have to decide whether that deference trumped a prior judicial interpretation, something the court declined to do on less than full briefing.

With those issues highlighted, it is highly likely that en banc consideration will follow, if not Supreme Court review.

Diablo Canyon Settlement May Hinge on Cost Allocation

Posted in California, Electric Power

On June 21, 2016, Pacific Gas and Electric Company (“PG&E”) announced a plan to close down the state’s last remaining nuclear power plant, the 2.3 gigawatt Diablo Canyon plant near San Luis Obispo, by 2026. Diablo Canyon currently produces about 9% of the electricity California uses and supplies the electric needs of more than 3 million people. PG&E announced that it intends to replace the lost Diablo Canyon generation through a combination of energy efficiency measures and greenhouse gas (“GHG”) free energy resources (as further described below). If successful, it would be the first time that a large commercial nuclear power plant was replaced by entirely clean energy resources rather than coal or natural gas.

The Joint Proposal for Closing Diablo Canyon

The Diablo closure plan is set forth in a Joint Proposal agreed to by PG&E, several of the main environmental groups that have long called for Diablo Canyon’s closure, and two of the major labor unions that represent Diablo Canyon’s large workforce. PG&E currently plans to submit the Joint Proposal to the California Public Utilities Commission (“CPUC”) for approval by the end of July.

The closure of Diablo Canyon does not come as a major surprise. The Nuclear Regulatory Commission licenses allowing PG&E to operate the plant expire in 2024 and 2025. While PG&E had applied for 20-year license renewals for the plant, the re-licensing was fervently opposed by environmental groups, local residents, and others. Diablo Canyon is also facing billions of dollars of upcoming maintenance at the plant to comply with California’s Once-Though-Cooling regulations, which require the adoption of technologies at certain power plants to reduce the impacts of their water use on marine life and habitats.

In the Joint Proposal, PG&E explains that it will seek to offset the capacity lost when Diablo Canyon is shut down in three steps, which it refers to as “tranches”:

  • Tranche 1: PG&E will obtain a target of 2,000 GWh of energy efficiency by 2025 through a solicitation process starting in June 2018. PG&E retains flexibility to propose its own utility-owned energy efficiency programs to meet this goal.
  • Tranche 2: PG&E will obtain an additional 2,000 GWh of GHG-free resources and/or additional energy efficiency measures through a second solicitation process starting in 2019.
  • Tranche 3: PG&E will procure whatever additional GHG-free energy resources are needed for it to provide 55% of its total retail sales from eligible renewable resources between 2031 and 2045 (which is over and above California’s current mandate that utilities procure 50% of their electricity from eligible renewable energy resources by 2030).

PG&E proposes to rely on the CPUC’s new Integrated Resource Planning process (Rulemaking 16-02-007) to identify what specific types and levels of renewables are needed in its service territory to meet the above procurement goals.

Many Parties Wary of PG&E’s Cost Allocation Proposals

On July 12, PG&E held its first of several meetings with interested parties to discuss the Joint Proposal. Along with other signatories to the Joint Proposal – including representatives from the Natural Resources Defense Council and organized labor – PG&E solicited feedback on the Joint Proposal from numerous interested parties. Many of the most vocal parties at this initial meeting were representing consumer protection groups, environmental groups, and community choice aggregators (“CCAs”) and electric service providers (“ESPs”) which offer competing electric service in PG&E’s service territory.

Many of the party representatives at the July 12 meeting voiced their concerns regarding PG&E’s cost recovery mechanisms set forth in the Joint Proposal. In particular, parties were concerned that PG&E has conditioned the effectiveness of the entire Joint Proposal on the CPUC approving a “non-bypassable” cost allocation mechanism through which PG&E would recover the costs of the Tranche 2 and 3 procurements described above:

PG&E’s commitment to replace Diablo Canyon energy with GHG-free energy resources under tranche 2 (Section 2.3) and tranche 3 (Section 2.4) is therefore conditioned upon CPUC pre-approval that any procurement PG&E makes associated with the Joint Proposal will be subject to a non-bypassable cost allocation mechanism that: 1) equitably allocates costs and benefits, such as [Renewables Portfolio Standard] and Resource Adequacy credits, associated with the procurement among responsible load serving entities; and 2) determines the net capacity costs of such procurement consistent with the methodology for the allocation of net capacity costs describes in California Public Utilities Code section 365.1(c)(2)(C).

See Joint Proposal, Section 2.6 (emphasis added).

The CPUC permits the investor-owned utilities, including PG&E, to pass along certain costs via non-bypassable charges to customers that have chosen to switch from PG&E’s service to either CCA or direct access (i.e. ESP) service. One of the non-bypassable charges that PG&E is already authorized to pass on to CCA and direct access customers in its service territory is a Nuclear Decommissioning Charge to be used in part to shut-down and decommission the Diablo Canyon plant. Given that the CCA and direct access customers are already paying the Nuclear Decommissioning Cost as well as other non-bypassable charges, several parties at the July 12 meeting questioned the fairness and appropriateness of PG&E’s insistence in the Joint Proposal that the costs of its procurement to make up for Diablo Canyon capacity be spread among non-PG&E customers that receive their electric services from CCAs and ESPs.

Next Steps

Whether or not the CPUC will authorize PG&E to pass along the costs of Diablo Canyon procurement through non-bypassable charges will likely be a hotly-contested issue in the upcoming CPUC proceeding to address the Diablo Canyon shutdown. Given that PG&E has expressly conditioned its commitments in the Joint Proposal to replace Diablo Canyon with GHG-free resources on the CPUC’s pre-approval of non-bypassable cost allocation, the CPUC’s resolution of this issue could make or break the entire settlement regarding the closure of the Diablo Canyon plant.

 

About the Author: Patrick Ferguson is an energy partner in Davis Wright Tremaine’s San Francisco office, where he focuses on energy policy, project development, and energy-related transactions in California and throughout the western United States. The views in this article are his own and do not represent the views of any of Davis Wright Tremaine’s clients.

Whither WOTUS?

Posted in EPA, Federal, Water Law

In June 2015, EPA and the Corps of Engineers released a rule to define “waters of the United States,” affectionately referred to as WOTUS.  This definition goes to the scope of federal jurisdiction over wetlands and other waters that are not obviously free flowing and navigable.  An in-depth analysis of the rule can be found here.

Safe to say the rule hasn’t exactly played to rave reviews.  It attracted over a million comments, mostly negative from those who think the rule represents gross government overreach, and others who believe the rule is not protective enough.  The rule is also the subject of multiple challenges around the country, some filed before the rule was officially released.  The lead case is now pending before the Sixth Circuit Court of Appeals.

On this first anniversary of the rule, we thought a brief summary of the controversies surrounding the rule and current status might be helpful.  The attached article, newly published in The Water Report, attempts to do just that.  Many thanks to Diego Atencio, a third year law student at the University of Oregon and a summer associate at DWT, for his assistance in writing the article.

Securing New Pipeline Capacity in Today’s Turbulent Gas Market: Best Practices and Things to Know

Posted in FERC, Oil & Gas

With the rapid growth of natural gas production from shale plays and growing demand due to low gas prices, pipeline companies have been scrambling to expand and reconfigure their systems to serve the needs of a changing gas marketplace.  Federal Energy Regulatory Commission (FERC) rules generally govern the commercial terms pipelines can offer prospective capacity purchasers, and also provide a measure of protection for the unwary.  If you are looking to contract for capacity, an understanding of these rules not only makes good business sense but may also help you get a leg up on your competitors.  In this article, a condensed version of which was published in the June 2016 issue of Pipeline & Gas Journal, Barbara Jost and Glenn Benson provide the advice you need.

LNG Global Impacts Not FERC’s Problem in Freeport and Sabine Pass Cases

Posted in Federal, Litigation

In companion cases, on June 28 the DC Circuit Court of Appeals held that the Federal Energy Regulatory Commission, in its environmental impacts analysis of two Gulf Coast LNG terminals, need not assess the potential for increased natural gas extraction and use, or market effects.  The first case deals with the Freeport project in Texas, and the second the Sabine Pass project in Louisiana; the court considered these cases in parallel with each other, and the Sabine Pass case follows the reasoning in the Freeport case. Read More

New Amendments To TSCA Invigorate Chemical Regulatory Regime And Empower EPA

Posted in EPA, Health and Safety, Rulemakings

On June 22, 2016, President Obama signed into law the Frank R. Lautenberg Chemical Safety for the 21st Century Act (the Act) which amends the core provisions of the Toxic Substances Control Act (TSCA), an environmental law whose use and enforcement has dwindled somewhat over the years (Available here). TSCA regulates chemical manufacturing and usage, and has not been substantially amended since it was enacted in 1976. The Act, which enjoyed bilateral support in both the House and Senate, updates TSCA to provide EPA with the discretion to prioritize the chemicals it regulates. The 2016 version expands and supports EPA’s authority to regulate industry and enforce the regulations.  The key elements are:

  1. Risk Assessment — EPA is required to review the safety of and to prioritize all chemicals in active commerce. For chemicals the EPA classifies as high-priority, the EPA must conduct a risk-based assessment to determine whether the chemicals pose an unreasonable risk.  The risk-based assessment evaluates the impact of the chemical to human health and the environment.

Importantly, the EPA may not consider “costs or other nonrisk factors” in determining whether to regulate a chemical.  The costs and benefits of  the regulation, including  the availability of alternatives to the chemical, may be considered in determining how to regulate the chemical. However, in all cases, chemicals found to pose an unreasonable risk must be regulated “so that the chemical substance no longer presents such a risk” and to ensure the protection of sensitive populations.  The Act allows anyone to challenge the EPA’s classification of a chemical as “low priority.”

2. Power to Order Testing — The Act empowers EPA to issue an order requiring testing without first having to promulgate a rule or show evidence of a potential risk or high exposure.  Currently, EPA must go through a consent agreement which can be slow and formal.

3. Inventory — EPA must maintain an up-to-date inventory of all chemicals in commerce.

4. Preemption — Federal regulation explicitly preempts states from regulating chemicals under the purview of TSCA.  Preemption is always an issue as companies must comply with a patchwork of state regulation as well as federal.  Under the updated TSCA, the federal government has preemption over the states for regulating a chemical which it has found presents an unreasonable risk.  In the event the federal government finds the opposite, that the risk of chemical is acceptable, then a state may step in and regulate. However, all state actions taken prior to April 22, 2016 are preserved.

5. Hold, please — EPA can hit the “pause” button.  While EPA is assessing the risk of a certain chemical, states may not regulate that chemical.

Simply looking at items 1-3 above, it is clear that the Act invigorates the existing chemical regulatory regime and empowers EPA to prioritize the field and demand testing. The Act also borrows from the Registration, Evaluation, Authorization and Restriction of Chemicals (REACH) program in the European Union, which is considered a success and has been used as a template for chemicals management by countries outside of the EU. Within the United States, however, this approach is new and far reaching.

Assessing and prioritizing every chemical in active commerce – and then keeping the inventory of the chemicals current — is a large task.  Many industries will feel the impact.  If a company uses chemicals in making products, it may be worthwhile to analyze the breadth of the updated TSCA.  Manufacturing toys or cosmetics may now trigger new environmental compliance challenges.

The Act also places tighter parameters around a company’s ability to shield information about active chemicals from the public, including setting a 10-year expiration for all confidential business information claims unless the claim is substantiated again.  Companies requesting confidentiality should calendar updates to keep the protections in place.

EPA now has specific power to act and it will act quickly.  The Act imposes aggressive implementation deadlines, requiring EPA to develop rules for the inventory, prioritization and risk evaluation processes within one year; develop all policies and guidance within two years;  and conduct at least 20 risk evaluations and 20 low-priority designations within 3.5 years. Including a certain workload and schedule is a rather rare requirement for environmental regulation, but it shows that Congress wanted EPA to actually use these new procedures. TSCA has been jumpstarted by this upgrade, but the government does not want to see it lay fallow. Therefore, companies should be prepared to see changes based on these amendments happen within the next few years.

The Utility as a Distribution System Platform: NYPSC Issues Order in REV Proceeding to Establish A New Paradigm for Utilities, Customers, and Distributed Energy Resources

Posted in Electric Power, Rulemakings

In an important order (“Order”) issued on May 21, 2016 in its Reforming the Energy Vision (“REV”) proceeding, the New York Public Service Commission (“NYPSC”) announced the details of a new paradigm to govern the relationship among utilities, customers, and distributed energy resources (“DERs”).[1] In this new framework, utilities are to play an important role in stimulating the development of DERs, and empowering customers to become more involved in the management of their energy consumption, to develop a modern power system that is “clean, efficient, transactive and adoptable to integrating and optimizing resources in front of and behind the meter.”  Essentially, utilities will become the distribution system platform (“DSP”) on which this new relationship between DERs and customers will be built.

The NYPSC is creating a new regulatory model under which utilities will have established (e.g., cost-of-service ratemaking) and new sources of revenue and earnings, including: Read More