Energy & Environmental Law Blog

Energy & Environmental Law Blog

Analyzing the critical energy and environmental issues of the day

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.

FERC and CPUC Approve Utilities’ Innovative Request to Own a 50 MW Solar Project in Partnership with a Tax Equity Investor

Posted in California, FERC

For the first time, a regulated electric utility, Liberty Utilities (CalPeco Electric) LLC (“Liberty”), recently obtained all state and federal regulatory approvals to partner with a tax equity investor to acquire, own, and operate a utility-scale solar project.  By using a tax equity partnership, the utility can more efficiently take advantage of federal solar tax incentives and thereby decrease the cost of the solar energy for the benefit of its customers.

The Federal Energy Regulatory Commission (“FERC”) and the California Public Utilities Commission (“CPUC”) each issued a series of orders approving various transactions and ratemaking requests which enable Liberty to utilize a tax equity structure to offer utility-owned solar generation to its customers at a low price that is competitive with independent power producers.  The commercial arrangements and associated regulatory approvals could serve as a blueprint for other electric utilities across the country to transition to utility-owned solar generation at lower costs for their customers.


Liberty is an investor-owned electric distribution utility that provides service to approximately 49,000 customers in and around the Lake Tahoe area of California.  Liberty has obtained almost 100% of its power supply through a “full requirements” services agreement with a neighboring utility.

In 2015, Liberty determined that it could offer its customers a more diversified, cost-effective, and reliable supply portfolio by owning and operating its own solar generation facility.  Areas in Northern Nevada offer excellent solar resources that can be readily delivered to Liberty.  Moreover, the 30% investment tax credit (“ITC”) available for solar facilities enables Liberty to reduce the costs of the energy for its customers.  However, IRS regulations require a utility owning a solar generation facility to flow the ITC benefits to its customers on a ratable basis over the expected life of the project.

To enable Liberty to flow the maximum benefit of the ITC to its customers on a more timely and efficient basis, Liberty partnered with a tax equity investor to purchase and own the solar generating facility.  While independent power producers often use tax equity partnerships to build utility-scale solar and wind projects, regulated utilities have not traditionally used this partnership model.  However, as Liberty has shown, the commercial arrangements necessary to implement the tax equity structure, and related regulatory approvals from both the FERC and the CPUC, are achievable in a relatively short time frame.

RFP and Tax Equity Structure

Liberty identified potential solar projects through a request for proposals (“RFP”) process that solicited bids for developers to permit, construct, and interconnect solar photovoltaic power projects near Liberty’s service territory.  Liberty ultimately agreed to purchase the 50 MW Luning Energy project (“Luning”), which was developed and initially owned by Invenergy Solar Development, LLC.

Prior to Liberty’s purchase of Luning, Liberty formed the partnership with a tax equity investor.  In exchange for the rights to almost all of the 30% ITC available to the project and a small amount of the partnership’s revenue, the tax equity partner contributed approximately 35% of the capital costs required to purchase the Luning project.   As a result of the tax equity investor’s capital investment, Liberty’s cost to purchase the Luning project was reduced by 35%.  Liberty will recover the reduced cost of the project through its retail ratebase.

The Luning project sells all of the facility’s energy and renewable attributes to Liberty pursuant to a power purchase agreement (“PPA”).  However, the vast majority of the revenues (minus financing and operating expenses) flow right back to the utility.  After 5-6 years, when all of the tax credits are used, Liberty intends to buy-out the tax equity partner’s interest in the project.  Liberty will then own 100% of the project and its customers will continue to benefit from the renewable power it produces.

The Luning project began commercial operations in February 2017.  When operating at full capacity, the project will produce enough power to satisfy almost all of the electric requirements of Liberty’s nearly 50,000 customers.

FERC Regulatory Requirements

The project’s tax equity financing was contingent on Liberty and Luning receiving all required state and federal regulatory approvals.  With respect to FERC approvals under the Federal Power Act (“FPA”), the project needed five approvals:  (1) market-based rate authorization under FPA section 205; (2); FPA section 203 prior approval for Liberty’s acquisition of Luning; (3) Luning’s exempt wholesale generator filing; (4) notice of change in status of Luning (post-transaction); and (5) Luning’s request under FPA section 205 to undertake affiliate sales of power to Liberty pursuant to the PPA.

The affiliate sales filing represented a matter of first impression for the FERC.  In the typical affiliate PPA transaction the FERC reviews under FPA section 205, the PPA’s $/MWh pricing is the rate the utility ultimately charges its customers for the generator’s power.  However, in the tax equity partnership model approved for the Luning project, Liberty’s customers will not be charged for solar power according to the rate set forth in the Luning PPA.  Rather, the cost of the Luning project is to be recovered from customers under traditional cost-of-service retail rates, just like any other utility-owned generation asset.

Luning’s affiliates sales filing for the Luning project had to adhere to the FERC’s rules against affiliate abuse established in Edgar (Boston Edison Co. Re: Edgar Electric Energy Co., 55 FERC ¶ 61,382 (1991) and clarified with respect to RFPs in Allegheny (Allegheny Energy Supply Co. 108 FERC ¶ 61,082 (2004)).  Luning’s affiliate sales filing demonstrated that the competitive solicitation process conducted by Liberty for the Luning project met each of the Allegheny guidelines.  The filing also supplied benchmark evidence showing that the PPA pricing was in line with other similar PPAs in relevant markets.  By delegated letter order, FERC approved Luning’s affiliate sales application (Letter Order issued in Docket No. ER17-299-000, January 31, 2017).

CPUC Approval

In addition to the FERC approvals, Liberty sought and received authorization from the CPUC to adjust its rates to recover the cost of its capital investment in the Luning project.   The CPUC’s approval of the Luning transaction was the first time the CPUC has authorized a utility to partner with a third party investor to take advantage of the 30% ITC.

The CPUC issued its decision approving the Luning project in January 2016.  (Decision 16-01-021).  Subject to certain conditions, the decision approved a settlement agreement between Liberty and the Office of Ratepayer Advocates (“ORA”) with respect to Liberty’s purchase, ownership, and operation of the Luning project.  The CPUC also approved of the commercial arrangements Liberty structured with its tax equity partner, the PPA and other related contracts, and several tariff mechanisms necessary to implement ratemaking treatment for the project.


With the 30% ITC currently in place until 2020, regulated utilities and investors have the opportunity to achieve this same type of “win-win” for both utility shareholders and customers.  Under this framework, the utility can diversify its energy portfolio while also adding a generation asset to its ratebase.  The utility’s customers, in turn, benefit from energy resource redundancy (i.e., reliability) while also receiving the benefit of a solar power supply at a lower cost.

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.