Energy & Environmental Law Blog

Energy & Environmental Law Blog

Analyzing the critical energy and environmental issues of the day

Federal Appeals Court Allows FERC to Continue Pipeline Policy that Encourages Overbuilding

Posted in FERC

Several weeks ago, we reported on a new Federal Energy Regulatory Commission (FERC) Notice of Inquiry (NOI) seeking comments on whether its existing return on equity (ROE) policy should be revamped. A recent federal court of appeals ruling enhances the importance of this new FERC NOI for those concerned that the current policy encourages pipeline overbuilding.

Under its existing policy, FERC grants virtually all new gas pipeline expansions an ROE of 14 percent regardless of perceived investment risk. FERC’s decision to reexamine this policy comes almost a year after it issued, to much fanfare, a still pending NOI seeking comments on whether its Certificate Policy Statement – which governs all aspects of how it evaluates pipeline expansions – should be revised. Under its Certificate Policy Statement, FERC will approve a proposed gas pipeline expansion as long as the pipeline can show there is a need for the new service and that the facilities can be constructed without subsidization by its existing customers. Due to recent changes at the FERC Commissioner level, it is uncertain whether FERC will move ahead with its Certificate Policy Statement NOI.

FERC’s policy on certificating new pipeline facilities coupled with its practice of granting a 14 percent ROE to new pipeline expansions raises concerns that pipelines will have the incentive to overbuild, thereby increasing costs to gas consumers and greenhouse gas emissions.

For those seeking a policy change, a recent federal court of appeals decision only heightens the importance of FERC’s ROE NOI. In an unreported order issued April 3, 2019, a panel of the United States Court of Appeals for the District of Columbia Circuit dismissed a challenge by the North Carolina Utilities Commission and the New York State Public Service Commission to FERC orders granting certificates to Transcontinental Gas Pipe Line Company, L.L.C. to construct three gas projects, each with approved ROEs of 14 percent. The state commissions challenged as unlawful FERC’s long-standing policy allowing expansion rates to be designed using the approved ROE from the pipeline’s most recent general rate case, here an ROE established 15 years ago. They contended that this policy led to ROEs that were outdated and overstated, and that the resulting recourse rates unlawfully failed to constrain the pipeline’s ability to exercise market power in its rate negotiations with customers.

However, the court did not reach the merits of these claims. It found that the state commissions lacked standing because they had failed to establish “injury in fact,” explaining that they failed to establish either that the gas to be made available by these new projects will enter their states or that any end-users within their states will pay higher rates as a result of these projects. It therefore dismissed the appeal.

Although this unpublished ruling is not precedential, it exemplifies the difficulty of changing a long-established FERC policy via litigation. However, commenters on the ROE NOI may attempt to persuade FERC that it doesn’t make sense to grant 14 percent ROEs for pipeline expansions when other economic indicators such as corporate bond rates that fluctuate with economic risk rarely, if ever, offer a 14 percent return on investment.

Trump Track: Clean Water Act §401—Whose Certification Is It?

Posted in Trump Track

As part of the Administration’s policy in favor of domestic oil and gas development, on April 10 President Trump issued an Executive Order “Promoting Energy Infrastructure and Economic Growth.” The EO seeks to make the regulatory process more efficient and to create “increased regulatory certainty.”

A policy focus in the EO is water quality certification under section 401 of the Clean Water Act. Section 401 provides that before a federal agency may approve a project that could result in a “discharge” to navigable waters, the state or tribe with jurisdiction must certify that the discharge would comply with water quality standards, effluent limitations and “other appropriate requirements of State law.” The statute imposes a one-year period for the state or tribe to act.

This issue arises frequently in the context of permits issued by the Corps of Engineers under section 404 of the CWA to fill wetlands, and licenses issued by the Federal Energy Regulatory Commission for hydroelectric projects under the Federal Power Act. Both trigger state review under section 401. Gas pipelines and LNG terminal developments almost always involve stream crossings or shoreline work, which means filling of wetlands.

The EO directs EPA to take the lead to review federal policy and regulations concerning section 401 implementation. In particular, EPA is to revisit the 2010 interim guidance entitled  “Clean Water Act Section 401 Water Quality Certification: A Water Quality Protection Tool for States and Tribes.” In its review, EPA is directed to focus on a list of issues, including the appropriate scope of 401 review, the “types of conditions that may be appropriate to include in a certification,” reasonable review times and how much information should be requested of the applicant.

What it Means
Who could be opposed to improved regulatory efficiency and certainty? To be sure, the section 401 process can be contentious and time consuming. Although section 401 prescribes a one-year review period, the issues are thorny and it has become a common practice for applicants to withdraw and refile applications to restart the clock. A recent decision by the D. C. Circuit Court of Appeals throws a shadow on that practice, but one year doesn’t necessarily mean one year. It is also true that states have used section 401 as a cudgel to block LNG developments, as in the AES Sparrows Point LNG Project.

The problem with the EO is that it directs EPA to “fix” a problem over which it has little authority. Section 401 is a program administered by the states and EPA has just a marginal role to ensure that one state’s 401 decision doesn’t violate a downstream state’s water quality standards. Even EPA’s 2010 interim guidance is just a compendium of case law and general principles to aid state implementation, not a document that establishes policy.

Indeed, the scope of state section 401 authority is broad, and states use that authority to promote state policies far beyond water quality standards. Any limitations on state discretion over the process and conditions of certification are likely to come from the courts, not EPA. States are not shy in asserting their sovereignty and no state is going to cede any of its authority to EPA, regardless of what any new guidance or rules might suggest.

Trump Track: Trump Repeal and Replace Strategy Again Strikes a Rock

Posted in Trump Track

In the continuing a series of Trump deregulation failures, a federal judge in the Northern District of California rejected in harsh terms an effort by the Department of the Interior (DOI) to replace the Valuation Rule for royalties on oil, gas and coal from federal and Indian lands adopted by the Obama DOI. That 2016 rule had been developed after five years of review, comment and consideration by the agency.  In State of California, et al. v. U.S. Department of the Interior, Senior Judge Saundra Brown Armstrong, a Bush appointee, held that DOI was arbitrary and capricious in replacing the existing regulation with the prior Valuation Rule, without providing a clear and reasoned explanation. The judge noted that DOI, without stating a basis, now accepted industry concerns the agency had only recently rejected, and faulted DOI for limiting the opportunity for public comment on the repeal.

Notably, there was no reference to “Chevron deference” in the court’s opinion.  One hopes that the Department of Justice at least had the grace not to attempt to justify this repeal under that banner.

The system of accounting for oil, gas and coal royalties has been a concern of Congress for nearly forty years.  In particular, critics claimed the system for setting royalties in “captive” or non-arms-length transactions between affiliated entities often resulted in the government receiving less than full value.  In 2011, the Office of Natural Resource Revenue (ONRR), the DOI sub-agency dealing with royalties, published two advanced notices of proposed rulemaking (ANPR) to obtain suggestions for new methodologies.  In 2015, ONRR then offered a Proposed Valuation Rule for comment for 120 days, and received over 1000 pages of comments from 300 commenters, and 190,000 petition signatories.  After consideration of the comments, the agency finalized the proposed rule in July 2016 with a January 1, 2017 effective date.

Industry groups sued to enjoin the rule on December 29, 2016.  ONRR under the new Administration then decided in February 2017, to postpone implementation of the Rule.  When California and New Mexico filed suit to bar the postponement, the magistrate judge held the postponement violated the Administrative Procedure Act (APA), but decline to vacate the postponement notice because ONRR stated it was planning to repeal the Rule.  ONRR then published two limited thirty day requests for comment on repeal and an ANPR for a new rule.  It denied numerous requests for an extension of the comment periods.

What it Means

The history of this effort is a roadmap for the Trump Administration’s repeal and replace strategy, and the problems with that strategy identified by practitioners from the outset.  The Administration cannot simply delay or defer implementation of regulations it does not like without complying with the APA.  Numerous adverse court decisions have made that apparent.

Nor can it simply do a 180 on the agency conclusions previously reached in issuing those regulations.  As Judge Armstrong makes clear, in the extensive comment periods leading to the original regulation, the industry opponents already made every conceivable argument for rejection or modification of the proposed regulation.  If those comments were not found sufficient before, the agency has to offer some reasoned basis for reaching a different conclusion now.  Yet, in the case of the Valuation Rule, the administration offered only conclusory statements.  Indeed, the court also found that ONRR unduly constrained the scope and the comment period when it requested comments on the repeal of the Rule.

If the Administration persists with this approach to regulatory rewrites, it is likely to simply continue on its long trail of adverse court decisions. Even with a change of strategy, it is late in the game to expect any success in this term. Trump’s best hope for regulatory change may be that with a change of approach that follows the normal legal process, he may find some in a second term.

FERC Staff Seeks Clarification of Proposed RTO/ISO Tariff Revisions to Facilitate Participation of Energy Storage Resources in Regional Markets

Posted in FERC

Energy storage resources such as pumped storage hydroelectric generators, lithium ion batteries, and flywheels, are becoming increasingly significant in maintaining the reliability and resilience of the interstate electricity grid. However, these resources, which both inject energy into the grid and receive energy from it, have unique operating characteristics which affect their ability to participate in organized markets for the supply of capacity, energy, and ancillary services.

In February 2018, the Federal Energy Regulatory Commission issued its Order No. 841, in which it required each Regional Transmission Organization and Independent System Operator to revise its tariff to facilitate participation of energy storage resources in the capacity, energy, and ancillary services markets that it administers. Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators, Order No. 841, 162 FERC ¶ 61,127 (2018). Among other things, the tariff revisions were required to ensure that each electric storage resource within a region served by an RTO/ISO is eligible to provide all capacity, energy, and ancillary services that it is technically capable of providing, and ensure that such resources can be dispatched and can set the wholesale market clearing price as both a wholesale seller and wholesale buyer consistent with existing market rules.

Proposed tariff revisions to comply with Order No. 841 were filed by each of the RTOs/ISOs in December 2018. After reviewing those revisions, the FERC Staff asked each RTO/ISO, by letter dated April 1, 2019, to clarify its proposed tariff language and/or otherwise explain how its proposal complies with the requirements of Order No. 841.

Each RTO/ISO has collaborated with its stakeholders to develop its own tariff governing markets for sales of capacity, energy, and ancillary services. Compliance filings made by each RTO/ISO to comply with Order No. 841 reflect to a certain extent the unique practices of such RTO/ISO, and each letter from the FERC Staff asks in part how the requirements of Order No. 841 mesh with those practices. However, taken collectively, these letters show that the FERC Staff is scrutinizing closely the proposals by each of the RTO/ISO to remove barriers to participation of electric storage resources in the RTO/ISO markets and to enhance competition in those markets, as well as identifying the characteristics of each compliance filing that are of greatest concern to the FERC Staff. The principal issues raised by the FERC Staff regarding the Order No. 841 compliance filings involve the following topics:

Definition of Electric Storage Resource

Order No. 841 defined an energy storage resource as “a resource capable of receiving electric energy from the grid and storing it for later injection of electric energy back to the grid.” Among the issues raised by the FERC Staff are whether energy storage resources that are pseudo-tied into an RTO/ISO could participate in its markets, and whether an RTO/ISO would permit aggregation of energy storage resources to participate in the RTO/ISO market.

Creation of a Participation Model for Electric Storage Resources

One goal of Order No. 841 is to ensure that rules adopted by each RTO/ISO will accommodate both existing and future technologies, regardless of the storage medium (e.g., batteries, flywheels, compressed air, and pumped hydro). In the letters, the FERC Staff asked about the ability of specific kinds of energy storage resources to participate in capacity, energy, and ancillary services markets under generally applicable market rules adopted by the various RTOs/ISOs. In addition, one RTO was asked whether an electric storage resource connected to its transmission system could pseudo-tie into different balancing authority areas.

Eligibility of Electric Storage Resources to Participate in the RTO/ISO Markets

RTOs/ISOs are required by Order No. 841 to adopt tariff provisions permitting electric storage resources to provide all capacity, energy, and ancillary services they are technically capable of providing, including services such as black start, primary frequency response, and reactive power services. RTOs/ISOs were asked by the FERC Staff to explain in detail how energy storage resources meet the tariff requirements for providing ancillary and other services that the RTO/ISO does not procure through an organized market. One RTO was asked how its “must offer” rules would apply to energy storage resources, and two RTOs were asked to explain whether – and if so, how – compensation would be provided for start-up costs or no-load costs of an electric storage resource.

Participation in the RTO/ISO Markets as Supply and Demand

Order No. 841 required that electric storage resources be capable of being dispatched and able to set the wholesale market clearing price as both a buyer and seller of electricity at wholesale. RTOs/ISOs were asked by the FERC Staff to explain in detail how energy storage resources might either be dispatched or self-schedule as both a seller and a buyer under generally-applicable tariff rules. One RTO was also asked to demonstrate how electric storage resources could set wholesale market clearing prices, and another was asked to explain the process by which energy storage devices might participate in the market as price takers.

Ability to De-Rate Capacity to Meet Minimum Run-Time Requirements

Order No. 841 requires RTOs/ISOs to permit electric storage resources to de-rate their capacity to meet minimum run-time requirements. The FERC Staff sought confirmation that certain types of energy storage resources would be permitted to de-rate their capacity under the rules proposed by certain RTOs/ISOs. In addition, one RTO was asked whether an energy storage resource that was “out of charge” would be considered to be experiencing a forced outage.

Mechanics to Prevent Conflicting Dispatch Instructions

Order No. 841 required RTOs/ISOs either to show that existing rules do not allow conflicting supply offers and demand bids from the same resource for the same market interval, or to modify market rules to prevent conflicting dispatch signals. One ISO was asked to explain how dispatch rules would resolve conflicting supply offers and demand bids in a way that was economic and respected the unit’s operating constraints, while another ISO was asked to demonstrate that certain electric storage resources would not receive conflicting dispatch signals to charge and discharge simultaneously.

Make Whole Payments

Order No. 841 required RTOs/ISOs to adopt rules under which energy storage resources available for manual dispatch as a wholesale buyer and wholesale seller are held harmless for manual dispatch through make-whole payments. RTOs/ISOs were asked by the FERC Staff whether energy storage resources would be entitled to the same make-whole payments for which conventional generation resources are eligible, and to explain the means by which an energy storage resource might receive make-whole payments when the resource is dispatched as load and the wholesale price is higher than the resource’s bid price and when it is dispatched as supply and the wholesale price is lower than the resource’s offer price.

Physical and Operational Characteristics of Electric Storage Resources

Order No. 841 required RTOs/ISOs to account for the unique physical and operational characteristics of electric storage resources through bidding parameters or other means. The RTOs/ISOs were asked by the FERC Staff to demonstrate how their proposed tariff provisions would comply with this requirement. In addition, two RTOs/ISOs were asked to demonstrate that an electric storage resource is able to submit its biddable parameters in both the day-ahead and real-time markets.

State of Charge Management

Order No. 841 requires each RTO/ISO to self-manage its State of Charge and related characteristics. RTOs/ISOs were asked to explain how their procedures account for Minimum State of Charge, Maximum State of Charge, Minimum Charge Limit, and Maximum Charge Limit, as defined in Order no. 841. In addition, one ISO was asked whether the State of Charge value it adopted is “the level of energy that an electric storage resource is anticipated to have available at the start of the market interval,” and another RTO was asked to explain how it would use the State of Charge in its day-ahead and real-time market operations.

Minimum Size Requirement

RTOs/ISOs were required by Order No. 841 to establish a minimum size requirement for energy storage resources to participate in the RTO/ISO markets that does not exceed 100 kW. The FERC Staff asked RTOs/ISOs whether their rules would permit resources smaller than 100 kW to be aggregated in order to meet the participation threshold. In addition, one ISO was asked whether an electric storage resource with a rated capacity of 100 kW or above that was connected to a distribution facility or located behind the meter could participate in the ISO market.

Price for Charging Energy

Pursuant to Order No. 841, the sale of electric energy from an RTO/ISO to an energy storage resource that the resource then resells back to the RTO/ISO markets must be at the wholesale locational marginal price of energy. RTOs/ISOs were asked by the FERC Staff to confirm that the energy storage resource’s wholesale energy purchases would be at the applicable nodal LMP, as required by Order No. 841, and not at the zonal price. In addition, one ISO was asked to confirm that an electric storage resource would not be subject to a transmission charge, either by the ISO or some other entity, when it was dispatched to provide a service to the ISO, and another RTO was asked to explain the circumstances under which an electric storage resource would be subject to charges for transmission service.

Metering and Accounting Practices for Charging Energy

Order No. 841 requires RTOs/ISOs to implement metering and accounting practices to prevent electric storage resources from paying twice for the same charging energy (i.e., they should not have to pay both the wholesale and retail price for the same charging energy). The FERC Staff asked one ISO to explain how it would ascertain from meter readings which energy should be accounted for at the wholesale LMP as opposed to the retail rate. Another RTO was asked whether procedures for protecting against duplicative (i.e., both retail and wholesale) charges would be applicable to electric storage resources connected to distribution facilities or behind the meter.


Tariff provisions adopted by each RTO/ISO pursuant to Order No. 841 will affect the ability of energy storage resources to participate in markets administered by those RTOs/ISOs, and the ability of customers within those markets to enjoy the benefits of reliability and economy expected to result from increased reliance on energy storage devices, for many years into the future. The FERC Staff has asked each RTO/ISO to respond to its letter within 30 days. It would be advisable for each interested stakeholder to review those responses after they have been submitted to determine whether any concerns it may have about the increased participation of energy storage resources in markets administered by the RTO/ISO in which it operates have been adequately addressed, and, if not, to submit comments to the FERC regarding any remaining concerns. Ultimately, the FERC is expected to issue orders either accepting or modifying each of the Order No. 841 compliance filings submitted by each RTO/ISO and establishing rules governing future participation of energy storage resources in RTO/ISO markets.


Letters mentioned in this article can be found below:

ISO New England Inc., Docket No. ER19-470-000, letter from Kurt Longo, Director, Division of Electric Power Regulation-East of the FERC, dated April 1, 2019.
PJM Interconnection LLC., Docket No. ER19-469-000, letter from Kurt Longo, Director, Division of Electric Power Regulation-East of the FERC, dated April 1, 2019.
New York Independent System Operator Inc., Docket No. ER19-467-000, letter from Kurt Longo, Division of Electric Power Regulation-East of the FERC, dated April 1, 2019.
Southwest Power Pool Inc., Docket No. ER19-460-000, letter from Penny Murrell, Director, Division of Electric Power Regulation-Central at the FERC, dated April 1, 2019.
Midcontinent Independent System Operator Inc., Docket No. ER19-465-000, letter from Penny Murrell, Director, Division of Electric Power Regulation-Central at the FERC, dated April 1, 2019.
California Independent System Operator Corporation, Docket No. ER19-468-000, letter from Carlos d. Clay, Acting Director, Division of Electric Power Regulation- West of the FERC, dated April 1, 2019.


FERC Approves Termination of Market Power Mitigation Measures

Posted in FERC

Market power mitigation measures adopted in 2005 to address horizontal market power concerns arising from the merger of Louisville Gas and Electric Company and Kentucky Utilities and the subsequent withdrawal of LG&E/KU from the Midcontinent Independent System Operator, Inc. have recently been terminated by the Federal Energy Regulatory Commission, over the objection of Commissioner Cheryl LaFleur. Louisville Gas and Electric Company and Kentucky Utilities Company, 166 FERC ¶ 61,206 (2019).

Need for Market Power Mitigation

LG&E and KU are electric public utilities in Kentucky which proposed to merge in 1998. One of the issues FERC considers  when it reviews utility mergers under Section 203 of the Federal Power Act is the effect of the merger on competition. In order to allay horizontal market power concerns raised by their proposed merger, LG&E/KU committed to join the Midcontinent Independent System Operator, Inc. (MISO), which was then being organized as an independent regional transmission organization.

Members of MISO may obtain transmission service throughout the multi-state MISO footprint for a single, non-pancaked transmission charge. Therefore, LG&E/KU’s participation in MISO enabled load-serving entities connected to its transmission system to obtain electricity from sources outside of the LG&E/KU footprint without paying multiple transmission charges. In its order approving the merger, the FERC found that the availability of transmission service to customers connected to the LG&E/KU system from anywhere within the MISO footprint at a single, non-pancaked rate helped to mitigate any horizontal market power concerns. An increase in potential electricity suppliers within the LG&E/KU destination market meant more competitive rates for consumers.

Adoption of De-pancaked Mitigation Measures

In 2005, after the merger had closed, LG&E/KU sought FERC authorization to withdraw from MISO, and proposed instead to offer transmission service over their combined transmission systems through a stand-alone Open Access Transmission Tariff (OATT).  In order to provide transmission customers the benefits of non-pancaked transmission rates comparable to those enjoyed while LG&E/KU belonged to MISO, it also adopted a De-pancaking Mitigation mechanism involving transmission rates for new service into and through its system from MISO.

Under that mechanism, certain load-serving municipal electric utilities within the LG&E/KU footprint that purchase power from generation sources in MISO receive a credit for transmission service under the LG&E/KU OATT equal to charges for transmission and ancillary services they paid under the MISO Tariff. In addition, LG&E/KU waived transmission and ancillary service charges under the LG&E/KU OATT for power delivered by such customers from generation sources connected to the LG&E/KU system into MISO. As a result, load-serving utilities within the LG&E/KU footprint have continued to obtain transmission service through the KG&E/KU and the MISO systems for a single, non-pancaked transmission charge.

Termination of De-pancaked Mitigation Mechanism

In August 2018, LG&E/KU filed an application with the FERC to terminate the De-pancaking Mitigation provisions. In considering this request, the FERC rejected arguments that any market power mitigation measures either (a) must remain in effect in perpetuity, or (b) have a finite term.  Instead, the FERC explained that the De-Pancaking Mitigation measures could be terminated “if LG&E/KU has demonstrated that loads located in the LG&E/KU market will continue to have access to a sufficient number of competitive suppliers after the mitigation is removed.”

In support of its request, LG&E/KU argued that market conditions in the Midwest have changed substantially since the adoption of the De-pancaking Mitigation mechanism. LG&E/KU submitted an analysis showing that the wholesale requirements customers within its boundaries have many more sources of power available today than in 1998; that many of those customers had successfully solicited power supply arrangements from suppliers other than LG&E/KU; and that a delivered-price test revealed more than 100 entities with capacity that could be delivered into the LG&E/KU footprint at competitive rates. After reviewing the record, the FERC found that:

…the Merger continues to be consistent with the public interest without the De-pancaking Mitigation because the record shows that loads located in the LG&E/KU market will continue to have access to a sufficient number of competitive suppliers after the mitigation is removed.

Transition Period

At the time of the FERC’s acceptance of the De-pancaking Mitigation, all wholesale requirements customers connected to the LG&E/KU system had long-term contracts to purchase the electricity needed to meet their bulk power supply requirements from LG&E/KU. Some of those customers have now terminated the purchase of power from LG&E/KU and are purchasing power from third-party suppliers, while other customers are in the process of doing so.

Nevertheless, the FERC was concerned that these customers may have made arrangements to procure power from generation sources located outside of the LG&E/KU footprint in reliance on the De-pancaking Mitigation measures. Therefore, as a condition of their termination, the FERC required that the De-pancaking Mitigation measures remain in effect for all wholesale requirements customers dependent upon the MISO transmission system during a transition period equal to the initial term of each power purchase agreement entered into by each such customer.

Commission La Fleur’s Dissent

Although the FERC granted the request to terminate the De-pancaking Mitigation provisions after a transition period, Commissioner LaFleur was concerned that the delivered price test provided by LG&E/KU showed that customers would have limited access to alternative generation suppliers during periods of the year when the market is highly or moderately concentrated. She also believes that because the solicitations relied on by LG&E/KU were conducted while the De-pancaking Mitigation mechanism was in place, they were insufficient evidence of adequate competitive options that might be available without mitigation. She therefore would have preferred that the FERC set the matter for an evidentiary hearing in order to confirm that the wholesale requirements customers connected to the LG&E/KU system would have adequate access to competitive third party generation suppliers after the mitigation was terminated. With due regard for rate pancaking, she concluded by saying that:

…while people frequently talk about how the sausage gets made, this case shows how the pancakes get made. While a single pancake may be fine, I do not believe that LG&E/KU should be able to force feed a short stack of pancakes to [the wholesale requirements customers]. Without better ingredients than are presented in this record, the conclusion that these customers have adequate menu alternatives is half-baked at best. While I expect the majority would rather than I hop to their decision, I am not waffling, and respectfully dissent.


The order reflects the FERC’s pragmatic attitude in determining whether horizontal market power mitigation measures are needed to protect against potential adverse effects of utility mergers on competition. Although termination of the De-pancaking Mitigation mechanism might affect the ability of some potential suppliers to serve loads within the LG&E/KU market economically, the FERC was satisfied that loads located in the LG&E/KU market would continue to have access to a sufficient number of competitive suppliers after the mitigation is removed. Although Commissioner LaFleur would have preferred that there be additional evidence to support the FERC’s conclusion, the transition arrangements provide a reasonable opportunity for affected wholesale customers of LG&E/KU to test the FERC’s conclusions while seeking new supplies of electricity to take effect when their existing power purchase agreements with LG&E/KU expire.




Cannabis Growers and Investors: Be Sure of Your Water Rights

Posted in Natural Resources, Water Law

In western states that have legalized cannabis over the last few years, water agencies have seen a sharp increase of permit applications to secure water rights. Cannabis is an agricultural crop and, of course, it needs water to grow. The water needed to irrigate those crops is similar to what almonds and pistachios require.[1] With the legalization of hemp in the 2018 Farm Bill came more economic opportunity for cannabis farmers and investors, but without secured water rights this opportunity will remain largely untapped.

This advisory first provides an overview of Western water law and the current issues that water agencies throughout the West are facing and then tailors these issues to the cannabis industry, identifying a path forward for growers and those considering investing in a growing operation.

Western Water Law: First-in-Time, First-in-Right

In the East, where sufficient rainfall means farmers need not depend on irrigation, states adopted the English common law principle of riparian rights. Under that system, riverfront properties share the resource. A different legal system developed in the arid Western states.  The doctrine of prior appropriation adopts a first-in-time, first-in-rights approach to water rights, meaning that the first person to put water to beneficial use may block future users if there is not enough water for all.  The resource is not shared so much as it is allocated, based on priority in time.

This approach emerged during the gold rush as a way to foster mining and settlement around agricultural economies. A major way to do that was to encourage diversion and beneficial use of water, a scarce resource in the American West. The California Supreme Court officially adopted the doctrine of prior appropriation in its landmark decision Irwin v. Phillips,[2] which continues in somewhat uncomfortable juxtaposition with riparian rights. The Court recognized “the rights of those who, by prior appropriation, have taken the waters from their natural beds, and by costly artificial works have conducted them for miles over mountains and ravines (…) and without which the most important interests of the mineral region would remain without developments.”[3]

Water rights based on prior appropriation quickly spread throughout the West and has been codified today in eighteen states, including Alaska, Washington, Oregon, California, Nevada, and Colorado, all states in which cannabis is now legal under state law. While the basic principles of prior appropriation have remained the same, legislatures and courts have refined the elements necessary to prove a water right under the doctrine. Typically, a water user wishing to secure water rights must show four components: intent, diversion, beneficial use, and priority. Most states have adopted a permitting scheme to administer the appropriation of water rights, with the notable exception of Colorado, which relies on a system of water courts to administer water rights.

Under these statutes, states generally require a two-step water rights permitting process. The process begins with a permit application, which establishes the priority date, and if approved results in a permit. The permit is not a vested water right but an authorization to develop the necessary water works to take possession of the water for beneficial use. After the permit holder can prove the rate and amount of water put to beneficial use, the right is “perfected” and a permanent water right is issued.

In most Western states, water rights have been issued for more water than exists in the stream or may be sustainably pumped from aquifers, which harms the resource and the aquatic life that depends on it. This has resulted in the imposition of constraints on and sometimes curtailment of water use.  Applications for new water rights are frequently contested.

As mentioned, there is no sharing under prior appropriation. During water-shortage conditions, which occur frequently in the West, senior water users can call upon the state to notify junior users to curtail their use of water to satisfy the more senior water rights first. An exception to this general principle is where the junior’s use is so attenuated from the senior that the senior would not benefit from the junior being curtailed. This is referred to as a “futile call.”

Water rights may be modified through an administrative process. Changes in place of use, nature of use, point of diversion (or point of appropriation for groundwater) are permitted if the change would not enlarge the water right or injure other water rights holders. Changes in place of use could result in water no longer being appurtenant to the lands under consideration for investment, which will not show up in a title report.

Beneficial Use: Use it or Lose it

Perhaps the most important element of prior appropriation is the requirement to put water to beneficial use. Water rights holders who fail to meet this requirement over a period of time risk having courts find that they have abandoned or forfeited their rights. While abandonment requires showing an intent to abandon a water right together with failure to put it to beneficial use, forfeiture statutes simply provide that a water user will lose its rights by failing to put the water to beneficial use for the statutory period, usually five consecutive years, unless certain exemptions apply. Loss of water rights for non-use is at the core of water rights auditing.

Water Rights and Cannabis Growers

With the legalization of cannabis in western states came an increase of water rights applications that state agencies have struggled to deal with. The California State Water Resources Control Board adopted a complex policy essentially treating cannabis as a crop inferior to other traditional agricultural crops from a water rights perspective.[4] Other states have not made such a strong policy choice yet, but will certainly be faced with how to address this influx of permit applications, and will feel pressure from farmers of traditional crops, who do not always welcome cannabis growers with open arms.

In Oregon, a cannabis producer license typically requires a water right permit or certificate number, a statement that water is supplied from a public or private water provider, or proof that the water is from a source that does not require a water right.[5] An applicant for a water right permit must submit maps, expected water use volume and rates, and show county approval for the use of the land. Once the applicant receives a permit (often between three and four months), he or she must prove beneficial use of the water to “certify” the water right.

Conclusion: Audit the Water Rights Before Investing

Before investing in a growing operation or entering into a long-term supply contract with a grower, prospective investors should pay particular attention to whether that operation has the necessary water rights and that they are intact. This can be done by conducting a water rights audit. The purpose of the audit is to confirm the water rights or identify problems that need fixing.  In virtually every instance there is a solution, but it is always best to be aware of and to address them as part of the acquisition or investment.

The water rights audit will allow prospective buyers to answer important questions:

  • Are there water rights associated with the operation? The water rights may be under a permit, a vested certificate or by contract, each of which present their own issues.
  • Are the water rights intact? Five consecutive years of non-use in many states could result in forfeiture of the water right. Also, using water inconsistently with the terms of the permit or certificate could lead to cancellation or reduction of the water right.
  • Do the documented water rights cover all the lands to be cultivated? During the audit we often find a disconnect between the “paper” water rights and use on the ground. Water rights can be separated from the real estate; be sure they still are attached and in the right amount.
  • What is the “rate and duty” of the water right? Just ensuring that a growing operation holds water rights is not enough. Different crops have different water requirements, and the rights must be tailored to growing cannabis.
  • What constraints apply to the water rights? The priority of the right relative to other users on the stream or the groundwater aquifer could affect the availability of water when it is needed most. There might also be state administrative limits on the use of water, such as maintenance of minimum fish flows.

[1] Christopher Ingraham, Forget Almonds: Look at How Much Water California’s Pot Growers Use, Washington Post, June 26, 2015,

[2] Irwin v. Phillips, 5 Cal. 140, 145-47 (1855).

[3] Id. at 146.

[4] See Amy Steinfeld, Legal Cannabis Ushers in a New Era of Water Regulation in California, The Water Report #181, Mar. 15, 2019.

[5] OAR 845-025-1030 (6)(g)(D).

Breaking Bad Habitats?

Posted in ESA

As reported in this space, in November 2018, the U.S. Supreme Court remanded to the Court of Appeals for the Fifth Circuit a determination by the U.S. Fish & Wildlife Service on critical habitat for the dusky gopher frog. The issues for the Fifth Circuit on remand would be whether habitat in which the dusky gopher frog could not currently live without modification could be designated “critical habitat” under the Endangered Species Act, and consideration of the cost implications of the critical habitat designation for the private landowner.

The FWS is now requesting that the Fifth Circuit remand the matter back to the agency and allow it to reexamine the issues itself. The agency reasoned that it could more quickly handle the matter, citing new information developed since the 2012 record before the Supreme Court. FWS is also considering an amended regulation regarding the designation of critical habitat. Remand would allow the policy considerations inherent in the new regulation to be taken into account first by the agency.

What is the motivation for the agency’s request? It could be as straightforward as stated. The agency has the responsibility to make the designation. It has additional and unanticipated guidance on how to approach designations from the Supreme Court’s decision. And the Fifth Circuit, if it now applied that decision on remand, would do it on the basis of a stale factual record, without the benefit of the agency’s new analysis and new regulations. Underlying that analysis, what will be the impact of Supreme Court rulings expected this year or next on Chevron deference? Should the agency be allowed to bulk up support for its position in anticipation of a less deferential standard of review? Or could this agency effort be an attempt to kick this matter down the road for two years or more for later consideration by a new administration not hampered by a Fifth Circuit ruling made this year?

The avalanche of litigation challenging Trump Administration environmental actions since 2016 may have made cynics of us all. Is this an agency effort to avoid embarrassment in defending a decision made years earlier that relied on strong deference in review of a weak record, or a Deep State effort to thwart a change of direction in policy? The plaintiffs object to the FWS request, which suggests their view. From outside the litigation, I remain conflicted.

Oregon Air Toxic Sources Need to Focus on Their Priority and Plan

Posted in Environmental Quality, Northwest
Upset man wearing a breathing mask giving

Oregon moved to regulate air toxics with SB 1541, which became effective April 10, 2018. Regulations implementing the air toxics requirements were adopted by Oregon DEQ in November of 2018 and, as explained below, draft risk assessment guidance has now been released for public comment.

The agency estimates that 400 facilities will be impacted by the new regulations and it hopes to complete permitting for 20 of those facilities by the end of the first year. DEQ has not said which 20 will have that honor, but new major source facilities will need to evaluate air toxics as part of their permit applications. Facilities who were already regulated may want to obtain better data on their emissions inventory and plan ahead to minimize adverse impacts on their business.

DEQ is using a complicated prioritization formula to determine which currently permitted facilities to evaluate first under the new regulations. The formula might foreshadow complexities of the program and would make your high school algebra teacher proud. The first step in prioritization is to take the summation of the risks from emissions that are likely to cause cancer risk, non-cancer risk, and acute risks and divide each by its associated risk. This total is then taken to the 0.75 power (not something you do every day but thank goodness for calculators). It is then added to the potential impacted population of the sum of four groups (low income persons, minorities, kids under five, and the general population) that are then divided by four. This extra weighting is apparently meant to serve as some “environmental justice” for the groups counted more than once. This total is then taken to the 0.25 power – in other words the square root of the square root. Add those two numbers together and you have the quantitative “score” for prioritization. DEQ noted, however, that the assigned priority is not intended to equate with the relative risk posed by facilities.

But liberal arts majors despair not, because after completing the quantitative analysis, DEQ applies a qualitative analysis to derive the prioritization. The qualitative factors that are considered, without regard to any mathematical formulas, include the data quality going into the quantitative factor, the nearest exposure point to a facility, and existing controls that are already in place at the facility.

After reviewing all this, you can understand why DEQ doesn’t have the prioritization completed yet. But the real work ahead for facilities will entail:

  • Preparing air toxics emissions inventories
  • Preparing a risk assessment work plan
  • Performing the risk assessment
  • If needed, developing a risk reduction plan to address unacceptable risk
  • Filing a permit addendum application
  • Going through public notice and hearings
  • Issuing a permit addressing air toxics

DEQ jumped ahead and issued draft risk assessment guidance in October 2017 and June 2018 and is currently seeking comments on its latest revision.

The complexity is inherent in aggregating risk from at least 260 chemicals where risk-based concentration limits have been established; stack emission sources and fugitive emission sources at each facility; evaluation of each chemical from each source at each of the nearest exposure points (based on zoning or where people may be known to spend more than one hour); the three kinds of potential risks that may be posed by each chemical; and 18 target organs that may be impacted. The matrix is going take up quite a bit of space.

Everyone agrees that the risk to be addressed is derived from the amount of exposure and the toxicity of the chemical at issue, but the details as to how to evaluate risk are still a work in progress, along with guidance documents for regulated facilities to navigate the new requirements. The rules are dense and some explanations only appear in response to past comments. What is clear is that the new rules will include penalties and that violations will create a stigma that might poison community relations or provide fodder for air toxics lawsuits.

FERC to Address Pipeline Overbuilding and Excessive Returns

Posted in FERC

Although primarily focused on the electric transmission industry, a recent Federal Energy Regulatory Commission (FERC) Notice of Inquiry (NOI) announced reconsideration of how the agency determines returns on equity (ROE) and seeks comments on whether it should apply any revamped ROE policies to interstate natural gas and oil pipelines. This NOI creates an additional avenue for gas industry participants seeking changes in how the FERC evaluates and approves the construction of new gas pipeline facilities.

As described in a previous article, almost a year ago, FERC announced another NOI seeking comments on its Certificate Policy Statement. The existing Certificate Policy Statement takes a light-handed regulatory approach to proposals to construct new pipeline facilities. Generally, under the Certificate Policy Statement, as long as a pipeline demonstrates a market need and is prepared to financially support its new project without relying on subsidization from existing customers, FERC is likely to approve the project. Under FERC’s existing Certificate Policy Statement, this demonstration of market need can come through precedent agreements executed with shippers, including shippers either affiliated with the applicant or who have a minority ownership interest in the new project. In recent years, state-regulated utilities, with the ability to flow through these costs to their retail customers, have begun to participate in the ownership of these new projects.

The recent growth in applications for new pipeline facilities has been spurred by the desire to access new production areas first made available by improved fracking technology. The number of applications has also increased because new projects are profitable investments. In approving new pipeline facilities, FERC has repeatedly granted a 14 percent ROE for new “greenfield” facilities. FERC has used this 14 percent ROE approach since 1997, regardless of wider economic indicators such as corporate bond rates, which fluctuate with economic risk and which rarely, if ever, offer a 14 percent of return on investment.

The idea that the 14 percent ROE granted to new pipeline projects does not vary regardless of broader market conditions indicates that FERC today may not be realistically incorporating risk into expansion facility pricing. This allows pipelines to over-recover on their investments and creates an incentive for pipelines to overbuild. Many commenters on the Certificate Policy Statement NOI urged FERC to change this approach. They noted that overbuilding is not only expensive for consumers who ultimately pay the costs in rates, it also leads to increased use of natural gas facilities and increased greenhouse gas emissions. The NOI’s reassessment of FERC’s ROE policies may be a productive forum for raising concerns about excessive ROEs for newly certificated pipeline facilities. Certainly to the extent FERC adopts policies that lead to lower ROEs for new facilities, this will put a damper on pipeline industry overbuilding in the future, even if the Certificate Policy Statement remains unchanged, as recent changes at the FERC Commissioner level suggest is likely.

Another area of opportunity for natural gas pipeline industry reform is FERC’s use of the discounted cash flow (DCF) methodology in ratemaking proceedings. FERC uses the DCF model to calculate a pipeline’s ROE by comparing the pipeline to other gas pipeline companies representing a comparable risk to investors. To find comparable companies, FERC uses a proxy group of regulated companies in accordance with certain parameters it has created over time. In recent years, however, FERC has grappled with a number of difficulties in composing proxy groups:  there are an insufficient number of publicly-traded natural gas pipeline companies, potentially comparable companies with publicly traded stock do not have a substantial proportion of their business in gas pipeline operations, and it is challenging to create a proxy group composed of both master limited partnerships and corporations. These practical difficulties highlight shortcomings of the DCF model and open the door to consideration of the other methodologies described in FERC’s NOI, which calculate ROE based on verifiable, market-based factors such as interest rates, book value, and beta.

Natural gas pipelines are already proposing to use new methodologies for calculating ROE in rate cases not only because of the existing difficulties with the DCF model but also in light of the FERC’s recently revised policy on the income tax allowance. FERC’s NOI presents an opportunity for all interested stakeholders to comment on what models FERC should use, and how FERC should reform its ROE policies to more realistically capture investment risk.

FERC Initiates Review of Return on Equity, Electric Transmission Incentives

Posted in FERC

On March 21, 2019, the Federal Energy Regulatory Commission issued Notices of Inquiry regarding (1) its method for determining the return on equity for rates charged by public utilities (and whether such ROEs should also be applied to interstate natural gas and oil pipelines) (Inquiry Regarding the Commission’s Policy for Determining Return on Equity,), and (2) the scope and implementation of its electric transmission incentives regulations and policies (Inquiry Regarding the Commission’s Electric Transmission Incentives Policy,). Initial comments are due no later than 90 days after they have been published in the Federal Register.

(1)        Rate of Return on Common Equity

Regulated utilities rely heavily on capital from external sources to fund their expansion programs. Therefore, it is essential that such utilities be able to earn an ROE that is both commensurate with the return that investors might realize from other enterprises, and sufficient to maintain investor confidence in the financial integrity of the enterprise.

Many transmission-owning utilities rely on cost-of-service formula rates which established the ROE under economic conditions different from prevailing conditions. In response to concerns raised by consumers, the FERC has begun investigations into whether the ROEs of transmission owners within certain regional transmission organizations/independent system operators should be adjusted to reflect current economic conditions and, if so, what the revised ROE should be.

By way of background, in Emera Maine v. FERC, the D.C. Circuit Court of Appeals vacated and remanded to the FERC its order to revise the ROE used by transmission owners in New England. In response to that decision, the FERC adopted a revised method for determining a just and reasonable ROE for transmission owners based on averaging the results produced by the following economic models:

(a) a two-step discounted cash flow method, which is based on the premise that a stock’s price is equal to the present value of the infinite stream of expected dividends discounted at a market rate commensurate with the stock’s risk.

(b) a capital asset pricing model, which is a measure of the cost of equity to utilities relative to risk.

(c) a forward-looking expected earnings model, which evaluates the return on equity that investors might expect to earn from investments in companies with risks comparable to those faced by the affected transmission owner.

(d) a risk premium model, in which the ROE is based on the premium investors require above the return they expect to earn on a bond investment.

Participants in proceedings pending before the FERC involving challenges to the ROEs used to set rates of transmission owners within ISO New England and within the Midcontinent Independent System Operator, Inc., have been asked to comment on this proposed methodology and on the application of this methodology in those proceedings.

In the new ROE NOI, the FERC expanded its inquiry about use of its revised method for determining the ROE for all transmission owners. In addition, the FERC has asked for advice generally on its approach to determining a proper ROE for public utilities, and is seeking comments on the mechanics of applying each of the models to establish a composite zone of reasonableness for ROEs applicable to public utilities. However, the FERC affirmed that any action taken as a result of this inquiry will not affect the ongoing proceedings involving ISO New England and MISO.

Perhaps most significantly in the ROE NOI, the FERC is also examining whether the policy used to determine ROEs for public utilities should also be used to determine ROEs for interstate natural gas and oil pipeline companies. Among the issues of concern to the FERC are whether comparable data are available for natural gas and oil pipelines to implement the methodology used to establish ROEs for public utilities.

(2)       Electric Transmission Incentives

The Energy Policy Act of 2005 requires the FERC to benefit consumers by providing incentives for transmission of electric energy to ensure reliability and reduce the cost of delivered power by reducing transmission congestion. Among the financial incentives adopted by the FERC were adders to the allowable ROE for transmission owners taking certain actions, assurance of the ability to recover costs of certain abandoned transmission development projects, and accelerated recovery of certain other costs. Taken together, these incentives were designed to encourage development of potentially risky transmission expansion projects and to reward transmission owners who took various actions to foster independence between the transmission function and the power marketing function of a utility.

The FERC noted in the Transmission Incentive NOI that since its policy to award such incentives was adopted, there have been numerous changes in the electric utility industry. These changes include “the Commission’s issuance of Order No. 1000 [relating to transmission system expansion], an evolution in the generation mix and the number of new resources seeking transmission service, shifts in load patterns, and an increased emphasis on the reliability of transmission infrastructure.” At the same time, consumer groups have complained that such incentives have resulted in excessive, unjust, and unreasonable charges for transmission service. The FERC is therefore beginning to consider whether revisions of those policies are warranted.

Among the transmission incentive-related topics on which the FERC has sought comments are the following:

  • Whether transmission incentives should continue to be based on consideration of risks and challenges associated with a particular project, or, alternatively, whether transmission incentives should be based on potential benefits related to reliability and reductions in the cost of delivered power.
  • Whether a cost-benefit analysis should be made (and, if so, how) to determine whether particular transmission incentives should be granted.
  • Whether, in lieu of considering the potential benefits of a project, the FERC should focus on the characteristics of the project as a proxy for potential benefits (e.g., located in regions with persistent needs).
  • Whether transmission incentives should be tailored to achievement of specified types of benefits, such as reliability, economic efficiency, and enhancements of physical and cyber-security of existing jurisdictional transmission facilities, and/or increased resilience of the transmission system.

The FERC also observed in the Transmission Incentive NOI that most applications for transmission incentives have involved transmission facilities to be developed in regions served by RTOs and ISOs. The FERC therefore asked about the potential use of transmission incentives to encourage desired transmission-based initiatives in non-RTO/ISO regions.

These inquiries into long-standing policies for determining ROEs for regulated entities and for granting electric transmission incentives involve two of the many important reform initiatives that have been discussed by FERC Chairman Neil Chatterjee in recent months. Taken together, these initiatives may have a significant impact on the reliability and cost of electricity throughout the United States, and on the success of market participants in meeting the challenges of the future. We therefore encourage interested stakeholders to make the effort to submit comments on these NOIs for consideration by the FERC, and intend to follow closely the developments relating to these and other industry initiatives coming before the FERC as they unfold.

Lessons In Persistence for Us All

Posted in EPA

Lessons In Persistence for Us All

Recent actions by the New Hampshire House of Representatives provide a variety of lessons about the value of persistence, both in the political process and in life. Four years ago, a group of fourth-graders attempted to have the red-tailed hawk designated the official state raptor. Oddly, the effort was derailed by those arguing the hawk was too violent…the state raptor was too violent?

Four years later, as eighth graders, the students returned, and this time succeeded easily. They wore t-shirts with the slogan “Our Second Try to Live Free & Fly,” a take-off on the State motto (“Live Free or Die”), and argued that the hawk was determined, adaptable and shared parental responsibilities. At the same time, the coyote, which to my mind is a predator at least as persistent, and even more adaptable than the hawk, was not so fortunate. Apparently lacking student sponsors, a bill to bar the hunting of coyotes only during pup-rearing season failed to pass.

It is not the animals who have profited most from this experience. The hawks have ample state and federal protection. The coyote has proven over the last century that it can survive, adapt and even flourish without statutory recognition and in the face of determined efforts by humans at eradication.  We treasure videos showing coyotes at the Golden Gate Bridge, heading through the fog into the city, and we now have over two dozen living inside San Francisco.

It is the kids who have learned valuable lessons about the quirky legislative processes that govern us. As one student said, the effort “taught us all that we don’t always succeed in getting what we want.” It also taught them that the same perseverance that they honored in the hawk could help them in the legislative process, and one hopes, that the persistence and wiliness of the coyote can overcome the worst that humanity throws at it.

Trump Track: Chevron Deference – Whose Ox Is Gored?

Posted in CERCLA, EPA, Federal, Trump Track
Gravel Piles And Factory Against Cloudscape, HDR

Federal courts often rely on “Chevron deference” in upholding regulations issued pursuant to vague congressional authorization. This doctrine dictates that where the statutory language is unclear, a court will defer to a reasonable interpretation of the language by the agency designated to enforce the statute. Agencies are not prone to reading their authority narrowly, and for decades, conservatives, including those on the Supreme Court, have chafed at the courts’ reliance on that deference to expand government regulation.

With a new conservative majority on the court, and increasing numbers in the lower courts, the demise of the Chevron doctrine has been a frequent prediction in judicial writings. However, the Trump administration is now facing an uncomfortable fact that may slow, if not prevent, that demise.

The Trump administration has had a laser focus on reversing regulatory efforts by the prior administration. However, in order to justify the elimination or replacement of regulations proposed or duly promulgated under the preceding administration, it will almost inevitably be required to rely on that same Chevron deference to support its own decisionmaking – thereby restricting agency authority to interpret regulations by asking that courts defer to it.

At oral argument last week before the D.C. Circuit, the Trump administration faced a particularly difficult dilemma when attempting to eliminate proposed Obama regulations under the Comprehensive Environmental Response and Liability Act (CERCLA or Superfund) related to financial responsibility in the hardrock mining sector.

Section 108(b) of CERCLA, passed in 1980, required that EPA prioritize industries by risk. For those industries designated as particularly risky, it required the agency to promulgate financial responsibility regulations. Despite the directives in the statute, EPA had not proposed such regulations for any class of industry for over two decades. Environmentalists sued, and the D.C. Circuit ordered the agency to make a determination on whether regulation was required for the hardrock mining industry. Following that ruling, EPA proposed regulations for the industry in 2016.

The need for such regulation is controversial, both in terms of the need for such regulation at all – the industry asserts that it is already subject to comprehensive financial responsibility regulation in the states – and in some particulars, such as a formula for natural resource damages. The formula produced substantial estimates for potential financial responsibility, where in practice claims have usually been at or close to $0, although on rare occasion have exceeded $100MM. But rather than modify the regulations, the Trump Administration has declined to issue them, resulting in new litigation. This led to DOJ arguing before the D.C. Circuit for adoption of the agency’s current view of the statute – that such federal regulation of the hardrock mining industry was not required at all. The DOJ attorney was quoted as saying “We are in a world of Chevron under this statute.”

This was not the first time, and will not be the last, that the administration finds itself in this position. The ironic result may be that we will close out the Trump administration with Chevron deference in disarray as courts refuse to grant deference to 180-degree changes in agency positions, or the doctrine may be more firmly in place than ever.

FERC Denies Authorization to Acquire Transmission Facilities Due to Adverse Rate Impacts

Posted in FERC

The Federal Energy Regulatory Commission (FERC) recently denied an application by GridLiance High Plains LLC for authorization to acquire certain transmission assets from People’s Electric Cooperative, a rural electric cooperative in Oklahoma. FERC found that the transaction would have an adverse impact on FERC-jurisdictional rates and would not result in any meaningful offsetting benefits.  GridLiance is a transmission-only or “transco” company. Operating control over the transmission facilities of GridLiance has been transferred to the Southwest Power Pool (SPP), which is a FERC-approved regional transmission organization. In July 2018, GridLiance requested authorization from the FERC pursuant to Section 203 of the Federal Power Act to acquire approximately 55 miles of 138 kV transmission lines and associated equipment from People’s Electric Coop.  Although the transmission lines currently are operated as radial lines, GridLiance claimed that the lines were constructed as a loop and may be capable of being operated as non-radial transmission lines, which would enhance system reliability. GridLiance proposed to transfer operational control over those lines to SPP after the transaction closed.

In accordance with its Merger Policy Statement, the FERC generally considers the potential impact of proposed transactions on competition, on FERC-jurisdictional rates, and on regulation. The FERC also considers the potential for cross-subsidization of a non-utility associate company. Even if a transaction is likely to have an adverse effect on rates, the transaction may nevertheless be acceptable under the Merger Policy Statement if there are resulting countervailing benefits.

Although it was undisputed that the transaction would cause an increase in transmission rates paid by SPP customers, GridLiance did not propose to adopt any ratepayer protection measures.  Instead, GridLiance claimed that there would be offsetting benefits similar to those which had been found by the FERC in other proceedings to justify approval of proposed transmission facility acquisitions.  In its order, the FERC concluded that there was insufficient evidence of any meaningful benefits arising from the acquisition of the facilities by GridLiance. The asserted benefits of this transaction, and the reasons given by the FERC for rejecting them, are as follows:

A. Improving the reliability of People’s Electric Coop’s existing system—GridLiance asserted that if it acquired the transmission lines, it could close the interconnections between the transmission lines and existing facilities on the SPP system and operate those lines as networked lines, thereby improving the reliability of service to customers of People’s Electric Coop. Because the amount of load served on those lines by Peoples Electric Coop. is relatively small (less than 50 MW), the FERC concluded that the benefit of improved reliability would not offset the rate increase to customers of SPP.

B. Promoting transco ownership of transmission facilities—GridLiance sought to rely on FERC assertions that ownership of transmission facilities by a transmission-only entity generally is beneficial. Although the transaction would result in transfer of ownership of transmission lines from a load-serving entity to a transmission-only company, FERC concluded that the benefits derived from the transfer would not be sufficient to offset the resulting rate increase.

C. Enhancing the operations and efficiency of SPP—GridLiance suggested that transfer of operational control over the transmission lines at issue to SPP after they had been acquired by GridLiance would provide planning and operational efficiencies by allowing those lines to be integrated with the SPP system. However, the lines would continue to be used primarily to serve industrial customers of People’s Electric Coop., and GridLiance acknowledged that it did not have any plans to upgrade, enhance, or add to the facilities after it acquired them.  The FERC therefore concluded that there was no indication that existing customers of SPP would receive any material benefit from having those lines included as part of the SPP system.

D. Increasing public power’s participation in SPP transmission planning—The FERC acknowledged that participation by public power entities in regional transmission organizations is generally considered to be beneficial, but explained that “FPA section 203 requires GridLiance to explain how it can achieve benefits as a result of its acquisition of the Assets.” FERC found that the transaction would not add substantial benefits: “the addition of 55 miles of transmission facilities whose only use is to deliver power to industrial customers does not materially add to the size or scope of SPP nor has it been shown to provide other material benefits to SPP.”

Although the FERC denied the request by GridLiance to acquire specified transmission assets from People’s Electric Coop., the FERC emphasized that its decision was based on the record developed by GridLiance, and that it would be open to reconsidering its decision if GridLiance proposes to adopt adequate ratepayer protection mechanisms or demonstrates specific additional benefits to offset the rate increase.

Hoopa Valley Tribe v. FERC: When Does One Year Mean One Year?

Posted in FERC, Water Law

On January 25, 2019, the U. S. Court of Appeals for the D. C. Circuit rendered a highly significant opinion with respect to state water quality certification under section 401 of the Clean Water Act (CWA). In Hoopa Valley Tribe v. FERC, the court rejected the commonly used workaround of the one-year statutory limit on state action by allowing multiple cycles of withdrawal-and-resubmittal of applications, holding that the States of Oregon and California had waived their authority by acceding to this practice. The attached article, just published in The Water Report, discusses the case in detail.

Section 401 provides that before a federal agency can approve a project that may result in a “discharge to the navigable waters” the applicant must obtain water quality certifications from the affected state. However, the state is deemed to have waived its delegated authority under section 401 if it “fails or refuses to act on a request for certification, within a reasonable period of time (which shall not exceed one year) after receipt of such request.”

Determining the water quality effects and appropriate mitigation for hydroelectric facilities that have been in place for over half a century is a complex undertaking. Additional study and data are often needed, which could take more than one year to complete. Moreover, since relicensing brings out a myriad of stakeholders seeking an opportunity to influence the next license term, 401 issues are frequently addressed through multi-party settlement negotiations, which can also take a long time to resolve. This has led state 401 agencies and applicants to enter into understandings under which the applicant would withdraw its application before the end of one year and then resubmit it to reset the clock. Such withdrawal-and-resubmittal cycles have often stretched over a period of many years.

The case at issue in Hoopa arises under a settlement agreement between the States of California and Oregon, PacifiCorp and other stakeholders leading to eventual removal of PacifiCorp’s Klamath River hydroelectric projects.  Such removal requires FERC approval, and thus water quality certification by the two states. The parties contemplated that this process would take years to complete and agreed that each year PacifiCorp would withdraw and resubmit its 401 applications to avoid waiver, but the new annual applications would be entirely unchanged from the previous ones. The D. C. Circuit was plainly put off by this common practice, and it is clear that the particular facts of this case drove the outcome.

The court’s holding has huge implications for owners of hydroelectric facilities going through the licensing or relicensing process at FERC. In the attached article, I describe the decision, the context in which it was reached, and what it might mean for the FERC and section 401 processes going forward.

More litigation is likely to come. Watch this space for updates.

Where Have All the Golf Balls Gone?

Posted in Environmental Quality

One of life’s eternal questions:  where do all those golf balls go that are hit into a water hazard?  If it was a pond, I knew the answer from my misspent youth – kids sneaking onto the premises at night fished them out of the ponds and sold them to other golfers.  But what about Pebble Beach?  Those balls went into the ocean!

Now we know that, too.  A diver and student at a nearby college removed nearly 30,000 golf balls from Stillwater Cove at Pebble Beach between 2016 and 2018.  The penalty strokes would be bad enough.  But the balls apparently disintegrate in the surf, contributing microplastic and chemicals to the ocean waters.  And she estimated that 1 to 5 million balls had been lost since the course opened in 1919.

The Pebble Beach Company has now made a five year commitment to undertake 198 annual dives to collect golf balls at 11 sites around the course.  And the college student who started this project has determined that some of the collected balls will become art – a representation of a barreling wave with a surfboard, to give one “the feeling of being barreled in a wave of trash.”  A lot of things we do for recreation can cause significant environmental harm.  Lead contamination at shooting ranges is one example where there is some substantial history of legal liability.  Golf courses with scenic and environmentally sensitive water hazards are becoming aware that they could be next.


Information referenced in this post can be found in Priyanka Runwal’s “Where did all these golf balls come from?

Washington State Aims for 100% Clean Electricity

Posted in Sustainability

The Washington State Legislature is completing work on major legislation that would require the state’s electric utilities to eliminate all greenhouse gas emissions from their generating fleet within the next quarter century.  Governor Jay Inslee, who is making climate change the focus of his recently-launched Presidential campaign, would undoubtedly sign the legislation with enthusiasm.

The bill, E2SSB 5116, passed the Senate on March 1 by a vote of 28-19, and is now making its way through the House.  Weighing in at 54 pages, it would establish a three-stage process.  First, utilities must eliminate their reliance on coal-fired resources by 2026.  Second, they must make their retail electricity sales greenhouse gas (GHG)-neutral by 2030.  Third, they must make their retail electricity sales using only non-emitting resources by 2045.  Failure to meet these benchmarks will result in a penalty of $60 (adjusted for inflation) for each megawatt-hour (MWh) of non-compliant electricity.

I. Background

This legislation builds on the state’s Energy Independence Act, a 2007 voter initiative that required utilities to increase their use of renewable energy to 15% by 2020.   It also attempts to overcome the failure of two subsequent voter initiatives, a 2016 measure that would have imposed a carbon tax, and a 2018 measure that would have imposed a carbon fee.  The failure of the 2018 measure is often touted by opponents of climate change legislation as evidence of voter skepticism toward such legislation, even in relatively liberal Washington State.

In an attempt to learn from prior defeats, the pending legislation does not rely on a tax or fee to incentivize behavior by putting a price on carbon emissions.  Instead, the Democratically- controlled Legislature is relying on an old-fashioned prescriptive approach, simply mandating that, with certain limited exceptions, electric utilities do whatever is necessary to achieve 100% clean electricity.  Thus, the legislation is less vulnerable to the charge that it is imposing an unpopular “energy tax,” even though the cost of utility compliance is ultimately borne by ratepayers.

II. Overview of the Legislation

Act I:  No Coal by 2026

The bill’s first step—eliminating coal-fired resources by 2026—is relatively simple because most of the heavy lifting has already been done.  Following years of intensive negotiations, two of the Northwest’s three coal-fired power plants are scheduled for closure: Oregon’s Boardman plant by 2020, and Washington’s Centralia facility by 2025.  That leaves only Montana’s Colstrip plant.  To facilitate withdrawal from Colstrip, the bill directs the Washington Utilities and Transportation Commission (WUTC) to allow rate recovery of all decommissioning and remediation costs prudently incurred as part of the withdrawal process.

Act II:  GHG Neutrality by 2030

Achieving GHG neutrality by 2030 is far more complicated.  As a starting point, the bill requires utilities to reduce or manage their retail load by pursuing all cost-effective, reliable, and feasible conservation and efficiency resources, and to use electricity from renewable resources and non-emitting electric generation in an amount equal to 100% of the utility’s average annual retail electric load.

Recognizing that moving to 100% renewables and non-emitting resources within 11 years would be very challenging for at least some utilities, the bill would allow them to satisfy 20% of that requirement through various alternative compliance options.  The simplest of the options would be to use renewable energy credits (RECs) or pay the $60 per MWh penalty, with RECs almost certainly being the less expensive choice.

A more creative but less certain path would be to invest in what the bill refers to as “energy transformation projects.”  In addition to traditional home weatherization and energy efficiency measures, energy transformation projects include support for electrification of the transportation sector and investments in distributed energy resources.

The electrification of the transportation sector is particularly important because it is the source of over 40% of Washington’s carbon emissions, the largest of any sector.  Under the bill, utilities would get credit for investing in infrastructure to connect more vehicles to the electric grid, and in the smart grid technology necessary to use the batteries in those vehicles as a form of energy storage.  This would, for example, allow utilities to charge car batteries at night when demand is low, and then draw upon those batteries during the day when demand is high, thereby reducing the need for additional generation to serve those high-load periods.

Act III:  100% GHG-free by 2045.

By 2045, the final step must be complete: all electricity sold to Washington retail electric customers must be from either non-emitting generation or renewable resources.  Again recognizing the ambitious nature of both the 2030 GHG-neutrality and 2045 GHG-free mandates, the legislation includes a safety valve.  The WUTC and the Department of Commerce would report bi-annually to the legislature on any impacts to system reliability.  If they find adverse impacts, the governor would have authority to delay the compliance deadlines in the bill until those reliability issues can be addressed.

Stay Tuned

Assuming this legislation becomes law later this session, we plan to unpack its many detailed components and their implications in later blog posts.  For example, how will this legislation mesh (or not) with California’s existing climate-related programs, and with the cap and trade approach currently being considered by the Oregon Legislature?  (For more on the Oregon bill, see this recent post by our colleague Derek Green.)  How will the bill affect investor-owned utilities differently from consumer-owned utilities?  How will it affect utilities that own hydropower facilities, by far the region’s largest source of renewable energy?  And how will it affect other participants in the electricity sector, such as large customers and those seeking to develop other renewables, such as solar, wind, or low-impact or pumped storage hydroelectric?

For now, you can track the bill on the Legislature’s website, and stay tuned here for more analysis.

FERC Reverses Course; Denies Tariff Waiver for Retroactive Collection of Transmission Upgrade Costs

Posted in FERC

The Federal Energy Regulatory Commission recently ruled that it lacks authority to waive tariff restrictions against retroactive adjustment of transmission service charges in order to enable a transmission provider to recover transmission upgrade costs from customers that benefit from such upgrades. In so doing, the FERC reversed an earlier decision in which it had granted such a waiver. Southwest Power Pool, Inc., 166 FERC ¶ 61,160 (2019).

FERC Initially Waived Tariff Restriction on Retroactive Bill Adjustment

Pursuant to the Open Access Transmission Tariff of the Southwest Power Pool, the costs of certain transmission network upgrades may be assigned directly to a customer whose transmission service request causes the network upgrade to be built (the sponsor). However, the sponsor may be entitled to revenue credits to offset such directly-assigned costs. Such revenue credits are funded by and recoverable from transmission customers taking new transmission service from SPP that could not have been provided but for the network upgrades in question. Under the Tariff, SPP collects credit payment obligations from new transmission service customers and disburses revenue credits to the sponsors until the amount of directly assigned costs has been reduced to zero.

Tariff sheets providing for direct assignment of transmission network upgrade costs and for associated revenue crediting were added to the Tariff by SPP in 2008. Nevertheless, for a variety of reasons, it was not until November 2016 that SPP began to collect the credit payment obligations from transmission customers and distribute those obligations to entitled upgrade sponsors.

In general, the Tariff requires adjustments to transmission service bills rendered by SPP to be made “within one year after rendition of the bill reflecting the actual data for such service.” Because SPP had not collected and remitted credit payment obligations prior to 2016 (other than in limited cases), SPP sought a waiver of the time limits on retroactive adjustment of transmission service bills so that it could bill responsible transmission customers from the date of the first impact on directly assigned upgrade costs and “claw back” revenues that were previously distributed to transmission owners. This waiver was granted by the FERC in July 2016.  Southwest Power Pool, 156 FERC ¶ 61,020 (2016) (the Waiver Order).

FERC Changed Its Decision After Ruling By Court of Appeals in Unrelated Case.

Following the issuance of an order denying rehearing, the Waiver Order was appealed to the U.S. Court of Appeals for the D. C. Circuit. While this appeal was pending, the Court affirmed a FERC ruling in an unrelated proceeding that Section 205 of the Federal Power Act bars the waiver of tariff limitations restricting retroactive adjustment of transmission service bills. Old Dominion Electric Coop. v. FERC, 892 F. 3d 1223 (DC Cir. 2018). Based on that ruling, the FERC sought a voluntary remand of the Waiver Order so that it could reconsider its earlier decision to grant a waiver to SPP. On remand, the FERC reversed the Waiver Order and denied SPP’s request.

FERC Concluded That Waiver Is Precluded by The Filed Rate Doctrine.

The Tariff provision imposing a one-year limitation on retroactive billing is deemed to be part of SPP’s filed rate schedule for transmission service. In its order denying the requested waiver, the FERC explained that it lacks statutory authority to waive the relevant provision because:

regulated utilities are forbidden to charge rates for services other than those on file with the Commission, a prohibition that has become known as the filed rate doctrine. The related rule against retroactive ratemaking also ‘prohibits the Commission from adjusting current rates to make up for a utility’s over- or under-collection in prior periods.’

The FERC further explained that “enforcing a tariff provision that places a time limitation on the correction of invoices (e.g., a time bar provision) is consistent with the filed rate doctrine,” regardless of the potential consequences. Because adjustment of bills for transmission service by SPP more than one year after the bill for such service was rendered is barred by the Tariff, the FERC refused to consider equitable considerations weighing in favor of the requested waiver:

We need not reach arguments that denial of SPP’s waiver request will result in extra litigation, including SPP’s statement that it may have difficulties recovering the money already paid out. Because we find that [the Tariff restriction] is part of the filed rate and that waiver of that provision under the circumstances here would violate the filed rate doctrine, such equitable considerations do not bear on our determination. For the same reason, we need not reach any of the parties’ cost causation, contractual, tariff violation, or equitable arguments.

Commissioners Cheryl A. LaFleur and Richard Glick submitted separate concurring opinions in which they stated that although they believe the result of the FERC order was inequitable, they supported the order based on their understanding that the FERC lacks the requisite statutory authority to grant the waiver.

FERC Found That Customers Had No Prior Notice of Potential Rate Adjustment.

The FERC recognized that although there may be a limit on the time during which bills for transmission service may be adjusted, that time limit is inapplicable if the affected ratepayers have sufficient notice at the time the original bill was rendered that the approved rate was subject to change. With specific regard to SPP, the FERC concluded that there was no evidence of any such notice to its transmission customers because (a) there was no prior agreement between SPP and the parties that were subject to the revenue crediting adjustment that their bills for transmission service might be adjusted at a later date, and (b) there was no pending judicial appeal that might have alerted parties to potential retroactive changes in the filed rate.

FERC Ordered Payment of Refunds To Remedy Its Error

In addition to reversing the Waiver Order and denying SPP’s request for waiver of specified Tariff provisions, the FERC ordered SPP to provide refunds, and to file a report detailing how it proposed to make the requisite refunds. The FERC did not specify how such refunds were to be calculated, but required the report to expand the record by providing detailed information affecting calculation of refunds, including “the amount of refunds of credit payment obligations paid and refunds of credit payment obligations received that each of the entities will receive for the historical period up to one year prior to the date SPP initially rendered bills to customers for credit payment obligations.” It therefore appears that the FERC may expect that SPP will recoup revenue credit payment obligations received by sponsors, thereby leaving all of the affected entities in the position they would have occupied if the waiver had never been granted.

RTOs/ISOs Urged To Consider Providing Greater Flexibility In Tariffs

In order to provide certainty to transmission service customers, many open access transmission tariffs contain limits on the time period during which bills for transmission service can be adjusted or corrected, similar to that in the Tariff. In a footnote to its order, the FERC contrasted the limitation against retroactive adjustment of bills in the Tariff with a provision in the New York Independent System Operator Inc.’s Market Administration and Control Area Services Tariff under which the FERC may order the reopening of an invoice after it is considered final, even if the RTO/ISO lacks the authority itself to adjust the bill.  See, e.g., GDF Suez Energy Resources, NA v. New York Independent System Operator, Inc., 149 FERC ¶ 61,257 (2014). Commissioners LaFleur and Glick encouraged RTOs/ISOs to consider adoption of language similar to that in the NYISO tariff to ensure that customers who benefit from transmission upgrades may be required to pay for them, and that upgrade sponsors can receive the funds to which they are otherwise entitled.

Seventh Circuit Affirms Both RCRA Liability and Denial of Injunctive Relief

Posted in Rulemakings, Water Law

In LAJIM LLC v. General Electric, in both the district court and on appeal, the plaintiff both won and lost. The U.S. Court of Appeals for the Seventh Circuit readily affirmed the federal district court’s grant of summary judgment under the Resource Conservation and Recovery Act (RCRA) to a down-gradient golf course operator who alleged that solvents from a now-closed GE facility had contaminated groundwater that migrated from the plant site to plaintiff’s property. However, the appellate court also affirmed the lower court’s determination that no injunctive relief should be ordered in the absence of any evidence that plaintiff’s injury was not already being addressed under an order implemented by the Illinois Environmental Protection Agency (IEPA), and affirmed dismissal of state law tort claims for damages as time-barred.

From the facts, this appears to be one of those frequent cases where a neighbor or citizen group files a citizen suit because it is unhappy with the pace and/or approach of a state cleanup.  IEPA had filed suit over the contamination from the former GE facility in 2004, and had been working with GE ever since to implement a cleanup. The plaintiff had bought the down-gradient property in 2007 with knowledge that contamination had reached the first tee, but understood that no further remediation was required. While there had been significant progress, GE had been attempting to obtain acceptance of a remediation program relying heavily on monitored natural attenuation and institutional controls for the remaining groundwater plume.

As the IEPA-supervised remediation dragged on, the plaintiff filed its own suit in 2013, alleging both RCRA claims for injunctive relief and tort law damage claims. Surprisingly, there is no discussion in the opinion of an effort to dismiss the RCRA action under the provision of RCRA barring citizen suits where a state action is pending. In any event, after “extensive discovery,” plaintiff obtained summary judgment on RCRA liability, while losing a cross motion for dismissal of the tort claims as time-barred. The court then denied plaintiff’s request for injunctive relief directing cleanup under RCRA, after taking it under advisement for two years.

On appeal, the Seventh Circuit held that while RCRA authorized injunctive relief, it did not require it, despite the finding of an imminent and substantial endangerment, as required for RCRA liability:“[t]he remedy of an injunction does not issue as a matter of course upon a finding of liability but only as necessary to protect against otherwise irremediable harm.” Slip Opinion, p. 30. In determining appropriate relief under RCRA, a court considers the same balancing factors as otherwise applied to requests for injunctions. In this case, the plaintiff’s expert would not state what additional remediation was required, but only opined that further investigation was required.  GE’s expert, on the other hand, explained why the additional investigation was unnecessary or potentially harmful, and the IEPA filed an amicus brief opposing an injunction as providing over-lapping and potentially inconsistent cleanup obligations. The appellate court refused to second-guess the district court on its assessment of the expert testimony.  It also affirmed dismissal of plaintiff’s tort claims on statute of limitations grounds.

This result is a pyrrhic victory for plaintiffs, a finding of liability, but no money damages under the tort claims and no injunction under RCRA. RCRA does not provide for damages, but does allow a request for attorney’s fees by a prevailing plaintiff, and LAJIM, LLC might try for that since there was a finding of liability. However, a fee award, like injunctive relief, is within the district court’s discretion. The moral here may be that you can’t always get what you want, even if you are right, especially if you don’t make it clear what you are asking for and why.

FERC Chairman Neil Chatterjee Announces Ambitious Agenda for Addressing Electric Industry Regulatory Issues

Posted in FERC

FERC Chairman Neil Chatterjee has announced an ambitious agenda for addressing a myriad of regulatory issues affecting the wholesale electricity industry during 2019. In remarks delivered during the NARUC 2019 Winter Policy Summit, Chairman Chatterjee observed that “the energy landscape in the United States is currently undergoing a dramatic and historic transformation,” and identified some of the major actions that the FERC may take during 2019 to facilitate this transformation. These remarks reiterate comments by Chairman Chatterjee in a 2018 year-end podcast which is posted on the FERC website. Although Chairman Chatterjee’s focus was on actions under consideration by the FERC, he observed it might be necessary for the FERC to collaborate with state regulators in order to achieve some of its regulatory objectives. Read more here.


Pending issues affecting wholesale electricity markets that Chairman Chatterjee expects the FERC to address during 2019 include the following:

PURPA. First and foremost on Chairman Chatterjee’s agenda is alignment of the implementation of the Public Utility Regulatory Policies Act of 1978 with the modern energy landscape. PURPA provided for the establishment of a class of wholesale generators known as Qualifying Facilities, and the adoption of rules under which a regulated electric utility may be required to purchase electricity from a QF at rates reflecting the purchaser’s avoided cost of electricity it would otherwise obtain from alternative sources. Certain practices adopted by the FERC to implement PURPA were reviewed during a June 2016 Technical Conference on Implementation Issues under PURPA in FERC Docket No. AD16-16-000. Among the actions being considered by Chairman Chatterjee are the possibility of providing more flexibility and market-driven pricing of electricity sold by QFs; the potential to foster development of new QFs in locations where they are most needed; and the possible reduction in administrative burdens and costs associated with PURPA.

Distributed Energy Resources. Potential reforms to eliminate barriers to participation of energy storage and distributed energy resources (DERs) in the competitive wholesale electricity marketplace were discussed in Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators, 157 FERC ¶ 61,121 (2016). Subsequently, the FERC hosted a technical conference to examine market design, reliability, and other challenges associated with participation of such resources in the wholesale electricity marketplace. Chairman Chatterjee expects that the FERC can now proceed to remove barriers to integration of energy storage and DERs so that consumers are better able to enjoy the benefits of electricity from such resources.

Grid Resilience and Cyber Security. In this modern era, the delivery of electricity to consumers may be affected not only by forces of nature, but also by acts of terrorism or cyber-attacks by foreign nations. Concerns have been raised that the closure of existing coal-fired and nuclear generating stations for economic reasons may have weakened the ability of the electric system to withstand these forces. The FERC has announced that a technical conference will be held in Docket No. AD19-13-000 in June 2019 to discuss policy issues related to the reliability of the bulk power system.

In Grid Resilience in Regional Transmission Organizations and Independent System Operators, 162 FERC ¶ 61,012 (2018), the FERC sought to develop a record on the risks of such forces to the bulk power system and possible ways to address those risks in the changing electric markets. Chairman Chatterjee believes that as the FERC considers actions to protect the resilience of the electric grid, it will need to weigh the cost of potential service disruptions against the benefits of additional reliability that might result from enhanced system security.

In Cyber Security Incident Reporting Reliability Standards, 164 FERC ¶ 61,033 (2018), the FERC directed the North American Electric Reliability Corporation to facilitate improved awareness of existing and future cyber security threats and potential vulnerabilities by augmenting the reporting of Cyber Security Incidents, including incidents that might facilitate subsequent efforts to harm the reliability of the bulk electric system. Submittal of the proposed rules by NERC is due early this year, so Chairman Chatterjee expects to review them during the year ahead.


In addition to resolution of matters currently pending before the FERC, Chairman Chatterjee believes the FERC may revisit the following transmission policies that are currently in effect:

Transmission Rate Incentives. Following enactment of the Energy Policy Act of 2005, the FERC offered financial incentives in Order No. 679, such as enhanced rates of return on common equity, to encourage transmission developers to undertake beneficial transmission projects that are subject to increased financial risks. Chairman Chatterjee stated that “[t]he time is ripe for the Commission to step back and ask whether we’re actually incenting the type of transmission that we need or if there are smart changes we should make to encourage what is needed in light of today’s realities.” Such review follows the FERC’s modification in Coakley v. Bangor Hydro Electric Co., 165 FERC ¶ 61,030 (2018), of its methodology for determining the base return on equity that transmission owners may use to calculate transmission service rates.

Order No. 1000. In Order No. 1000, the FERC required each transmission provider to participate in a regional transmission planning process that produces a regional transmission plan, and to improve coordination with neighboring transmission planning regions. The FERC intended Order No. 1000 to foster competition among transmission developers for the right to construct new transmission facilities to meet regional and inter-regional transmission needs.  Chairman Chatterjee observed that “everyone seems to agree that Order 1000 is not working as intended,” but there is no consensus on how to fix it. In his view, the ideal solution lies in greater competition that results in lower costs of new transmission facilities and promotes more technically advanced solutions to transmission needs.


In addition to these major programmatic issues to be addressed, the FERC has other work to do. The FERC has before it, either initially or on rehearing, a number of contested proceedings involving participants in the wholesale electricity market – some of which have been pending for more than a year – that cannot be resolved by the FERC Staff on delegated authority. The FERC also is tasked with the regulating hydroelectric power plants and natural gas pipelines. This extensive workload associated with other matters impacts the ability of the Commissioners to focus on the complex policy questions affecting the wholesale marketplace discussed by Chairman Chatterjee.

At the same time, the FERC is significantly handicapped by recent changes in membership which may affect its operation as a collegial body. Although the FERC nominally is comprised of five commissioners, there is a vacancy due to the recent death of former FERC Chairman Kevin McIntyre. Commissioner Bernard L. McNamee, who was sworn in late last year, has refrained from participating in a number of FERC orders. Additionally, the term of Commissioner Cheryl A. LaFleur will expire in June, and she is no longer seeking another term. As a result, there will soon be a second vacancy to be filled.

Perhaps significantly, the FERC is now comprised of two Republicans (Chairman Chatterjee and Commissioner McNamee), and two Democrats (Commissioners LeFleur and Glick). This even split of FERC Commissioners along party lines affects the FERC’s ability to resolve controversial issues. For example, the FERC recently was unable to act on a petition for relief by Vineyard Wind LLC in a timely manner because it lacked a majority of votes for a particular action. See, Statement of Cheryl A. LaFleur and Richard Glick issued Feb. 4, 2019 in Docket No. ER19-570-000. It therefore is not clear whether and to what extent the FERC may proceed to follow the agenda laid out by Chairman Chatterjee until a full complement of commissioners has been restored.

Observing the rise of renewable energy resources and new technologies, the development of competitive electricity markets, and the evolution of consumer preferences, Chairman Chatterjee declared that “it’s an exciting time to be at the Commission.” Members of DWT’s Energy Practice Group agree, and will be following developments on these critical issues closely on behalf of interested entities as the year unfolds.

Newly Proposed Guidelines Offer Opportunities for Energy Storage Developers in California

Posted in California
Close-up view of electric DC battery in row. Accumulator batteries connected plus and minus. Direct current storage.

On February 26, 2019, Administrative Law Judge Stevens of the California Public Utilities Commission (CPUC) issued a proposed decision (Proposed Decision) ruling on the applications for programs and investments in energy storage systems submitted by the state’s three investor-owned utilities (IOUs) pursuant to Assembly Bill (AB) 2868. The Proposed Decision rejected a number of energy storage programs proposed by San Diego Gas & Electric Company, Pacific Gas and Electric Company, and Southern California Edison Company, including each IOU’s proposed front-of-the-meter energy storage program. To address the applications’ deficiencies, the Proposed Decision issued guidelines on how the IOUs must seek future approvals for front-of-the-meter energy storage projects. If adopted, these guidelines should lower competitive barriers and present new opportunities for storage developers to bid into competitive solicitations on a more neutral playing field.

AB 2868, passed in 2016, directed the CPUC to encourage the IOUs to “accelerate widespread deployment of distributed energy storage systems” by adding up to 500 megawatts (MW) of new storage capacity. Accordingly, the CPUC directed each IOU to incorporate proposals for programs and investments for up to 166.66 MW of distributed energy storage systems into their 2018 energy storage procurement plants. In early 2018, each IOU filed its application for up to 166.66 MW of new storage projects, which included behind the meter as well as front-of-the-meter projects.

The Proposed Decision accepts certain aspects of each IOU’s application, but rejects a number of proposed programs including each IOU’s front-of-the-meter investment proposal. To help the IOUs gain approval for future front-of-the-meter investment proposals, the Proposed Decision includes a set of guidelines to better ensure that the IOUs’ future AB 2686 applications for energy storage projects comply with CPUC requirements.

These new guidelines require the IOUs to procure energy storage through a competitive solicitation process involving requests for offers (RFO). The guidelines state that IOUs may only procure energy storage resources that are cost effective and meet a least-cost, best-fit criteria.

The guidelines go on to address a number of areas in which the Proposed Decision considered the IOUs’ applications deficient. In particular, the guidelines require the IOUs to consider all forms of resource ownership rather than providing preference to utility-owned projects. The guidelines require the IOUs to evaluate RFOs without bias towards any ownership model. They also mandate that each IOU employ an independent evaluator to assess the competitiveness and integrity of its solicitation. The independent evaluator must prepare a detailed post-solicitation report that the IOU must submit to the CPUC as part of its application for approval. The guidelines also provide a detailed list of information each IOU must include in each application to the CPUC.

The Proposed Decision’s guidelines represent an opportunity for front-of-the-meter energy storage projects to compete on a more even playing field. Storage developers will benefit from the mandated competitive solicitation process as well as the increased flexibility in ownership structures. Developers had argued that the IOUs’ prohibition of independent ownership structures excluded otherwise competitive storage projects proposed by experienced developers. One developer even went so far as to identify an existing third-party owned project that had the ability to provide the same benefits as a project owned by San Diego Gas & Electric Company but was rejected because it was not utility-owned.

Parties are permitted to file comments on the Proposed Decision, and it will then be reviewed by the CPUC at the earliest at its March 28, 2019 Business Meeting.

Any questions regarding the Proposed Decision or the potential commercial storage opportunities it may present can be directed to DWT energy attorneys Patrick Ferguson ( and Will Friedman (

Energy Efficiency Resource Advocates Challenge ISO-New England Attempt to Reduce Compensation

Posted in FERC, Sustainability

Energy efficiency resource advocates recently petitioned FERC to block an attempt by the ISO New England to reduce the compensation paid for energy efficiency in its Forward Capacity Auctions. Advanced Energy Economy and Sustainable FERC Project, FERC Docket No. EL19-43-000, Petition for Declaratory Order filed Feb. 13, 2019.

Energy efficiency resources are products such as lighting, HVAC systems, and appliances that use less energy than conventional products. By reducing energy consumption, these products reduce the amount of generating capacity that ISO-NE needs to procure thorough its annual Forward Capacity Action in order to maintain reliable electric service in the region.

Each New England state has adopted financial incentives for its residents to use energy efficiency resources. The ISO-NE Tariff permits an energy efficiency resource program administrator to aggregate the reduction in capacity needs in New England resulting from energy efficiency, and to bid that capacity reduction into each Forward Capacity Auction conducted by ISO-NE. As a result, providers of energy efficiency resources that are successful bidders into a Forward Capacity Auction are compensated for the reduction in regional capacity needs that they provide in the same manner as generators are compensated for providing capacity.

The Petitioners allege that ISO-NE historically has calculated the capacity value of energy efficiency resources based on how much they reduce energy consumption below that which would result from the use of products that only comply with state and federal standards.They further allege that ISO-NE staff intends to change that methodology to one that reduces the capacity value of energy efficiency resources by as much as 65 percent. The Petitioners suggest that the new methodology would instead compare reductions in energy consumption from use of energy efficiency resources to what would have occurred in the absence of the financial incentives provided by the states. In other words, ISO-NE would compensate only for the net savings resulting from the financial incentives.

The Petition raises two interesting questions:

  1. Is it reasonable for ISO-NE to change from measuring capacity associated with energy efficiency resources based on total reduction in energy consumption below that based on compliance with state and federal energy efficiency standards to measuring capacity reductions based on net energy savings?

The Petitioners argue that ISO-NE should not be allowed to abandon its existing compensation methodology for one that would substantially reduce the compensation of energy efficiency resources. Moreover, they believe that the change would have an adverse effect on ratepayers:

The measurement and verification changes proposed by ISO-NE…would substantially impact the energy efficiency market in New England, reducing the value of energy efficiency resources in the FCM, driving up prices, and ultimately forcing ratepayers to pay higher prices.

The Petitioners also suggest that the existing method of measuring the capacity reduction associated with reliance on energy efficiency resources is easier to implement than that being discussed by ISO-NE. Under the current methodology, there is no requirement for bidders to demonstrate that the energy efficiency resources were installed for any particular reason.

In contrast, the Petitioners believe that providers of energy efficiency resources would not be compensated for capacity reductions under the methodology proposed by ISO-NE unless the energy efficiency resource providers could prove that their qualified resources “were installed by consumers only because of the providers’ efficiency programs,” a much more stringent test than a simple comparison to the amount of electricity that would have been consumed under state and federal energy efficiency standards.

The Petition suggests that the ISO-NE Staff has not yet fully developed it alternative compensation methodology. As the discussion proceeds, ISO-NE presumably will explain why it believes a methodological change is appropriate.

  1. May ISO-NE change the method for measuring capacity reductions associated with use of energy efficiency resources without first making a filing with the FERC pursuant to Section 205 of the Federal Power Act?

Insofar as it appears from the Petition, there is nothing in the ISO-NE Tariff or in any of ISO-NE’s business practice manuals which prescribes the method by which the capacity reductions associated with the use of energy efficiency resources should be determined for the purpose of the Forward Capacity Market. Instead, this method has evolved over time based on discussions among stakeholders in New England.

Nevertheless, the Petitioners assert that because “ISO-NE has consistently applied this long-standing approach and approved gross savings as an appropriate measure for the capacity value of efficiency resources,” this methodology may not be modified without a rate change filing at the FERC under Section 205 of the Federal Power Act. A declaratory order finding that ISO-NE may not change the methodology without first making a filing with the FERC pursuant to Section 205 of the Federal Power Act would give Petitioners and other interested parties a forum at the FERC in which to contest the proposed changes.

Petitioners are concerned that energy efficiency resources relied on the existing methodology when they participated in the recently completed Forward Capacity Auction. Because rate changes under Section 205 of the Federal Power Act generally may not be made effective retroactively, a ruling that a rate change filing is required would preclude ISO-NE from using a different methodology to reduce the payments to energy efficiency resources that participated in that Forward Capacity Auction.

The Petitioners also believe that a Section 205 filing would lead to the establishment of clear, uniform rules regarding the compensation paid to energy efficiency providers. Petitioners have asked the FERC to act on the Petition on or before April 12, 2019, so that providers of energy efficiency resources planning to participate in the next Forward Capacity Auction in New England will have the benefits of that decision before they are required to submit a Show of Interest form to participate in that auction. Presumably to accommodate this request, the FERC has established March 7, 2019 as the deadline for submittal of petitions to intervene and protests in this proceeding.

DWT’s Energy Practice Group will be following this proceeding closely on behalf of interested entities.

Oregon Legislators Publish Priority Cap and Trade Legislation

Posted in Cap and Trade, Climate Change

wind turbines in the Oiz eolic parkThe Oregon legislature’s Joint Committee on Carbon Reduction has introduced HB 2020, a highly anticipated bill that would establish a cap-and-trade system to significantly reduce greenhouse gases attributable to sources within the state. The bill, prepared by the Joint Committee led by Senator Michael Dembrow of Portland and Representative Karin Power of Milwaukie, aims to reduce the state’s greenhouse gas emissions to 45 percent below 1990 levels by 2035, and then to 80 percent below 1990 levels by 2050.

The ambitious legislation, which comprises over 50 pages of text, is a high priority of both the Democratic leadership in the state legislature and of Governor Kate Brown, who made cap-and-trade legislation a promise of her successful campaign for reelection in 2018. As proposed, the bill would have a significant effect on a wide range of industries throughout the state. To implement the program, the bill would establish a new Carbon Policy Office and the need for new rulemaking by a number of agencies.

HB 2020 aims to achieve the state’s carbon reduction goals by establishing a firm cap on emissions starting in 2021; the cap would then be reduced annually by a tonnage amount calculated to meet the program’s emission reduction goals. As the cap took effect, market forces would shape who may continue to pollute, based on which emitters are willing to pay at auction for the state-issued allowances needed to emit greenhouse gases. Some of the highest-emitting market participants, like public utilities, would initially receive a certain amount of allowances without paying for them, but would see these so-called “direct allocations” reduced annually at the same rate as the program’s overall emissions cap. Regulated entities would also be permitted to achieve up to eight percent of their compliance obligation through carbon “offset projects” with verifiable impacts.

The program would directly impact a large portion of Oregon’s economy. Covered emissions would include those produced by transportation fuels like gasoline and diesel (but excluding fuels for aviation, watercrafts, and trains), which represent the largest portion of Oregon’s greenhouse gases. Other regulated emissions include those resulting from electricity generated within the state (and electricity imported for use in the state), emissions resulting from natural gas supplied for use in Oregon buildings, and emissions from large industrial sources, including certain manufacturing processes and landfills.

Proceeds from the sale of emissions allowances would be used to invest in projects that advance the transition to a low-carbon economy. For example, some of the proceeds would be deposited into a “Just Transition Fund” to assist Oregonians who lose their jobs due to emissions reduction efforts. Other proceeds from the program would be invested in projects that mitigate the impacts of climate change or that help adapt to those impacts. With a nod to specific provisions within the state’s constitution, the legislation designates certain transportation-related proceeds to a new account within the State Highway Fund, and other proceeds to the Common School Fund.

The bill establishes a mechanism for direct Supreme Court review to evaluate anticipated legal challenges on two issues in particular: Whether the legislation is subject to the constitution’s revenue-raising requirements, and whether the legislation’s use of revenue is in conformance with the constitution’s Highway Funds requirement.

The Joint Committee on Carbon Reduction has included a trove of information about the proposed legislation on its website, which features a helpful FAQ page and a summary of the policy’s core elements.

Children’s Climate Crusade Litigation: Trump Administration Files Opening Brief in 9th Circuit

Posted in Climate Change, Trump Track

The Juliana v. U.S. climate change litigation (better known as part of the Children’s Climate Crusade) is back in the spotlight. The case was filed in Oregon U.S. District Court in 2015 on behalf of future generations to force governmental action on climate change. In a previous post from November 2016, our colleague Rick Glick considered whether Trump’s election would bring greater urgency and likelihood of success to Juliana and similar attempts to address climate change through the courts. We’re now one step closer to finding out, as the battle before the Ninth Circuit began in earnest with the filing of the government’s opening brief last Friday seeking dismissal of the case.

This follows more than two years of dramatic pre-trial skirmishing. On November 10, 2016, Judge Aiken denied the government’s motion to dismiss the complaint, concluding that: “Federal courts too often have been cautious and overly deferential in the arena of environmental law, and the world has suffered for it.” In response, the government took the extraordinary step of asking the U.S. Supreme Court and the Ninth Circuit to terminate the case. When both courts declined, the government returned to again seek dismissal from Judge Aiken, but she declined to do so last October 15. Then, only days before the beginning of a scheduled 10-week trial, the government finally won a reprieve when Judge Aiken certified an interlocutory appeal to the Ninth Circuit, putting the trial on hold while the Ninth Circuit decides if the case should be dismissed.

Last Friday’s brief tees up four primary issues that will determine whether the case eventually goes to trial:

  1. Are the plaintiffs’ climate grievances sufficiently specific to constitute a “case or controversy”?

First, the government argues that the plaintiffs lack standing because their allegations do not constitute a “case or controversy” under Article III of the Constitution. According to the government, plaintiffs “have only a generalized grievance and not the required particularized injury because global climate change affects everyone in the world.” As a result, the government argues that the plaintiffs “cannot plausibly connect their narrow asserted injuries — like flooding or drought in their neighborhoods — to any particular conduct by the government.” The government also argues that the court cannot remedy the claimed injuries, another requirement of standing.

This is a high hurdle for the plaintiffs. The government argues that a single federal judge should not be allowed to “seize control of national energy production, energy consumption, and transportation” in ways that would address the alleged harms.

  1. Must the plaintiffs’ claim conform to the requirements of the APA?

The second issue is whether a claim that the federal government is not doing enough to control carbon emissions must fit within the constraints of the Administrative Procedure Act. Under the APA, one may appeal specific governmental decisions, but the Juliana plaintiffs take a much broader approach, arguing that the federal government must develop and implement a national plan to stabilize the climate system.

  1. Do future generations have a Constitutional right to a stable climate?

The third issue is the most interesting: whether future generations of Americans have a Constitutional right to a stable climate. In this regard, the plaintiffs rely on the Fifth Amendment’s Due Process Clause, which provides that “No person shall be . . . deprived of life, liberty, or property, without due process of law.”

Judge Aiken agreed that there is a fundamental Constitutional right to a “climate system capable of sustaining human life,” and held that the plaintiffs had adequately alleged infringement of that right. To this the government’s brief responds bluntly: “Plaintiffs’ alleged fundamental right to a ‘livable climate’ finds no basis in this Nation’s history or tradition and is not even close to any other fundamental right recognized by the Supreme Court.” However this issue is decided, the consequences for future climate change litigation will be enormous.

  1. Does a failure to adequately limit carbon emissions violate the public trust doctrine?

Finally, the plaintiffs have invoked the public trust doctrine, a rather amorphous body of law that—where applicable—obligates a government to protect resources needed for future generations. Judge Aiken accepted this theory, concluding that the federal government has a duty to maintain a healthy climate for the benefit of the public. Among other arguments, the government counters that the public trust doctrine is a matter of state law, and is not applicable to the federal government.

Next steps 

The plaintiffs’ responsive brief is due on February 22, 2019, and the government’s reply is due by March 8, 2019. Oral argument has not yet been scheduled.

Down the road, Juliana will very likely end up before the Supreme Court, where the plaintiffs’ prospects appear fairly grim, but a lot can happen between now and then. With the impacts of climate change increasingly evident, how will the courts respond to the fact that the other two branches of the federal government are doing nothing, and that President Trump calls climate change a hoax? Will judges stick to a more traditional approach and let the other two branches eventually figure it out (or not)? Or does prolonged inaction by the other branches potentially move the judicial branch to take a broader, more assertive approach to an urgent problem?

Only time will tell; stay tuned for future updates.

FERC Issues Order Protecting Its Jurisdiction Over Wholesale Power Agreements of Bankrupt Utility

Posted in FERC

PG&E Gate Access to Field with Power Lines

The Federal Energy Regulatory Commission has ruled that if any party purchasing electricity pursuant to a FERC-jurisdictional wholesale power agreement proposes to reject that contract as part of a reorganization under the Bankruptcy Code, such party, “must obtain approval from both this Commission and the bankruptcy court to modify the filed rate and reject the contract, respectively.” NextEra Energy, Inc. v. Pacific Gas and Electric Company, 166 FERC ¶ 61,049 (2019); see also, Exelon Corp. v. Pacific Gas and Electric Company, 166 FERC ¶ 61,053 (2019).

Pacific Gas and Electric Company has announced that it expects to file a petition for reorganization under Chapter 11 of the Bankruptcy Code in the near future. The FERC’s orders are intended to preserve the FERC’s jurisdiction over wholesale power agreements such as those governing purchases of power by PG&E, and to deter a bankruptcy court from permitting PG&E to reject or modify such contracts without FERC authorization.

Conflicting Precedent Regarding the Authority of the Bankruptcy Courts vs. FERC

There have been conflicting court decisions regarding the authority of bankruptcy courts to permit public utilities to reject executory wholesale power agreements without first obtaining FERC authorization under the Federal Power Act. NextEra Energy, Inc., Exelon Corp., and EDF Renewables, Inc. each sell electricity to PG&E under FERC-jurisdictional wholesale power agreements. In anticipation of the possibility that PG&E might seek to have a bankruptcy court enjoin the FERC from exercising its authority over rates for sales of electricity at wholesale, each of those sellers asked the FERC to affirm that if PG&E files a petition for bankruptcy, PG&E may not abrogate, amend, or reject in bankruptcy any of the rates, terms and conditions of its wholesale power agreements subject to FERC jurisdiction without first obtaining FERC approval under Sections 205 and 206 of the Federal Power Act.

In its decisions, the FERC acknowledged that the law regarding its authority over modification of wholesale power agreements where a party to such agreements has sought protection of the bankruptcy courts is unsettled. The FERC also noted that it has broad authority under the Federal Power Act over rates and charges for the sale of electricity at wholesale, and exclusive authority to determine the reasonableness of such rates. After review of both the Federal Power Act and the Bankruptcy Code, the FERC concluded that the “Commission and the bankruptcy courts have concurrent jurisdiction to review and address the disposition of wholesale power contracts sought to be rejected through bankruptcy.” The FERC further explained that “rejection of a Commission-jurisdictional contract in a bankruptcy court alters the essential terms and conditions of the contract and filed rate; thus, this Commission’s jurisdiction is implicated and our approval is required.”

FERC Assertion of Authority May Mitigate Impact of PG&E Bankruptcy

The potential impact of a PG&E bankruptcy on its existing wholesale power agreements is not entirely clear. PG&E’s announcement of its intention to seek bankruptcy protection stated that one of its goals is to “support the orderly, fair and expeditions resolution of PG&E’s potential liabilities resulting from the 2017 and 2018 Northern California wildfires.” There was no suggestion that PG&E might be using the bankruptcy process to reduce its wholesale purchased power expense.

Each of the petitioners noted that in bankruptcy proceedings, the debtor has initial responsibility to determine which contracts should be rejected, and its decision generally is reviewed by the bankruptcy court under the “business judgment rule.” In contrast, the FERC has authority under the Federal Power Act to consider whether modification or termination of a wholesale agreement is in the public interest. The FERC’s ruling that it and the bankruptcy court have concurrent jurisdiction to review and address the disposition of wholesale power contracts sought to be rejected through bankruptcy may be expected to give sellers additional protections against premature termination of their wholesale sales agreements.

Since other power suppliers may be in the same position as NextEra and Exelon, the FERC stated in a footnote to the NextEra order that its jurisdictional position is the same with regard to other wholesale power contracts that PG&E may seek to terminate or modify through bankruptcy.

Exelon and EDF Renewables noted in their respective petitions that rejection of existing wholesale power agreements by PG&E would put the continued financial viability of the electricity suppliers from which it is purchasing electricity at risk, and could have a chilling effect on investments in new generating facilities. Therefore, the FERC may have been concerned with the potential adverse impact on wholesale electricity markets in the West if PG&E was able to modify or terminate significant long-term wholesale power agreements without first obtaining FERC authorization.

QF Contracts Not Addressed

A significant issue not addressed in the FERC orders is whether FERC approval will be required for modification or termination of power purchase agreements to which PG&E is a buyer where the seller is a Qualifying Facility under the Public Utility Regulatory Policies Act of 1978. The FERC explained in the orders that it sought to protect the authority over rates and charges for sale of electricity at wholesale which was granted to it under Sections 205 and 206 of the Federal Power Act. However, the FERC regulations state that certain agreements under which QFs sell electricity to electric utilities are exempt from FERC scrutiny under those sections of the Federal Power Act. Because the FERC relied on Sections 205 and 206 of the Federal Power Act as authority to assert jurisdiction over modification or termination of wholesale power agreements of a bankrupt utility, it is at least arguable that the bankrupt utility may reject agreements which are not subject to FERC scrutiny under those provisions without first obtaining FERC authorization to do so.

SCOTUS, Denying Cert, Subjects Exxon to Broad Massachusetts Climate Investigation

Posted in Climate Change, Oil & Gas

Yesterday, by refusing to hear an appeal from Exxon Mobil (see docket), the U.S. Supreme Court declined to protect the oil giant from handing over decades of climate change-related documents to the Massachusetts Attorney General.

Back in 2015, InsideClimate News and the L.A. Times each ran multiple stories digging into Exxon’s knowledge of climate science and regulatory risk back to the 1970s. The Attorneys General of Massachusetts and New York soon thereafter launched investigations into Exxon’s potential deception of investors and the public regarding the risks of climate change.

Massachusetts demanded that Exxon hand over documents about its scientific knowledge and messaging on climate change as far back as 1976. Exxon resisted, arguing that the Massachusetts Attorney General lacked personal jurisdiction over Exxon. In January, 2017, the Massachusetts state trial court rejected Exxon’s arguments and granted the Massachusetts Attorney General’s motion to compel Exxon’s compliance. Last April, the Massachusetts Supreme Judicial Court affirmed the trial court.

That loss left the U.S. Supreme Court as Exxon’s last hope, and Exxon petitioned for certiorari in May. With yesterday’s denial of certiorari, SCOTUS leaves Exxon no apparent option but to comply.

In the meantime, New York has wrapped up its investigation and sued Exxon, alleging that it defrauded investors by hiding the risks of climate change. For complete, up-to-date summaries of these and other major climate change lawsuits, check out InsideClimate News’s timeline.

FERC Rejects Notice of Termination Despite Breach of LGIA

Posted in FERC

The Federal Energy Regulatory Commission (FERC) recently rejected a notice of termination of a large generator interconnection agreement (LGIA), despite finding that the interconnection customer had breached the terms of the agreement. The interconnection customer failed to make scheduled interim payments toward the estimated cost of interconnection facilities and network upgrades, as required under the LGIA. Duke Energy Florida, LLC, 165 FERC ¶ 61,230 (2018). In this rejection, the FERC explained that the transmission provider had not shown that a significant increase in the estimated cost of installing and constructing the interconnection facilities and network upgrades after the LGIA had been executed was just and reasonable.

In March 2011, Duke Energy Florida (Duke Energy) agreed to purchase the output of a biomass electric generation facility being developed by U.S. EcoGen Polk, LLC (USEG Polk) for a term of approximately 30 years. Subsequently, in June 2015, Duke Energy and USEG Polk entered into an LGIA (Polk LGIA) pursuant to which USEG Polk is responsible for the costs of interconnection facilities and network upgrades needed for interconnection of that generation facility to the Duke Energy transmission system.

The Polk LGIA provided for Duke Energy to send invoices monthly to USEG Polk based on the estimated costs of the interconnection facilities and network upgrades. At the time the Polk LGIA was executed, the estimated cost of the interconnection facilities and network upgrades was $1,720,000. However, the estimated cost of these facilities was increased by Duke Energy thereafter, to approximately $3.9 million in March 2017, and again to $6.2 million in August 2017.

The FERC concluded in the order that USEG Polk was in breach of the Polk LGIA because it was undisputed that USEG Polk had failed to pay invoices dated May 14, 2018 and June, 12 2018 for the estimated costs to procure, install, and construct the interconnection facilities and network upgrades identified in the Polk LGIA and it had failed to cure the breach after being given written notice. As a result of this breach, Duke Energy argued that it had the right to declare a default and terminate the Polk LGIA.

In its order, the FERC concluded that, because Duke Energy had failed to demonstrate that the increase in estimated costs of the interconnection facilities and network upgrades from $1,720,000 to more than $6 million over the course of approximately two years was just and reasonable, it was unable to determine whether Duke Energy had met its burden under Section 205 of the Federal Power Act to show that the notice of termination was just and reasonable. Therefore, the FERC rejected the notice of termination of the Polk LGIA and ordered an investigation under Section 206 of the Federal Power Act concerning the justness and reasonableness of the increased estimate in the costs of interconnection facilities and network upgrades. Presumably, Duke Energy’s right to terminate the Polk LGIA will be determined at the conclusion of that investigation.

Also in its order, the FERC rejected the suggestion by USEG Polk that the costs of the interconnection facilities and network upgrades for which USEG Polk was responsible might somehow be limited on the basis of the initial cost estimate prepared by Duke Energy. In so doing, the FERC explained that “the costs in an LGIA are simply estimates and that interconnection customers are responsible for paying the actual costs of interconnection facilities and network upgrades” unless a transmission provider voluntarily adopts a fixed price or cost cap based on its estimate.

FERC Proposes to Reduce Information Burdens on Certain Market-Based Rate Sellers of Electricity

Posted in FERC
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In a Notice of Proposed Rulemaking dated December 20, 2018, the Federal Energy Regulatory Commission is proposing to reduce the burden on certain entities that sell electricity into organized wholesale electricity markets at market-based rates.

At the present time, each entity proposing to sell electricity at market-based rates in wholesale electricity markets must include two FERC-prescribed preliminary horizontal market power screen analyses in its application for FERC authorization. These analyses are used by the FERC to assess whether the seller has the ability to exercise horizontal market power to increase wholesale electricity prices in relevant geographic markets. Thereafter, each entity with market-based rate authority must submit updated market power screen analyses every three years.

The FERC is proposing to eliminate these filing requirements for sellers participating in energy, capacity, and ancillary services markets administered by any Regional Transmission Organization or Independent System Operator that has FERC-approved RTO/ISO market monitoring and mitigation procedures. In addition, sellers that participate in RTOs and ISOs that operate only energy and/or ancillary services markets, but not capacity markets, would no longer be required to submit indicative market power screen analyses unless the sellers desired to sell capacity at market-based rates.

The FERC has adopted a rebuttable presumption that FERC-approved rules for monitoring and mitigating the exercise of market power in RTO/ISO-administered wholesale electricity markets are sufficient to address market power concerns. The proposed rules would permit sellers in RTO/ISO-administered energy, ancillary services and capacity markets to rely on that presumption in lieu of submitting detailed indicative market power screen analyses. However, the presumption would be subject to challenge under appropriate circumstances.

There currently are two RTOs/ISOs that do not have organized capacity markets within the regions in which they operate—the Southwest Power Pool and the California Independent System Operator. Thus, CAISO and SPP currently do not have FERC-approved market monitoring and mitigation procedures in place for capacity sales. The NOPR reflects FERC’s belief that rules for day-ahead and real-time energy markets administered by CAISO and SPP may be sufficient to protect consumers against the potential exercise of market power in the supply of energy and ancillary services.

As part of the NOPR, the FERC would eliminate the presumption that market monitoring and mitigation procedures in CAISO and SPP are sufficient to address horizontal market power concerns for capacity sales in those markets. Therefore, under the proposed rules, sellers operating in CAISO and SPP that desire to sell capacity (either as a bundled or unbundled product) at market-based rates would need to submit the indicative market power screens. However, the NOPR includes an exception for operators of wind-powered and solar-powered generating facilities within CAISO and SPP, which would not have to submit indicative market power screen analyses.

The FERC has asked for comments on whether either CAISO or SPP currently has adequate safeguards in place to prevent the exercise of horizontal market power in sales of capacity.

Comments on the NOPR will be due 45 days after it has been published in the Federal Register.

Second Phase to Reform “Exit Fees” Paid by CCAs Begins

Posted in California

We have previously discussed on this blog the California Public Utilities Commission’s (“CPUC”) decision in its Power Charge Indifference Adjustment (“PCIA”) proceeding. (see post 1 and post 2). The CPUC’s recent decision deferred to a second phase the development of a long-term solution to the PCIA or “exit fee” charged by California’s large investor-owned utilities (“IOUs”) on customers who begin taking electric service from community choice aggregation programs (“CCAs”).

The second phase has now begun, with nearly a dozen parties filing responses to questions posed by the CPUC to help it establish a “working group” process that will enable parties to further develop a number of proposals for future CPUC consideration. The CPUC proposed four topics for consideration in working groups: (1) Benchmark True-up, including both Resource Adequacy (“RA”) and Renewables Portfolio Standard (“RPS”); (2) Prepayment; (3) Portfolio Optimization and Cost Reduction; and (4) Allocation and Auction.

The CPUC will hold a prehearing conference on December 19, 2019 for parties to discuss their recommendations for the working group process, which will inform the scope the CPUC adopts for Phase 2. Below is a high-level categorical summary of party recommendations.

Number and Scope of Working Groups

Several parties have supported using the working groups specified by the CPUC. Others supported consolidating the Portfolio Optimization and Cost Reduction working group and the Allocation and Auction working group into a single group.

A number of parties proposed additional working groups, such as the Forecasting and Bill Presentation working groups proposed by the California Community Choice Association (“CalCCA”), which represents CCAs throughout the state; the Procurement Review Group and Independent Evaluator Process Reforms working group proposed by Protect Our Communities; and a miscellaneous” working group to address issues such as retail cost allocation, rate design, and bill presentation proposed by several parties including the IOUs.

Three northern California based CCAs – Peninsula Clean Energy, Marin Clean Energy, and Sonoma Clean Power (collectively, the “NorCal CCAs”) – recommended that the Commission initiate a separate track, which they referred to as the “Unavoidable and Attributable” Track, to determine (1) whether costs included in the PCIA to date were avoidable and/or were not attributable to departed customers and (2), if so, how an appropriate recompense should be structured, including whether such recompense should come from utility shareholders.

Governance of Working Groups

Several parties, including the IOUs and CalCCA, recommended that each working group be co-chaired by representatives from both a utility and a non-utility load-serving entity.  Another party recommended that only one party be assigned the facilitator role for each working group and if an IOU was not given this role, then an IOU should be appointed as a “deputy” facilitator. Some parties recommended that Energy Division staff should facilitate and/or be assigned to assist the working groups, whereas others recommended that Energy Division should not play a role in facilitation or management.

Schedule and Timelines

Parties generally agreed with the CPUC’s proposal to issue a proposed decision addressing each working group’s recommendations by September 2019 and proposed subject-specific tasks, milestones, and deliverables for each working group to accommodate this timeline.

Only one party supported the Energy Division facilitating a single “kick-off” workshop for the purpose of forming each of the proposed working groups. The majority of parties stated that they did not think such a workshop was necessary.

Several parties, including all CCA groups, the IOUs, and the Public Advocates Office, among others, supported prioritizing  the RA and RPS benchmark true-up working groups since the outcomes will have immediate and direct impacts on the PCIA calculation approved in the decision issued in Phase 1 and it must be completed in time for integration in the IOUs’ next Energy Resource Recovery Account (“ERRA”) proceedings that are used to determine which fuel and purchased power costs can be recovered in rates.

The Norcal CCAs recommended a schedule to address its proposed separate “Unavoidable and Attributable” Track discussed above.

Evidentiary Hearings

A couple parties stated evidentiary hearings are necessary, others contended they are not, and several stated that it is premature to know whether hearings will be necessary. A couple recommended avoiding hearings if possible and others recommended retaining the right to request hearings if working groups are unable to reach consensus. One party recommended that each working group recommend whether evidentiary hearings are necessary.

Appropriate Category for Phase 2

The majority of parties recommended that Phase 2 be categorized as ratemaking. Only one party recommended it be categorized as a rulemaking. The IOUs stated they were amenable to either a rulemaking or ratemaking categorization.

Discovery Issues

The IOUs recommended the Commission issue guidance strictly limiting further discovery in Phase 2 to information material to structures and processes to avoid unwarranted delay. The NorCal CCAs requested a clear determination that past portfolio management and forecasting are within scope of Phase 2 and that the Commission will require timely and responsive answers to data requests on those issues. Several parties recommended that Phase 1 non-disclosure agreements (“NDAs”) should be used for discovery in Phase 2, although one party recommended use of NDAs should be discouraged so as not to restrict certain working group member’s ability to participate fully in group deliberations.

Residential Solar Developers and Investors Seek Regulatory Clarity from FERC

Posted in FERC

As the costs of residential solar photovoltaic (PV) systems fall and installations rise, developers and investors face new regulatory hurdles. Registration as a qualifying facility (QF) under the Public Utility Regulatory Policy Act (PURPA) recently has become a common subject of concern among both developers and tax equity investors. Developers are working to determine whether they are triggering compliance obligations, and investors are asking whether they have to register by virtue of their ownership interests. One solar developer, SunRun Inc., is seeking clarity at the Federal Energy Regulatory Commission (FERC).

PURPA, among other things, grants generators that meet the eligibility requirements for QF status an exemption from most regulations under the Public Utility Holding Company Act of 2005, the Federal Power Act, and state laws respecting the regulation of utilities. Under FERC’s regulations, the owner or operator of a QF with a net power production capacity greater than 1 megawatt (MW) must either submit a self-certification to FERC or file an application for certification. QFs under the 1 MW threshold are exempt from FERC’s filing requirement. The complication for residential solar developers comes in determining whether the 1 MW threshold has been met.

FERC calculates the size of a facility by examining its power production capacity together with the capacity of any other facilities that use the same energy source, are owned by the same person(s) or its affiliates, and are located at the same site. FERC considers facilities “at the same site” if they are located within one mile of each other. If multiple facilities located within a one-mile radius are owned by the same person or its affiliates, their capacities will be aggregated for PURPA purposes.

FERC’s capacity aggregation rule leads to problems for solar developers, particularly developers of residential PV systems. As developers install tens or hundreds of thousands of small PV systems, it becomes increasingly difficult to determine whether a developer owns or operates more than 1 MW of aggregated capacity within a one-mile radius. This is particularly true in high concentration areas like California. Additionally, tax equity investors are concerned that they may own more than 1 MW of capacity within one mile and be required to register with FERC. Tax equity investors generally do not have the means to track such thresholds, relying instead on the developer – and developers rarely track capacity between portfolios – so investors are put at risk of violating PURPA unknowingly.

In September, SunRun filed a petition at FERC in Docket No. EL18-205 seeking a waiver of the QF filing requirements for residential solar PV systems, irrespective of whether such systems aggregate to over 1 MW within a mile. The waiver request is limited to solar PV systems (and accompanying battery systems) of 20 kilowatts or less that are located on the property of a residential homeowner. According to SunRun, the waiver would apply to over 150,000 systems within its portfolio totaling 1,106 MW of capacity. SunRun argues that without the waiver, the QF self-certification would be unduly burdensome for developers and would result in voluminous and unhelpful information for FERC. While several parties filed comments asking that FERC address PURPA issues in a more generic proceeding, no one has strictly opposed SunRun’s requested waiver. FERC is likely to act on the petition by spring of 2019.

If FERC grants the requested waiver, it will alleviate compliance concerns for residential solar developers and tax equity investors. However, it will not apply to all solar PV systems, and developers and investors will still need to track the concentration of larger systems. Additionally, it may lead to implementation questions, such as how to address a situation where a developer owns a larger commercial-scale solar project located within one mile of smaller residential-scale projects that in the aggregate surpass the 1 MW threshold. SunRun’s petition is not the end of PURPA compliance questions, but it is a good place to start.

CPUC Set to Open a New Rulemaking to Decide When a Utility Can Turn Off Power in Dangerous Conditions

Posted in California

On December 13 the California Public Utilities Commission (“CPUC”) will vote on whether to open a new rulemaking to determine when an electric utility can de-energize power lines in cases of dangerous conditions that threaten life or property in California.

The CPUC is considering this new proceeding because California is experiencing unprecedented wildfire events. While the CPUC has granted utilities the authority to proactively shut down power to specific power lines in an effort to reduce the risk of wildfires started by utility equipment, utilities have been wary to do so. Part of the utilities’ caution is due to the negative consequences of leaving communities and essential facilities without power. Among other issues, this new proceeding will aim to identify a balance between reducing wildfire risk through de-energization and protection for vulnerable communities.

We anticipate that this new proceeding will be one of many at the CPUC that will address wildfire prevention and mitigation. Indeed, less than seven weeks ago the CPUC opened up another proceeding related to electric utility wildfire mitigation plans in response to. The CPUC will also host California’s first Wildfire Technology Innovation Summit in March 2019.

Congress to Consider Carbon Fee Legislation

Posted in Federal

Bi-partisan legislation under which a fee would be assessed on production or importation of certain fossil fuels as a means of reducing greenhouse gas emissions has recently been introduced in the U.S. House of Representatives by Rep. Ted Deutch (D-FL), and co-sponsored by Reps. Brian Fitzpatrick (R-A), John Delaney (D-MD), Francis Rooney (R-FL) and Charlie Crist (D-FL). Under this legislation, entitled the Energy Innovation and Carbon Dividend Act of 2018 (H.R. 7173), the fee would be collected, in the case of coal, from coal mining operations in the U.S. and importers of coal; in the case of crude oil, from refineries in the U.S. and importers of petroleum products; and, in the case of natural gas, from any entity supplying natural gas into the natural gas transmission system, and any importer of natural gas. This legislation has been referred for consideration to the House Ways and Means Committee, as well as the House Committees on Energy and Commerce and Foreign Affairs.

Most experts agree that greenhouse gas emissions from sources in the United States and elsewhere are contributing to adverse changes to the climate, with the potential to cause flooding along the coasts of the United States and an increase in storm violence. The goal of the legislation is to encourage market-driven innovation of clean energy technologies and market efficiencies which will reduce harmful pollution. The legislation resembles closely a proposal for reduction of greenhouse gas emissions that was endorsed by former Secretary of State James A. Baker III and other prominent Republicans in February 2017.

Imposition of a fee on enterprises contributing to the level of greenhouse gas emissions in the U.S., such as that proposed in the Energy Innovation and Carbon Dividend Act of 2018, is intended to create financial incentives for affected businesses to reduce their reliance on fossil fuels with high greenhouse gas content in an economically efficient manner. The concept has been touted as a free-market solution to climate change, and, if enacted, the legislation would provide an alternative to the complex administrative program for regulating greenhouse gas emissions through the Clean Power Plan, implementation of which has been delayed indefinitely.

Notwithstanding the recognition that increased emission of greenhouse gas during the latter half of the 20th Century has caused adverse climate changes, voters have been reluctant to support adoption of fees as a means of reducing greenhouse gas emissions. In the November 2018 elections, voters in Washington State rejected a ballot initiative that would have imposed a fee on carbon dioxide emissions, presumably because the fee would have resulted in higher energy prices. The Energy Innovation and Carbon Dividend Act of 2018 is designed to overcome this reluctance by providing for distribution of substantially all of the revenues collected through the carbon fee on a pro-rata basis, primarily to adults who are citizens or residents of the United States, to offset any potential increase in energy prices.

Although there is bi-partisan support for the Energy Innovation and Carbon Dividend Act of 2018 in the House of Representatives, it is unlikely that this legislation will be enacted in the near future. Even if the legislation is approved by the House of Representatives, there is no indication that the legislation would be able to gain support in the Senate and signed into law by President Trump. Nevertheless, the introduction of this legislation in the House, and associated Congressional hearings designed to illuminate the problems caused by climate change and the potential for mitigating those problems in an economically efficient manner, might lead to enactment of similar legislation in the future.


Structuring Supply Chain Agreements: New Guidance on Prop 65 Compliance [Webinar]

Posted in California


December 4, 2018

1:00pm-2:30pm EST
10:00am-11:30am PST


Please join Davis Wright Tremaine’s Kerry Shea on December 4 for a CLE webinar in which she will present on a three person panel discussing the impact of California’s Proposition 65 on supply chain agreements. The panel will provide practical guidance on drafting (or amending) supply agreements to ensure compliance with the new regulation and explore how counsel representing manufacturers, producers, importers, and suppliers in both the up- and downstream supply chain can structure language to balance risk and mitigate potential losses from noncompliance.

For more information and 50% off registration, please click here.

Supreme Court Decides Critical Habitat Must Be Habitat

Posted in ESA, Federal

In a unanimous decision (with Justice Kavanaugh not participating), the Supreme Court on November 27, 2018, remanded a controversial Endangered Species Act (ESA) decision for further consideration by the Fifth Circuit Court of Appeals. Weyerhaeuser v. U.S. Fish and Wildlife Service (FWS) The Court held that “critical habitat” must be “habitat.”

The Court agreed that the ESA did not require that the designated area have members of the species living on it when the determination is made. It did not directly rule on the scope of the term “habitat,” leaving that for the lower court. However, its discussion implies, while not directly ruling, that the area must be able to support recovery of the endangered species without the need for improvements. It also concluded that decisions by the FWS on whether to exclude areas from critical habitat designation on economic grounds are subject to judicial review.

The case involved the dusky gopher frog, which currently lives in Mississippi in areas of longleaf pine forests, with ephemeral ponds. Most of that habitat has disappeared, endangering the species. Because the frogs are currently found only in a few areas of Mississippi, the FWS designated not only those areas, but also a 1500 acre area in Louisiana as critical habitat. The record shows the frogs do not now live on the Louisiana parcel and could not survive as a sustainable population, unless the forested area was modified. The courts below held that FWS acted within its discretion in designating areas that would require modification to support the species, and declined to review the FWS determination that the area should be excluded as critical habitat in balancing the costs and benefits.

On remand, it appears the question will not be bright line. At the Supreme Court, FWS conceded that critical habitat must be habitat, but argued that the frog could survive in the Louisiana habitat, although recovery of a sustainable population would require modification of some of the forest area. A distinction, but one the court of appeals may find less than compelling when it also considers whether the FWS was arbitrary in its decision to designate the area as critical despite the potential $33MM cost to the owners if the land cannot be developed.

It had been expected that the Supreme Court would place limitations on the exercise of discretion in the designation of critical habitat. It did, but did not go as far as some may have hoped. That is likely the price of obtaining a unanimous court.

Could Pairing Storage + Renewables Change a Qualifying Facility’s Status?

Posted in FERC

The Federal Energy Regulatory Commission (FERC) is currently considering whether pairing energy storage with a wind power project could change that facility’s status in FERC Docket No. EL18-195-000. In August 2018, Northwestern Energy petitioned FERC to revoke qualifying facility (QF) status from four Beaver Creek Wind II, LLC (“Beaver Creek”) wind-plus-battery projects under the Public Utility Regulatory Policies Act (PURPA). FERC has limited experience squaring energy storage with PURPA. In the 1990 case Luz Development and Finance Corp., FERC found that a battery storage project could receive QF status. Specifically, FERC found that “battery system[s] … are a renewable resource for purposes of QF certification” and battery storage facilities may be certified as QFs, subject to meeting PURPA’s fuel use requirements. FERC now must consider whether wind generation facilities paired with storage should be treated as a single QF and if so, how a QF’s aggregate capacity should be calculated.

Congress enacted PURPA in response to the U.S. energy crisis of the early 1970s, seeking to promote conservation and increased use of domestic renewable energy resources. The latter purpose was accomplished by creating a class of qualifying “small power production” and “cogeneration” facilities eligible to receive special rate and regulatory treatment (i.e. QFs). A facility is eligible to be a “small power production” QF if its primary energy source is renewable (hydro, wind or solar), biomass, waste, or geothermal and 75 percent or more of the total energy input is from these sources. Additionally, a small power production QF’s capacity must not exceed 80 MW.

In calculating a QF’s power production capacity, the aggregated capacity of other small power production facilities is also included if those facilities use the same energy resource; are owned by the same person or its affiliates; and are located at the same site. In determining whether two or more facilities are located at the same site, FERC’s regulations specify that a facility located within one mile of the facility for which QF status is sought is deemed to be “located at the same site.”

In its petition, Northwestern Energy argues that Beaver Creek’s integration of energy storage results in the wind projects exceeding the 80 MW capacity limit for QF status. Beaver Creek argues that each of the paired projects can be considered a single QF because they will be controlled by software systems that ensure the storage facilities are only charged by wind energy from the adjacent turbines and each project’s total power discharge would be less than 80 MW. Beaver Creek further argues that battery storage “simply provides a time-shifting of the wind production and not additional generation.”

While this petition is pending, FERC is also considering a more comprehensive review of PURPA. In testimony before the Senate Committee on Energy and Natural Resources, Chairman McIntyre directed FERC staff to re-initiate a review of FERC’s policies under PURPA, which will build on the record that FERC already developed and allow for additional robust stakeholder input. Time will tell if, or how, FERC will integrate its review of QF treatment of energy storage paired with wind into its comprehensive review of PURPA.

Marine Pollution: A Continuing Problem

Posted in Environmental Quality

International efforts to reduce marine pollution are bearing fruit, according to a press release issued by INTERPOL on November 13. But it’s a big problem that won’t go away soon. Is it really that bad? Yes. Is it just a problem in U. S. waters? No. It’s international.

Those of us who regularly read environmental reports, especially those involving marine transportation, cannot help but be struck by the frequent reports of criminal prosecutions, often settlements or court orders involving seven figure fines, for falsification of discharge log books and use of mystery pipes discharging waste water to marine waters.

INTERPOL established a global network of law enforcement and environmental agencies, and customs and port authorities, resulting in an international investigative effort code-named “30 Days at Sea” to bring attention to marine pollution. In December 2017, INTERPOL issued its first report of a coordinated enforcement effort by agencies from 43 countries over the month of June 2017. That effort resulted in the detection of 1.5 million tons of illicit waste, and 664 cases, involving 483 individuals and 264 companies.

The coordinated program was repeated in the month of October 2018, with 58 countries participating. 5200 inspections resulted in 185 investigations and detected more than 500 offenses, a slight decrease from 2017. These included discharges of oil and garbage from vessels, shipbreaking, pollution on rivers, and land-based runoff to the sea, with arrests and prosecutions anticipated.

It is often said in response to stories of marine releases, that “it’s a big ocean.” It is a big ocean, but we also live in a highly polluted world. “Small” discharges from ships in the ocean from thousands of vessels and miles of coastline mount up. Polluted beaches and islands of microplastic debris the size of Texas in the open sea have made it clear that dilution is no solution to marine pollution. In the US, the authorities have tried to use multiple criminal prosecutions to deter misconduct. Other countries have also ramped up enforcement. The lower 2018 numbers may suggest some progress. But these two reports make it clear that there is still a ways to go.

Trump Track: Presidential Memo to Boost Western Water Projects—Can It Succeed?

Posted in ESA, NEPA, Trump Track
The Keystone Dam in Oklahoma with all the gates open and flowing a lot of water. Shot at Twilight.

On October 19, President Trump issued a “Memorandum Promoting the Reliable Supply and Delivery of Water in the West.” The memorandum calls for streamlining federal water infrastructure development and operations, apparently by skirting environmental and other administrative processes. As previously noted, the administration is intent on weakening the laws controlling federal water projects, but that cannot be accomplished by executive fiat alone.

At the core of the memorandum is a directive to the Secretaries of the Interior and Commerce to designate, within 30 days, “one official to coordinate the agencies’ [Endangered Species Act (ESA)] and [National Environmental Policy Act (NEPA)] compliance responsibilities” and to “develop a proposed plan, for consideration by the Secretaries, to appropriately suspend, revise, or rescind any regulations or procedures that unduly burden the project beyond the degree necessary to protect the public interest or otherwise comply with the law.”

What It Means

This directive evinces a misapprehension of the legal framework, and continues a failed approach to regulatory change by shortcutting federal law.

First, Cabinet departments are not monolithic entities; they are made up of multiple sub-agencies, each with its own statutory guidelines. Among others, Interior includes the Bureau of Reclamation, which builds and operates the water projects, and the U.S. Fish and Wildlife Service, which has responsibility for resident fish and terrestrial species. BOR is the lead agency for NEPA, while the FWS is a reviewing agency of BOR’s work, and serves an independent consulting role under the ESA. The only role of Commerce is through NOAA Fisheries, an agency within Commerce with responsibility for anadromous fish and marine mammals.

While the agencies can and do coordinate to a certain extent, they have discrete legal functions and responsibilities. A single officer to coordinate these disparate activities seems impracticable.

Second, the administration’s overarching approach to loosening environmental rules is to rescind, suspend, or delay implementation of environmental regulations that it believes impede the economy. However, time and again the courts have found such actions to violate the Administrative Procedures Act or other statutes. See, for example, the decision of a federal judge in South Carolina earlier this year invalidating “suspension” of the Waters of the U. S. (WOTUS) rule, or the D. C. Circuit’s rejection of extending the effective date of the Chemical Disaster Rule. Implementation of the memorandum is likely to meet the same fate.

Bringing efficiency to a convoluted, expensive, and protracted process is a laudable goal, but one that has eluded previous administrations. The problem is that the APA and the environmental protection laws are not designed for efficiency, but to make sure that the government has considered the potential impacts of its actions before implementation. Without an act of Congress, efficiency gains will be at the margin.



Clarification of OSHA’s Position on Workplace Safety Incentive Programs and Post-Incident Drug Testing

Posted in Federal

On October 11, 2018, OSHA issued interpretive guidance designed to “clarify” controversial language in the Preamble to the anti-retaliation provisions in the recordkeeping and reporting amendments adopted by the Obama OSHA Administrator in 2016. The Preamble, which can be cited as authority in contested OSHA matters, suggested that employer safety-incentive programs are generally suspect because, in OSHA’s view, they incentivize workers not to report injuries/illnesses (or put peer pressure on co-workers not to report) and suggested that post-incident drug-testing was facially grounds for proving retaliation against workers for reporting injuries/illnesses.

Read the full analysis here.

CPUC Approves Controversial Decision to Reform “Exit Fees” Paid by CCAs

Posted in Electric Power, Renewables
Power lines course through the hills east of San Francisco Bay

On October 11, by a 5-0 vote, the California Public Utilities Commission (CPUC) approved Commissioner Peterman’s alternate proposed decision to reform the Power Charge Indifference Adjustment (PCIA). The PCIA fee is comprised of financial obligations the utilities made on behalf of customers to build power plants and, more commonly, enter into long-term power purchase contracts with independent power producers. The PCIA appears as a line item on most Californians utility bills, and is meant to compensate the utilities for electricity generation built or contracted in the past at prices that are now above-market.

The unanimous decision of all five commissioners comes as a bit of a surprise, because this proceeding has been hotly contested and the other proposed decision authored by Administrative Law Judge (ALJ) Roscow was heavily supported by many parties, including Community Choice Aggregators (CCAs). Given that Commissioner Peterman authored the alternate decision and President Picker had been working with her on drafting it, it was much clearer what their final votes would be. But heavy lobbying of the other three commissioners (including by the mayors of San José, Oakland, and San Francisco) to vote in favor of the ALJ’s decision instead of Commissioner Peterman’s alternate decision was apparently unsuccessful.

The CCAs believe the alternate decision will stifle CCA development in California in the short term because the PCIA fee will increase significantly, making it harder for CCAs to offer clean energy to their customers at prices cheaper than the existing utilities. The CPUC estimates that CCA residential customers in PG&E’s territory departing in 2018 will see a 2% increase in their bills as the result of today’s decision (departing customers in Southern California Edison and SDG&E’s service territories will see 2.5% and 5% bill increases, respectively).

A long-term solution to the high-priced renewable contracts that necessitated the PCIA fee (including a possible replacement of the PCIA) remains necessary and will be the subject of a second phase of the proceeding that will commence later this year. Commissioner Peterman will complete her term as a commissioner at the end of the year and speculation is rampant that President Picker may not serve out his term, so the commission’s composition may significantly alter the outcomes of this second phase. Furthermore, given the likelihood that the California legislature will also weigh in on the PCIA during its next session, the PCIA war seems likely to continue for the foreseeable future.

The final decision has not yet been issued, but the most recent version of the Peterman Alternate Proposed Decision that was issued can be found here.

Third Circuit Decides That “All Costs” Means “All Costs”

Posted in CERCLA

Courts have often noted that CERCLA is not a model of drafting excellence, and that some of the statute’s definitions are simply tautologies, e.g., that an owner means an owner. In Commonwealth of Pennsylvania Dept. of Env. Protection v. Trainer Custom Chemical, decided in 2016, we reported in this space that the district court had provided a unique twist on that definition, holding that the current owner under CERCLA meant the owner at the time response costs were actually incurred. It therefore held that the party holding title at the time of the litigation was not liable for response costs incurred by the PaDEP prior to that owner’s purchase of the property. The district court noted that while CERCLA liability is broad, “strict liability is not limitless.” Not surprisingly, the PaDEP immediately sought an interlocutory appeal.

On October 5, 2018, in PaDEP v. Trainer Custom Chemical, the Third Circuit ruled on that appeal, reversing the district court. The decision did turn on the clear meaning of the language of CERCLA, but not the meaning of “owner” – there was no question that the defendant was the current owner. It turned on “all costs.” Stating that Section 107(a) of CERCLA makes the owner of a facility liable for all costs of removal or remedial action, the court observed that “this is a statement of remarkable breadth, but a statute may be broad in scope and still be quite clear….The term ‘all costs’ means just that,” regardless of whether incurred before or after the defendant took ownership. Thus ends another quirky effort to find a way out of the entanglements of Superfund liability.

Three Circuits Set Up CWA Application to Groundwater for Supreme Court Test

Posted in Water Law

There have been five circuit court decisions in 2018 addressing the application of the Clean Water Act (CWA) to discharges reaching navigable waters through groundwater. The year started with a decision by the Ninth Circuit which, addressing discharges through groundwater from an injection well, held that where there was a direct hydraulic connection between the point source and the navigable water, the fact that the discharge traveled through groundwater from the point source did not preclude CWA liability. Hawai’i Wildlife Fund v. County of Maui. That decision was followed a similar holding by the Fourth Circuit in a case involving discharge from a broken pipeline through groundwater to a nearby creek. Upstate Forever v. Kinder Morgan Energy Partners.

Then in September, three appellate decisions addressing discharges from coal ash ponds ruled in each instance that there was no CWA violation. Sierra Club v. Virginia Electric & Power Company (“VEPCO”), a subsequent Fourth Circuit decision, affirmed in part and reversed in part a district court decision finding VEPCO liable for unpermitted discharges to navigable waters through groundwater from a coal ash landfill and settling ponds. VEPCO had not challenged the lower court’s finding that there was a direct hydraulic connection to the navigable water through groundwater, and the court accepted without discussion that such a connection was sufficient to establish liability under the Clean Water Act, based on the earlier Fourth Circuit decision in Upstate Forever. However, the court went on to reverse the district court’s finding of CWA liability on a different basis, concluding that the CWA requires discharge from a “point source” – defined as a ”discernible, confined and discrete conveyance,” and that as so defined, a settling pond (and implicitly, a landfill) is not a device for conveyance, and hence not a “point source.”

Then, on September 24, 2018, the Sixth Circuit issued two opinions – Tennessee Clean Water Network v. TVA and Kentucky Waterways Alliance et al v. Kentucky Utilities Company — in citizen suits addressing coal ash ponds, holding categorically in both cases that the CWA covered only direct discharges from point sources to navigable waters, with no movement through an intervening medium, rejecting the “direct hydraulic connection” rationale. Both opinions also noted that they doubted the existence of a point source in the case of the coal ash ponds, quoting at length the ruling by the Fourth Circuit in Sierra Club.

This battle has been a long time coming, as it has become more and more apparent that control of the standard “point sources” is far from sufficient to produce clean rivers and streams. Over the years, courts addressing the application of the CWA have maneuvered along the spectrum from requiring clear conduits to accepting hydraulic connections. The issue of conflicting RCRA and CWA application is a red herring. As the dissents in the Sixth Circuit opinions  point out, the rationale in the majority opinions would extend far beyond discharges from coal ash plants that are already regulated under RCRA. Congressional action is a pipe dream. But with these five decisions the stage appears set for a Supreme Court resolution. Let’s just hope that the result is actually a resolution, not another Rapanos.

California Court Holds Public Trust Doctrine Applies to Groundwater Impacts on Surface Streams

Posted in California, Water Law

In Environmental Law Foundation v. State Water Resources Control Board, the California Court of Appeal for the Third District on August 29, 2018 affirmed a district court’s application of the Public Trust Doctrine to the impact of groundwater wells on the Scott River in Siskiyou County. The case has far-reaching implications for groundwater use in California, undermines the measured implementation groundwater management provided in the Sustainable Groundwater Management Act (SGMA), and is a further extension of public trust principles into appropriative water law.

The parties had previously narrowed the factual and legal questions and requested relief to expedite an appeal, leaving this decision as simply a request for declaratory relief on the application of the Public Trust Doctrine to the extraction of groundwater. Specifically, the legal question was whether, in issuing groundwater well permits, the County had a duty to consider the public trust impacts.

The Public Trust Doctrine, derived from English common law, provides that some resources are so central to the public good that governments can never convey them outright. The doctrine was imported to the U.S. in the 1892 case of Illinois Central Railroad v. Illinois, holding that the public interest in tidelands along the Chicago lakefront prevents unfettered private property rights. The doctrine was applied for the first time to appropriative water rights in the 1983 National Audubon Society v. Superior Court case, in which the California Supreme Court held that vested water rights held by the City of Los Angeles are subject to continuing state authority to address harm to Mono Lake associated with diversions of tributaries.

Unlike other Western states, California has no permit system for groundwater. Instead, overlying landowners have “correlative rights” to aquifers. In the face of record drought and overdrafting of groundwater basins, in 2014 California enacted SGMA. That law directs local entities in critical areas to develop management plans to prevent overdraft over 20 years, subject to state approval. By now super-imposing the Public Trust Doctrine, this case may undermine the efficacy of the SGMA planning process.

The decision has potentially great impact on the application of SGMA to agricultural interests throughout California, opening the door to litigation from environmental groups concerned about environmental harm from reduced stream flows. The full impact of the decision, assuming it survives further appeal or a legislative fix, could be quite large, as environmental groups in California, including the lead plaintiff in the case, have not been shy about adopting an aggressive litigation posture.

Recent DOE Audit Spurs Modernization of FERC.Gov

Posted in FERC

Controversies over natural gas pipeline siting and construction have turned the Federal Energy Regulatory Commission (FERC) into a newsmaker in recent years. As public awareness concerning pipeline projects grows, more members of the public are turning to the FERC’s website (, to understand how FERC evaluates pipeline certificate applications and to get updates on the status of individual applications.

Concerned that FERC is not yet ready for this challenge, a May 2018 Department of Energy (DOE) audit of FERC’s gas pipeline certificate process concluded that FERC’s website needs revamping to provide greater transparency and more timely public access to all project-related information. Specifically, DOE faulted for not containing a step-by-step flow chart or a comprehensive narrative of the entire natural gas certificate process. But although FERC Chairman Kevin McIntyre immediately committed to implementing DOE’s recommendation, the pipeline process flow charts available on FERC’s website today remain those first posted several years ago.

An important element of is the eLibrary portal, the FERC’s official public document repository for all FERC submissions and issuances. eLibrary is now 20 years old and it is generally agreed that it is in need of reliability improvements (a too frequent complaint is that eLibrary is down, yet again). It also lacks search functionality – its user interface is overly complex and searches do not always provide accurate and/or complete results.

DOE also had criticisms for eLibrary.  Its design, search functionality/reliability and limited ease of use, DOE concluded, makes it “challenging” for the public to assess the status of pending applications even when using appropriate search criteria. Another problem noted by frequent eLibrary users, although not addressed in the DOE audit, is that many older (pre November 2000) documents accessible only via eLibrary are scanned images of paper documents that are often illegible and are not maintained in any readily usable electronic format. In responding to the DOE Audit, Chairman McIntrye offered December 2018 as an estimated completion date for planned improvement to certain eLibrary search functions, but it is unlikely that a complete revamp of this interface can be completed in such a short time frame.

In the short term, FERC is giving first priority to reliability and resiliency upgrades to eLibrary by the purchase of new servers to enhance system reliability. In the longer term, according to its FY 2019 Congressional Performance Budget Request,  FERC has requested $10.1 MM and $6.7 MM in IT capital investments for FY 2018 and 2019 respectively, to continue a transition to a cloud-based service modernization of its entire website. This modernization is intended to improve usability, content, navigation and design and to make the site mobile friendly and to place content in the cloud, further enhancing reliability. Another element being addressed in the modernization effort is improved cyber security. No definitive timetable for completion of any of these actions is offered, but the FERC suggests it likely will require at least three years (through FY 2020).

Clean Diesel Engines

Posted in EPA

According to the EPA, about 10,000 semi-truck glider kits are sold in the U.S. each year. Glider kits consist of new truck bodies fitted with remanufactured or salvaged engines and transmissions that do not use exhaust gas recirculation and do not require exhaust gas after-treatment. Because of this, an EPA study in 2017 found that NOx emissions were as much as 43 times higher on glider kit vehicles than on compliant trucks. Particulate matter emissions were up to 450 times higher.

Under the Obama administration, glider kits were to be limited to 300 per year in 2018. In July 2018, the EPA announced it was exercising its enforcement discretion in 2018 and would not enforce the 300 per-year kit cap. An environmental coalition and 16 state attorney generals filed requests for review by the U.S. Court of Appeals for the District of Columbia claiming that not enforcing the glider provisions in the 2016 Phase 2 heavy truck greenhouse gas rule would allow thousands of glider trucks on U.S. roadways. The court quickly issued a temporary stay of the EPA Nonenforcement Plan. Then, on July 26, acting EPA Administrator, Andrew Wheeler, reversed the controversial decision so the polluting trucks are once again an endangered species.

Trump Track: Is This the End of Sue and Settle?

Posted in EPA

On October 16, 2017, the now former Administrator of EPA, Scott Pruitt, issued a memo to the agency directing steps intended to end what has been known pejoratively as “sue and settle” – the practice of suing agencies, particularly EPA and the federal resource managers, for failing to meet statutory and regulatory deadlines, and then quickly settling with a consent decree mandating compliance by a set date, but not with a pre-determined result. And of course, payment of attorney’s fees to the plaintiffs.

In a post on October 18, 2017, we questioned the efficacy of the proposed actions, even assuming the alleged practice existed. A settlement reached on August 24, 2018, by the Department of Commerce over a deadline suit filed by environmental groups, raises another question: do agencies outside of EPA share the “sue and settle” concern?

In 2016, the National Marine Fisheries Service (NMFS) had determined that four distinct population segments of humpback whales remained endangered, but did not designate critical habitat as required under the Endangered Species Act. After it continued to delay designation, environmental groups filed suit on March 15, 2018, in the Northern District of California to force agency action. On August 24, the parties filed a Stipulated Settlement Agreement requiring agency action on the designation by June 18, 2019, along with the payment of $10,000 in attorney’s fees to plaintiffs. This settlement appears to be exactly what EPA’s memo was directed at.

What It Means

This settlement may be an example of what the Administration has railed against, but it is hard to argue this is a “bad deal” for anyone. The statute will be complied with, without forcing a particular result, and $10,000 seems extremely reasonable even for six months of litigation. One could legitimately ask why the Pruitt memo was issued to avoid this kind of result. Even more legitimately, one can ask whether anyone else in the government agencies even cares about a made-up issue.

Trump Track: Natural Resource Damage Assessment Regulations Rewrite?

Posted in CERCLA, Trump Track

On August 27, 2018, the Office of Restoration and Damage Assessment (ORDA) at the Department of the Interior published an Advance Notice of Proposed Rulemaking and request for public comment on revision of the Department’s regulations for the conduct of natural resource damage assessments (NRDA) in connection with releases of hazardous substances. The notice identified several specific areas on which it solicited comments, although it welcomed comments and suggestions regarding other areas. Comments will be accepted through October 26, 2018.

What It Means 

Federal, state and tribal agencies can be trustees for the purpose of bringing actions for the recovery of damages for injury to resources under their ownership or management. The primary federal statutes allowing such actions are the Comprehensive Environmental Remediation, Compensation and Liability Act (CERCLA), and the Oil Pollution Act (OPA). The DOI NRDA Regulations address hazardous substance releases, which are covered by CERCLA. NOAA Fisheries has issued similar regulations under the OPA. The agencies are not required to comply with either set of regulations, but if they do comply, they may be entitled to a “rebuttable presumption” on their claims in any subsequent legal proceeding.

The DOI NRDA regulations were first issued in 1986 and have not been modified since 2008. The regulations include two processes: Type A assessments, intended for relatively simple releases and claims; and Type B, intended to address the specific elements of more complex claims. As a practical matter, there have been virtually no Type A assessments, and trustee agencies almost never attempt to comply with the Type B regulations beyond using them as a general road map. Where agencies have tried to comply, they have been unsuccessful in obtaining the presumption. Indeed, less than a handful of NRD claims under either CERCLA or OPA have ever been litigated. The complexity of claims, the cost of litigation, and the fact that for NRD claims, trustee litigation costs are not recoverable, have made settlement the almost universal result.

Not surprisingly, then, the issues of interest to ORDA in this rulemaking relate to easing resolution, not litigation. These include: 1) Suggestions for adapting the Type A process so that it can actually be used as intended, i.e., an efficient, cost effective and standardized procedure; 2) procedures to encourage early restoration and negotiated settlements, perhaps making the complex DOI regulations more comparable to the NOAA regulations, which emphasize moving quickly to discussion of restoration; 3) use of restoration banking; and 4) compliance with NEPA requirements in the course of restoration planning.

Focusing NRD assessment efforts on early settlement and restoration has been a long-time goal of many if not most practitioners in the field, regardless of whom they represent. The barriers to rapid and cost effective enforcement here have affected both sides, as well as the public and the environment. This is one effort that should be applauded by all sides, and everyone should submit their comments to assure their voices are heard in the rewriting effort.

Trump Track: What is Behind the Administration’s Failed Attempts at Delaying Rules?

Posted in EPA, Trump Track, Water Law

Road construction sign telling motorists to expect delaysOn August 17, the day after a federal judge in South Carolina invalidated the Trump administration’s suspension of the rule defining “waters of the United States” (WOTUS) under the Clean Water Act, a panel on the D.C. Circuit invalidated an effort by the administration to extend by 20 months the effective date of the Chemical Disaster Rule, and ordered the rule implemented immediately.

What It Means

This loss in Air Alliance Houston v. EPA, and the earlier WOTUS decision continue a long losing streak in the courts for the administration’s efforts to undue the environmental legacy of President Obama’s and earlier administrations. The issue is not with the substance of the Trump administration’s positions. The courts rarely get anywhere near to that. It is the unwillingness of the administration to go through the procedures required by the Administrative Procedure Act, or in this case by the express wording of the statute itself.

Congress had provided that if there is a legitimate request for reconsideration of a rule under the statute, EPA can delay the effective date of the rule for three months. EPA invoked that provision first, then tried to use other, more general provisions to adopt a Delay Rule extending the effective date for another 20 months. No need to go beyond step one of Chevron to find that EPA was entitled to no deference in its interpretation—the statute is clear on its face and requires no interpretation. The Court of Appeals called the administration’s arguments “a mockery of the statute” under which the rule had been promulgated.

The Administration’s losses for failure to comply with standard administrative or express statutory procedures have become so frequent that one has to ask whether these “suspensions” and “delays” are ill-considered, or a deliberate effort by the administration to show quick action to its base, and shift blame for the ineffectiveness of the effort to the courts.

Trump Track: WOTUS Lives! . . . at Least in Half the States (for Now)

Posted in Environmental Quality, EPA, Trump Track, Water Law

Geese Swimming on the Missouri RiverOn August 16, a federal judge in South Carolina invalidated the Trump Administration’s suspension of the rule defining “waters of the United States” (WOTUS), under the Clean Water Act. In South Carolina Coastal Conservation League v. Pruitt, the court found that the notice-and-comment opportunity supporting the Suspension Rule was too narrow and thus violated the Administrative Procedures Act. The WOTUS suspension is the latest in a series of attempts by the administration to stall implementation of Obama era regulations, none of which have met favor with the courts.

As reported here about one year ago, the Trump administration announced a two-step process to undo WOTUS. The first step was to suspend WOTUS for two years, during which a revised WOTUS rule would be developed. In the meantime, guidance on jurisdictional waters that had been issued in the 1980s by the Army Corps of Engineers would be reinstated. The public notice of the Suspension Rule requested comments only on the suspension, but not the substance of either the Obama WOTUS rule or the 1980s guidance.

U.S. District Court Judge David C. Norton, a George H. W. Bush appointee, reasoned that the practical effect of the Suspension Rule is that the WOTUS rule would not apply and instead the 1980s guidance would control. The judge then noted that the definitions in the WOTUS rule and the 1980s guidance are “drastically different” and it is hard to comment on the Suspension Rule without talking about that difference. That refusal to allow comment on the substantive differences violates the notice-and-comment provisions of the APA: “An illusory opportunity to comment is no opportunity at all.” The judge therefore rejected the Trump Suspension Rule, and imposed a nationwide injunction.

What It Means

Explaining the jurisdictional reach of the Clean Water Act has flummoxed the federal agencies and courts for decades. Far from bringing clarity, the Obama WOTUS Rule drew over one million comments and multiple judicial challenges on the merits of the rule. Initially the question was whether such challenges should be made in the U. S. district courts or the Circuit Courts of Appeal. The 6th Circuit held that the appellate courts had original jurisdiction and stayed all of the pending district court actions, but that decision was reversed earlier this year in a unanimous decision of the U. S. Supreme Court. Thus, those lower court cases can continue.

Judge Norton, in South Carolina Coastal Conservation League, was clear that he was not ruling on the merits of the WOTUS Rule, but just the procedural correctness of the Suspension Rule. In challenges on the merits, other federal courts have stayed the WOTUS Rule in 24 states. Striking down the Suspension Rule means that WOTUS remains in effect in the other 26 states.

At the moment, then, about half the country is subject to the WOTUS Rule, while the other half is not. What could go wrong?

Don’t Touch That Dial

Posted in California, Proposition 65

Retro pitch man in black and white from a 1950's era TV commercialA reminder that new Prop 65 regulations become effective the end of this month and some key changes may directly affect online on-product warnings, internet sales, catalog sales and even on-TV sales.  The new regulations are explicit about the timing of the warning. Warnings must now be given prior to completion of the sale, not just prior to the exposure. This new timing has online sellers, resellers, and even TV sales programming scrambling to make sure the warnings are given on time.

“Operators are standing by!” may trigger a new sales tagline: “And if you’re buying in California, WARNING: This product can expose you to a chemical including. .  . . .”

Remember, in just a few weeks (August 30, 2018), the new safe harbor warnings are in effect for products manufactured after that date!

For more information, see our prior blogs on Prop 65.

Trump Track: Look Before You Tweet, or How Not to Respond to Wild Fires

Posted in California, Trump Track

In a tweet released August 6, President Trump offered his analysis of how to combat the ongoing human and ecological tragedy of one of the worst fire seasons of record.

The president then directed Commerce Secretary Wilbur Ross to take action to free up all that wasted water and solve the fire problem, which the Secretary dutifully did. On August 8, Secretary Ross directed NOAA Fisheries, the agency within the Department of Commerce that implements the Endangered Species act with regard to anadromous fish and marine mammals, to:

Consistent with the emergency consultation provisions under the ESA, Federal agencies may use any water as necessary to protect life and property in the affected areas. Based on this directive, NOAA will facilitate the use of water for this emergency.


What It Means

Call me old fashioned, but I think an inquiry to California officials as to what they actually need might have been appropriate. It also couldn’t have hurt to include an expression of concern for the lives and homes lost to the conflagration. Instead, Mr. Trump chose to cast blame on purportedly limiting environmental laws restricting the amount of water available to fight the fires.

In fact, California has repeatedly informed the Administration that lack of water is not the problem. The fires are driven by hot, dry conditions and high winds. They are primarily fought not by dumping water but by constructing fire breaks to contain the fire.

It is interesting that the Administration chose not to invoke the “God Squad” provisions of the Endangered Species Act to exempt federal response agencies from ESA requirements.  The reason may reflect that this is an elaborate and politically fraught process. Still, invoking the emergency consultation procedures under the ESA is a grave undertaking that requires NOAA to step through a process to mitigate emergency measures, document its decision not to impose protective measures for listed species, and then at the end of the emergency to remediate the resulting damage.

The ESA does affect water use, but the conflict is generally between agricultural water interests and aquatic habitat advocates. It may be that the Administration is using the fire emergency to highlight a different priority, to remove ESA impediments to allow more water for irrigation. In his statement, Secretary Ross concluded: “Going forward, the Department and NOAA are committed to finding new solutions to address threatened and endangered species in the context of the challenging water management situation in California.”

That’s a fairly innocuous statement, but could easily be read as a policy statement that the Administration sees the ESA as an impediment to water management in California and elsewhere. That may be, but it is one Congress put in place decades ago and which Congress has not seen fit to address further.

CPUC Proposal Tweaks PCIA “Exit Fee” Calculation; But Defers Ruling on a Comprehensive Solution to Address Excess Resource Costs in Utility Portfolios

Posted in Electric Power, Renewables

On August 1, 2018 the California Public Utilities Commission (“CPUC”) issued a proposed decision that would adopt tweaks to the methodology used to calculate the Power Charge Indifference Adjustment (“PCIA”) — the “exit fee” charged by California’s large investor-owned utilities (“IOUs”) on customers who begin taking electric service from community choice aggregation programs (“CCAs”). While the proposed decision would adopt short-term changes to make the PCIA calculation more accurate and equitable, it would defer developing long-term solutions to the growing mismatch between IOU portfolio resources and bundled load resulting from growing retail energy choice.


The PCIA is designed to cover above-market IOU portfolio costs from legacy energy contracts that the utilities entered into but no longer need and cannot sell in the market for the price they paid. The purpose of the PCIA is to make bundled utility customers financially indifferent to the fact that customers have left the utility. The current PCIA methodology calculates an “indifference amount” by starting with the forecast costs of the IOU generation portfolio (e.g., contract payments, utility-owned generation (“UOG”) revenue requirements), and subtracting a proxy of the revenue those resources could garner in the market using forecasts of energy prices and administratively-determined benchmarks that collectively comprise what’s called the “Market Price Benchmark.”

The Commission opened the PCIA rulemaking to address growing dissatisfaction among IOUs and departing load parties that the current PCIA methodology does not achieve “indifference” between customer groups. The Commission recognized that the PCIA must be designed to prevent cost shifting both from departing load to bundled customers and from bundled to departing load customers.

The CPUC’s Proposed Decision

On August 1, after more than a year of deliberations, the CPUC issued a proposed decision which determines that the current PCIA methodology does not prevent cost-shifting between customer groups and proposes to address problems in the short-term with a revised methodology to calculate the PCIA beginning January 1, 2019.

The proposal involves three main short-term solutions:

  • Adopting revised inputs to the Market Price Benchmark to improve the initial accuracy of the PCIA that will be in effect each year.
  • Adopting an annual true-up mechanism to ensure that bundled and departing load customers pay equally for PCIA-eligible resources.
  • Adopting a cap to limit the change in the PCIA rate from year to year, in an attempt to provide the rate stability and predictability sought by departing load interests.

Corrected Market Price Benchmark

The Proposed Decision would tweak the methodologies for calculating the value of capacity and renewable energy credits provided by PCIA-eligible resources using components of the Market Price Benchmark referred to, respectively, as the resource adequacy adder (“RA Adder”) and renewable procurement standard adder (“RPS Adder”). It would also require electric service providers (“ESPs”) and CCAs to report detailed information about their contracts to ensure the accuracy of the RPS Adder. The CPUC believes its proposed changes will result in utilization of the best available transactions data to approximate a realistic PCIA obligation.

Annual True-up

The Proposed Decision would implement an annual true-up process that would require IOUs to create balancing accounts to track costs related to Market Price Benchmark components and pass any year-end under- or over- collection to the subsequent year’s PCIA calculation.


To mitigate major fluctuations in the PCIA from one year to the next, the Proposed Decision would also include a 2.2 cent/kWh cap on the PCIA and require that the annual change to the PCIA charge be capped at 0.5 cents/kWh for any PCIA charge above 1.5 cents/kWh.

Other Changes

In response to requests for simplicity and predictability, the Proposed Decision would include an option for departing load customers to pre-pay their PCIA obligation through agreements requiring Commission approval on a case-by-case basis.

The Proposed Decision would also side with CCA stakeholders on two important issues: (1) exclusion from the PCIA calculation of the costs of legacy utility owned generation projects (“UOG”) installed prior to 2002, and (2) preservation of a 10-year limit on cost recovery of UOG installed post-2002. The Proposed Decision explains that removing the 10-year limitation on recovery “would also remove any incentive for the IOUs to manage their portfolios more aggressively to eliminate their long positions in non-RPS-eligible UOG.” It further notes that “the imperative from this point onward will be to work toward portfolio optimization and cost reduction, and leave behind static portfolio management and the associated cost recovery of above-market costs for utility-held resources that are no longer needed by the bundled customers that they serve.”

Development of Comprehensive Solution Kicked to Second Phase

The Proposed Decision would open a second phase of the proceeding to consider the development and implementation of a longer-term, comprehensive solution to address the costs of excess resources in utility portfolios. The Proposed Decision notes that the Commission expects the solution “to be based on a voluntary, market-based redistribution of excess resources” in the IOUs’ electric supply portfolios. Phase 2 would establish a “working group” process to enable parties to further develop a number of proposals regarding portfolio optimization and cost reduction.


Next Steps

Interested parties may file comments on the Proposed Decision by August 21. Reply comments are then due by August 27. The Proposed Decision is currently on calendar to be considered at the CPUC’s September 13 Business Meeting, although the vote may be delayed.


For more information, contact members of the DWT Energy Team.

Vidhya Prabhakaran at 415-276-6568 or
Patrick Ferguson at 415-276-6563 or
Emily Sangi at 415-276-6582 or

CPUC: New Standard Offer Contracts for Qualifying Facilities 20 MWs or Less May Be Coming Soon

Posted in California, Renewables, Rulemakings

Energy project developers interested in securing qualifying facility (QF) contracts in California for small power projects of 20 MWs or less may soon have new commercial opportunities because of a new Order Instituting Rulemaking issued on August 1 by the California Public Utilities Commission (CPUC). A wide range of power projects can qualify as QFs, including solar, wind, geothermal, biomass, hydroelectric, and co-generation facilities.

The new rulemaking will focus on the CPUC’s implementation of the Public Utility Regulatory Policies Act (PURPA). The CPUC will consider adoption of a new QF standard offer contract (QF Contract), which would allow any QF of 20 MW or less the right to sell its electric output to a Commission-jurisdictional utility pursuant to a set of standard terms and conditions and at a rate based on avoided cost. The rulemaking will also consider the adoption of a price to be paid at the time of delivery where a QF has opted to sell as-available energy to the utility without a contract.

The new QF Contract could essentially guarantee a QF’s right to enter into a contract to sell electricity to California investor-owned utilities (IOUs) and guarantee a contract if a developer could build and interconnect a QF energy project in California under 20 MWs in size.


The CPUC’s rulemaking follows Winding Creek Solar LLC v. Michael Peevey, et al., a federal district court decision issued in December 2017 which found that one of the CPUC’s major regulatory programs to foster renewable energy development (the “Re-MAT” program) was unconstitutional because the pricing provisions and statewide MW cap violated PURPA. The district court also found that the CPUC’s existing standard offer contract for QFs 20 MW or less failed to provide QFs the option to choose energy rates determined either at the time of contract execution or at the time of product delivery.

Following the decision, the CPUC suspended the Re-MAT program and instructed the IOUs to refrain from executing any new Re-MAT contracts, holding any new Re-MAT program periods, or accepting any new Re-MAT applications. The matter was appealed and is currently before the Ninth Circuit Court of Appeals.

The CPUC’s present rulemaking appears to take a second shot at PURPA compliance, aiming to develop a new QF Contract that would be the “foundation” of PURPA compliance and meet all contracting regulations as established in FERC regulations.

The Nuts and Bolts

The rulemaking will not make any changes or interfere with the Re-MAT program, existing PURPA contracts between the IOUs and QFs, any currently-available PURPA contracts, any existing PURPA program, or any aspect of the QF Settlement approved in D.10-12-035. The CPUC has not provided any indication of when and how a new QF Contract would be implemented or be available to developers.

The rulemaking will consider whether PURPA requires that any of the non-price terms of the existing standard offer contract for QFs 20 MW or less be modified before they are incorporated into the new QF Contract, and/or whether the CPUC should use this opportunity to modify any of the non-price terms of the new QF Contract to ensure implementation of PURPA consistent with state and federal laws.

The specific issues that will be addressed in the course of the proceeding as they relate to a new QF Contract and the price for as-available energy sold to a utility without a contract are based on the CPUC’s Staff Proposal, which advocates methodologies to establish four avoided cost price options for QFs seeking a contract – a time of delivery and a time of execution price for both energy and as-available capacity.

The Procedural Road Ahead

The CPUC is seeking comments from parties regarding the following initial scoping questions:

  • Whether the proposed energy price at the time of delivery and at the time of contract execution is consistent with PURPA
  • Whether the proposed capacity price at the time of delivery and at the time of contract execution is consistent with PURPA
  • Whether the proposed energy price for as-available energy sold by a QF to the utility without a contract is consistent with PURPA
  • Whether there are any other terms for the Standard Contract for QFs 20 MW or less that should be modified to ensure that the new QF Contract is consistent with PURPA

Interested parties can file comments in response to the initial scoping questions in the rulemaking within 30 days from the issuance of the decision, by August 31. Reply comments are due 45 days from the issuance of the decision, by September 15. A prehearing conference is anticipated for September or October 2018.

For more information, contact members of the DWT Energy Team.

Patrick Ferguson at 415-276-6563 or
Vidhya Prabhakaran at 415-276-6568 or
Tahiya Sultan at 415-276-6539 or

Trump Track: Are the Gasoline Wars About to Begin with California?

Posted in EPA, Federal, Trump Track

Rush hour in downtown Los Angeles, California on highway 110.On August 2, 2018, after many months of public rhetoric from the administration and the states, EPA and the National Highway Traffic Safety Administration sought comment on a joint proposal to modify the Corporate Average Fuel Economy (CAFÉ) standards for years 2021-2025. The Trump administration’s preferred modification would be a freeze on the standards at 2020 levels, but some alternatives are offered for comment. The administration also intends to revoke the waiver granted to California allowing it to set its own air standards. The comment period is 60 days, and it is expected that a new rule would be promulgated by the end of 2018 or early 2019.

What It Means

There are two elements to this plan of action, with the revocation of the California waiver likely the most contentious, but both will be tied up in litigation for at least a year or two. The Clean Air Act explicitly provides for California to obtain a waiver from regulations promulgated under the Act and set its own, more stringent, standards. Currently nine other states have adopted the California standards. The governor of California has already described the administration’s actions as “stupidity” and that state and 18 others, plus the District of Columbia, have already announced their intention to fight the administration’s new CAFE proposal.

And this is not the first attack on the California waiver, which exists because Congress recognized California’s uniquely bad air conditions and its leading role in improving air quality. Two district courts rebuffed earlier efforts in 2007 by the auto industry to overturn the waiver. There is no reason to think that California would let the administration take away that waiver now without a lengthy court battle, in which it would have good odds of success.

Of course another possibility – highly remote with the existing Congress — is that the legislative branch acts to amend the Clean Air Act, to remove the California waiver altogether.

Whatever now happens, it is hard to see any real winners in this fight.

The National Interest

If the administration wins its battle to freeze the CAFE standards, Bill Wehrum, assistant administrator of EPA’s office of Air and Radiation, said it would be a “win-win” situation: lower costs for auto manufacturers, lower costs for consumers. In fact, the agencies refer to their policy as the Safer Affordable Fuel-efficient Vehicles Rule (SAFE Vehicles Rule), proffering analyses that suggest requiring more fuel efficient vehicles would result in a less safe vehicle fleet. Oddly enough, Mr. Wehrum makes no mention of the environmental impact, although in its proposal EPA estimates the freeze would result in only a minimal increase in global warming.

On the downside, consumers will face the costs of higher gas consumption; however EPA suggests in its economic analysis that such costs will be short-lived as it will cause consumers to drive less. Also, EPA’s success might lessen the incentives for U.S. automakers to develop the models they will need to successfully compete in other countries more focused on electric vehicles, such as China, now the largest auto market in the world. But that’s a trade balance issue.

As California Goes, So Goes the Country…

California and the nine other states that also use its standards, make up a third of the national car market. If the CAFE standards are frozen at 2020 levels, but California successfully defends and exercises its waiver, that fact, along with the pressure to innovate for international markets, will likely force the U.S. automakers to accept the California standards regardless of the administration’s wishes. And even if California should lose its waiver, no one should be surprised if the fifth largest economy in the world used its market leverage to meet its air quality goals through other routes affecting the auto industry.

…And the Auto Industry

It had originally sought to have the administration derail the Obama administration CAFE standards, but did not want the wholesale approach ultimately taken. Now it faces what it most dislikes—uncertainty. It has to make model decisions years in advance, without knowing what standards it will have to meet, or whether there will be two different sets of standards in the U.S. market. Some manufacturers have already indicated they simply intend to continue what they had planned to do regardless of whether the administration succeeds in this rollback effort.

In this type of brouhaha, one would expect a negotiated outcome. EPA says it is involved in discussions and willing to reach a compromise. California says it is still waiting to hear from EPA, but it has no intention of compromising on the waiver. The auto industry is encouraging both sides to talk this out. Will a compromise be reached? At least EPA is asking for comments this time before it issues a rule.

If the administration wants to actually take effective action, and not just check off another box on its political bucket list, it will have to act very quickly or its efforts will be rendered irrelevant by the realities of the long-term automotive market.

Trump Track: BLM Bar on Compensatory Mitigation: Optics Only?

Posted in Land Use, Natural Resources, Trump Track

Panoramic view of mountain landscape with forest and hill under blue sky with clouds - vector illustrationOn Monday, July 24, 2018, the Bureau of Land Management (BLM) issued a memorandum prohibiting BLM from requiring “compensatory mitigation” projects, except where specifically mandated by the Federal Land Policy and Management Act (FLPMA). BLM will consider “voluntary proposals for compensatory mitigation,” but will not accept monetary payments as compensatory mitigation. “Compensatory mitigation” is defined as mitigation off site, so the memorandum does not address mitigation required on the project site itself.

In issuing the memorandum, BLM cited to 2017 Executive and Secretary Orders regarding energy independence that rescinded a Presidential Order and guidance issued in 2016. In addition, the memorandum points to a 1995 joint BLM/State of Wyoming policy memo raising concerns that requiring compensatory mitigation could amount to an unauthorized tax or an equally unauthorized attempt to augment BLM’s exiting appropriations.

Note that this memorandum addresses only BLM procedures, although it is certainly possible that the Department of Agriculture could impose similar strictures on compensatory mitigation for projects on Forest Service lands.

What It Means

The memorandum itself states simply that it “may” result in some decreased costs to oil and gas and geothermal lessees. And that it is “unlikely” to have any material adverse impact on energy supply, distribution or use. Both statements seem accurate.

The appropriate amount and nature of mitigation is not a bright line question, and hurdles can often be overcome through changes in terminology, or tweaks in design. The project proponent wants its project to go forward, and will take whatever steps it deems appropriate to obtain the permit. Neither it, nor BLM, is likely to allow ideological purity to prevent development of the resources. Both are likely to realize that in many situations, providing compensatory mitigation may be less expensive and time-consuming than developing additional mitigation on-site to address some impacts, or battling a challenge to the permit in court over whether those impacts represent unnecessary or undue degradation.

The point about ideological purity is not made lightly. Although the memorandum includes multiple reporting and approval requirements that would appear intended to assure the casual reader that the intent of the memorandum will not be evaded, the memorandum also provides a roadmap for proponents who want to wade through that thicket. Notably:

  • It does not affect the ability of state governments to require compensatory mitigation, including payments.
  • It does not affect compensatory mitigation that may be required by other federal statutes.
  • A proponent may voluntarily offer compensatory mitigation, and BLM will consider that mitigation as a means to reach a Finding of No Significant Impact (FONSI) or as part of the project design.

If a proponent determines that it has to sweeten a project in order to move it through the regulatory process, it should be able to accomplish that handily with the assistance of competent counsel by following the paths laid out in the memo itself.

Which leads one to ask what was the purpose of this memorandum? It won’t streamline the process, and is unlikely to even cure the disease it seems to want to attack. Was it just to check another box on the administration’s regulatory reform schedule?

Trump Track: EPA Superfund Task Force – Will Anything Really Change?

Posted in EPA, Trump Track

Gowanus Canal, Brooklyn, NYThe EPA Superfund Task Force was commissioned by then Administrator Scott Pruitt to develop recommendations for sweeping changes to the Superfund process to provide more clarity and efficiency to the process. The task force issued a long list of recommendations in July 2017 and EPA recently issued a report documenting the status of EPA’s implementation of the task force’s recommendations.

EPA reports that it has completed 27 percent of the task force recommendations, but the question is, what has really changed? Rather than making changes to improve the Superfund process, it appears EPA may be redefining some of the task force recommendations so it can conclude existing programs are sufficient to address the concerns identified by the task force. For example, the task force recommended that EPA provide clarification on when groundwater would need to be restored. The task force recognized there may be sites where it may not be necessary to remediate groundwater. Rather than developing new guidance to address the deficiencies in the existing guidance, EPA has focused on identifying the existing “groundwater policy flexibilities.” The annual report does not indicate that new guidance will be developed or that additional flexibility will be added to existing policies.

What it Means

Is this report just a means of EPA patting itself on the back for policies and practices already in place? It certainly appears to be business as usual.

D.C. Circuit Sinks FERC Hydro License for Failure to Adequately Consider Past Environmental Harm

Posted in Electric Power, FERC, Natural Resources, Renewables, Water Law

Last Friday, the D.C. Circuit torpedoed a hydroelectric license issued in 2013 to Alabama Power Company because the Federal Energy Regulatory Commission (FERC) and the U.S. Fish and Wildlife Service (USFWS) “declined to factor in the decades of environmental damage already wrought by exploitation of the waterway for power generation and that damage’s continuing ecological effects.” In doing so, the court rejected FERC’s attempt to follow its longstanding practice of limiting environmental review of past impacts by using existing conditions and operations as the environmental baseline.

The decision—American Rivers v. FERC—uses unusually sharp language to chastise FERC and USFWS for sloppy analysis, relying on weak or non-existent data, and failing to properly explain their reasoning. But it remains to be seen how far this case will shift the law regarding the use of environmental baselines under the Federal Power Act (FPA), the National Environmental Policy Act (NEPA), and the Endangered Species Act (ESA). Are the shortcomings in FERC’s analysis easily fixable on remand, or does this represent a fundamental shift in how the courts will view the relicensing of dams constructed long before enactment of the environmental safeguards of the 1970s and 80s?

In this advisory, we explain the court’s reasoning and highlight the decision’s uncertain—but likely important—implications for FERC relicensing going forward.

Big Tribal Victory in Culvert Case, Big Implications for Taxpayers

Posted in Environmental Quality, Natural Resources, Rulemakings

On June 11, the Supreme Court issued a one-sentence order affirming the Ninth Circuit’s 2016 judgment in United States v. State of Washington. In that case, the federal government sued Washington on behalf of several Indian tribes, asserting that culverts constructed by the state over decades blocked salmon runs for which the tribes held treaty fishing rights. The Court of Appeals ordered Washington to repair or replace the offending culverts. The Supreme Court split 4-4, with Justice Kennedy recusing himself, which allows the Ninth Circuit ruling to stand.

The ruling is a major victory for Indian treaty rights. The historical tradeoff for acceding to white settlement throughout the West was preservation of hunting and fishing rights dating from time immemorial. These rights were to ensure tribal sustenance and to preserve religious and cultural practices. The Court of Appeals held that inherent in fishing rights is a duty to maintain viable salmon habitat and migration corridors.

The justice for the tribes in the outcome cannot be denied. However, compliance with the ruling carries an enormous price tag, in the many billions of dollars. Further, culverts aren’t the only sources of degradation of salmon habitat. Settlement of the West entailed construction of hundreds of dams and other stream obstructions. More than a century of agriculture, mining, and industrial activities have denuded riparian zones, straightened meandering streams, filled spawning gravels with sediments, and added nutrients and other pollutants to waterways. Most, if not all, streams listed by Western states as water quality impaired under Clean Water Act section 303(d), are on the list for temperature, suspended solids, dissolved oxygen and other pollutants related to development.

A great deal of litigation and regulatory activity is ongoing to address these concerns, but does the U.S. v. Washington case add the potential for accelerated court mandated corrections? How will state and local government budgets cope with aggressive timelines for compliance? Will the Administration and Congress step up to help?

The latter question raises justice issues of its own. Washington argued that the culverts it installed were in accordance with federal designs. In a statement, state Attorney General Bob Ferguson said, “It is unfortunate that Washington state taxpayers will be shouldering all the responsibility for the federal government’s faulty culvert design.”

Interestingly, other Washington State officials do not appear to share AG Ferguson’s sense of outrage. As reported in the New York Times, Gov. Jay Inslee and Public Lands Commissioner Hilary Franz did not support petitioning the Supreme Court for review: “For some time now I’ve hoped that instead of litigation we could focus together on our ongoing work to restore salmon habitat,” Inslee said. Franz added, “It is time to stop fighting over who should do what.” And indeed, the state has been actively working on the culverts.

The courts were not moved by Ferguson’s argument that the federal government is to blame for bad culvert design. Still, it does seem that the issue of salmon habitat restoration is not for Washington State to resolve by itself, but is a national problem resulting in significant part from national policies, and requires a national solution.

12 Weeks Until New Safe Harbor Prop 65 Warnings Take Effect

Posted in California, Proposition 65

What meets the standard today may not meet the standard in 12 weeks. On August 30, 2018, California’s “safe harbor” Proposition 65 warnings are changing, increasing the information needed for those warnings and  imposing specific requirements on newly regulated industries, classes of products and internet sales.

We’ve previously posted on this upcoming change. For more information on how to ensure compliance, click here.



California Proposition 65 Amendments – An Unsavory Impact on Food and Beverage Industries?

Posted in California, Proposition 65

Now is the time to update your Proposition 65 warnings in California. On August 30, 2018, new regulations go into effect changing the warnings required for the food and beverage industries. Amendments to California’s Proposition 65, also known as the Safe Drinking Water and Toxic Enforcement Act of 1986, require businesses to provide “clear and reasonable” warnings about the presence of certain chemicals, including chemicals in food, beverages, and other consumer products manufactured, sold or distributed to consumers. The new regulations provide new suggested language as a “safe harbor” which meets the “clear and reasonable” standard.

While Prop 65 has been around for 30 years, recent actions focus on food and beverage products, including: acrylamide in coffee, baked goods, French fries and chips; furfuryl alcohol, which can be found in a variety of foods including baked goods, coffee and pasteurized milk; and, of course, alcohol beverages.

Here we highlight the updated warnings applicable to establishments that sell food products, including shops and restaurants. While some establishments and distributors may already provide warnings, the 2018 “safe harbor” language has new requirements. Key changes include a requirement to identify the chemical and include the address of the State’s Proposition 65 website.

Effective until 8/30/18 Effective Beginning 8/30/16, Mandatory Beginning 8/30/18*

*Exception – court approved settlements

Old Warning



This product may contain a chemical known to the State of California to cause cancer, or birth defects or other reproductive harm.

New Warning

WARNING: Consuming this product can expose you to chemicals including [name of one or more chemicals], which is [are] known to the State of California to cause cancer and birth defects or other reproductive harm. For more information go to


Importantly, the new regulations specifically include products sold on the internet. It is imperative that warnings be provided pre-purchase – before the final confirmation of the shipment.  This can be accomplished by including the warning on the product page, product description, or at warnings appearing with California addresses before the consumer finalizes the purchase.

California restaurants with 10 or more employees must post a warning at the public entrance to the restaurant and at each point of display. Restaurants may also choose to provide the Prop 65 warnings on their menus.

Old Warnings – None Required Effective Beginning 8/30/16, Mandatory Beginning 8/30/18
Method of Transmission Specific size and placement requirements include for each public entrance to the restaurant, point of sale, or point of display

Restaurants in San Francisco must post Proposition 65 warnings in English, Chinese and Spanish.

WARNING: Certain foods and beverages sold or served here can expose you to chemicals including acrylamide in many fried or baked foods, and mercury in fish, which are known to the State of California to cause cancer and birth defects or other reproductive harm. For more information go to
New Warning


BPA in Containers New Warning

WARNING: Many food and beverage cans have linings containing bisphenol A (BPA), a chemical known to the State of California to cause harm to the female reproductive system. Jar lids and bottle caps may also contain BPA. You can be exposed to BPA when you consume foods or beverages packaged in these containers. For more information go to:


Alcohol sales still require warnings. Stores and restaurants that sell alcoholic beverages should update their alcohol-specific warning.

Effective until 8/30/18 Effective Beginning 8/30/16, Mandatory Beginning 8/30/18*

*Exception – court approved settlements

Old Warning
Drinking distilled spirits, beer, coolers, wine and other alcoholic beverages may increase cancer risk, and, during pregnancy, can cause birth defects.

New Warning


WARNING: Drinking distilled spirits, beer, coolers, wine and other alcoholic beverages may increase cancer risk, and, during pregnancy, can cause birth defects.  For more information go to


This is the time to check in on Prop 65 compliance programs. For more information on how to comply with these updates, please contact Kerry Shea, Larry Burke or Tahiya Sultan.

FERC’s New Gas Pipeline Certificate Notice of Inquiry: Unlikely to Change the Status Quo

Posted in FERC

On April 19, FERC issued a Notice of Inquiry (NOI) soliciting public comments on whether to revise its long-standing policy governing the processing and approval of new natural gas pipeline facilities under Section 7 of the Natural Gas Act. Although this opens the floodgates to public comment on very contentious issues, it is unlikely to result in significant changes in the process.

FERC has issued less than two dozen NOIs in the past decade. Typically, this is a vehicle used by FERC to highlight regulatory problems and offer possible solutions for public input. For example, in a 2016 NOI, FERC advised it was rethinking its approach to assessing market power when evaluating proposed public utility sales of facilities under Section 203 of the Federal Power Act (FPA) and applications under Section 205 of the FPA for market-based rate authority. An integral element of that NOI was a request for public comment on several “potential improvements” FERC staff had developed.

In contrast, FERC is silent on the underlying problems that have led to the issuance of this new NOI and it offers no potential improvements. But anyone reading the trade press is well aware that new gas pipeline construction projects are engendering extensive landowner/environmental opposition. Further, increasing court challenges of orders approving such projects is causing FERC to devote additional efforts to building a bullet-proof administrative record in advance, thereby slowing down processing substantially. Yet at the same time, FERC’s Chairman recently has signed onto an inter-agency Memorandum of Understanding to implement a Trump Administration Executive Order designed to expedite infrastructure project review.

Put between a rock and a hard place, FERC here sits on the sidelines. It asks whether its existing policies – namely its method of determining project need, its consideration of eminent domain use/landowner rights and its analysis of environmental impacts should be “adjusted.” Additionally, it asks whether procedural process changes are needed to improve “efficiency and effectiveness” or ways “to improve the transparency, timing and predictability of the Commission’s certification process.” Treading even more delicately it asks “commenters to identify, with specificity, any perceived issues with the Commission’s current analytical and procedural approaches and to provide detailed recommendations to address those issues.”

But just asking questions does not give the public the benefit of lessons learned by the agency in 19 years of processing applications under the existing certificate policy statement. It is a remarkably passive stance for this agency as compared to its usual approach in an NOI. That FERC punts on taking any position or making concrete proposals for public comment signals that it is unlikely to make wholesale changes to its existing policies. This is not surprising in the current acrimonious political climate.

That doesn’t mean this NOI will be ignored. Stakeholders dissatisfied with the current approach can be expected to offer extensive commentary on why each of the identified policies should be “adjusted.” The Fourth Circuit’s recent order effectively halting construction of the Atlantic Coast Pipeline is likely to invigorate environmental and landowner groups seeking to convince FERC that construction should not be allowed until  after all litigation is complete. Pipelines can be expected to argue that now is not the time for the agency to make the certificate process more attenuated, pointing to FERC’s March 15, 2018 finding that no Master Limited Partnership (MLP) pipeline (and potentially non-MLP pass through pipelines) can recover an income tax allowance in its cost of service. From the point of view of the pipeline sector, this recent policy change, and its resulting adverse impacts on cash flows and credit metrics, is already likely to discourage needed energy infrastructure projects previously developed by MLP pipelines.

But in addition to addressing these broad and important policy questions, parties should not neglect FERC’s call for procedural process improvements. To that end, below are three relatively lower hurdle procedural changes that could be proposed to FERC. They would each help make the process more transparent and thereby enhance public confidence in the pipeline siting process.

  1. Only issue public notice of new pipeline certificate applications after first verifying that the public version of the application complies with the privileged material rule.Under FERC rules, pipelines may excise from the public version of an application only Critical Energy Infrastructure Information (CEII) and materials it claims are exempt from mandatory disclosure under the Freedom of Information Act (FOIA). The pipeline must justify all such privileged materials redacted from the public version on the basis of an exemption from FOIA.

However, this rule is rarely enforced and as a consequence, routinely violated by a number of pipelines. For example, precedent agreements, which are central to an analysis of a pipeline’s ability to demonstrate project need, are usually designated as non-public even though the rule provides for redaction of only specific privileged material and then only if  justified. Pipelines are also required to include in certificate applications a form of protective agreement under which an interested party, upon execution, can get copies of this privileged material. Not surprisingly, the pipelines that excise significant portions of an application on the basis of privilege without justification also fail to include a form of protective agreement in the application. If FERC were to delay the start of the public notice process until after it verifies that the public version of each certificate application it receives is in compliance with this rule, offending pipelines would have incentive to comply in the first instance.

  1. Extend the public comment/intervention period to 60 days to match the 60 day period for hydroelectric license applications. This would be exceedingly valuable and help allay due process concerns in light of FERC’s recent decision to make it exceedingly difficult for anyone to intervene out-of-time in a pipeline certificate proceeding. It would also make sense because FERC justified this new hardline policy on how it already handles late interventions in hydroelectric proceedings. See our previous blog communication here.
  2. Revise the text for each “Notice of Availability of the Draft Environmental Statement” for new gas pipeline projects to highlight the fact that the issuance of this document provides a second opportunity for public intervention. Currently, one has to read to the very end of a multi-page notice to learn of this valuable right; and the brief text alluding to the ability to intervene is unnecessarily obtuse.

The CPUC Effort to Define Climate Adaptation Is Ambitious Even for the CPUC

Posted in California

On May 7, 2019, the California Public Utilities Commission issued an Order Instituting Rulemaking to consider strategies and guidance for climate change adaption. The broad scope of this rulemaking is intended to ensure that the investor-owned public utilities take proper steps to ensure safety and reliability at a time where the impacts of climate change continue to worsen.  

Phase 1 of the rulemaking is aimed only at the electric and gas utilities, but subsequent phases will deal with water and telecommunication utilities as well.  

The potential ramifications of the rulemaking are significant, as it could result in the CPUC focusing on climate change adaptations in every proceeding in a manner similar to the way in which the CPUC has sought to have an increasedsafety and risk focus. The California Governor, Legislature, and the CPUC have already made climate change a significant focusfor the State, but this rulemaking seems to suggest that there is further need to 1) systematically look at the vulnerabilities that each utility faces and 2) give the CPUC oversight over how individual utilities plan and incorporate adaptation strategies into their operations.  

Since the CPUC has to approve significant future infrastructure investments that are part of climate change adaptation strategies based on forecasts of future climate change, this rulemaking is sure to be a battlefield as the outcomes will result in significant monetary and rate consequences. Moreoever, this rulemaking is the CPUC’s ambitious attempt to create a shared understanding/definition of climate change adaptation and establish shared tools for climate change assessment and forecasting. Policies adopted in this rulemaking will likely be utilized not only at the CPUC but in other jurisdictions all across the world. But the reality is that this proceeding is likely to devolve into a war of modeling assumptions and among climate change experts.

My guess is that the consistency the CPUC hopes to create when addressing climate change adaptation and in making real-world investment decisions may be too difficult to achieve in a cumbersome rulemaking. And maybe that’s OK. At the very least, the discussion that this rulemaking will generate should aid the general effort to understand climate change, its impact on the State, and actions the utilities can take to combat such impacts.

Comments on the OIR are due by Wednesday, June 6. We expect participation from a wide variety of stakeholders. Any stakeholders interested in commenting are invited to reach out to a DWT energy attorney.  

FERC Raises the Bar for Public Participation in Gas Pipeline Certificate Proceedings

Posted in FERC

The Federal Energy Regulatory Commission (FERC) has a long-standing reputation for non-partisan decision-making. This was reinforced by its January 2018 rejection of the Department of Energy’s demand that electric pricing rules be changed to incentivize coal-fired and nuclear electric generation.  More recent FERC actions, however, suggest that this independent regulatory agency is trending towards greater partisanship.

Just in the last month, FERC has issued two orders that make it significantly harder for environmental/ landowner groups to obtain party status in new gas pipeline construction proceedings.  Party status is only achieved at FERC via the grant of a motion to intervene.  Importantly, grant of party status gives one the right to seek judicial review of FERC’s actions.  Absent such status, affected environmental/landowner groups lack the ability to hold FERC accountable for orders that fail to address their particular concerns. This status is even more important today as pipeline projects become increasingly controversial and such groups rely on judicial review – together with adverse media coverage of FERC actions — to advance their policy goals.

Yet these same groups, many of whom are non-profit, frequently lack the resources to keep up with the stream of new pipeline infrastructure applications flooding into FERC.  While such applications can run thousands of pages, key portions are routinely excised from the version made public on the basis that the information is privileged and confidential.  Detailed maps provided to depict the proposed project may be designated non-public Confidential Energy Infrastructure Information (CEII). Yet FERC public notices of new certificate applications typically allow only 28 days for timely interventions and comments.  And for groups that rely on the Federal Register, the available time period is cut in half because it takes two weeks for the notice to first appear there. Two weeks is rarely enough time to evaluate these complex applications, decide whether to participate, and then formulate comments. As a consequence, many such groups routinely find themselves filing late interventions.

In recognition of these groups’ limited resources and this time crunch, FERC has always been liberal in its treatment of late filed interventions, particularly since gas pipeline infrastructure projects take many months to process. Indeed, FERC’s past policy has been to grant such late interventions as long as the motion was filed before issuance of an order on the merits of the application.

FERC’s liberal late intervention policy will no longer be the case. In an order issued February 27, 2018, FERC announced a new policy for determining whether good cause exists to grant late filed motions to intervene. Stating that it was concerned that parties filing such late motions were failing to adequately address the reasons why they were late, FERC concluded there was a “pattern of failures to address these requirements . . . going forward we will be less lenient in the grant of late interventions.”  In addressing whether there was “good cause” not to have filed a timely motion to intervene, FERC cautioned, movants must explain why they should not be held to the FERC’s expectation that they intervene “in a timely manner based on reasonably foreseeable issues arising from the applicant’s filing and the [FERC’s] notice of the proceeding.”

In a March 15, 2018 order, FERC clarified this point and signaled it will be significantly more difficult to demonstrate good cause in the future. In discussing an intervention filed by an environmental group approximately 5 weeks after the public notice period ended, FERC found that the environmental group’s statement that it filed its motion to intervene the same day it first became aware that the application had been filed was insufficient evidence of good cause.  Further, FERC reiterated that it was putting all other future participants in pipeline certificate proceedings on notice that it was going to be less lenient in grant of late interventions in the future. These statements drew a dissent from the two democratic FERC Commissioners, Cheryl LaFleur and Richard Glick, who raised concerns regarding the political ramifications of this new late intervention policy, suggesting it will only serve to further erode public confidence in the impartiality of the FERC’s pipeline siting process.

This unexpected policy change is likely to figure in public comments on FERC’s upcoming proceeding to reevaluate its 1999 Policy Statement governing the pipeline certificate process. At a minimum, a strong argument can be made that this more rigid late intervention policy supports significantly extending the public notice period.  In the March 15, 2018 Order, FERC states it is basing its reinterpretation of what is “good cause” for late intervention in pipeline proceedings on how this issue is already handled in hydroelectric proceedings. Yet when a new hydroelectric license application is filed at FERC, the public is given 60 days to comment, in contrast to the 28 days given for new gas pipeline infrastructure applications.

Dumpster Divers Extract Millions of Dollars. Again.

Posted in California, Environmental Quality

From 2013 through 2015 investigators checked trash dumpsters from Home Depot stores. Based on what they found, the California Attorney General and various District Attorneys (collectively the “State”) brought a claim with astronomical potential penalties for what they had found.

Home Depot agreed to pay $27.8 million to settle the claim when faced with the evidence of discarded materials that included regulated hazardous waste and readable customer information. The March 8, 2018 Consent Judgment provides not only for that penalty, but for injunctive relief requiring programs to prevent future inadvertent disposal of such materials.

The lawsuit capped three years of “Dumpster Dives” by the investigatory arms of these agencies. Investigators followed trash collectors off more than 300 Home Depot retail sites and sifted through the rubbish. They then catalogued and photographed batteries, aerosol cans and electronic devices which had been thrown in the trash, rather than recycled. These types of wastes are technically Hazardous Waste, but under California law they fall under a less stringent regulatory program for Universal Waste due to their less serious hazard to human health/environment and their ubiquitous nature in society. Businesses should recycle them. The investigators here also found paint (a classic hazardous waste) and items containing customer information that had not been correctly redacted or covered to conceal customer information. The lawsuit alleged violations of hazardous waste laws, universal waste law, customer privacy laws and unfair competition (e.g., Home Depot enjoyed an alleged advantage over competitors since it wasn’t properly recycling universal waste or shredding confidential information).

The Consent Judgment entered by the Court on March 8 imposes penalty payments, injunctive relief, and a host of environmental compliance programs (some required by law and some characterized as “above compliance programs” that require Home Depot to spend $6,840,000 in order to offset up to $3,420,000 in penalties). In total, the company must:

  • Pay $27.84 million in penalties, environmental projects, and reimbursement to the agencies for investigation and enforcement costs.
  • Comply with environmental and customer record regulations. The injunctive relief basically tracks the regulations – the company must comply with all laws and regulations relating to generating, storing and disposing of hazardous waste, including universal waste, as well as those regulations requiring the company shred or somehow make unreadable any customer records or personal information.
  • Implement compliance programs, explicitly agreeing to:
    • employ environmental managers;
    • implement a daily inspection program of various store areas, such as Garden and Paint;
    • enhance its IT program to identify hazardous materials in products it stocks; and
    • provide proof of prior trash compactor assessments it claims to have already performed.

This is not Home Depot’s first battle with the State on this topic. On October 2, 2007, it entered into a similar Consent Judgment with the State and paid $9,900,000 as penalties. The 2007 Consent Judgment was one of the earliest settlements by the State’s environmental investigatory team, and it represents more of a “bare bones” agreement. It required future compliance, but, unlike the 2018 decree, did not contain explicit requirements regarding training, updating regulatory programs, adding new hires, status reports or certifications under penalty of perjury.

The State’s years-long Dumpster Diving investigation into the practices of a company with which it already had a Consent Judgment shows an aggressive bent. These agencies are extracting millions of dollars in settlements for alleged violation of hazardous waste disposal in a program based on human activity and error (trash discard). Companies – even, and maybe especially, those that have previously settled with the State over their trash management practices – better review their training programs and compliance records, focusing on environmental department programs and trash inspection….or they may find the State comes knocking. Again.

FERC Should Reconsider Its Bias in Favor of Incremental Pricing of Pipeline Expansions

Posted in FERC

At his first Federal Energy Regulatory Commission (FERC) meeting this past December, Chairman Kevin McIntyre announced the agency will be soliciting comments on whether to revise its 1999 Certificate Policy Statement (CPS), which FERC uses to evaluate applications to build new pipelines or expand existing ones.

Under the CPS, the pipeline must show that the project could proceed without any financial subsidies from its existing customers, causing most pipeline expansions to be priced on an incremental basis. Prior to adoption of the CPS, expansion costs were routinely rolled into existing pipeline rates upon a showing that the project would provide commensurate benefits to both new and existing shippers.

The CPS rejected any preference in favor of rolled-in pricing. Rather, it started from the proposition that to roll-in expansion costs, the pipeline must demonstrate that the project could be built without any subsidies from existing customers. In 2005, FERC clarified that rule by explaining that generally expansion costs can be rolled-in only if expansion revenues exceed costs (and thus permit a future rate decrease for existing shippers). Otherwise, the pipeline must price the expansion on an incremental basis.

This meant that existing shippers would benefit from rate decreases for expansions that lower mainline system costs but not be burdened by rate increases for expansions that could increase such costs.  Although beneficial to existing shippers, from the pipeline industry’s point of view, this created a “heads you win, tails I lose” situation.

In response, pipelines turned their focus to expansion projects that could be incrementally priced and to soliciting new entrant partners to co-sponsor increasingly expensive incremental projects.  Newly created utility-affiliated midstream companies began to joint venture on projects with traditional pipeline companies as their utility affiliates separately entering into precedent agreements for project capacity.

Since the FERC, under the CPS, looks primarily to precedent agreements as evidence of sufficient need for these projects, this new joint venturing practice by pipelines has led to much public outcry. Environmental groups, affected landowners, and competitors all question the legitimacy of a need showing based on affiliate precedent agreements and urge a broader analysis by FERC of what constitutes project need going forward. But this joint venturing approach is an entirely rational response as pipelines seek to reduce financial risk for incremental projects under the CPS.

The CPS preference for incremental pricing is also fostering an increasing balkanization of pipeline networks — with new markets and services increasingly made available to only new shippers and with existing customers receiving no benefits from this system growth.

The CPS has also encouraged a marked decline in the transparency of expansion capacity pricing. Under FERC’s negotiated rate policy, the availability of a cost-based recourse rate for a service is intended to mitigate for pipeline market power because shippers can always elect recourse rates in lieu of negotiated rates. In practice, however, most shippers commit to negotiated rates. The negotiated rates are likely to be lower than the projected recourse rates (not surprising since recourse rates typically come with a hefty 14% assumed return on equity). Thus the existence of recourse rate does not mitigate for pipeline market power for these expansions.

Indeed, the negotiation process gives great leverage to the pipeline.  Each potential shipper can be kept in the dark as to what rate other shippers are being offered. Negotiated rate precedent agreements are filed with FERC as non-public documents and pipelines have been very successful in keeping the terms of these precedent agreements secret. In most instances, an expansion shipper doesn’t know other shippers’ negotiated rate for the same service until the project is about to go into service and it has entered into a binding service agreement. Then and only then must the pipeline file shipper-specific negotiated rates with the FERC.

It is unclear why this rate secrecy is condoned by FERC and how it is consistent with the agency’s goal of insuring that market participants receive accurate price signals for valuing new gas capacity as compared to other market options.

Another unaddressed issue is how this flight to negotiated rates will impact FERC’s future ability to reset pipeline rates to insure they remain just and reasonable. For example, pipelines are today resisting shipper efforts to have FERC require them to reduce their rates to reflect the recent drop in corporate tax rates effective January 1, 2018 under the Tax Cuts and Jobs Act of 2017. Even if forced by FERC to reduce system recourse rates to account for this change, it is likely that pipelines will maintain that no refunds are due shippers with negotiated rate contracts. One pipeline recently reported that over 95 percent of its capacity is sold under such contracts.

Assuming FERC orders tax-related refunds, with this growing level of negotiated rate contracts, how will FERC insure that now excess pipeline revenues are distributed equitably? More generally, how can FERC exercise its Natural Gas Act Sections 4 and 5  responsibilities to insure just and reasonable and non-discriminatory rates when virtually all capacity is locked up under long-term fixed rate contracts?

These are just a few of the market and regulatory distortions fostered by the current CPS requirement that most expansions be incrementally priced.  Reexamining this current requirement – and the resulting biases — should be an important element for public debate as FERC revisits the CPS later this year.   Stay tuned.

FERC Allows Electric Storage Participation in Wholesale Markets; Sets Technical Conference for Distributed Energy Resource Aggregation

Posted in FERC

Electric Storage

On February 15, 2018, the Federal Energy Regulatory Commission (“FERC” or “Commission”) issued a final rule (Order No. 841, the “Order”) requiring each independent system operator (“ISO”) and regional transmission organization (“RTO”) to adjust their tariffs to better accommodate energy storage resources. Eligible storage facilities include any “resource capable of receiving electric energy from the grid and storing it for later injection of electric energy back to the grid.”

FERC acknowledged that emerging electric storage technologies currently face barriers to entry in the energy, capacity and ancillary service markets operated by ISOs/RTOs. Each ISO/RTO was directed to develop a “participation model” which allows energy storage resources “to participate in the RTO/ISO markets in a way that recognizes the physical and operational characteristics of electric storage resources.”

The storage participation models must meet the following broad criteria:

  1. Ensure that a resource using the participation model is eligible to provide all capacity, energy, and ancillary services that the resource is technically capable of providing in the ISO/RTO markets;
  2. Ensure that a resource using the participation model can be dispatched and can set the wholesale market clearing price as both a wholesale seller and wholesale buyer consistent with existing market rules that govern when a resource can set the wholesale price;
  3. Account for the physical and operational characteristics of electric storage resources through bidding parameters or other means; and
  4. Establish a minimum size requirement for participation in the ISO/RTO markets that does not exceed 100 kW.

FERC gave ISOs/RTOs “significant latitude” on how to implement these new market rules within different market constructs. Each ISO/RTO must file its proposed tariff changes within 270 days of the rule’s publication in the Federal Register, with an additional 365 days to fully implement the new market rules.

Distributed Energy Resource (“DER”) Technical Conference

The 2016 Notice of Proposed Rulemaking that led to the Order would also have required ISOs/RTOs to allow aggregation of small distributed energy resources to meet minimum size requirements.  However, FERC left this out of the final rule, instead opting to gather more information about DERs from stakeholders.  FERC will host a Technical Conference on April 10-11, 2018.  According to the notice, the conference will have seven panels covering the following topics:

  • Economic dispatch, pricing, and settlement of DER aggregations;
  • Operational implications of DER aggregation with state and local regulators;
  • Participation of DERs in RTO/ISO markets;
  • Collection and availability of data on DER installations;
  • Incorporating DERs in modeling, planning and operations studies;
  • Coordination of DER aggregations participating in RTO/ISO markets; and
  • Ongoing operational coordination.

FERC also issued a lengthy Staff Report on the “technical considerations” of DERs on the bulk power system.


FERC has already addressed electric storage participation in markets on a case-by-case basis. For example, the California Independent System Operator has already implemented modern market participation requirements (approved by FERC) to avail itself of innovative storage technologies.  However, FERC’s Order lays a foundation for all ISOs/RTOs to enhance the participation of DERs in various markets, thereby providing more market certainty and spurring growth of these resources (which have already seen significant drops in development costs).  The end result should be stronger competition in wholesale markets and more efficient market results.

While FERC’s decision not to authorize DER aggregation will certainly disappoint developers of these resources, the Technical Conference and Staff Report mark a significant advance in the Commission’s incorporation of non-traditional resources in wholesale markets. Without question, DERs will represent an important part of the energy grid of the future and all technical implications should be explored. FERC’s DER decision also gives its staff, state regulators, market operators, local utilities, reliability entities and other stakeholders another opportunity to voice their opinions to facilitate the creation of new market rules and minimize future controversies.

Weighing the Costs and Risks of Litigation

Posted in Water Law

Citgo Petroleum received a Valentine’s gift of sorts from the Fifth Circuit Court of Appeals on February 14, in United States v. Citgo Petroleum Corporation. The Court affirmed an $81MM civil penalty assessed by the district court for a spill at the company’s Louisiana facility.  The “gift” was the Court’s determination that the lower court did not err when it assessed a penalty $10MM less than what had been determined to be the economic benefit to Citgo from its non-compliance, despite the fact that the lower court had also found Citgo to be grossly negligent.

There are parallels between Citgo’s approach to Clean Water Act (CWA) penalty litigation, and that of Anadarko, a passive owner of a 25% share in the BP lease associated with the massive Gulf Spill. In both cases, a defendant took an aggressive approach to litigation over the penalty amount, forcing the matter to trial.

Prior to the initial Citgo trial, no CWA penalty case for an oil spill had ever been litigated to a conclusion, so pushing hard against hefty government demands was not irrational.  That decision at first seemed to work quite well for Citgo, when the district court assessed only a $6MM penalty after trial.  But that was reversed on appeal, and an $81MM penalty imposed on remand.

Anadarko’s position was buttressed by the added fact that prior to the Gulf Spill, the government had only once sought recovery of a penalty from a non-operating owner in a spill situation – and in that case, which settled, the pipeline operator did not appear to have sufficient assets to cover the penalty. But Anadarko fought its liability through discovery, a three stage trial, and a liability appeal, and refused to settle even after BP resolved its own liability. The district court then assessed a penalty of nearly $160MM against Anadarko, about twice what another passive owner paid to settle well before discovery and trial.

Was it worth several years of litigation to end up with these results? The penalty sought by the government at trial in both cases was vastly larger than the court outcome, but we are not privy to the government’s pre-trial settlement positions. What we do know is that both parties also incurred years of litigation costs, and have now established precedent that they and the rest of us will have to deal with.

With no court precedents to rely on, the pre-trial dickering over penalty amounts was a crap shoot. But in negotiations, the threat of trial is just leverage.  The government now has a couple of big benchmarks to put on the board in their negotiations, even if there is still a lot of room to argue over the details.  If a party ultimately decides to follow through on its threat to litigate, courts, at least in the Fifth Circuit, have shown they are not afraid to assess big numbers, even on a party who is a passive investor, if the spill involves major environmental impacts and bad behavior.

Industry Petition Pushes FERC to Require Gas Pipelines and Storage Companies to Immediately Reflect Lower Tax Rates in Shipper Rates

Posted in FERC

In light of reduced corporate tax rates as the result of Tax Cuts and Jobs Act of 2017 (Tax Act), a broad coalition of gas industry trade associations and gas producers recently filed a petition with the Federal Energy Regulatory Commission (FERC) urging the agency to lower gas pipeline and storage company rates to reflect tax rate reductions. The January 31, 2018 petition also offers a blueprint for how FERC could quickly accomplish this task.

Petitioners urge FERC to immediately initiate individual show cause proceedings requiring each pipeline and storage company to file its most recent 12 months of actual cost and revenue data and then adjust this data to: (a) reflect 2018 tax rates on the income tax allowance; (b) reduce and refund amounts in accounts for Accumulated Deferred Income Taxes (ADIT); (c) indicate the rate of return/capital structure assumptions used; (d) indicate the cost allocation and rate design methodologies that underlie their existing rates; and (e) include a derivation of the per unit rates, as adjusted. If this data, as adjusted, demonstrate that revenues received will exceed costs once Tax Act changes are factored in, Petitioners ask FERC to immediately order rate reductions.

Petitioners contend that such summary action by FERC would be appropriate because tax law changes are known and measureable and not subject to dispute. Anticipating pipeline and storage company opposition, petitioners also propose that such companies first be given an opportunity to demonstrate that their preexisting rates are still just and reasonable despite the Tax Act changes.

A key difficulty is that under Section 5 of the Natural Gas Act (NGA) [15 U.S.C. § 717d], FERC cannot require a reduction in rates until after a final FERC order based on the evidence presented. And although FERC has required the filing of cost and revenue studies in a number of pipeline NGA Section 5 investigations which have led to lower rates, the process for evaluation of such evidence has been slow. For example, in one recent NGA Section 5 investigation order, FERC set a timeline for decision on the rates more than a year later. [158 FERC ¶ 61,044 (2017)] Typically, pipeline cost and revenue studies generate a lot of time-consuming discovery requests. There is every reason to think this would be the case here.

A more practical problem with an industry-wide “show cause” process is the amount of agency resources it will consume. Anticipating this concern, Petitioners offer some proposals as to how FERC could attempt to streamline the process. First, they propose that FERC exclude from the show cause process any pipeline or storage company that is already required to file an NGA Section 4 [15 U.S.C. § 717(c)] rate case in 2018.  Second, they propose that FERC exempt Natural Gas Policy Act of 1978 Section 311 [15 U.S.C. § 3371] pipelines because these pipelines are otherwise required to file updated rate justifications on an ongoing basis. Third, they propose that any pipeline or storage company that is currently subject to a settlement rate change moratorium be exempted from submitting such a filing through the end of the moratorium term.

Even with these streamlining efforts, however, implementation will put a considerable burden on FERC staff resources. And exempting pipelines already making NGA Section 4 filings this year doesn’t reduce the burden on FERC staff — the general rate case filing will still need to proceed simultaneously.

Petitioners ask FERC to act as soon as reasonably possible, but the agency is unlikely to act without first soliciting public comment. Assuming FERC adopts the Petitioner’s recommended process, it is likely to be another year before any rates are found to be unjust and unreasonable. In the interim, pipeline and storage companies will continue to earn excessive returns by pocketing Tax Act savings.

Petitioners maintain that addressing Tax Act issues via notice and comment rulemaking would take too much time and unreasonably delay rate relief to consumers. But it is not clear why an expedited rulemaking process to allow development of a formula-based adjustment to existing rates, which is the approach adopted by FERC in 1986 when tax rates last declined significantly, would not be an equally or more speedy alternative to what they have proposed.

California Public Utilities Commission Issues Resolution ALJ-344, Constricting Procedures

Posted in California

At the end of 2017, the California Public Utilities Commission issued Resolution ALJ-344 which implements statutory amendments pursuant to Senate Bill (SB) 215, reflects changes in the Commission’s administration, streamlines certain procedures, and provides greater clarity. These changes come amidst mounting pressure on the CPUC to address allegations of “cozy” relationships with utilities, in the wake of several reports of backroom CPUC dealings with utilities. Of the many changes to the CPUC Rules of Practice and Procedure, there’s a balanced mix of proposed changes that could be seen as favorable or unfavorable from the perspective of regulated utilities, as detailed below.

Potential upside for regulated entities:

  • For ex parte rules, definition of “Party” includes CPUC staff acting in an advocacy capacity—this will bar prohibited ex parte communications with CPUC advocacy staff and add to a level playing field
  • Clarifies notice for ex parte is 3 working days in advance
  • Clarifies that at conferences, decisionmaker’s/interested person’s presentation or dialogue during a question and answer session where the audience includes a decisionmaker/interested person is not a prohibited one-way communication or an ex parte communication

Potential new challenges for regulated entities:

  • Bars ex parte communications within 3 days of Commission meeting
  • Assigned Commissioner has discretion to restrict ex parte communications in quasi-legislative and ratesetting proceedings
  • Limits definition of “procedural” matters, for purposes of ex parte rules, to matters that inquiring party does not reasonably believe is in controversy
  • Adds Commissioner advisory staff to definition of “decisionmaker” for ex parte rules, which will expand the prohibition on ex parte communications
  • Removes discretion not to conduct a prehearing conference
  • Removes discretion not to issue a scoping memo in adjudicatory and ratesetting proceedings
  • Eliminates the requirement that the Commission will make agenda item documents available at 9:00 a.m. on the day of the Commission meeting, but rather moves availability to the start of meeting
  • The Commission now has express authority to impose penalties and sanctions for ex parte violations, from $500 up to $50,000 for each offense

FERC Faces Complications in Adjusting Gas Pipeline Rates to Reflect Lower Federal Corporate Tax Rates

Posted in FERC

One of the major recent changes made to the federal tax code as the result of the Tax Cuts and Jobs Act was the reduction in corporate income tax from 35 percent to 21 percent. As soon as the corporate tax cuts took effect at the beginning of 2018, the Federal Energy Regulatory Commission (FERC) started to received requests that it use its authority under Section 5 of the Natural Gas Act (NGA) to lower pipeline rates to reflect the reduced corporate tax rates. Absent such action, it is alleged, recourse rates will be inflated and therefore no longer “just and reasonable” as the NGA requires.

In one request to FERC, the American Public Gas Association (APGA) estimates that firm recourse rates should be reduced by 5-9 percent to pass through these tax savings. A related issue is how to handle taxes collected from shippers which have not been paid but recorded in the pipeline’s accumulated deferred income tax (ADIT) account. Such ADIT accounts are likely overfunded because they were collected when the corporate tax rate was 35 percent and, if so, such monies should be refunded to shippers or used to reduce rates going forward.

APGA also asks that FERC take immediate industry-wide action, but it is not clear whether FERC can take this approach. Many rates in effect today were established under settlements that prohibited the rates from changing for a period of time. Does the FERC want to walk away from its longtime support of the sanctity of settlements and order changes in such rates before the rate change moratorium periods end? On a more nuts-and-bolts level, how will FERC investigate and modify rates to reflect lower tax expenses if existing recourse rates are based on a “black-box” settlement that does not specify, for example, the debt-to-equity ratio or the debt and equity cost rates used?

In 1987, FERC adopted in Order No. 475 a voluntary, abbreviated rate filing procedure to allow electric utilities to file for rate decreases to reflect the decrease in the federal tax rate as a result of the Tax Reform Act of 1986. The procedure adopted was a formula reduction in rates based on data supplied by the utility in its most recent rate case. FERC did not use this approach to downwardly adjust gas pipeline rates. At the time, most gas pipelines had tax trackers in their tariffs that caused recourse rates to adjust automatically when tax liabilities changed. That is no longer the case. As a result, if FERC does favor an industry-wide approach to address this issue, an order modeled on Order No. 475 may be in the offing.

Webinar, Feb 28: Alchemy in the Courtroom? The Transmutation of Public Nuisance Litigation

Posted in Environmental Quality

After long being a mere remnant of the old English common law, public nuisance has been experiencing an elongated renaissance. Courts have expanded the elastic doctrine into an all-purpose cause of action. As a result, lawsuits have alleged that everyday products such as paint, life-saving drugs, and pervasively regulated sources of carbon emissions are an unlawful nuisance. Our speakers will trace this tort’s transformation, discuss its current applications, and explain why judges should curtail its growth.


Thursday, February 28, 2018, 2:00-3:00 pm EST

Live online at




Richard Faulk

Counsel, Davis Wright Tremaine LLP

Neil Merkl

Partner, Kelley Drye & Warren LLP

Trump Track: One Brief Shining Moment of WOTUS Clarity

Posted in Trump Track, Water Law

In a rare moment of clarity in the benighted history of the Waters of the United States or WOTUS rule, a unanimous Supreme Court declared that jurisdiction to review the WOTUS rule lies in the District Courts and not the Courts of Appeal. The immediate effect of the January 22 ruling in National Assn. of Manufacturers v. Dept. of Defense is to lift the nationwide stay of the rule imposed by the Sixth Circuit—which held that the appellate courts have original jurisdiction over the rule—thus reigniting a lot of dormant trial court challenges.

The Clean Water Act applies to “navigable” waters, which is defined simply as “waters of the United States, including the territorial seas.” EPA and the Army Corps of Engineers administer the CWA, and have tried without much success to refine this vague definition.  The latest attempt is the WOTUS rule, adopted by the Obama EPA in 2015.  The issue in National Assn. of Manufacturers is not whether that attempt hits the mark, but in which court should challenges be heard.

The CWA extends original jurisdiction to the Circuits for EPA “approving or promulgating any effluent limitation or other limitation.” The government argued that the WOTUS rule falls within “any . . . other limitation.”  The Supreme Court rejected that argument, holding that such other limitations must be related to effluent limitations, and the WOTUS rule just establishes a definition that would apply generally to the scope of CWA.  The Court also rejected applicability of another CWA basis for Circuit Court jurisdiction advanced by the government, “issuing or denying any [NPDES] permit,” concluding simply that the WOTUS rule is not the same as permit issuance.

What it Means

So what difference does it make if a trial judge or an appellate judge makes the initial decision on WOTUS? WOTUS has drawn a multitude of challenges in both the District Courts and Courts of Appeals, including some in which plaintiffs filed in both courts to be on the safe side.  The case will end up at the Supreme Court anyway, right?

True, but consider that the Sixth Circuit consolidated all the challenges in other Circuits and issued a decision that applied across the country. The district court litigation has not been consolidated, and some cases have come to different conclusions, with many remaining to be litigated.  So, we can expect years of litigation in many different courts, followed by years of appeals heard by the Circuits, and finally to the Supreme Court . . . again.

But wait, Scott Pruitt’s EPA has initiated a rulemaking process to rescind and replace the WOTUS rule, so wouldn’t that moot the pending challenges to the rule?  It would not.  EPA has announced it is delaying the effective date of the 2015 rule for two more years to allow the present EPA to develop its replacement.  But in the meantime, the 2015 WOTUS rule remains in place.

The practical result is that the current round of cases in the District Courts will continue, followed, if not accompanied, by a new round challenging the proposed change of effective date, and the proposed rescission and replacement rules. Safe to say there will be no certainty on the definition of WOTUS and the scope of Clean Water Act jurisdiction for many years to come.

FERC Rejects FirstEnergy’s Application To Transfer Generating Facility to an Affiliated Utility

Posted in FERC

In an order issued on January 12, 2018, the Federal Energy Regulatory Commission (“FERC” or “Commission”) rejected an application by Monongahela Power Company (“Mon Power”), a franchised public utility subsidiary of FirstEnergy Corp. (“FE”) engaged in providing electric service in West Virginia, to acquire needed generation capacity from an affiliate. Mon Power had concluded through an integrated resource plan (“IRP”) that it faced a substantial capacity shortfall which was expected to exceed 850 MW by 2027. Mon Power therefore conducted a competitive RFP to acquire upwards of 1,300 MW of needed capacity reserves. In response to the RFP, Mon Power’s unregulated affiliate, Allegheny Energy Supply Company, LLC (“AE Supply”),  submitted a bid to sell its Pleasants power station (a 1,159 MW coal-fired electric generation facility)(the “Facility” or “Pleasants”) to Mon Power.  Although other entities participated in the RFP, AE Supply’s bid was recommended by an independent RFP administrator and was accepted by Mon Power.

Mon Power and AE Supply submitted an application to FERC under section 203 of the Federal Power Act (“FPA”) for authorization for AE Supply to transfer the Facility to Mon Power, and under Section 204(a) of the FPA for authorization for Mon Power to assume a $142 million promissory note (the “Note”) to secure a line on AE Supply’s interest in certain pollution control assets at the Facility. In denying authorization under Section 203, FERC concluded that the applicants have not demonstrated that the proposed transfer is “consistent with the public interest” and dismissed as moot Mon Power’s request for Section 204(a) authorization to assume the Note.

FPA Section 203

FPA section 203(a)(4) requires the Commission to approve proposed dispositions, consolidations, acquisitions, or changes in control of generation and transmission facilities if the Commission determines that the proposed transaction will be consistent with the public interest. The Commission’s analysis of whether a proposed transaction is consistent with the public interest generally also involves consideration of three factors: (1) the effect on competition; (2) the effect on rates; and (3) the effect on regulation. FPA section 203(a)(4) also requires the Commission to find that the proposed transaction “will not result in cross-subsidization of a non-utility associate company or the pledge or encumbrance of utility assets for the benefit of an associate company, unless the Commission determines that the cross-subsidization, pledge, or encumbrance will be consistent with the public interest.”


In Ameren,[1] the Commission explained how it would evaluate a transaction that involves the acquisition of an affiliate’s assets, noting that the Commission must assure that a public utility’s acquisition of a plant from an affiliate is free from preferential treatment.  The Commission set forth guidelines that apply four principles to different stages and aspects of the solicitation process: (1) Transparency: the competitive solicitation process should be open and fair; (2) Definition: the product or products sought through the competitive solicitation should be precisely defined; (3) Evaluation: evaluation criteria should be standardized and applied equally to all bids and bidders; and (4) Oversight: an independent third party should design the solicitation, administer bidding, and evaluate bids prior to the company’s selection.


FERC concluded that Mon Power’s competitive solicitation did not meet the Ameren principles because Mon Power failed to demonstrate that the proposed transaction will not result in inappropriate cross-subsidization. In denying authorization for transfer of the Facility to Mon Power, the Commission noted that its finding is without prejudice to a future application resulting from a new competitive solicitation by Mon Power.

Ameren – Definition and Evaluation Principles

In finding that the RFP did not meet the Ameren principles, FERC did not offer an opinion on compliance of the RFP with the Transparency and Oversight principles. Rather, FERC limited its opinion to the Definition and Oversight aspects of the RFP.


Mon Power proposed to acquire facilities, rather than to meet its needs through power purchase agreements (“PPAs”), because of the “increased control and flexibility asset ownership affords Mon Power relative to a PPA – including greater control over operations, maintenance, fuel procurement, and capital improvements, as well as the flexibility to modify facility operations.”   However, FERC found that the product sought by Mon Power was overly narrow because the stated objective, i.e., for Mon Power to acquire needed generation capacity, could have been achieved if the RFP considered PPAs as well as generating facilities. By excluding PPAs, the RFP, in FERC’s view, unduly limited the number of potential respondents and thus products that could have met the RFP’s stated objective. FERC concluded that the justification offered by Mon Power could have instead been a factor in the evaluation of offers, similar to the score for development risk, rather than eliminating from consideration an entire class of offers that could have been used to meet the capacity shortfall identified in the IRP. FERC also noted that two non-conforming bids for PPAs were received but not evaluated.

Mon Power also limited bids to only sources within the APS zone of PJM Interconnection, LLC because of the need to minimize Capacity Performance penalty risk. Mon Power explained that, because PJM allows capacity resource owners during a Performance Assessment Hour to net performance over multiple units within the same PJM load zone, the risk of penalty to Mon Power’s portfolio units is eliminated if the units are located within the APS zone. However, FERC found that the APS zone limitation in the RFP improperly excluded resources that otherwise could meet Mon Power’s stated objective. After finding such penalty risk to be quantifiable, and rare, FERC determined that the APS zone limitation in the RFP was overly restrictive.


In holding that the RFP did not meet the Evaluation principle, FERC explained that in its view, the use of a 15-year net present value (“NPV”) calculation excessively favors existing, older generation resources with low up-front costs but potentially high maintenance costs in subsequent years. While acknowledging that the estimates of future expenses and revenues become more uncertain the further into the future that they are projected, FERC concluded that ignoring years beyond 15 in the NPV calculation gives an advantage to a facility with a low purchase price and higher future costs, such as the affiliated Facility. FERC recommended that an NPV calculation that considers the total value of the proposal, including a terminal value, would more closely capture the comparable economics of each proposal in order to satisfy the Evaluation principle.

Mon Power included an “ease of integration” factor as part of the non-cost evaluation protocol, but FERC rejected this factor as dampening participation by other bidders and establishing an inappropriate preference for Mon Power’s corporate affiliates. Finally, FERC found that the RFP did not properly disclose the scoring criteria upfront. In FERC’s view, the Evaluation principle requires that “RFPs should clearly specify the price and non-price criteria under which the bids are to be evaluated. Price criteria should specify the relative importance of each item as well as the discount rate to be used in the evaluation.” While the RFP explained what the price and non-price criteria were, the weights of the criteria were not clearly articulated in FERC’s view. The Commission recommended that the RFP administrator should have allowed all parties to see how each price and non-price factor would be weighted in scoring the bids, including what discount rate would apply to the NPV calculation.

Safe Harbor

As an alternative to demonstrating compliance with the Ameren principles, a party can show that it comports with one of the safe harbor transactions reflected in FERC’s regulations that do not raise cross-subsidization concerns. One class of transaction that qualifies as a “safe harbor” are transactions that are subject to review by a state commission. Mon Power asserted that it qualifies for this safe harbor because the West Virginia Public Service Commission (“WVPSC”) regulates all aspects of Mon Power’s retail rates, facilities, and service (including the IRP), and the proposed transfer of the Facility required WVPSC approval.

FERC rejected Mon Power’s contention, noting that the mere fact that a state commission regulates an applicant and must approve the transaction at issue does not meet the standard established for the safe harbor. FERC determined that the applicants provided no evidence that any ratepayer protections regarding cross-subsidies were proposed in the proceeding before the WVPSC. In addition, the Commission observed that it would recognize the safe harbor “absent concerns identified by the Commission or evidence from interveners that there is a cross-subsidy problem based on the particular circumstances presented.” Because FERC noted that such concerns have been identified in this proceeding, it found that the proposed transfer did not fall within the safe harbor.

Guidance for future solicitations

As a general observation, FERC noted that properly designed competitive solicitations should provide non-affiliate competing suppliers with the same opportunity as an affiliate to meet the utility’s needs. In the interest of providing guidance for a future competitive solicitation by Mon Power, FERC noted that it disagreed with arguments questioning the need for generation or the accuracy of the load forecasts in Mon Power’s 2015 IRP, as it is the role of the WVPSC to make such determinations. FERC also disagreed with challenges to the independence of Mon Power’s RFP administrator by noting that, despite protestor arguments to the contrary, a repeated business relationship does not by itself indicate a lack of independence. Finally, the Commission rejected arguments that the RFP time-line to submit pre-qualification paperwork may have been restrictive and could have resulted in limiting the participation of potential bidders by observing that nine potential bidders submitted pre-qualification documents.


Mon Power will need to consider whether, and how, to engage in another RFP to meet its forecasted capacity deficiency. Unfortunately, the Commission’s order presents a mixed set of guidance for the company. FERC’s resolution of the state commission “safe harbor” issue against Mon Power appears to be based on a narrow reading of its regulations, particularly given the comprehensive jurisdiction the WVPSC asserts over Mon Power’s activity and its authority to approve the proposed transfer. Additionally, the Commission failed to describe appropriately why the company’s presentation of the basis for there being no prospect of cross-subsidization (in Exhibit M of the 203 application) was deficient.

Adding to the regulatory uncertainty related to conducting another solicitation, FERC too easily dismissed cogent justifications for RFP elements (e.g., the APS zone requirement for which 25 generation facilities – existing and in development – qualified), and the Commission provided minimal guidance on whether the RFP met the Transparency and Oversight principles under Ameren. While there are concrete recommendations in FERC’s order for another solicitation that Mon Power will undoubtedly assess, and FERC has enunciated its disagreement with some of the intervener arguments (e.g., as the RFP administrator’s alleged lack of independence), it remains to be seen whether these recommendations will be sufficient to overcome the uncertainty that the order has understandably cast over proposed acquisitions of affiliated generation, particularly for a company like Mon Power who had previously acquired an affiliated generation facility (with FERC’s approval).

[1] Ameren Energy Generating Co., Opinion No. 473, 108 FERC P61, 081 (2004)(“Ameren”).

New Tax Law Exerts Downward Pressure on Incremental Project Recourse Rates

Posted in FERC

Pipeline expansion capacity is priced at the incremental cost of service of the new facilities to be constructed. This causes the incremental recourse rate to generally be higher than the otherwise applicable system recourse rate.

That is no longer necessarily the case. In an order issued to Transcontinental Gas Pipe Line Company January 18, 2018, FERC recomputed a project’s proposed incremental recourse rate using the new 21 percent corporate tax rate.  This lowered the incremental cost of service so that the incremental rate was lower than the otherwise applicable system recourse rate.  As a consequence, FERC ordered the pipeline to charge the system recourse rate for the incremental project’s capacity.  The sole shipper on this project had elected negotiated rates so this reduced recourse rate had no impact on its capacity costs.  However, FERC’s action suggests that customers who have inked similar negotiated rate contracts for incremental expansions that are pending at the FERC might want to reevaluate that capacity’s value and consider reopening commercial negotiations with their pipeline counterparties.

Trump Track: Be Careful What You Ask For

Posted in Federal, Trump Track

The Trump Administration has taken the position that the President not only has the power under the Antiquities Act of 1906 to unilaterally establish national monuments, but also the unfettered authority to reduce in size or eliminate national monuments established in earlier administrations. Accordingly, the Trump Administration has undertaken a review of every national monument established since 1996 that is over 100,000 acres, and in December 2017, issued two executive orders reducing the size of the Grand Staircase-Escalante National Monument by 700,000 acres and dividing it into three parts, and reducing the Bears Ears National Monument from 1.35 million acres to 200,000 acres.

It is expected that these decisions will be challenged in court by tribes and environmental groups. The supporting and opposing arguments: the unquestioned power of the President to establish monuments without congressional action necessarily includes the authority to modify or eliminate existing monuments; and the absence of any mention of such authority to modify or eliminate monuments in the Antiquities Act reflects a congressional decision to leave that power in Congress, not in the President.

What It Means

As with many of the actions of this Administration, it is writing on a largely blank slate in terms of legal authority on the specific questions raised. This is not to say the questions have not been raised in the political arena.  The designation of monuments, like the scope of regulatory authority under the Clean Water Act and the Clean Air Act, to take just two prominent examples, has long been a bitterly contested political policy issue.  But, the procedural path to reverse earlier decisions has not been clearly delineated by the courts.

The situations are legally different, with the President’s authority for his monument action turning on statutory intent, while the reversal of Obama Administration CWA and CAA decisions will turn on rulemaking requirements under the Administrative Procedures Act, but it is beyond doubt that the Administration’s decisions on the monuments, like its CWA and CAA decisions, will produce significant judicial rulings on these important procedural issues

Thus, whatever the outcome of the particular cases, those judicial decisions over the next two or three years on procedural questions may re-set the balance of power between the legislative branch (Congress), and the executive branch (both the President and the administrative agencies). These decisions will be a double-edged sword.  The Trump Administration, which has appointed the most prominent skeptic on Chevron deference to the Supreme Court, may now rely on that same judicial deference to decisions of the executive branch, whether Presidential executive orders or regulations, to support its goal of unwinding past decisions.

If the Administration is successful, the outcomes it obtains will live on to enhance the administrative branch of government under future administrations seeking greater government involvement, not less. The Trump Administration, as it deals with the massive volume of litigation created by its actions, must tread carefully to avoid creating the very shift in balance of power between branches of governments it claims to abhor.

2018 Tax Law to Reduce Pipeline Expansion Recourse Rates

Posted in FERC

FERC staff has asked gas pipelines with pending expansion applications how 2018 tax law changes will impact their proposed project’s cost of service and the project’s proposed incremental rates.  FERC has imposed a quick, three business day turnaround on responses.

In identical data requests sent to a number of pipelines within the last week, FERC notes that effective January 2018, the Tax Cuts and Jobs Act of 2017 reduced the federal corporate income tax rate to 21 percent and allows certain investments to receive bonus depreciation treatment.  It asks pipelines to explain how these changes impact the proposed project cost of service and the resulting initial recourse rate proposal. Finally, it asks the pipelines to provide an adjusted cost of service and recalculated an initial incremental rate.

Pipelines with pending expansion applications who have received this data request include: Columbia Gas Transmission, LLC, Florida Gas Transmission Company, LLC, Gulf South Pipeline Company, L.P., Paiute Pipeline Company, Southern Natural Gas Company, Texas Eastern Transmission, LP, and WBI Energy Transmission, Inc.

Trump Track: Who’s Driving This Train?

Posted in Environmental Quality, Trump Track

On Thursday, January 4, 2018, the Department of the Interior (DOI) announced a proposal to open 25 of its 26 offshore planning areas for leasing for oil and gas drilling, reversing an Obama Administration drilling plan that had put the Atlantic and Pacific Oceans off-limits, along with new regions in the Arctic Ocean. The Administration emphasized that the plan was potentially subject to revision, beginning with a 60 day comment period after publication in the Federal Register.

Even before official publication, the plan drew immediate adverse comment from both red and blue coastal states. Republican governor of Florida, Rick Scott, who otherwise supports the Administration, vigorously criticized the plan the same day it was announced. . On Monday, January 9, 2018, DOI announced that it would remove Florida’s coast from the plans for future drilling, with Secretary Zinke stating that “Florida is unique and its coast is heavily reliant on tourism as an economic driver.”  Of course, the economies of other coastal states are also dependent on their beaches, oyster beds and fisheries, and it seems certain they will push for what Florida got.

The reversal of the offshore leasing policy is a big deal, but was not unexpected. President Trump had signed an Executive Order in April directing a review of the restrictions.  DOI also recently reduced the regulatory requirements placed on offshore drilling by the Obama Administration after the Deepwater Horizon spill in the Gulf.  All of that is consistent with the Administration’s clear intent to reverse almost every action taken by the Obama Administration in the area of environmental protection.

But as with so much of the activity by this Administration, one has to wonder who, if anyone, is vetting them for compliance with procedural standards, given the fact that legal challenges will almost certainly follow.

What It Means

Any observer could have predicted that opening both coasts to offshore drilling would draw fire from essentially every affected state. The original Obama proposal had also included some coastal lease areas, but opposition from the affected coastal states caused the administration to ultimately bar offshore drilling on both coasts. That would seem to suggest some pre-announcement consultation with at least the “friendly” red state governors, but that does not appear to have happened.  What does it say about the seriousness of a sixty-day comment period that even before the notice is published, informal comments by a governor of one state, after only a weekend of deliberation, results in its exclusion from the proposed listing?  And what will remain of that policy in a month, given that almost all of the affected coastal states have requested a similar waiver for the same reasons?

The offshore leasing proposal and its immediate revision has all the earmarks of a public relations event, not a serious policy re-evaluation of off-shore leasing. That may reflect confusion about who is in charge, the absence of seasoned management at the agency, or a rush to burnish the Administration’s list of accomplishments in advance of the mid-term elections.  Perhaps all of the above.  The Trump Administration is certainly entitled to reverse the policies it attacked during the 2016 election, but it also has an obligation to replace those policies with alternatives that are well-thought out through procedures designed to protect them against inevitable litigation challenges.

Trump Track: FERC Rejects DOE Coal/Nuclear Rule Proposal But Initiates A New One

Posted in FERC, Trump Track

On January 8, 2018, the Federal Energy Regulatory Commission (“FERC” or “Commission”) issued an order declining to conduct a rulemaking proposed by Department of Energy Secretary Rick Perry to that would create rate incentives for the coal and nuclear industries (“Proposed Rule”). The Proposed Rule would have required FERC-jurisdictional Independent System Operators (“ISOs”) and Regional Transmission Organizations (“RTOs”) to develop rules for compensation of certain “fuel-secure” electric generating facilities for their grid reliability and resiliency attributes.

The proposal attracted controversy because the proposed rules would effectively have provided subsidies to traditional generators like coal and nuclear plants, some of which presently face economic challenges in the ISO/RTO administered markets. Proponents of the Proposed Rule argued that the regulations would stave off plant retirements which would preserve electrical reliability and resiliency, reduce the likelihood of electrical outages in the event of fuel disruptions, and save jobs. However, critics argued that the subsidies would risk disruption of competitive wholesale electricity markets and driving out more efficient energy resources.

FERC rejected the rulemaking because the record was bereft of evidence that the existing ISO/RTO rules and practices are unjust, unreasonable, unduly discriminatory or preferential as required by section 206 of the Federal Power Act. In other words, the Commission concluded that it could not legally impose the proposed regulations with the evidence currently before it.

FERC, however, reiterated that “resilience remains an important issue that warrants the Commission’s continued attention, including through the development of a clear understanding of what each RTO/ISO currently does with respect to the assurance or strengthening of resilience and what more the RTOs/ISOs and the Commission could be doing on this issue.” In furtherance of its goal of providing assurance or strengthening of the resilience of the bulk power grid, the Commission initiated a holistic information gathering proceeding in which ISOs and RTOs are asked for certain information about grid resiliency in their respective regions. FERC’s goal is to “(1) to develop a common understanding among the Commission, industry, and others of what resilience of the bulk power system means and requires; (2) to understand how each RTO and ISO assesses resilience in its geographic footprint, and (3) to use this information to evaluate whether additional Commission action regarding resilience is appropriate at this time.”

Certain Commissioners made it very clear where they stood regarding the Proposed Rule. Democrat Commissioners Cheryl LaFleur and Richard Glick issued concurring statements criticizing the Proposed Rule. “In effect, it sought to freeze yesterday’s resources in place indefinitely, rather than adapting resilience to the resources that the market is selecting today or toward which it is trending in the future,” LaFleur said.  Commissioner Glick called it a “multi-billion dollar bailout targeted at coal and nuclear generating facilities.” In contrast, Republican Commissioner Neil Chatterjee issued a statement supporting the NOPR’s goal and said he would have preferred that the Commission require the ISO and RTOs to implement an interim rule while working out a longer term solution. He also noted that short-term interim measures still need to be considered in context of new proceeding.

Secretary Perry’s reaction was appreciative of FERC’s commitment to seeing the issue through, albeit at a slower pace than the DOE desired. His statement read: “I appreciate the commission’s consideration and effort to further assess the marketplace distortions that are putting the long-term resiliency of our electric grid at risk.  As intended, my proposal initiated a national debate on the resiliency of our electric system.  What is not debatable is that a diverse fuel supply, especially with onsite fuel capability, plays an essential role in providing Americans with reliable, resilient and affordable electricity, particularly in times of weather-related stress like we are seeing now. I look forward to continuing to work with the commissioners to ensure the integrity of the electric grid.”

What it Means

The Commission’s new approach is more aligned with how the agency traditionally undertakes rulemaking. However, FERC is not letting the matter stagnate.  The information sought by the FERC is extensive. ISOs and RTOs are required to provide the requested information within 60 days of the order and reply comments by interested parties are due 30 days after those submissions.  After these filings, FERC will have a substantial record with which to determine whether additional Commission action is warranted to address grid resilience.

California Feed-in-Tariff Program that Promotes Renewable Energy Procurement (Re-MAT) Found To Be Unconstitutional

Posted in California, Renewables

As California marches forward with its aggressive renewable energy targets, expecting to procure half of its electricity from renewables by 2030, a recent federal district court decision calls into question the constitutionality of one of the major regulatory programs that the California Public Utilities Commission (“CPUC”) implemented to foster further renewable development.

On December 6, 2017, the U.S. District Court for the Northern District of California issued an order granting summary judgment in favor of a solar developer, Winding Creek Solar LLC (“Winding Creek”), which is attempting to build a solar facility in Lodi, California and seeking a contract to sell energy from the project to Pacific Gas and Electric Company (“PG&E”). The decision involves the Renewable Market-Adjusting Tariff (“Re-MAT”) that the CPUC created in 2013 and which is implemented by the state’s investor-owned utilities (“IOUs”), including PG&E, Southern California Edison Company, and San Diego Gas and Electric Company.

Re-MAT is what is commonly referred to as a “feed-in tariff,” which is a regulatory policy mechanism designed to accelerate the development of renewable energy projects such as wind and solar. The CPUC’s Re-MAT program guarantees certain renewable energy generators, known as “Qualifying Facilities” or “QFs,” the right to enter into a standard contract to export electricity to California’s IOUs.  In essence, if a developer can build a working renewable project in California under 3 megawatts in size, it is guaranteed a contract to sell the project’s energy to one of the state’s IOUs.

Each IOU offers standard $/MWh pricing for Re-MAT contracts, but the price fluctuates over time based on principles of supply and demand (i.e. when many developers are seeking to enter Re-MAT contracts, the price falls; when fewer developers are seeking re-MAT contracts, the price increases). At the start of the Re-MAT program, the offer price for peaking as-available facilities like Winding Creek was $89.23/MWh, but the price has consistently fallen over time.  In addition, due to concerns that too many projects would take advantage of the Re-MAT program, California placed a 750 megawatt statewide cap on the quantity of Qualifying Facility generation that the IOUs are required to purchase under the Re-MAT program.

After failing to secure a Re-MAT contract at a price that it deemed acceptable, Winding Creek challenged the constitutionality of the Re-MAT program in federal court.   Winding Creek argued that Re-MAT was in conflict with the federal Public Utility Regulatory Policies Act (“PURPA”) and it’s implementing regulations for two reasons.   First, Winding Creek argued that the statewide cap of 750 megawatts conflicts with the federal mandate under PURPA that utilities must buy all of the energy and capacity offered by QFs (this federal mandate is known as a “must-take” obligation).  Second, Winding Creek argued that the method for setting Re-MAT contract pricing does not satisfy the definition of “avoided cost” in PURPA’s implementing regulations, which generally requires that QFs be compensated at a price equal to what the utility would otherwise have paid for alternative energy (i.e. the utilities “but-for” cost).

In a surprising decision issued on December 6, the Northern District of California agreed with Winding Creek’s two arguments, finding that the Re-MAT program conflicts with PURPA and its implementing regulations and thereby violates the Supremacy Clause of the U.S. Constitution. The court determined that: (1) the CPUC’s imposition of caps in the Re-MAT program violates PURPA’s must-take obligation for QFs; and (2) the procedure for setting Re-MAT pricing strays too far from the PURPA requirement that QF contract pricing be set on a utility’s but-for cost.  The case is Winding Creek Solar LLC v. Michael Peevey, et al., Case 3:13-cv-04934-JD (N.D. Cal).

On December 15, 2017, in response to the court’s decision, the CPUC’s Executive Director issued a letter to the state’s IOUs directing them to refrain from executing any new Re-MAT contracts, holding any new Re-MAT program periods, or accepting any new Re-MAT applications, effective immediately and pending next steps by the CPUC. It is not yet clear whether the CPUC intends to appeal the district court’s decision to the Ninth Circuit Court of Appeals.  The CPUC will have 30 days from the district court’s December 6 decision to file its notice of appeal.

The Road Ahead

The Winding Creek decision does not impact the validity of the contracts previously-executed under the Re-MAT program. However, it is unclear whether the decision could have ramifications for other feed-in-tariff programs instituted by the CPUC, particularly the Bioenergy Market Adjusting Tariff (BioMAT) program through which the IOUs are obligated to purchase power from qualifying biomass projects that produce energy from fallen trees and other forest material.  The BioMAT program was launched in 2015 in part to help address California’s ever-growing risk of forest fires by providing developers with an incentive to use forest material and debris as the fuel for producing renewable energy.

Trump Track: Polluters Play?

Posted in EPA, Trump Track

On December 11, 2017, the NY Times’ headline read: Under Trump, E.P.A. Has Slowed Actions Against Polluters, and Put Limits on Enforcement Officers.  The article reviews EPA enforcement during the first nine months of the Trump Administration.  The writers cite not only statistical comparisons with the first year of the Bush and Obama EPAs, but also quote an internal enforcement memorandum, interviews with current and former EPA staff, and residents at a facility under investigation in Ohio.

In a sidebar explaining their methods, the writers acknowledge that environmental investigations can take years to ripen into a settlement, and a few major settlements can shift numbers markedly. In addition to the factors cited in the sidebar, it is my observation that many experienced EPA personnel will retire rather than fight what they perceive as a hostile administration, especially following several years of continuing cutbacks in funding  by an equally hostile Congress.  To the extent that has occurred, it could bias first year numbers downward, as case management shifts and personnel are stretched thin.  In fact, a letter is now circulating that asks incumbents to stay the course, which mirrors efforts during other administrations to encourage incumbents in environmental, civil rights and other politicized areas to stay rather than leave or “retire in place.”

What It Means

The Trump Administration came into office promising to rein in what it perceived to be overly aggressive environmental enforcement. The information cited in the Times article is certainly consistent with what Trump promised.  However, it may also reflect other factors, such as an aging work force, and start-up delays, as much as budgeting and management priorities.  The numbers after a second year of control will be more obviously meaningful.  But the combination of numbers and other facts make a convincing case that the environmental enforcement record of this administration should continue to be examined.

Trump Track: EPA’S Sue and Settle Process – Justification or Rejection?

Posted in EPA, Trump Track

As noted in this space, on October 16, 2017, EPA Administrator Scott Pruitt issued a memorandum announcing new policies to avoid what he considered inappropriate approaches to resolving litigation, commonly referred to by the rubric “sue and settle.”  The major changes in policy included inviting participation by all interested parties in any settlement negotiations, more aggressive defense of claims based on alleged non-discretionary duties or deadlines, and refusal to pay attorneys fees to plaintiffs in connection with settlements.  That policy will soon be tested.

Relying in part on the arguments in that memorandum, the State of North Dakota sought reversal by the DC Court of Appeals of a lower court decision denying it the right to intervene to challenge a settlement by EPA over EPA’s failure to meet statutory time deadlines for regulatory review. In Environmental Integrity Project v. Pruitt, the DC Circuit in an unpublished opinion rejected the State’s appeal, even though it recognized that states are entitled to “special solicitude.”  The Court held that the State did not show the necessary impairment to its interests under FRCP Rule 24(a) because the settlement only affected EPA’s timing of a decision to either revise a regulation or determine that no revision was required.  In that instance, the State could at best assert the possibility of potentially adverse regulation; not a legally protected interest.

What It Means

The outcome here will not affect the policy change adopted by the Trump Administration. Viewed from the Administration’s perspective, the outcome here demonstrates the need for an opportunity outside the litigation process for stakeholders such as States to involve themselves in deadline settlement discussions. However, it also supports the arguments of critics that what the Administration has characterized as “sue and settle” cases that effect substantive change without involvement of outside parties, in fact are cases that do not present enough substantive impact for courts to allow intervention of right under traditional principles.

Major Public Nuisance Ruling by California Court of Appeals

Posted in Environmental Quality

On November 14, 2017, California Court of Appeals affirmed liability findings in $1.15 billion judgment ordering three lead paint manufacturers to abate public nuisance in 10 counties and cities containing homes built before 1978 (when lead paint was outlawed).  The complete opinion is here (143 pages):  (critical issue was whether lead paint manufacturers “created or assisted in the creation of the nuisance” by the “affirmative promotion of lead paint for interior use.”). 

The appellate court did not accept the entire scope of the original judgment, however.  It found that substantial evidence does not support causation regarding residences built before 1950.  As a result, the judgment was reversed and remanded with instructions to (1) recalculate the amount of the abatement fund to limit it to the amount necessary to cover the cost of remediating pre-1951 homes, and (2) hold an evidentiary hearing regarding the appointment of a suitable receiver.  The total reformed judgment on remand estimated by defense counsel to be $400 million.  

Defendants pledged to appeal current decision to California Supreme Court before remand to trial court. 

This decision will probably encourage the plaintiffs who are pursuing public nuisance litigation in California and other West Coast states regarding for PCB contamination and energy companies for climate change damages.   It may also encourage those who seek public nuisance recoveries in other states, particularly on the West Coast.

Nevertheless, the decision conflicts with at least two major California Supreme Court decisions that reject public nuisance judgments because of problems of “standardless liability.” People  ex rel. Gallo v. Acuna, 929 P.2d 596, 606 (Cal. 1997) (“The legislature’s lawmaking supremacy serves as a brake on any tendency in the courts to enjoin conduct and punish it with the contempt power.”); People v. Lim, 118 P.2d 472, 476 (Cal. 1941). (In a field where the meaning of terms is so vague and uncertain, it is a proper function of the legislature to define breaches of public policy which are to be considered public nuisances.”)  see also Richard O. Faulk and John S. Gray,  Public Nuisance at the Crossroads: Policing the Intersection Between Statutory Primacy and Common Law,  15 Chapman L. Rev. 495, 528-531 (2011); Richard O. Faulk, Uncommon Law: Ruminations on Public Nuisance, Mo. Env. L. & Policy Rev. 1, 8-10 (2010).

Prop 65 – Version 2.0: New Rules for Prop 65 Warnings Shake Things Up

Posted in Environmental Quality, Proposition 65

California’s old Proposition 65 warnings, which have been in place since 1986 are about to get a facelift – under newly adopted regulations by the Office of Environmental Health Hazard Assessment (OEHHA), what was once “clear and reasonable” may not be anymore.  Also, internet sales may face new requirements to ensure consumers are warned prior to purchasing a product.  Companies will need to update the warnings to keep pace with a hungry plaintiff’s bar.

The main changes focus on (1) the wording, (2) the application of the warning for internet sales, and (3) newly regulated products and classes of products. While the effective date of the new requirements is August 30, 2018, companies should begin planning now to ensure compliance.


Proposition 65 has always required “clear and reasonable” warnings, and the regulations have always offered sample language which presumptively meets the “clear and reasonable” standard. Last year, the Office of Administrative Law approved new sample language which becomes effective August 30, 2018. The main changes to the warning label for most consumer products (excluding food and beverages, which have specific prescribed warnings) are:

  • The name of the listed chemical(s) that prompted the warning and the corresponding risk of harm (cancer, birth defects and/or reproductive harm);
  • A triangular yellow warning symbol with an exclamation point on nonfood products; and
  • Direction to the internet address for OEHHA’s new Proposition 65 warnings website –

Internet Sales

The new regulations for internet sales are a significant departure from the current regulations, designed to increase disclosure and transparency and destined to shake up the regulated marketplace. Warnings in general must be provided to consumers prior to or during purchase, as compared with the current regulation, which requires warning prior to exposure or use of the product. For in-store purchases, on-product warnings or posted signs would be adequate.  However, warnings for internet sales are getting more stringent.  Internet retailers will be required to provide separate warnings for products sold online, even if the products themselves contain a compliant Proposition 65 warning.  The product-specific warnings may be provided via electronic device or process that automatically provides the warning to the purchaser prior to or during the purchase of the product.

Newly Regulated Products

The new regulations provide specific, tailored “safe harbor” warning provisions for new products, classes of products, exposure scenarios and places, including:

  • Alcoholic beverages
  • Food and non-alcoholic beverages
  • Restaurants
  • Prescription drugs
  • Dental care and emergency medical care
  • Raw wood and wood dust
  • Furniture products
  • Diesel engines
  • Passenger vehicles or off-road vehicles
  • Recreational vessels
  • Enclosed parking facilities
  • Amusement parks
  • Petroleum products
  • Service stations and vehicle repair facilities
  • Designated smoking areas


A warning for any consumer product manufactured prior to August 30, 2018 will be deemed “clear and reasonable” if it complies with the existing regulations. Under the new rules, however, warnings for consumer products manufactured on or after August 30, 2018 will need to conform to the new regulations.  Until then, warnings may use either the current warning language under existing 2008 regulations or the new language; businesses can choose to operate under the new regulations immediately.

The rules provide an exception for court approved consent judgments. Warnings containing the older Proposition 65 language will always be deemed “clear and reasonable” and thus compliant, so long as they were approved by a judge in a consent judgment before August 30, 2018.

Anytime regulations change, the regulated marketplace must adapt. New products and newly manufactured items will need to bear the new warnings.  But a lot of uncertainty remains:

  • What about products comprised of multiple chemicals?
  • How do you determine the manufacture date when production includes many steps?
  • What is the effect of prior settlements that were not confirmed by a court?

What It Means

Suddenly, the adequacy of, and not just the need for, a warning will be challenged. We anticipate new litigation regarding prior warnings. Although businesses may use alternative warnings so long as the warnings are deemed “clear and reasonable,” the safest thing for a business to do is adopt the language in the regulations.  Given the considerable changes to Proposition 65, businesses should revisit their compliance programs, inventory stock and ingredient/component lists.  What meets the standard today may not meet the standard next year.

Trump Track: Test for EPA’s Sue and Settle Process

Posted in EPA, Federal, Health and Safety, Litigation, Trump Track

As noted previously on this blog, on October 16, 2017, EPA Administrator Scott Pruitt issued a memorandum announcing new policies to avoid what he considered inappropriate approaches to resolving litigation, commonly referred to by the rubric “sue and settle.” The major changes in policy included inviting participation by all interested parties in any settlement negotiations, more aggressive defense of claims based on alleged non-discretionary duties or deadlines, and refusal to pay attorneys fees to plaintiffs in connection with settlements. That policy will soon be tested.

On October 19, 2017, the Sierra Club filed suit against Administrator Pruitt, alleging failure to meet deadlines and complete required assessments and reports under the Renewable Fuel Standards provisions of the Clean Air Act. See Sierra Club v. Scott Pruitt. The complaint presents a standard “failure to perform non-discretionary acts” claim, alleging that the uncompleted non-discretionary acts form the basis for the discretionary decisions required of the Administration. Notably, while the Obama Administration had also not undertaken the alleged non-discretionary actions, it was not sued, but then the Trump Administration has chosen to reverse the course of the Obama Administration with respect to those discretionary decisions.

What It Means

The suit is unlikely to result in any policy change by the Trump Administration. However, it should provide an early glimpse of how the new agency settlement policies will work in practice, and more specifically, whether the policies will result in more protracted litigation, with fewer settlements and more court-directed deadlines.

Trump Track: EPA Sue and Settle Fix?

Posted in EPA, Trump Track

On October 16, 2017, EPA Administrator Pruitt issued a memo to his agency directing that managers take certain steps to curtail the practice known as “sue and settle.” This practice most often is used for relatively quick resolution of citizen suits by environmental groups against the EPA involving the agency’s failure to comply with statutory deadlines for issuance of regulations.  The memo provides, inter alia, for developing a list of consent decrees and settlement agreements governing agency actions, including attorneys fees paid; notifying regulated parties and states of such citizen suits when filed, with various provisions to allow such parties to participate in negotiations and litigation; and a refusal to pay attorneys fees as part of any settlement, on the grounds that in a settlement, there is no “prevailing party.”


Loosely defined, “sue and settle” is a pejorative description used by the political party out of power to complain that the incumbents roll over for friends who file suits challenging unfavorable regulatory or statutory provisions. Both parties can dredge up examples of the alleged practices cited by Pruitt – alleged sweetheart settlements or forum-shopping for favorable courts who issue nationwide injunctions.  But in the recent past, it has been used by Republicans more specifically to refer to suits filed by environmental groups to force agencies – particularly EPA, which is subject to many such statutory mandates —to comply with non-discretionary statutory deadlines for issuance of regulations and other actions.

Republicans complained regularly throughout the Obama Administration that when such suits were filed, the agencies then quickly settled the cases through negotiations in which the regulated industry had no role, and paid significant attorneys fees to the attorneys for the settling plaintiffs. Environmental groups and other plaintiffs consider this a “phantom issue” since in their view, the cases often offered the government little recourse but to negotiate an acceptable timeline for compliance, and the statutes generally provide for attorneys fees to the prevailing party.

There is truth on both sides of this argument, but it is also true that this is a bipartisan issue, depending on whose ox is being gored. It is not entirely surprising that settlements are negotiated between the parties to the litigation, without the involvement of other interested groups.  But the result is not necessarily a one-sided deal.  The settlements over issuance of regulations do not dictate the substance of the regulation, only the schedule of agency issuance of the regulation.  In the case of a settlement, all interested parties will have an opportunity to comment on the schedule, but only the environmental group plaintiffs will have been involved earlier in the process.  To the extent that earlier access is important, the new process is intended to provide earlier access to all parties.  It remains to be seen how evenhanded that process will be in practice.

What it Means

One almost inevitable outcome of the new process will be more hard fought litigation. Multi-party negotiations make it likely that more matters will go to full litigation, even though the mandatory schedule issues come close to being the “slam dunks” that are almost never found in the law.  That will leave scheduling issues in the hands of a judge, not the parties, an outcome that the agency may come to rue.  And a battle over attorneys fees – which will most likely result in incurring more attorneys fees – is likely in every piece of litigation, unless Administrator Pruitt exercises his authority to waive that provision of his memo for such settlements.

The real problem is not addressed at all by this memo. The agency has not been given sufficient resources to meet statutory deadlines, many set decades ago to require periodic regulatory reviews.  Accordingly, when EPA prioritizes its resources to meet its current view of the most serious issues, meeting those dates often is low on the list.  If it is worried about these suits, Congress could either change the statutes or provide adequate resources. It has chosen to do neither, which may in the end simply mean more of the limited resources being spent on litigation.

Trump Track: Portland Harbor Reset Redux

Posted in EPA, Trump Track

Last Thursday, I posted about EPA apparently looking at resetting the approach to the Portland Harbor Superfund site.  I believe that the cost associated with the cleanup plan contained in Region 10’s Record of Decision (ROD) is out of proportion to the environmental benefits it would achieve, and despite the 17 years it has taken to produce the ROD at a cost exceeding $110 million, I think a review is in order.

The focus of my prior post, however, is that EPA headquarters was working on a new Administrative Order on Consent (AOC) to perform this fresh look without involvement by state, local and tribal governments. The legitimacy of such an effort depends on transparency on how changes, if any, are made.

News of EPA’s initiative prompted strong objections by Oregon officials, with apparently salutary effect. The day after my post went up, Region 10 Acting Administrator Michelle Pirzeda sent a reply letter offering assurances that the state, city and tribes will be involved going forward.  The letter sets a deadline of October 24 to submit comments on the draft plan.

What it Means

While unnecessary confrontation over who may participate in the process is averted for now, the substance of the Portland Harbor reset is likely to be contentious. Watch this space for developments.

Trump Track: EPA Beginning Anew at Portland Harbor Superfund Site?

Posted in CERCLA, Trump Track

Although no official pronouncement has been issued, it appears that EPA Headquarters is looking at resetting the scoreboard for the Portland Harbor Superfund site. EPA had already signaled  that it would be reviewing significant, long-unresolved Superfund sites with an eye toward streamlining the process.  However, the latest action on Portland Harbor may have the opposite effect, since EPA has not yet involved major stakeholders, including the State of Oregon, City of Portland, Port of Portland, or the tribes.

Portland Harbor is an 11-mile stretch of the Willamette River in industrial Portland. After a 17-year, PRP-led remedial investigation process, at a cost exceeding $110 million, EPA Region 10 issued a Record of Decision (ROD) in the closing hours of the Obama Administration. The ROD itself recognized that the baseline data upon which Region 10 relied in selecting its preferred remedy had grown stale, and called for another site-wide round of sampling prior to any Remedial Design for specific facilities.

EPA now is negotiating with certain, undisclosed private responsible parties on an Administrative Order on Consent (AOC) and a new sampling plan. A review of the current draft drew a sharp response from Oregon Department of Environmental Quality Director Richard Whitman.  In a letter  dated October 5, 2017 to Acting Regional Administrator Michelle Pirzadeh, Whitman invoked a 2001 Memorandum of Understanding between EPA, the state and tribes on the process for investigation and cleanup of Portland Harbor.  The letter criticizes EPA for keeping the state in the dark and demands the opportunity to fully participate in and comment on the new planning work.  Similar objections were raised by Governor Kate Brown, the City of Portland and the Yakama Nation.

Director Whitman also voiced substantive concerns with new directions in the draft AOC. These include revisiting assumed fish consumption rates, a “reset of achievable remedy targets/actions,” and a focus on downstream sites with “data gaps” within Portland Harbor itself.

What it Means

There is much to be critical of in Region 10’s handling of the Portland Harbor site, and revisiting the Region’s conclusions is appropriate. The assumptions driving the cleanup approach, emphasizing removal over natural riverine processes, could cost well over $1.5 billion for questionable environmental benefit.  Indeed, had EPA not added Portland Harbor to the National Priority List, Oregon DEQ would likely have implemented a cleanup plan incorporating routine Army Corps of Engineers maintenance dredging of the Willamette River at far less cost.  The resulting economic hit to the region will be enormous.

Still, I am reminded of Sen. John McCain’s famous thumbs down vote on bills to repeal and replace the Affordable Care Act. Apart from substantive elements of the bills, Sen. McCain decried the absence of “regular order” in enactment of major legislation.  That is, the congressional leadership bypassed the usual committee and collaborative review that identifies and fixes problems with the bill and lends legitimacy to the outcome.

Trump Track: EPA Moves on its Plan to Repeal [and Eventually Replace?] the Clean Power Plan

Posted in EPA, Trump Track

On October 10, 2017, EPA announced  it is taking steps to repeal the Clean Power Plan (CPP), regulations put in place in 2015 which requires existing power plants to roll back their CO2 emissions by 2030.  EPA is taking the unusual position that the agency exceeded its powers under the Clean Air Act when it created the CPP. The new EPA intends to look into its own powers and reconsider whether, when and how to issue a rule regulating greenhouse gases from existing facilities.

The process launched today begins a procedure which can, and likely will, take years to complete. The end result is unclear and likely will be determined by a court.

Given that the CPP is a complete and formally – adopted set of regulations promulgated under the Clean Air Act, the Trump Administration cannot simply wave a wand or issue an executive order to erase it. Instead, it must follow certain procedures, essentially beginning its own rulemaking process. Thus, EPA issued a Notice of Proposed Rulemaking (NPRM)  which opens a 60 day public comment period (beginning upon publication of the NPRM in the Federal Register, and which can be extended).  According to EPA’s press release, the new procedure “proposes to determine that the Obama-era regulation exceeds the Agency’s statutory authority.” As a practical matter, the current EPA contends any regulation of CO2 must relate to an entity’s operations and cannot direct an entity to employ changes “outside the fence line.”

Further, in 2007 the United States Supreme Court has held that EPA is required to regulate CO2. In Massachusetts v. Environmental Protection Agency  the Court ruled that CO2 and other greenhouse gases are pollutants under section 202(a)(1) of the Clean Air Act as they can cause or contribute to the type of pollution which ”may reasonably be anticipated to endanger public health or welfare.” Subsequently, after years of scientific study and input, in 2009, EPA issued a formal Endangerment Finding, concluding Greenhouse Gases, including CO2, are in fact a threat to human health and wellbeing and should be regulated. At that point, Greenhouse Gases could be regulated under a new law or the existing Clean Air Act.

The current NPRM does not dispute the Endangerment Finding, and requests commenters refrain from opining on the potential health hazards of greenhouse gases in general.  Rather, it requests comments to be limited to the confines of the NPRM package.  The NPRM package includes a “preamble” which contains a legal interpretation and policy analysis of the costs-benefits analysis of the proposed repeal, as well as a new Regulatory Impact Analysis of its proposal.  The Regulatory Impact Analysis of this new proposal estimates that repealing the CPP will result in a “savings” of $33 billion (in avoided compliance costs by industry, but does not include an analysis of likely rising health care costs associated with the repeal).

For background, in 2015, the Obama EPA promulgated the final CPP regulations. Some states, including Oklahoma (and industries) immediately challenged the CPP in court, in actions brought by Scott Pruitt, then- Oklahoma Attorney General and now-EPA Administrator. Prior to the September 2016 oral arguments, in February that year the US Supreme Court stayed the enforcement of the CPP pending the lawsuit. Thus, while the CPP was formally “on the books,” any attempt to comply with the regulations was voluntary until the resolution of the lawsuit.

What it Means

The rationale supporting the NRPM, the “beyond the fence line” arguments, essentially mirror the arguments made in court by Pruitt when challenging the CPP in 2015-16.  EPA contends the former administration failed to adequately consider (certain) states’ objections, and focused too broadly on promoting global climate benefits and energy efficiency.

EPA’s intent to scrap the CPP is obvious. It could have crafted ways to interpret and enforce the CPP regulations and encourage technological advances to strive for targeted reductions in CO2 emissions. Instead, it chose to erase the CPP as best it can, by beginning a long and “thorough” process, to discuss, re-analyze and calculate savings.

In other words, we are off the races, but it looks like it will be a slow-motion marathon, not a sprint, to a destination unknown.

U.S. Reversed on 100% Allocation to Contractor

Posted in CERCLA

The Ninth Circuit Court of Appeals has reversed a district court decision allocating 100% of CERCLA response to costs to a U.S. military contractor, where both the U.S. and the contractor were liable parties. TDY Holdings, LLC et al. v. United States.  The appellate court held that the district court had properly applied its discretion in its analysis of several factors favoring the government, but had misapplied the two most on-point circuit decisions regarding CERCLA cost allocation involving the US and WWII military contractors:  United States v. Shell Oil, and Cadillac Fairview/California, Inc. v. Dow Chemical Co  In both those cases, the Ninth Circuit had affirmed rulings in which the U.S., not the contractor, had been allocated 100% of response costs.

In contribution cases under CERCLA Section 113, the district court has wide discretion to apply “such equitable factors as the court determines are appropriate.” The Ninth Circuit’s ruling was not a wholesale dismissal of the lower court’s analysis, but rather an expression of concern that the lower court’s analysis reached a result so wholly different than that in other, similar cases. Indeed, in a short concurrence, one member of the panel stated that he thought the contractor should be held liable for something close to 100% of the costs, and that all the district court need do on remand is assign at least some of costs to the US.

If there is a lesson here, it could be the oft-cited dictum that in CERCLA cases, no one gets out of here without paying. The US has often played hardball in defending against liability under CERCLA — the long litigation history in the Shell and Cadillac Fairview cases is illustrative. After this decision and recent liability findings against the US based simply on its ownership of land with unpatented mining claims, it might remember that dictum when considering its settlement positions, particularly in WWII related claims.

Trump Track: Court Blocks Postponement of Methane Rule, But Battle Continues

Posted in Trump Track

On October 4, the district court for the Northern District of California in State of California and Sierra Club, et al v. BLM, et al.  held that BLM could not postpone its enforcement of various provisions of the Obama-era Methane Rule, which had gone into effect on January 17, 2017, after a district court in Wyoming had refused to enjoin the Rule. State of Wyoming, et al. v. United States Dept. of the Interior.  The Methane Rule requires steps to limit methane emissions from oil and gas operations on public land.

The district court held that BLM could not rely on authority in Section 705 of the Administrative Procedure Act to postpone the effective date of a Rule where the Rule had already gone into effect, even if some of its compliance dates in the Rule did not occur until January 2018. The court went on to hold that a repeal of the Rule would require following the same notice and comment procedures as promulgation, and that this could not be circumvented by a notice suspending or delaying enforcement, rather than a repeal. Finally, the court held that the rationale offered by BLM for the delay – the needs of justice – could not be supported by simply considering one half of a cost/benefit analysis, i.e., the costs of implementation.

What It Means. It may have been underway in court for six months in two district courts, but the fight over the Methane Rule is just beginning.  On October 4, 2017, BLM published a proposed rule suspending some provisions of the Methane Rule currently in effect, and postponing others until January 18, 2019, a broader action than the postponement just blocked by the Northern District court.  The comment process may take some time – when BLM put the proposed rule out for comment in 2016, it generated over 300,000 comments from both sides.

The history of this effort by the Trump Administration to sidetrack the Obama Methane Rule illustrates the fact that it is becoming increasingly aggressive in its efforts to walk back the regulatory efforts of the prior administration. Likewise, opponents are becoming more aggressive in their responses, developing new strategies to match the approach taken by the Administration.  It is almost certain that once the comment period is completed, the proposed rule will be challenged by the same groups that succeeded in blocking EPA in State of California v. BLM, through litigation in either the Northern District of California or the Wyoming district court.  Where this ends is uncertain.  Further litigation is not.

Trump Track: DOE Proposes FERC Action to Benefit Coal and Nuclear Power

Posted in FERC, Trump Track

On September 28, 2017, the Department of Energy (“DOE”) issued a Notice of Proposed Rulemaking (“NOPR”) to the Federal Energy Regulatory Commission (“FERC”) pursuant to §403(a) of the DOE Organization Act.  Regulations proposed in the NOPR would require FERC-jurisdictional Independent System Operators (“ISOs”) and Regional Transmission Organizations (“RTOs”) to develop rules for compensation of certain “fuel-secure” electric generating facilities for their grid reliability and resiliency attributes.  The NOPR establishes a tight 60-day timeframe for FERC action on the NOPR.  On October 2nd, the FERC issued a notice inviting comments on the NOPR, which are due on or before October 23, 2017.  As discussed in more detail below, FERC Staff has now issued a list of questions that it invites commenters to address.

DOE explained in the NOPR that existing wholesale markets have failed to provide adequate compensation for “grid reliability and resiliency resources,” including coal-fired and nuclear generators. According to the NOPR, market changes are necessary to prevent the rapid retirement of such resources, which provide electrical reliability and resiliency, reduce the likelihood of electrical outages in the event of fuel disruptions, and provide jobs.  Citing an August 2017 DOE Staff report and studies prepared by the North American Electric Reliability Corporation (“NERC”), DOE believes that the premature retirement of fuel-secure generators would threaten the reliability and security of America’s bulk power system.

It appears that the DOE has structured the proposed new regulations after those compensation mechanisms available to generators that offer environmental benefits, such as production tax credits and revenues from renewable energy credits. Under the regulations, each FERC-regulated ISO/RTO with a day-ahead and a real-time market or the functional equivalent would be required to establish new just and reasonable rates in its tariff for the purchase of electricity from eligible generators.  In order to be eligible, such generating facilities would need to provide “essential” energy and ancillary reliability services, have a 90-day fuel supply on the premises which would enable it to continue operating in the event of a supply disruption, and not already benefit from cost-of-service rate regulation. The new rate would need to ensure that each eligible generator is compensated for the benefits and services it provides to grid operations, such that it recovers its fully allocated costs along with a fair return on equity.

The NOPR does not specify how the cost recovery mechanism should be designed, which means that each ISO/RTO and its stakeholders would have the leeway to establish a cost recovery mechanism that is best adapted to the design of its market. Each ISO/RTO would then need to file the new rates with the FERC pursuant to section 205 of the Federal Power Act.  Such filings would then be subject to public comment, FERC scrutiny, and subsequent judicial review.

On October 4, the Director of the FERC Office of Energy Policy and Innovation issued a list of questions to be addressed by parties filing comments regarding the NOPR. The list of questions gives an indication of the issues and complexities that FERC Staff anticipates as it evaluates the proposed new rules.

For example, the FERC Staff asks a critical threshold question: “What is resilience, how is it measured, and how is it different from reliability?” and “How are reliability and resilience valued, or not valued, inside RTOs and ISOs?”   The FERC Staff also addresses what will undoubtedly be a thorny issue – what generating resources will be eligible?  Should the final rule be limited to existing units, or include new resources or repowered units?   Staff also asks whether there are “alternative approaches that could be taken to accomplish the stated goals of the proposed rule?”

With respect to rates, commenters are asked to opine on what costs should be included or excluded and how ISO/RTOs should allocate such costs on market participants. From a procedural standpoint, Staff addresses the quick time frame head-on by asking for comments on the 15 day time frame for the development of new market rules and an additional 15 days to implement such rules.

What it Means

Even with a short notice period, FERC will undoubtedly receive a vast number of comments from all energy industry sectors and consumer organizations with highly divergent opinions. It is unlikely that the aggressive timeline proposed by the rule will be met given the wide range of issues and technical complexities to be sorted out by FERC and eventually the ISO/RTO stakeholders in their respective governance processes.  On the other hand, too long of a delay could defeat the primary purpose of the rule which is to stave off premature baseload generation retirements.

Trump Track: EPA/DOJ Funding Split

Posted in EPA, Trump Track

EPA has proposed to end its funding of Superfund enforcement activities by the Department of Justice’s (DOJ) Environment and Natural Resources Division (ENRD). In its proposed budget for FY 2018, EPA has cut the nearly $26MM that DOJ included in its budget for FY2018.  This represents a complete change from the practice since 1986, when EPA, through an agreement with DOJ, has provided over $800MM in reimbursement funds to DOJ, representing 27% of the ENRD budget.

What it Means

This is not small change. The eliminated funding could cut 115 FTE’s (Full Time Employees), including 69 of the approximately 431 lawyers in the Division.  It also appears that EPA’s own budget for enforcement efforts for 2018 would be cut.

Virtually all cleanups are now carried out under unilateral enforcement orders (UAOs), rather than through EPA cleanup followed by collection efforts. It is difficult to imagine how additional compliance could be obtained by reducing the resources directed to negotiation of settlements and issuance of UAOs.

DOJ would now have to continue to provide enforcement support to EPA, but from its base funding, not reimbursement from EPA. In the past, ENRD attorneys have been known to grouse that the reimbursement agreement between EPA and DOJ resulted in a misallocation of enforcement resources, putting Superfund ahead of air and water enforcement.  If Congress approves EPA’s change in policy, the issue will not be misallocation, but rather how limited DOJ funding will be allocated among its various environmental missions. Hard choices lay ahead.

In the short run, diversion of more of EPA’s budget to cleanup activities may result in more aggressive cleanup at some existing sites. However, the impressive voluntary cleanup performance of recent years may be difficult to maintain.  Potentially responsible parties may feel that they can avoid or slow-walk the enforcement process, particularly at small sites, due to limited enforcement resources.

Trump Track: WOTUS Wrangle

Posted in Trump Track, Water Law

We have strange bedfellows, as business groups, states and environmentalists maneuver before the Supreme Court over the Obama Administration regulation defining “waters of the US” (“WOTUS”) under the Clean Water Act (CWA). Organizations supporting and opposing the rule all argue that the Court should overrule the decision of the Sixth Circuit Court of Appeals holding that the legitimacy of the WOTUS regulation must be decided by an appellate court under the terms of the CWA.

What It Means

The Obama WOTUS regulation was intended to resolve a conflict set up by the Supreme Court several years ago, when it split 4-1-4 (conservative, Kennedy, liberal) in a case involving a jurisdictional wetland issue.  In enforcement action subsequent to that decision, the Department of Justice requested that district courts apply a WOTUS definition aligned with the Kennedy and liberal bloc approaches.  Ultimately, the Obama Administration issued a regulation that adopted that general approach, over the opposition of business, farming and red state groups.  Following adoption of the regulation, there was a flurry of litigation in both district and appellate courts, with fierce arguments not so much over the substance of the challenge, but a procedural dispute over which level of court had jurisdiction under the CWA.

The Sixth Circuit finally held that the CWA required that jurisdiction over the WOTUS rule was in the appellate courts. The Supreme Court then accepted certiorari on that procedural issue, with business, state, and environmental groups all supporting the position that the Sixth Circuit had erred.  It is not often we find those groups aligned before the Supreme Court on an environmental issue.  However, in this case, the alignment may reflect how those groups see the future, as much as it does their interpretation of the language of the CWA.

From one perspective, it is better that regulatory issues of national scope are before a three judge appellate panel, rather than a single federal judge. Analysis by three appellate judges will be more thorough-going, and the road to the Supreme Court more swift.  On the other hand, even national regulatory issues might benefit from consideration of a variety of local concerns. And, not to be too cynical, jurisdiction in district courts provides great opportunities for forum shopping.

The situation is complicated by the fact that EPA, under the Trump administration, announced it is commencing a two-step process to unwind the WOTUS rule.  The first step rescinds the rule and public comments on that are due September 27.  At the same time, EPA announced that it will develop a new substantive WOTUS jurisdictional rule.  We expect multiple challenges to both steps of the rulemaking, making the challenge to the Sixth Circuit’s procedural ruling still central to the discussion.  In the meantime, EPA and the Corps of Engineers are supposed to carry on under the definition in place in the mid-1980’s and a guidance issued in 2008.

In this muddled context, parties with disparate interests in the ultimate outcome appear to see common interests in the forum issue. The business and red state opponents of the current regulation certainly do not want a decision by the Sixth Circuit upholding the regulation, and would like to have multiple opportunities to obtain district court rulings that the regulation is unconstitutional or otherwise an abuse of discretion.  Assertion of federal wetlands jurisdiction around the country would remain in constant flux while the Trump Administration undertakes the lengthy effort to replace it.  In addition, the ability to cite a variety of judicial views on the existing regulation may make it easier for the Trump Administration to defend its revised definition as equally reasonable.

From the environmentalist viewpoint, a Supreme Court decision giving them the opportunity to create similar litigation havoc with the Administration’s new rule must seem very inviting, particularly if the attraction of appellate review changes as Trump fills appellate court vacancies and shifts the ideological balance within the circuits.

You may note the absence of any analysis of the merits in this discussion. It was deliberate.

Trump Track: Is Superfund Small Ball Best?

Posted in CERCLA, Trump Track

The most active agency in carrying out the Trump agenda in its first year has been the EPA, where there has been a raft of efforts to roll back the regulatory initiatives of the Obama Administration. However, in one area the agency has promised to take a more active approach, with Administrator Pruitt promising to aggressively push the Superfund program to make progress on long-delayed cleanups.  In an earlier blog post, DWT assessed the multi-point program and the likelihood that the program could produce significant results.  But if the approach is successful at one site — the Bonita Peak Mining District Site — we may have a template for implementation of that program in the context of addressing the tens of thousands of complex abandoned mining sites in the Western U.S.

Bonita Peak is the site of the massive blowout at the Gold King Mine in August of 2015. As EPA itself noted at the time, the 3 million gallon release was simply a larger instance of continuing releases of contaminated water from the Gold King and surrounding mines that had long devastated the habitat in the Animas River for tens of miles.  It was cold comfort for EPA to note that the sediment concentrations in the River had soon returned to “normal,” when normal meant that no trout could live in a twenty mile stretch of the river.  The resulting Superfund site includes 48 mines, not just the Gold King.  With the current administration announcing a big cut in EPA spending, the locals are afraid that an under-funded and multi-decade Superfund process – the very fear that fed opposition to Superfund listing the past twenty years—was inevitable.

That multi-decade investigation and remediation is in fact inevitable, absent the discovery of some magic bullet for mine remediation. However, EPA is taking a slightly different approach here that could produce very significant results in the short term, long before the completion of the remedial investigation process.  EPA is now proposing, subject to completion of a public information process, the implementation of up to forty separate “quick fixes” to reduce the flow of acid mine drainage (AMD) into the Animas and its tributaries.  These range from the potential installation of a bulkhead to block large scale flow from one mine, to smaller projects involving the diversion of stormwater runoff around waste rock piles, and movement of waste rock and tailings from streambeds and adjacent banks.  These smaller actions won’t eliminate all of the AMD, but they could result in a significant improvement in water quality.

What it Means

This quick, incremental approach has been broached before in the context of Good Samaritan statutes under the Clean Water Act. Those statutes failed passage because of the conflict between the mining companies and environmentalists.  The former feared picking up additional liability if they carried out incremental fixes, and the latter feared half-baked remedies.   But here EPA can carry out the partial remediation while continuing with the full CERCLA remedial process.  Should the effort at Bonita Peak be successful, there may be some hope for expansion of that approach to the tens of thousands of abandoned mines throughout the West and lessening the pollution of Rocky Mountain trout streams.

Fundamental Hazard Communications to Control Risk

Posted in Environmental Quality, Health and Safety

To assure environmental health and safety, businesses must let their employees know the potential chemical hazards in the workplace. Businesses with such hazards were required to implement OSHA’s revised Hazard Communications Standard (“HCS”) in 2016. Safety Data Sheets (“SDS”) are a key component of HCS, and SDS issues are one of the most frequently cited OSHA violations. Employers should take a moment to make sure their program:

  • Identifies the employee(s) responsible for obtaining and maintaining SDSs for every product that may present a workplace hazard;
  • Contains a written description on how SDSs are maintained;
  • Has instructions and procedures for employees to obtain SDSs and how SDSs can be obtained if a backup is necessary due to a power failure or other event;
  • Provides a procedure for follow-up if an SDS is not received with an initial shipment of a chemical; and
  • Provides a procedure to assure the SDSs are adequate and current.

By now most employers recognize they are required to have an SDS available for each potentially hazardous product present on their property. The SDS provides a basis for what employee training is required to assure that employee exposure to chemicals is appropriately limited.

Remember, if you can’t document compliance, you are not compliant.

The United Nations has also established a Globally Harmonized System of Classification and Labeling of Chemicals (“GHS”). GHS Revision 7 was adopted for international use in 2017, but in the U.S., OSHA currently enforces GHS Revision 3 from 2009. Businesses with international reach should be aware of the potential difference in labeling requirements, and all companies should expect OSHA to further revise the HCS to align with the GHS.

A Win for Appropriative Water Rights

Posted in NEPA, Water Law

In an unpublished opinion released August 24th, the Ninth Circuit rejected a long waged effort to upend the City of Bend’s water planning by forcing it to abandon its vested surface water rights in favor of an all-groundwater supply. As is often the case, plaintiffs chose a somewhat oblique attack on the City’s water planning, relying on NEPA and forest planning laws to force a change of direction.

Central Oregon LandWatch v. Connaughton  was a challenge to a Special Use Permit issued by the U. S. Forest Service to the City to construct a new pipeline and to upgrade water diversion facilities on Tumalo Creek, within the Deschutes National Forest.  The existing pipeline also was previously constructed within the national forest under a SUP, but needs replacement.  The project drew controversy.

Plaintiffs contended that cessation of water withdrawals by the City is necessary to preserve Tumalo Falls, whereas the City argued that the project would enhance Tumalo Creek. To maintain pressure, the old pipeline needed to be kept full, resulting in constant diversions and discharge of surplus water downstream.  The new pipeline allows the City to withdraw water on demand, which will keep more water in the stream.  In addition, the City is working closely with the Tumalo Irrigation District to further protect the creek.

An amici group comprised of municipal and agricultural water users, intervened on behalf of the Forest Service and the City.  (Disclosure:  Our firm represents the amici, and serves as water counsel to the City, though we did not represent the City in this case).  The Oregon Water Resources Department separately intervened as an amicus.

The central concern for amici was the integrity of Oregon’s appropriative water rights law, which follows the first in time, first in right principle of other Western states.  Plaintiffs sought to upend that principle by elevating federal minimum flows, in the forest planning context, over state water law.  Oregon law allows the Oregon Department of Fish and Wildlife to apply for instream water rights, which would have priority from the date of application and would be treated like any other water right.  The purpose of the instream right is to prevent future appropriations, and so the “minimum” flows in the water right usually comprise or exceed the entire flow of the stream.

Plaintiffs argued that the Forest Service should have imposed minimum flows for the creek in the SUP, which they contended should be derived from the instream water right established for Tumalo Creek. The problem is that the instream water right is junior in priority to the City’s water rights.  Imposing the instream water right flows as a condition of the SUP would effectively turn appropriative water rights law on its head.  The instream right—with its aspirational flow regime—would then take precedent over the City’s right.

The court below  rejected that outcome, as did the Ninth Circuit, but on the basis that establishment of minimum flows are not required by rule or case law.  Further, doing so would not benefit Tumalo Creek because the City’s project would “positively impact stream flows” in one reach of the creek and “have no or minimal impact” in two other reaches, one of which is subject to Tumalo Irrigation District diversions that are not subject to the SUP.

The court also found that the Forest Service did not violate NEPA by limiting the alternatives analysis in the Environmental Assessment to just two: (1) implementation of the project and (2) a “no action” alternative based on the existing SUP. In other words, the court was not troubled by the Forest Service assuming that continuing exercise of the City’s surface water rights represents the status quo.   The court rejected plaintiffs’ argument that the Forest Service needed to additionally evaluate an alternative scenario where the City reduces or ceases withdrawals from Tumalo Creek.  The court found that the discussion in the Environmental Assessment was adequate, and relied on language in the EA that fully supports the City’s water planning:

The Forest Service determined that the surface water formed a “critical component of the City’s dual-source [water] supply.” . . . The EA explained that groundwater-only options would “compromise the City’s ability to provide a safe and reliable water supply,” reduce water flows in other parts of the Deschutes River, be costly, and be less reliable than a dual-source system. The EA also flagged possible environmental concerns posed by the groundwater-only option, including reduced surface stream flows (which are fed by groundwater) and increased energy consumption caused by pumping groundwater. This discussion was sufficient.

A dual source water system is the dream of every municipal water planner. That redundancy is insurance against natural or human-caused catastrophes that could disable one source.  And all water users need to be able to rely on the priority of water rights under the law.  That the Forest Service and the Ninth Circuit declined to upset the City’s long-term water planning is a victory for municipal water planners everywhere.

Trump Track: Executive Order To Speed Infrastructure Projects

Posted in Trump Track

On August 15, 2017, President Trump issued yet another executive order (EO) intended to speed environmental review of infrastructure projects. His first executive order with that objective, issued January 24, 2017, was devoid of detail and largely hortatory.  The August EO, is more detailed, but is merely aimed at implementing legislation passed during the Clinton and Obama Administrations: The Government Performance and Results Act of 1993, and the Government Performance and Results Modernization Act of 2010 (collectively GPRA).

The key new elements of the EO are a goal of achieving a two year average duration for agency environmental reviews, and scoring of agency performance by OMB pursuant to the GPRA. The EO also includes several provisions calling for coordination among agencies and appointment of a lead federal agency for each project. However, these do not appear to add to existing coordination obligations among federal agencies, other than to identify more coordination groups. In addition, without explanation, the EO revoked an Obama era executive order directing flood risk reduction measures for federal projects.

What it Means

Better coordination among federal agencies and a two-year duration for environmental reviews are worthy goals. However, there is little in the EO that provides confidence that those goals will be achieved to any greater degree than earlier efforts under other administrations.  The accountability feature may make this EO more successful, but planned agency budget and staff cuts could quickly undermine efforts to speed the process.  The EO itself contains many off ramps from time requirements to accommodate legal requirements and the need to assure that environmental reviews are defensible.  If the agencies short-cut required processes in order to meet the two year “average,” the most likely result is the kind of litigation that has often been the cause of the lengthy project delays the President complains of.

With respect to the revocation of the order calling for flood risk reduction measures, it may be that the “flaw” in that order was that it was based on climate change. But however one feels about climate change, rising sea levels are a fact well-recognized by insurance companies and coastal cities.  Revoking those requirements will not streamline the permitting process, but it may well result in government spending on projects that are not well-designed to survive changing conditions later in this century.

Over decades Congress has layered time consuming, expensive and sometimes duplicative environmental review for major federal projects. Each agency has its own statutory responsibilities and review criteria, meaning that any administration will be constrained in moving the process along too fast or risk being hung up in the courts for years.  True streamlining remains dependent on sound congressional action.

Trump Track: Federal Environmental Civil Penalties Drop by 60%

Posted in Trump Track

Last week, the Environmental Integrity Project released its report on environmental enforcement during the first six months of the Trump administration. The Environmental Integrity Project, a nonprofit, nonpartisan group founded by former enforcement attorneys at EPA, found that civil penalties are down 60% on average compared to past administrations.

The Environmental Integrity Project reviewed civil cases referred to the Justice Department from EPA, with the exception of Superfund cases. Looking at consent decrees lodged in federal court between January 21 and July 31, 2017, the Justice Department lodged 26 civil cases with an aggregate total of $12 million in penalties to resolve violations under environmental laws.  During the same time period of the first term of Presidents Barack Obama, George W. Bush and Bill Clinton, the Justice Department lodged a total of 34, 31 and 45 cases, respectively, with $36 million, $30 million and $25 million in penalties.  Estimates of the value of injunctive relief in the cases, such as pollution controls, also showed significant reductions from prior administrations.

What It Means

Caution should be taken in drawing conclusions about longer trends from the limited sample, but the first six months show EPA pursuing less enforcement actions with smaller fines. With the Trump Administration proposing to cut EPA’s budget by over 30% and Secretary Pruitt planning to shrink its workforce, it seems unlikely for this trend to reverse.  Polluters aren’t totally off the hook, however. States may step up enforcement activity to fill the void. With environmental NGOs receiving unprecedented levels of donations since the election, they may also have the resources they need to step up citizens’ suit litigation in the Trump era.

Ninth Circuit Addresses Finality Requirements for CERCLA Contribution Actions

Posted in CERCLA

The Ninth Circuit Court of Appeals revived a contribution action under CERCLA, and in the course of ruling, it addressed three issues of first impression in the Circuit regarding contribution litigation under CERCLA. Asarco, LLC v. Atlantic Richfield Company.

First, it joined the Seventh Circuit in holding that a settlement entered into under an authority other than CERCLA could give rise to a CERCLA contribution action. Second, it held that corrective measures under a RCRA settlement could be response actions for purposes of CERCLA. Third, it held that in order to bring a contribution action under CERCLA Section 113(f)(3)(B), a party must resolve with “certainty and finality” at least some of its liability for response costs at the site.  In addressing the latter issue, the court addressed not only the absence of such resolution in the RCRA decree at issue, but also clarified what it would require by way of “certainty and finality” to establish resolution in a CERCLA settlement.

Asarco brought its contribution action in June 2012, three years to the day after entry of a settlement with the United States in Asarco’s bankruptcy. Atlantic Richfield sought dismissal of the case because Asarco had entered into a 1998 settlement of RCRA claims at the same facility, paying a civil penalty and committing to substantial cleanup activities. Thus, the case hinged on which settlement commenced the start of the three year statute of limitations for contribution claims under CERCLA.

The district court held that the RCRA settlement satisfied the provisions of Section 113, and dismissed the action as untimely filed. On appeal, the Ninth Circuit agreed with the district court that a settlement satisfying Section 113 did not have to be a CERCLA settlement, and also that cleanup actions taken under the RCRA settlement were response actions for purposes of that section.  It found that, however, that the RCRA settlement, unlike the bankruptcy agreement, did not constitute a final resolution of any part of Asarco’s liability under CERCLA.

In ruling, the court noted that the specific terms of the RCRA settlement resolved only liability for civil penalties, and specifically reserved all authority of the US to take other actions under CERCLA and other statutes. More significant for future cases, the court, contrary to decisions in the Sixth and Seventh circuits, also held that “certainty and finality” is not defeated by a party’s non-admission of liability, or by terms that reserve the government’s ability to enforce the agreement, or that condition the release of liability on completed performance of the terms of the agreement—all provisions ubiquitous in CERCLA settlements with EPA and the Department of Justice.

The often confusing language of CERCLA has given rise to a great deal of litigation, particularly in the area of contribution claims. As the court notes, the test of certainty and finality will require a case by case analysis.  However, this decision provides parties a much clearer road map for analysis of such claims, at least in the Ninth Circuit.

Trump Track: WOTUS Washington Two-Step

Posted in Environmental Quality, Federal, Trump Track, Water Law

The Trump Administration has begun rulemaking to undo the controversial rule defining “waters of the United States” or WOTUS. In the July 27 Federal Register, EPA and the Army Corps of Engineers jointly announced that it is proposing a two-step process.  The first would be to rescind the 2015 WOTUS rule, and the second would replace it with something aligned with the Administration’s thinking.  As reported here, on February 28, 2017, President Trump issued an executive order directing the agencies to change direction.

The Clean Water Act confers federal jurisdiction over “navigable” waters, which are defined as “waters of the United States.” The agencies, courts and property owners have since struggled to elucidate that vague definition, particularly in the context of wetlands.  A divided Supreme Court, in Rapanos v. U. S., offered competing definitions.  Justice Scalia, writing for a plurality of the Court, would require running water, whereas Justice Kennedy in a concurring opinion, looked to whether a “significant nexus” exists between the waters or wetlands at issue and a navigable waterway.

The Obama Administration’s WOTUS rule attempted to bring clarity to the scope of federal jurisdiction, with an emphasis on the Kennedy approach. Under President Trump’s  executive order, the new rule is to follow Justice Scalia’s view of WOTUS.

What It Means

During the interim between step one (rescission) and step two (replace), we will have to muddle along as before. The Federal Register notice states:

The agencies would apply the definition of “waters of the United States” as it is currently being implemented, that is informed by applicable agency guidance documents and consistent with Supreme Court decisions and longstanding practice.

Simply stated, that means continuing uncertainty. It will probably take some years before a new replacement rule can be developed under the deliberate process required by the Administrative Procedures Act.  If the reaction to the Obama WOTUS rule is any guide, the replacement rule will face many legal challenges, which could also take years to resolve, probably at the Supreme Court.  Thus, it is unlikely that there will be binding policy change during the first term of the Trump Administration.

In the meantime, it is useful to remember that the states are free to adopt their own definitions of jurisdictional wetlands, which many have done or in the process of doing.  States with strong environmental protection traditions—such as Oregon, California and Washington State—can be expected to assert jurisdiction, perhaps where the federal government does not.  We’ll be providing more on state responses to environmental deregulation under the Trump Administration in the coming weeks and months.

Trump Track: Pruitt Moves to Streamline Superfund Process, Accelerate Pace of Cleanups

Posted in Environmental Quality, EPA, Federal, Trump Track

On May 22, 2017, EPA Administrator, Scott Pruitt, convened a Superfund Group to examine the existing Superfund process and make recommendations to streamline the process and incentivize parties to accelerate remediation and revitalize the properties. On July 25, he received the group’s report and ordered implementation of its recommendations.  In particular, the recommendations and the Administrator’s accompanying memorandum are aimed at expanding the role of EPA Headquarters in oversight of major sites, and re-focusing the Regions on assessing and facilitating the re-use of sites.  Among the highlighted steps were

  • A priority of list of ten sites that had been on the National Priorities List (NPL) for at least five years without meaningful movement, which would be subjected to weekly scrutiny by his office
  • Optimization reviews to closely track progress at old sites
  • Use of early action at sites to accelerate partial cleanup during an often extended investigative process
  • Use of indirect cost reductions as an incentive to PRPs to conduct timely and high quality cleanups
  • Use of Unilateral Administrative Orders to discourage negotiation delays
  • Regions to focus on the re-use potential of sites
  • Establishment of strong stakeholder relationships, with communities, PRPs, and potential developers of the sites

In addition, he directed the Regions to make a list of sites they expect to delete from the NPL within the next 12 months.

What It Means

A call by the Administrator for reform of the Superfund process is not new. Most of the proposed approaches likewise have been in the agency arsenal for years, and have even been used.  And the directive to list sites expected to be deleted this year sounds like the bean-counting that has often characterized agency performance – numbers, not real results.  However, there is some reason to expect that this time, there could be significant progress made.

Administrator Pruitt had already indicated that any site with an estimated remediation cost over $50MM would be reviewed directly by his office. Under this directive, there will be greater attention paid to mega-sites, particularly sediment sites, that have dragged on for decades without final remediation plans, absorbing an inordinate share of agency and PRP resources.  PRPs will apparently have greater access to highly qualified headquarters personnel, without having to fight through levels of regional review by often inexperienced managers.  That factor alone may markedly accelerate the process at those sites.  Greater reliance on private sector developers who seek to reuse the sites should also reduce the agency’s costs, accelerate the cleanup process and benefit the communities by restoring sites to economic use.

Of course, this all assumes the agency is not hamstrung by a lack of resources due to budget cuts. That is a big assumption, since it would be easy to assign a major share of responsibility for the problems in the existing process to regular budget cuts, leading to frequent staffing changes and inordinate delays in the review of work plans, investigative reports and preparation of remediation decisions. EPA has announced significant personnel cuts, many of which will occur through the attrition of experienced employees.  And a $50MM cutoff for Headquarters review of a Superfund site unfortunately does not limit that review to a small number of sites for that staff to handle in addition to its regular workload.  $50MM is actually a fairly low bar in the Superfund context.  For example, EPA Region 10 estimates the cost to cleanup Portland Harbor $1.2 BB, which most PRPs see as much too conservative.

If the personnel necessary to administer the program are simply not available, all the new process won’t make Superfund easier or less expensive to navigate. Nothing is quick in the Superfund world, but we should know within the next year whether this is real change, or just more rhetoric.

Trump Track: Environmental Policy Changes

Posted in Environmental Quality, Federal, Trump Track

While the Trump Administration has struggled overall to develop and implement coherent policies, the Administration has had some success in the environmental sphere. Through a series of presidential memoranda, executive orders, agency administrative notices, and legislative action, there is a lot of change in the air (no pun intended).

DWT has undertaken to track developments for our clients and friends on this blog site. Each post will include an explanation with the phrase “what it means” to help put new developments in context and to take a step beyond just reporting the news.  If you don’t subscribe (and we certainly invite you to), a search of “Trump Track” and “what it means” should get you there.

Much of what the Administration has put forward to date directs federal agencies—EPA, Interior, Transportation—to review Obama-era regulations with an eye toward rescission. Undoing these regulations, however, does not happen with a stroke of the president’s pen. There is a lot of process for the government to go through, which will create a target-rich environment for NGOs or states to bring challenges in court.  Existing federal law requires deliberate, standards-driven, and time consuming decision making.  Watch for cases invoking the Administrative Procedure Act and National Environmental Policy Act as entry points for contesting major policy shifts under the Clean Water Act, Clean Air Act, Superfund, and other substantive federal environmental laws.

In addition, many states have announced their intentions to proceed with environmental policy regardless of what the federal government does, particularly in the control of greenhouse gas emissions. Where DWT has offices, we intend to track state actions in response to or despite federal changes.

To get started, we have prepared the attached cheat sheet that summarizes Trump environmental initiatives to date. Watch this space for updates.

Inside the Beltway

Posted in Federal

You are invited to join us as we host Former Congressmen Norm Dicks (D-WA) and George Nethercutt (R-WA); Bruce Evans, Majority Staff Director, Senate Committee on Appropriations; and Alex Keenan, Minority Staff Director, Senate Appropriations Subcommittee on Labor, HHS & Education for an exclusive look into the changing face of Washington, D.C. Learn about the new landscape for government contracting, best practices in pursuing federal procurements and more as our esteemed panel discusses the ins and outs of working “Inside the Beltway.”

This one of a kind event will provide attendees with timely and topical information for government contractors as well as those companies or individuals who are interested in doing business with the federal government.  You will have the rare opportunity to hear from these leading insiders on both sides of the aisle on hot topics and policy priorities that are essential for business and strategic planning. The panel will discuss infrastructure development, deregulation, outsourcing, cyber security and more. And all with their unique perspective of Washington’s “new normal.” In addition, you will have direct access to this esteemed panel during the Q&A period as well as during the reception that follows. This is a must attend event for anyone doing business or seeking to do business with the federal government, CEOs, Presidents, CFOs, General Counsel and other in-house lawyers, and Government Relations executives. 


Inside the Beltway

Tuesday, September 12, 2017 4:30 PM – 7:00 PM EST

Davis Wright Tremaine LLP

1919 Pennsylvania Avenue NW, Suite 800

Washington, D.C. 20006-3401

Note: In D.C., registration begins at 4:30 p.m., program at 5:00 p.m., reception and “meet and greet” with panelists at 6:30 p.m. The event will be live-streamed to Davis Wright Tremaine’s offices in Seattle (2:00 pm), Portland (2:00 pm), and Anchorage (1:00 pm)

CLE credits pending

Complimentary Program


Contact Joshua Dyer with questions.


About the Panelists 

Former Congressman Norm Dicks (D-WA)

Congressman Dicks represented Washington’s 6th district in the House of Representatives for 36 years (from 1977 – 2013) where he received a rare first-term appointment to the House Appropriations Committee, a committee he served on for his entire tenure in Congress. In addition, he served on and chaired the Interior Appropriations Subcommittee where he made environmental issues a priority and worked tirelessly on issues affecting the National Parks, National Forests, and Native American issues. Congressman Dicks also became the chair of the Defense Appropriations Committee and concluded his tenure in Congress as a top-ranking Democratic Member on the Defense Appropriations Committee, as well as a top-ranking Democrat on the House Appropriations Committee. From 1990 – 1998, Congressman Dicks served on the House Intelligence Committee and was awarded the CIA Directors Medal.

Former Congressman George Nethercutt (R-WA)

Congressman Nethercutt represented Washington’s 5th District from 1995 – 2005. He was first elected to Congress in 1994 in a dramatic election in which he unseated Speaker of the House Tom Foley. Congressman Nethercutt sat on the House Appropriations Committee and the House Science Committee. Currently he is the Chairman of Nethercutt Consulting and he also founded the George Nethercutt Foundation aimed at fostering civic involvement. 

Bruce Evans, Staff Director, Senate Committee on Appropriations

Staff Director Evans currently serves as the Staff Director for the Senate Committee on Appropriations. He has had a long and distinguished career in the Senate and is widely known for his knowledge of the appropriations process. Previously he served as Chief of Staff to Senator Thad Cochran. Prior to that, he directed Republican staff on the Senate Appropriations Committee, addressing federal spending matters and preparing the annual budget, and served as Staff Director for the Senate Committee on Energy and Natural Resources.  

Alex Keenan, Democratic Staff Director, Senate Appropriations Subcommittee on Labor, HHS & Education

Staff Director Keenan has vast experience driving budget decisions at a variety of federal agencies. Currently he serves as the Democratic Staff Director for the Senate Appropriations Subcommittee on Labor, HHS & Education. He has also worked as the Staff Director for the Transportation, Housing and Urban Development Appropriations Subcommittee (from 2009 – 2015). Previously he served as the Chief Financial Officer at Immigration and Customs Enforcement and worked as the Budget Director at the FAA, during which time he dealt extensively with various Congressional committees and Appropriations panels. Staff Director Keenan also has more than two decades of experience in the Executive Branch, having spent 10+ years analyzing budgetary fine print for the Office of Management and Budget and the Justice Department. 

California’s Cap-and-Trade Regulations Extended Through 2030 – A Victory for Climate Policy and Business Alike

Posted in California, Cap and Trade

On July 17, 2017, the California Assembly and the Senate voted to extend California’s Cap-and-Trade Program from 2021 to 2030 (Assembly Bill (“AB”) 398). Governor Brown is widely expected to sign the bill in the coming weeks.

AB 398 is considered as a major win for Governor Brown and his commitment to fight climate change, because it reinforces and extends one of California’s marque programs to reduce greenhouse gas (“GHG”) emissions. The Cap-and-Trade Program—which is administered by the California Air Resources Board (“CARB”)—requires factories, power plants, and other companies (“covered entities”) to pay for the GHG emissions associated with their industrial activities.

The Cap-and-Trade Program aims to encourage pollution reduction at the lowest possible cost by placing a cap on each source of GHG emissions, allocating GHG emissions permits to covered entities on a yearly basis, and then creating a market for covered entities to buy and sell such emissions permits through an auction process. In general, AB 398 will extend the existing Cap-and-Trade Program, with a few notable changes detailed below.

  • Ten-year extension. Extends CARB’s authority to adopt rules and implement the Cap-and-Trade Program and achieve GHG emission limits through the end of 2030.
  • Applies to the same industries and uses same industry assistance factors. The same industries will continue to be subject to the Cap-and-Trade Program and CARB’s authority. CARB will set the industry assistance factors for the post-2020 Program at the same levels that are applicable to the 2015 through 2017 compliance period.
  • Same reporting threshold.   No mention of changes to the current threshold triggering reporting obligations for emissions of more than 10,000 metric tons of CO2 per year.
  • Decrease of free allowances/reduction of cap adjustment factor. Directs CARB to “apply a declining cap adjustment factor to industry allocation.” The “cap adjustment factor” is another component of the free-allowances formulas and will reduce the number of free allowances given out by 40 percent by 2030.
  • Lowers the cap for the use offset credits. Under the current law, GHG “offsets” (i.e. projects that otherwise reduce GHG emissions or mitigate the impacts of climate change) can be used for up to 8% of a regulated entity’s compliance obligation. AB 398 reduces that to 4% from 2021 through 2025, and 6% from 2026 through 2030.
  • Impact of offsets must be tied to California. Half of all offsets used for compliance from 2021 through 2030 must come from projects that have “direct environmental benefits” in California.
  • Increased focus of offset projects. CARB must develop approaches to increase offset projects in the state.
  • No specific price ceiling. CARB must consider certain factors such as the “need to avoid adverse impacts on resident households, businesses and the state’s economy.”
  • Two price containment points. The “price containment points” will be two prices set below the price ceiling for the yearly GHG emissions permit auction. CARB must offer for sale certain amounts of allowances at those two price containment points.
  • Suspension of fire prevention fee. Suspends a fee that primarily affects rural landowners.
  • Establishes an Independent Emissions Market Advisory Committee. Establishes the Independent Emissions Market Advisory Committee to report to CARB and the Joint Legislative Committee on Climate Change Policies on the environmental and economic performance of the Cap-and-Trade Program and other relevant climate policies.
  • Establishes a Compliance Offsets Protocol Task Force. Directs CARB to create the Compliance Offsets Protocol Task Force to provide guidance to CARB in approving new offset protocols for the purposes of increasing offset projects with direct environmental benefits in the state while prioritizing disadvantaged communities, Native American or tribal lands, and rural and agricultural regions.
  • Linking with other jurisdictions. Allows for linking of California’s program with other jurisdictions, which helps spread effective climate policy beyond state borders.
  • Preemption. Preempts regulation by local governments or regional air quality management districts of GHG emissions by any stationary sources covered by the Cap-and-Trade system until 2031.
  • Extends tax breaks. Extends sales and use tax exemptions to manufacturers and research and development activities in the state, and expands them for electricity production through 2030.
  • Annual reports on specified GHG emissions targets. Requires the Legislative Analyst’s Office to annually report to the Legislature on the economic impacts and benefits of specified GHG emissions targets.
  • Use of money. Cap-and-Trade Program moneys are to be appropriated in accordance with specified order of priorities, but no instruction on how money from the Program will be used.The link to the final bill can be accessed at:

AB 398 goes hand-in-hand with other recently-approved legislation, including AB 617, which is meant to address local air quality concerns, and ACA 1, which puts a measure on the 2018 ballot regarding control of the cap-and-trade program’s revenue spending.

The link to the final bill can be accessed at:

For additional information about changes to California’s GHG Cap-and-Trade Program, please contact Patrick Ferguson or Tahiya Sultan.

Vidhya Prabhakaran In Fireside Chat with CPUC President Picker

Posted in California

Vidhya Prabhakaran, a partner in national law firm Davis Wright Tremaine LLP, interviews California Public Utilities Commission President Michael Picker about the relevant developments and implications around expanding retail choice in California at the Advanced Energy Economy’s Pathway to 2050 conference. The full presentation may be viewed here.

The annual California energy policy event brings together an influential group of advanced energy business leaders and state policy-makers to discuss opportunities to accelerate California’s economy through the growth of advanced energy. Davis Wright Tremaine was a Gold Sponsor of the event.

Prabhakaran sought to turn the recent joint CPUC/CEC en banc meeting held on May 19 focused on retail choice on its head and questioned President Picker using many of the same questions President Picker had asked of the panelists at the joint en banc.  Accordingly, Prabhakaran spoke with President Picker about what the term “full retail choice” actually means and how the CPUC will be able to ensure reliability and consumer protections in a “full retail choice” world.

Prabhakaran, located in the firm’s San Francisco office, is the incoming Energy Practice Group co-chair at Davis Wright Tremaine.

Court Rules DOJ Enforcement Directive Arbitrary and Capricious

Posted in ESA

A U.S. District Court in Arizona has ruled that DOJ’s narrow interpretation of the requirements for a criminal misdemeanor under the Endangered Species Act went beyond unreviewable prosecutorial discretion, and its policy was arbitrary and capricious and in violation of the Administrative Procedure Act. WildEarth Guardians v. U.S. Department of Justice

The Endangered Species Act (ESA) provides that it is a criminal misdemeanor to “knowingly” violate the statute. In 1998, the Ninth Circuit Court of Appeals in United States v. McKittrick held that in 1978 Congress had changed the wording of the statute from “willingly” to “knowingly” to make violations of the ESA into “general” intent, rather than “specific” intent crimes.  The Court of Appeals applied the intent obligation narrowly, holding that the government was only required to prove that the defendant intended to shoot an animal, and that the animal shot was endangered, not that the defendant intended to shoot an endangered species, or that the defendant knew the species of the animal shot. When certiorari was sought, the Department of Justice, concerned over how the Supreme Court would rule on this interpretation of “knowingly,” had informed the Supreme Court that it would require that its prosecutors proceed with cases only where the violator knew the biological species of the animal taken.  After the Supreme Court denied cert, DOJ then notified all of its prosecuting attorneys to stop using and to object to the instructions approved by the Ninth Circuit in McKittrick (the “McKittrick policy”).

Environmental groups filed suit in 2013 after they had received information on the McKitrrick policy in response to FOIA requests in 2012. The suit did not challenge any particular application of the policy, but the policy itself.  In ruling on summary judgment on the difficult issue of whether the policy represented unreviewable prosecutorial discretion, or whether DOJ had consciously and expressly adopted a narrow construction of the ESA based on the belief that it lacked authority under the law as espoused in McKittrick, the district court held that in applying the term “knowingly” to every term of the offense, the government in effect had eliminated what Congress intended with its 1978 amendment:  “Putting this in perspective, willfulness would require proof the defendants shot an animal intending to shoot a wolf.  The Court has a hard time distinguishing this from the ‘McKittrick policy – knowingly’ instruction which requires proof the defendant knowingly shot an animal, knowing it was a wolf.”  The court concluded that “Congress placed the burden to know the identity of the wildlife species being killed on the killer.”

The practical impact of this decision, if any, is difficult to predict. Prosecutorial discretion in individual cases, as the District Court recognizes, is non-reviewable by the courts.  Indeed, “[i]t is the case by case discretion to prosecute ‘mistaken’ shootings which is foreclosed by the McKittrick policy.”  However, at least in the Ninth Circuit, United States v. McKittrick appears to be the law, and if the DOJ decides to apply it, those shooting Mexican wolves may find that “oops, thought it was a dog” may not suffice to avoid prosecution.

The Yanomami Model for Superfund

Posted in CERCLA, Environmental Quality

In a recent editorial, the Wall Street Journal celebrates the new priorities being set by Scott Pruitt’s EPA.  Mr. Pruitt, in the Journal’s opinion, is properly elevating the “more immediate” problem of Superfund sites over the “religion” of climate change.  Sadly, it seems, the misguided and naïve Obama Administration preferred “symbolic” climate measures over the more prosaic but urgent cleanup of Superfund sites.

This of course is a false choice, since the country—and planet—must confront a wide array of pressing environmental problems. Implementation of the Clean Power Plan doesn’t have much bearing on Superfund administration; both climate change and environmental cleanups need attention.  But aside from the Journal’s gratuitous trolling of climate policy, they are correct that Superfund is a program in need of reform.

One of the examples cited in the editorial is the Portland Harbor Superfund site, comprised of about 10 miles of contaminated river sediment. Prior to listing, Oregon DEQ’s approach was to control potential ongoing contributions from upland sites, coordinate with the Army Corps of Engineers to remove the most serious pockets of contamination in the course of routine maintenance dredging, and then let natural riverine processes bury the rest.  There is a lot of science to support the notion that this approach would be plenty protective of human health and the environment.

Alas, EPA Region 10 added Portland Harbor to the National Priority List in 2000. Seventeen years and over $100 million later, Region 10 issued its Record of Decision, but then hit the pause button because much of the data supporting the ROD had become stale.  A new round of sampling is soon to begin.  In the meantime, scores of PRPs are locked into the process with no way out until costs are fixed.  EPA currently pegs the cost at $1.05 billion, a figure no one but Region 10 believes to be close to the actual cost.

EPA’s selected remedy relies much more heavily on contaminant removal and capping, and less on natural processes, than the remedy proposed by the PRPs. Unfortunately, EPA’s remedy does not reflect the enormous body of data that indicate such an aggressive approach is not necessary to protect people or the environment.  A prime driver for EPA is that it assumes a much higher rate of resident fish consumption by humans than do the PRPs’ scientists.  The region’s iconic salmon species migrate through the Portland Harbor without bioaccumulating toxins in the sediments.  Never has so much money been deployed to produce so little environmental benefit.

In his book In Trouble Again, the English gonzo explorer Redmond O’Hanlon describes his adventures trekking the Amazon rainforest and his encounter with the Yanomami people.  O’Hanlon witnessed the Yanomami blowing a hallucinogen called yoppo up each other’s noses and decided to give it a try.  What could possibly go wrong?  It turned out that the drug induced excruciating pain and that the only high he realized was relief when the effects wore off.

As administered, Superfund is much like taking yoppo. The process is so time consuming, expensive and uncertain that its chief benefit is to induce PRPs to enter state voluntary cleanup programs to avoid a federal Superfund listing.  Many more sites have been remediated, and I would bet at much lower cost, through such state programs than ever will through the formal Superfund process.

Change is Coming for CPUC Procedures

Posted in California

Spring cleaning has come to the California Public Utilities Commission (CPUC) as it sets on a path to overhaul its Rules of Practice and Procedure. On May 4, 2017, Administrative Law Judge Wildgrube issued Draft Resolution ALJ-344 with the purpose of implementing statutory amendments pursuant to SB 215, reflecting changes in the CPUC’s administration, streamlining certain procedures, and providing greater clarity.

The Draft Resolution proposed 25 modifications to the rules.  The comments are due 45 days after publication in California Regulatory Notice Register (likely due in July 2017).

Of the 25 proposed rule changes, there’s a balanced mix of proposed changes that are favorable, unfavorable, and neutral from the perspective of regulated utilities. The most significant changes have been made to the rule governing ex parte communications, pursuant to SB 215. Below are some highlights from the Draft Resolution.

Key Changes to Ex Parte Communications Rules

  • Adds the definition of “party” to include CPUC staff assigned to a proceeding in an advocacy capacity. This change would presumably limit certain communications by CPUC staff.
  • Defines “procedural matters” narrowly, which would restrict certain communications that in the past were made on the basis that they were relevant to procedural items.
  • Expands definition of “decisionmaker” to include Commissioners’ policy and legal advisory staff assigned to a Commissioner’s office.
  • Bars individual oral ex parte communications in ratesetting proceedings within 3 days of the scheduled vote on the matter.
  • Provides the Assigned Commissioner authority to issue a ruling to restrict or prohibit ex parte communications in a quasi-legislative or ratesetting proceeding or to require reporting of ex parte communications in a quasi-legislative proceeding.
  • Subjects oral ex parte communications regarding adjudicatory or ratesetting proceedings at conferences to notice and reporting requirements, except in regard conference presentations and accompanying question and answer periods.
  • Provides the Commission with express authority to impose penalties and sanctions for ex parte violations from $500 up to $50,000 for each offense per day, or more in certain circumstances.

Other Key Changes

  • Rescinds the assigned Commissioner’s discretion not to conduct a prehearing conference, or issue a scoping memo in adjudicatory and ratesetting proceedings.
  • Eliminates the requirement that the Commission will make agenda item documents available at 9:00 a.m. on the day of the Commission meeting.
  • Eliminates the option of tendering documents for filing in hard copy.
  • Allows eligible local government entities to seek intervenor compensation.
  • Eliminates the requirement that an intervenor who intends to request compensation for costs of judicial review to file a supplemental notice of intent after appearing in judicial review proceeding.

Jordan Cove LNG Project Scores Legal Victory

Posted in Natural Resources, Oil & Gas, Renewables

The Jordan Cove LNG project in Coos Bay, Oregon, prevailed in a legal challenge to a key permit.  The permit, issued by the Oregon Department of State Lands, allows dredge and fill work for a deep water ship channel.  In Coos Waterkeeper v. Port of Coos Bay, the Court of Appeals rejected that challenge and upheld the permit.

Petitioners’ main argument on appeal was that DSL’s permitting decision should have applied statutory environmental standards not only to the dredge and fill work, but also terminal operations after construction.  The court found this argument to lack merit, finding that DSL’s authority is limited to the “project,” defined in the statute and its legislative history as the dredge and fill work only.

Petitioners also argued that DSL should have asserted permitting jurisdiction over complementary uplands excavation.  This work would initially be separated from the bay by a 40-foot berm, and then the berm would be removed to create the channel.  The court concluded that DSL jurisdiction would not apply to uplands work (i.e. above the high tide line), and that removal of the berm and flooding the affected uplands are within scope of the permit.

The politics of LNG development in Oregon are highly charged.  The Oregon LNG project was abandoned following election of a new county board of commissioners made up of project opponents.  Local opposition slowed down state regulatory review and the project never was tested against objective legal standards.  It is heartening to see that for the Jordan Cove project, which also is controversial, both the state agency and the court assessed the project as they would any other. The politics are still there, but the rule of law in this instance rose above.

The outcome of this case highlights an anomaly in green Oregon.  Unlike our neighbors to the north and south, we have no mini-NEPA law.  If we did, the environmental effects of the Jordan Cove project taken as a whole would certainly have been part of the state permitting calculus.  Many bills to create a comprehensive environmental impact review process have been proposed, but none have taken hold.  With a Democratic controlled legislature and state house, it seems only a matter of time.

Tenth Circuit Reverses Ruling Limiting Endangered Species Act Jurisdiction Over Intra-State Species

Posted in ESA

The Tenth Circuit U. S. Court of Appeals dashed the hopes of property rights activists by overturning a district court decision that the Fish and Wildlife Service (FWS) had no jurisdiction under the Endangered Species Act (ESA) over intra-state species located on non-federal lands. In People for the Ethical Treatment of Property Owners v. USFWS, plaintiffs challenged a special FWS rule to protect the Utah prairie dog, which mostly occurs on private lands.  The rule had the effect of limiting where development could occur.

The case is an illustration of how unpredictable environmental litigation can be. In oral argument before the court of appeals, the plaintiffs apparently characterized their case as just a challenge to the special FWS rule. However, the Tenth Circuit concluded that plaintiffs attacked the ESA more generally.  The court got there in the course of rejecting the Government’s assertion that plaintiffs lacked standing based on the absence of “redressability” — the fact that simply eliminating the special regulation aimed at the prairie dog would have had the effect of greater regulation, not less.  Having found standing by characterizing the suit as a challenge to a comprehensive statutory scheme, the court then easily concluded that the comprehensive scheme under the ESA had a substantial relation to commerce and is therefore within the Interstate Commerce Clause.

It won’t be good news to the new Administration to have another Circuit Court ruling that protective action under the ESA is constitutional, particularly from the same mostly conservative court on which the president’s Supreme Court nominee, Neil Gorsuch, currently sits. This case was briefed and argued under the prior Administration, so it will be interesting to see what course the case now follows as the plaintiffs, amply supported by amici curiae, consider whether to seek Supreme Court review, and how the new Administration reacts.

President Trump to Restore Quorum at FERC

Posted in FERC

It has been widely reported that President Donald J. Trump is preparing to nominate three new commissioners to fill existing vacancies at the Federal Energy Regulatory Commission.  The prospective nominees are Kevin J. McIntyre, Neil Chatterjee, and Robert F. Powelson.  A little bit about each:

Kevin McIntyre is co-head of the energy practice of Jones Day.  Kevin began his career as a colleague of mine in the Washington, DC office of Reid & Priest, and has had broad experience in regulation of both natural gas pipelines and electric public utilities by the FERC.  He and I are both co-authors of a book entitled “The Electric Power Purchasing Handbook” which provided practical strategies for electric supplier-purchase relationships.

Neil Chatterjee, a native of Kentucky, has been an aide to Senate Majority leader Mitch McConnell since 2009 and, in particular, has helped support the Senator’s efforts on behalf of the coal industry.  Prior to joining Senator McConnell’s staff, Neil was a lobbyist for the National Rural Electric Cooperative Association.

Robert Powelson has been a member of the Pennsylvania Public Utility Commission since 2008.  Bob was Chairman of the PPUC from 2011 until 2015, and currently serves as President of the National Association of Regulatory Utility Commissioners (NARUC).  As President of NARUC, Bob has emphasized infrastructure replacement and nuclear waste as key energy issues that must be tackled.

The FERC has been operating without a quorum since the resignation of former Commissioner Norman Bay in early February 2017, and several U.S. Senators have written to President Trump to encourage him to expedite restoration of the quorum with qualified nominees so that it can resume fulfillment of its regulatory responsibilities. Nevertheless, the time required for completion of the vetting process and final confirmation of these candidates by the Senate is uncertain.

WOTUS, We Hardly Knew Ye

Posted in Water Law

With a flourish of his pen, on February 28 President Trump signed an Executive Order aimed at dismantling the ill-fated Waters of the United States (WOTUS) rule.  The rule was the latest attempt by EPA and the Army Corps of Engineers to bring some clarity to the limits of federal authority under the Clean Water Act.  Clarity in this area has been elusive, and though many were unhappy with the rule, no one benefits from the current state of confusion.

The uncertainty begins with the Clean Water Act, which Congress said applies to “navigable” waters and then helpfully defined navigable to mean “waters of the United States.” The agencies and the courts have struggled ever since to figure out when wetlands are jurisdictional.  The courts have not helped.  In Rapanos v. U. S. , a 5-4 majority of the Supreme Court found the Government had overreached, but could not agree as to why.  Justice Scalia, writing for a plurality of the Court, would limit jurisdiction to “relatively permanent, standing or continuously flowing bodies of water,” excluding intermittent or ephemeral channels and most drainage ditches.  In a concurring opinion, Justice Kennedy invoked a “significant nexus” test whereby jurisdiction should apply if a hydrologic connection between a wetland and a navigable water could be demonstrated.  Later courts have tried to follow both tests, with mixed results.

Justice Scalia’s test is a lot easier to apply: If you can see the water or the land goes squish under your feet, there is jurisdiction.  Justice Kennedy’s test requires a case-by-case review and exercise of professional judgment.  The WOTUS rule focused more on the Kennedy test to indicate how the Government would make its jurisdictional determinations.

Without getting into detail that now is mostly moot, the rule generated about one million public comments and lots of litigation—17 District Court complaints and 23 petitions to various Circuit Courts of Appeal. It seemed certain that the Supreme Court would get another opportunity to declare the law of WOTUS.

No doubt the Court will get that chance, but in a drastically different context. The president’s Executive Order has no legal effect, other than to get the process started.  The Obama Administration’s WOTUS rule was subject to years of notice and comment before adoption, and the Trump Administration’s revisions will have to go through the same process.  No doubt they will be as controversial and will also be fiercely litigated.  That will take a very long time to play out, and won’t likely be completed during a Trump first term.

In the meantime, property owners still would like to develop their property, and the Government still has to apply the law. The Trump Executive Order gives direction that a new WOTUS rule should follow the Scalia test, but that doesn’t reflect the way jurisdictional determinations are made today.  Suffice it to say that the Kennedy significant nexus test will still be in play for the near-to-intermediate term, and a prudent developer will include a wetlands determination as a key part of the due diligence for the project.

PG&E Narrows Scope of the CPUC Proceeding to Shut Down the Diablo Canyon Nuclear Plant by Unilaterally Withdrawing Its Procurement and Cost Allocation Requests

Posted in California

On February 27, 2017, Pacific Gas and Electric Company (“PG&E”) announced it is withdrawing several portions of its plan to close its 2.3 gigawatt Diablo Canyon Power Plant near San Luis Obispo by 2025. Specifically, PG&E has withdrawn its requests that the California Public Utilities Commission (“CPUC”) authorize PG&E to replace Diablo’s generation capacity with additional procurement of clean energy resources and to pass some of the costs of that procurement on to non-PG&E customers.

PG&E gave up on its procurement and cost allocation proposals because these proposals were widely criticized in opening testimony filed by intervening parties on January 27. But PG&E will very likely continue to pursue the same procurement and cost allocation proposals in different forums, in particular as part of the CPUC’s ongoing Integrated Resource Planning (“IRP”) Proceeding (R.16-02-007).


As we detailed in a previous post, in June 2016, PG&E and several other parties, including some environmental groups and labor unions, sought CPUC approval of a Joint Proposal regarding the shutdown of Diablo Canyon.  In the Joint Proposal, PG&E sought to offset the capacity lost from Diablo Canyon retirement through three replacement procurement steps, referred to as “tranches.”

Numerous parties opposed PG&E’s proposed three-tranche procurement approach. Among other things, the intervening parties argued that any replacement procurement necessary to replace Diablo Canyon (if any is needed at all) should be considered in connection with the ongoing IRP process.  Many parties — particularly Community Choice Aggregators and Direct Access providers — also opposed PG&E’s proposed method of allocating the cost of replacement procurement through a new non-bypassable charge, which PG&E referred to as the “Clean Energy Charge.”

Based on widespread opposition, PG&E decided to withdraw its Tranche #2 proposal to procure a mix of energy efficiency and greenhouse gas (“GHG”)-free supply-side resources in 2025–2030 and its Tranche #3 proposal to procure GHG-free resources sufficient for PG&E to reach a 55% Renewables Portfolio Standard (“RPS”) target in 2031–2045. PG&E also withdrew its proposal to implement the Clean Energy Charge to recover the costs associated with Tranches #2 and #3.

As a result, the only procurement-related request that remains within the scope of the Diablo Canyon proceeding is PG&E’s Tranche #1 proposal to procure 2,000 GWh of energy efficiency resources by 2025 through a solicitation process beginning in June 2018.

Parties Will Continue to Address Procurement and Cost Allocation in the IRP and Other CPUC Proceedings

In 2015, in Senate Bill 350, the California legislature mandated that the CPUC adopt an IRP process by 2017. The IRP process is intended to help optimize electric utilities’ long-term planning and procurement to achieve a variety of public policy goals, including a 50% RPS and a doubling of energy efficiency by 2030.

In its notice withdrawing portions of the Diablo Canyon application, PG&E called for the CPUC to “adopt a policy directive” in the Diablo application proceeding “that the output of Diablo Canyon be replaced with [GHG-]free resources, and that the responsibility for, definition of, and cost of these resources be addressed as a part of the IRP proceeding.” While such a “policy directive” would have limited practical effect, PG&E’s request underscores the importance of the ongoing IRP proceeding to the future procurement of renewables in California.

PG&E is also likely to continue to look for ways to pass on some of its procurement costs to other load serving entities through the implementation of “exit fees” or other non-bypassable charges.   The importance of these non-bypassable charges (and the corresponding scrutiny of the methods used to develop such charges) only increases as more customers move from PG&E’s bundled service to alternatives such as community choice aggregation.

Hazardous Waste Transporters Beware !

Posted in Environmental Quality

The Oregon Supreme Court upheld a penalty assessed against a hazardous waste Transporter for failure to manifest hazardous waste regardless of whether it reasonably relied on a determination by the generator that the waste was not hazardous. This ruling suggests an affirmative duty on transporters to make their own determinations.

By way of background, the law requires that hazardous waste be accompanied by a manifest identifying the material from its creation, transport and ultimate disposal. This is often referred to as “cradle to grave” management.  Liability may be imposed at any stage from cradle to grave for failure to properly manifest the waste.

ORRCO was penalized $118,800 for transporting a methanol-water mixture that the generator failed to identify as hazardous waste, and which later was determined to be. ORRCO sought review in the Court of Appeals but did not dispute the commission’s finding that the water/methanol waste it transported and treated was in fact a hazardous waste. Instead, ORRCO argued only that the commission erred by interpreting the manifest and permit requirements to impose strict liability. The Court of Appeals affirmed the commission’s order and its interpretation. The Supreme Court agreed, relying on the fact that Oregon lawmakers expressly chose to require evidence of culpable mental states for “extreme violations” and criminal offenses but not for “simple violations.”  The Court concluded that lawmakers intended to authorize the DEQ to bring enforcement actions without evidence of a culpable mental state.  Interestingly, the culpable mental states referenced as the basis for more serious violations do not include mere negligence, but the Court ignored that fact.  Perhaps more persuasive was the Court’s finding that no federal authority cites a negligence standard as being applicable to a transporter.  The Court had no problem differentiating the DOT standard that requires “knowing” conduct for a transporter violation.

As a practical matter, if a transporter relies on the generator’s characterization of the waste, the transporter could seek indemnification to account for the risk that the characterization is wrong. Of course this may increase non-hazardous waste transportation costs, and, if the generator does not have financial resources, the transporter may find it necessary to change its business practices in some cases.

Oregon DEQ to Review Sites with Long-Term Controls

Posted in Environmental Quality

The Oregon Department of Environmental Quality (“DEQ”) announced that in March 2017, it will launch a pilot program to take a second look at 25-30 randomly selected sites that received a No Further Action (“NFA”) determination where the owner agreed to institutional or engineering controls in lieu of cleanup. The purpose is to assess the effectiveness of such controls in protecting human health and the environment. DEQ intends to use the pilot to help determine whether a permanent review program is warranted.

Institutional or engineering controls often present a cost-effective alternative to cleanup for contaminated sites to receive a NFA determination. Such controls may allow some contamination to stay in place if measures are taken to prevent exposure to human health or the environment, such as deed restrictions on the use of the property and/or groundwater, or physical controls such as capping or installation of barriers.  These controls can be particularly useful where, for example, contamination is inaccessable without removing structures or incurring other material costs.  Currently, there are approximately 650 sites in Oregon with institutional or engineering controls.

DEQ will select sites in the Northwest Region with controls put in place before 2010. Property owners will be notified and may be tasked with conducting the review themselves.  Other sites will require a DEQ site visit and/or review by a professional engineer.  If controls are determined to be ineffective to protect human health and the environment, DEQ could require additional actions by the property owner. Property owners will be invoiced for DEQ’s review costs.

A review of sites considered to be long-settled with DEQ may be a cause of anxiety for some property owners, but NFA letters are by their nature DEQ’s judgment at that moment, subject to their periodic inspection. Because these are older NFAs, it would be a good idea to look at the reopener language in the NFA letter to see the scope of DEQ’s reserved authority.  On a positive note, an effective review program could underscore the continued viability of controls to avoid an expensive cleanup and still protect both human health and the environment.

Can Electric Storage Resources Collect Both Cost-Based and Market-Based Revenue?

Posted in FERC

The short answer is: yes, with a few caveats.

On January 19, 2017, the Federal Energy Regulatory Commission (“FERC”) issued a policy statement that, under appropriate circumstances, electric storage resources may concurrently receive cost- and market-based revenues for providing separate services. If an electric storage resource owner/operator wants to receive cost-based rate recovery and market-based rate recovery, it must address the following concerns:

  1. The potential for double-recovery of costs; and
  2. Regional transmission organization (“RTO”)/independent system operator (“ISO”) independence from market participants.

FERC’s policy statement explains that an electric storage resource receiving cost-based rate recovery for providing one service may also be capable of providing other services for which market-based rates are appropriate. The policy statement provides examples of effective methods to address the concerns that arise when electric storage resources concurrently receive cost- and market-based revenues.  Outside of the examples described below, FERC has expressed its willingness to consider other solutions proposed by electric storage resource owners/operators that are shown to be effective.

FERC’s statement largely continues the current regulatory trend of encouraging integration of energy storage resources, such as FERC’s Proposed Rulemaking to better integrate energy storage and distributed resources into organized markets and the California Public Utilities Commission’s consideration of electric vehicle chargers as eligible energy storage technology.

Avoiding Double Recovery of Costs

Public utilities using electric storage resources to recover costs under cost-based rates from captive customers must address the potential for the recovery of those same costs through market-based sales. The policy statement suggests that crediting any market revenues back to the cost-based ratepayers is one possible solution to address the potential for double recovery.  Current FERC accounting provisions, coupled with the requirement to submit Electric Quarterly Reports, should provide sufficient transparency to allow effective oversight for any needed revenue crediting.

Alternatively, the policy statement suggests that a market-revenue offset can be used to reduce the amount of the revenue requirement used to develop the cost-based rate. The up-front rate reduction can also ensure that the cost-based rate remains just and reasonable and provides the electric storage resource owner or operator with an incentive to estimate market revenues as accurately as possible.

RTO/ISO Independence

Coordination between the RTO/ISO and the electric storage resource will be crucial. Among other operational concerns that individual RTOs or ISOs may need to address, the storage resource should be maintained so that the necessary state of charge can be achieved when necessary to provide the service compensated through cost-based rates.  But, assuming the storage operator can predict and meet this priority charging need, it should also be permitted to deviate from this state of charge at other times of the day in order to provide other, market-based rate services.  In situations where the need for the service compensated through cost-based rates is not reasonably predictable as to size or the time it will arise each day, the cost-based rate service may be the only service that the electric storage resource could provide.  Additionally, the policy statement clearly states that RTO/ISO dispatch of the electric storage resource to address that need should receive priority over the electric storage resource’s provision of market-based rate services.  To ensure this priority scheme, performance penalties may be implemented.

Control of the energy storage resource is another concern that arises in the context of concurrent cost- and market-based revenues. To ensure RTO/ISO independence, provision of market-based rate services should be under the control of the storage resource, rather than the RTO/ISO.  The policy statement explains that there is nothing unreasonable about an RTO/ISO exercising some level of control over the resources it commits or dispatches where it can be shown that the RTO/ISO independence is not at issue.  When those resources are dispatched through the organized wholesale electric market clearing process, the level of RTO/ISO control will be lower because such dispatch will be based on offer parameters submitted by resource owners or operators.  When resources are operated outside of the organized wholesale electric market clearing process (e.g., to address reliability needs), then the RTO’s/ISO’s control may be greater and concerns regarding RTO/ISO independence may arise.

Other Concerns: Minimizing Adverse Impacts on Wholesale Electric Markets

The policy statement rejects the arguments that electric storage resources concurrently receiving cost- and market-based revenues will adversely impact other market competitors. In particular, denying storage resources the possibility of earning cost-based and market-based revenues on the theory that having dual revenue streams undermines competition would be counter to years of precedent allowing such concurrent cost-based and market-based sales to occur.  Additionally, concerns that storage resources would offer in a manner that suppresses market clearing prices could be addressed in the same way in which double recovery is addressed above.

Acting Chairman LaFleur’s Dissent

Since the vote on the policy statement was taken, Commissioner LaFleur has been appointed Acting Chairman of FERC. As stated in her dissent, LaFleur views the policy statement as “both flawed in its conclusions and premature in its timing.”

While LaFleur’s dissent states she is open to potential structures that compensate storage providing transmission service at a cost-based rate while participating in the wholesale markets, LaFleur does not agree with the policy statement’s sweeping conclusions about the potential impacts of multiple payment streams on pricing in wholesale electric markets. In particular, LaFleur is concerned that the policy statement, while nominally limited to storage resources, could be read to reflect FERC’s views about the impact of multiple payment streams on market pricing more generally, thus implicating broader regional discussions on state policy initiatives and their interaction with competitive markets.  Additionally, LaFleur disagrees with the decision to separate this issue from its pending Notice of Proposed Rulemaking on storage participation, which is itself directed to enabling greater participation of storage technologies in wholesale markets.

Next Steps

FERC’s policy statement largely continues the current regulatory trend of encouraging integration of energy storage resources. While Commissioner LaFleur’s dissent may cast a shadow on the policy statement’s potential impact, she does not appear to disagree with the statement’s immediate impact, which is to provide a guide to electric storage resources to, under appropriate circumstances, concurrently receive cost- and market-based revenues for providing separate services.

On Remand from Supreme Court, Hawkes Wins Challenge to Army Corps’ Wetland Determination

Posted in Federal, Water Law

As described on this site  last year, the Supreme Court first affirmed the right to challenge wetlands jurisdictional determinations by the Army Corps of Engineers.  On remand, plaintiff Hawkes Company, a peat mining company in Minnesota, defeated the Corps’ wetland determination.  In granting summary judgment  to Hawkes, the district court applied the “significant nexus” test of Justice Kennedy in Rapanos v. United States, holding that the Corps failed to address deficiencies in its determination report that had been identified by the agency itself in an internal administrative appeal.

The court declined to give the Corps another shot at the determination, noting that in 2007, Hawkes told the Corps that unless it could expand its mine, it would run out of peat within 10 years. Losing patience, the court declared:  “Plaintiffs should not have to continue to wait to mine their land while the Corps engages in a third effort to establish regulatory jurisdiction over the Wetlands.”  The potential environmental harm from mining would have to be addressed in the state permitting process.

The wetlands in question were 90 river miles and 40 aerial miles from the nearest navigable river, with the connection of the wetland to the river through a series of ditches and streams. An administrative appeal of the initial Corps determination remanded the determination, requiring documentation of a significant nexus, particularly on the volume, duration and frequency of water flow, and the significance of any biological contribution to the navigable water.  On remand from the administrative appeal, the Corps simply revised the wording of the determination and addressed the flow questions with modeled estimates rather than actual observations.

Given the length of the litigation process, and the perfunctory response of the Corps to its own administrative appeal decision, the district court’s determination gives ample support to the concerns of the U.S. Supreme Court about the need for judicial review of wetland determinations.

NYPSC Clarifies Clean Energy Standard (“CES”) and Commences First Compliance Year

Posted in Renewables

On August 1, 2016, the New York Public Service Commission (the “NYPSC” or “Commission”) issued an Order Adopting a Clean Energy Standard (CES Order).[1]  In the CES Order, the Commission adopted the State Energy Plan (“SEP”) goal that 50% of New York’s electricity is to be generated by renewable sources by 2030 as part of a strategy to reduce statewide greenhouse gas emissions by 40% by 2030.  Consistent with the SEP goal, the Commission also adopted a Clean Energy Standard (“CES”) consisting of two major components.  Renewable Energy Standard (“RES”) and a Zero-Emissions Credit (“ZEC”) requirement.  The RES consists of a Tier 1 obligation on every load serving entity (“LSE”) to serve their retail customers by procuring new renewable resources, evidenced by the procurement of qualifying Renewable Energy Credits (“RECs”) or through Alternative Compliance Payments (“ACPs”).  The RES also includes a Tier 2 maintenance program with the purpose being to provide support to those “at risk” eligible facilities which, if not for the support, are demonstrated to be economically inviable.  The ZEC requirement consists of an obligation that LSEs purchase ZECs from NYSERDA under long-term contracts in amounts proportionate to load served.

Following the issuance of the CES Order, several parties filed petitions for rehearing. In an “Order on Petitions for Rehearing” issued on December 15, 2016 (the “Rehearing Order”), the NYPSC:  (a) denied most of the petitions because they did not raise mistakes of law or fact or new circumstances warranting rehearing; (b) noted that some of the eligibility issues raised will be further explored but that granting rehearing is not the appropriate approach for addressing those issues; and (c) approved Exelon’s petition requesting elimination of the condition requiring transfer of the FitzPatrick Nuclear Facility in order for the ZEC agreements to go beyond the first tranche of the program (2 years).

REC Requirement

Tier I Eligibility – Hydropower

In its petition for rehearing, H.Q. Energy Services (U.S.) Inc. (“HQ”) argued: that excluding existing large scale hydroelectric (“LSH”) generation from the RES as well as all hydroelectric involving storage impoundment is contrary to the public policy goals of New York and the Commission’s obligation to ensure reliability and cost-effective electric service to the State’s consumers.  Specifically, HQ argued that the Commission’s reliance on old Renewable Portfolio Standard (“RPS”) findings concerning impoundments is improper and concerns about methane emissions are baseless.  HQ argued that all forms of generation included in the baseline of existing renewable generation as described in the CES Order should also be eligible for RES Tier 1 compensation.

In rejecting HQ’s arguments, the NYPSC ruled that the exclusion of LSH generation and all hydro electric involving storage impoundments is supported by the record, including “considerable information” regarding the environmental impacts of LSH power and impoundment (Rehearing Order at 6). The NYPSC did offer HQ the opportunity to produce evidence “countering the impact of Impoundments,” which evidence the NYPSC offered to consider in its triennial reviews (Rehearing Order at 7).

Maintenance of Baseline Resources

Several parties asserted that by counting all existing renewable resources toward the 50% mandate by the State, but not providing a mechanism for compensating those existing resources, the CES Order creates confusion, market disruption, and unfair complications for existing generators. Others argued that without adequate compensation, some existing baseline resources will sell their energy and attributes into neighboring markets, noting Massachusetts’ recent legislation requiring utilities to enter into long-term power purchase agreements (“PPAs”) with renewable generators.[2]  The Commission concluded that it does not have sufficient information to support the assertions that all baseline merchant facilities are at risk of ceasing operation or fleeing the New York energy markets, and observed that, to date, there has been no significant attrition of hydro or wind resources.

Notwithstanding these observations, the Commission agreed that it is in the best interests of electric consumers to retain existing renewable resources, provided that the cost of retention is less than the cost to replace them with new facilities under the Tier 1 REC program. For that reason, the Commission found that it is necessary to begin immediately to further develop the eligibility criteria for Tier 2 to ensure that cost effective retention of baseline resources is achieved to the extent practicable.  Therefore, the Commission required Department of Public Service Staff to prepare, for Commission review, recommendations for consideration of eligibility changes for Tier 2, in consultation with stakeholders, without waiting for the first triennial review.

Eligibility of Incremental Pre-2015 Resources

Several parties argued that the CES should recognize incremental renewable power that flows into the New York control area and is not currently counted in the 2014 Baseline inventory, or that is delivered over new transmission lines.

In recognizing that such 2014 Baseline inventory will contribute towards achieving the 50 by 30 goal, the NYPSC concluded that the intent of the mandatory obligation component of the RES program is to encourage investments in new renewable resources generation infrastructure (Rehearing Order at 16).  The NYPSC directed its Staff, however, to consider the question on how to treat new voluntary arrangements to purchase incremental existing renewable resources that do not qualify under Tier 1 but can provide long lasting benefit to New York.

Miscellaneous Rulings

In a series of miscellaneous rulings, the NYPSC: (a) directed Staff and NYSERDA to complete their assessment of what revisions can be made to the testing requirements for syngas technologies to establish eligibility for participation; (b) rejected the argument that biogas projects have the potential to provide environmental and economic benefits beyond the production of renewable energy and therefore, should be eligible for increased attributes and related increased costs; and (c) rejected the argument against the application of the REC and ZEC requirements to municipal utilities because much of the electricity consumed by customers of these entities is already derived from renewable power.

ZEC Requirement

State Law

Several parties challenged aspects of the ZEC requirement and the NYPSC’s authority to create such a requirement, claiming that the NYPSC had exceeded its authority under the State law. In concluding that it acted well within its authority, the NYPSC noted that PSL §5(2) requires the Commission to consider preservation of environmental values and the conservation of natural resources and PSL §66(2) gives the Commission the responsibility of preserving public health.  Furthermore, the NYPSC concluded:  (a)  the balancing the costs, environmental impacts, and rate impacts of various options is well within the Commission’s expertise; and (b) the ZEC Requirement is the best way to preserve the affected zero-emissions attributes while staying within the State’s jurisdictional boundaries.

Federal Law

Several parties argued, consistent with the Supreme Court’s decision in Hughes[3], that the ZEC requirement impinges upon the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) over wholesale rates.  Others asserted that the ZEC requirement discriminates against out-of-state resources.  The NYPSC rejected both as incorrect.

As the NYPSC noted in the CES Order, neither the ZEC requirement nor any other aspect of the CES program inappropriately intrudes on the wholesale market or interferes with interstate commerce. FERC has determined that attribute credit payments do not interfere with wholesale competition.  Further, the ZEC requirement does not establish wholesale energy or capacity prices, it only establishes pricing for attributes completely outside of the wholesale commodity markets administered by the NYISO and regulated by FERC.  According to NYPSC, the ZEC requirement does not impinge upon interstate commerce.  ZECs, like RECs, provide a revenue source for generation assets that do not obtain sufficient revenues from the NYISO markets to operate.  This requirement in no way requires specific power purchases or otherwise administratively favors instate economic interest over others.

Miscellaneous Rulings

The NYSPC also addressed and dismissed a number of arguments that it had erred in failing to explain key aspects of the ZEC Requirement, including how the Commission planned to reconcile this requirement with the rules governing wholesale markets in New York. Finally, the NYPSC accepted Exelon’s request to remove the CES Order requirement which conditioned the 12-year duration of the ZEC contracts on transfer of the James A. FitzPatrick Nuclear Power Plant by September 1, 2018.  The Commission’s purpose in imposing the condition was to attract a buyer for the Fitzpatrick facility so as to ensure the preservation of the zero-emissions attributes of all of the qualifying facilities given the publically known intentions of the FitzPatrick facility’s current owner, Entergy, to close the plant absent a transfer.  Because the intent of the condition has been met by Exelon, now being contractually obligated to purchase the FitzPatrick facility, Exelon’s request for rehearing is granted and its Petition to remove the condition is approved.


As the NYPSC and its Staff move forward to implement the REC and ZEC requirements for the first compliance year, namely, calendar year 2017,[4] it remains to be seen whether parties will mount additional legal challenges to the CES Order, particularly with respect to the ZEC requirement and whether that requirement will be upheld as comparting with FERC’s jurisdiction over wholesale power sale rates. As of the date of this writing, a group of merchant generators, including Dynegy and NRG, filed suit in Federal District court in New York challenging the ZEC requirement and its financial assistance to nuclear generation facilities as disruptive of the state’s wholesale power markets, as infringing on FERC’s exclusive jurisdiction over those markets, and as violative of the Commerce Clause of the U.S. Constitution.

In Hughes, the Supreme Court left open the opportunity for a state to support energy markets through policies that do not intrude in FERC – regulated markets.  It remains to be seen whether the courts recognize that the ZEC program is designed differently from the Maryland subsidy program struck down in Hughes.  Unlike the Maryland program, the ZEC subsidy (as characterized by the NYPSC) is not linked to prices set in FERC – regulated markets but rather to what the NYPSC deems to be the difference between the cost to operate and market revenues. As well, the NYPSC has asserted that the ZEC price sets a value for an emission-reduction attribute and not a commodity, and that price is based on an administratively-determined societal cost of carbon.  We will see if the court views this difference as being dispositive.

[1] Case 15-E-0302, et al., Clean Energy Standard, Order Adopting a Clean Energy Standard (issued August 1, 2016).

[2] 2016 Mass. Act Ch. 188.

[3] 136 S. Ct. 1288 (2016)

[4] On November 1, 2016, the NYPSC issued a “Clear Energy Standard – Phase I Implementation Plan Proposal” proposal prepared by NYPSC Staff and NYSERDA Staff and dated October 31, 2016 (“CES Implementation Plan”).  The NYPSC is currently considering party comments regarding the CES Implementation Plan.

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.