5 Key Takeaways from FERC’s Recent Energy Storage Order

In February, FERC issued Order 841, Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators (the “Order”), requiring RTOs and ISOs to establish new market participation rules for energy storage that recognize the physical and operational characteristics of these resources. While the Order set forth some minimal requirements that each RTO/ISO must meet when proposing market rules, the Commission also left considerable flexibility for each RTO/ISO in implementation.

A number of ISOs/RTOs submitted motions for clarification and requests for rehearing in March, and last Friday, April 13 FERC issued a tolling order to allow for more time to consider these motions and requests. As we await FERC’s response, here are our five key takeaways from the Order as it currently stands:

  1. New Revenue Opportunities for Storage. With the Order, there is now a pathway for energy storage to be able to participate in wholesale markets on something like a level playing field with other resources. Market rules, for example, will now need to include storage-specific bidding parameters such as state of charge and allow for market participation of storage assets as both supply and demand resources. For the storage industry, this can open up new opportunities for multiple revenue streams in the Capacity, Energy, and Ancillary Services markets. At the same time, storage resources will not be precluded from participating in existing programs, such as demand response. The end result is that, in markets with existing programs, storage resources will now have more options for participation.
  2. Market Access Does Not Always Lead to More Storage Projects. Opening the door for storage participation is not the same as saying more storage will be built. Like any energy project, it can be hard to finance storage in the absence of fixed revenue contracts. Today, state procurement mandates are largely driving the storage market and how much more storage will be built on the basis of wholesale market access is hard to predict. This will depend in part on how energy storage companies choose to compete in wholesale markets, and whether accessing multiple revenue streams is possible. This will especially be true if wholesale energy prices alone do not make a project cost-effective.
  3. The ISOs/RTOs Are Generally Supportive of the Order, But Have Sought Further Guidance. A number of the ISOs/RTOs submitted motions for clarification on certain implementation issues. These were generally supportive of the overall direction of the Order, and asked for clarifications related to applicability in their specific markets and their role in implementation when there could be overlap with state authority. Reading the tea leaves suggests that while the ISOs/RTOs have already begun to consider these issues in the context of their unique regions, the interaction with state jurisdiction at the distribution level and the opportunity to participate at both wholesale and distribution level will be key to driving more storage procurement. Following the Order, we can also expect new voices in ISO/RTO stakeholder proceedings that will address the technical capabilities of new technologies.
  4. Compliance Filings Are Due in December, But Expect Some Delays. Compliance filings are due December 3rd of this year. While FERC stated that the Order’s allowance for as much regional flexibility as possible is intended to assist in meeting the compliance and implementation deadlines, it is unclear whether RTO/ISOs will have enough time to initiate robust stakeholder initiatives. Especially in markets with no existing programs, unforeseen stakeholder issues could slow down the process. MISO has already requested a 6 month extension in consideration of this time crunch as it relates to the distributed energy resource technical conference held last week.
  5. Individual ISO/RTO Stakeholder Processes Will Be More Important to Track. Once FERC responds to the motions for clarification, the ISOs/RTOs will be working on implementation details. It will be important to follow each one to see how unique details play out in each ISO/RTO region. For example, in light of MISO’s motion, we anticipate new storage market participation rules that go beyond FERC’s Order to address issues specific to distributed energy resources. The CAISO will be another one to watch, though their filings have stated that they already largely comply with the requirements of the Order, because of their recently identified operational issues associated with high levels of renewable integration and the opportunities storage can provide to solve them.

Check back here for updates as implementation of the Order progresses over the rest of the year.

California May Need up to 2,000 MW of New Battery Energy Storage Resources by 2030, Commission Finds

On February 8, 2018, the California Public Utilities Commission (“CPUC”) adopted a new procurement process in a decision which suggested that 2,000 MW of new battery energy storage resources may be needed in California by 2030. This means an additional 2,000 MW of storage on top of the existing 1,325 MW that is already required.

The new integrated resource planning process included modelling to explore the optimal energy resource portfolio designed to meet a greenhouse gas emissions planning target at the lowest possible cost while maintaining system reliability. This portfolio will be updated every two years. Each utility will need to file a procurement plan that either aligns with the optimal portfolio or explains the reasons for deviating from the optimal portfolio.

Here is an illustration of the new resources called for by the decision:

Here are the key things to keep in mind:

First, this calls for additional resources, on top of what is required by existing programs. This means grid planners see the need for an additional 2,000 MW of new battery energy by 2030 to allow the state to meet its policy goals. As shown, this also anticipates the need for substantial quantities of new utility-scale solar resources (9,000 MW) and in-state wind resources (1,100 MW).

Second, this refers to the need for battery energy storage resources, as distinguished from other types of energy storage technologies. In California, the largest source of energy storage other than batteries is in the form of pumped hydroelectric energy storage.

Third, this portfolio will change over time, as each two year cycle will revisit the models and adjust the optimal resource mix. However, the portfolio shown here represents a snapshot of what resource planners see as the future of California’s energy mix as of today. And as you can see, this points to a future that is heavily reliant on new battery storage resources.

Solar PPA Provider That Only “Arranges” Installation of System It Owns Is Not a “Contractor” in California

In the recently issued but unpublished decision Reed v. SunRun, Inc. (Los Angeles County Super. Ct. No. BC498002, Feb. 2, 2018), the Second District Court of Appeal ruled that a solar power purchase agreement (“PPA”) provider that only sells solar energy to homeowners is not required to be a licensed California contractor under certain circumstances. Specifically, the court held that where the PPA provider “arranges” installation by a licensed contractor of the solar energy system (“system”) installed on the homeowner’s house but the PPA provider retains ownership of the system and sells the electrical output from the system to the homeowner, the PPA provider does not need to be a licensed contractor.

This ruling is good news for PPA providers in the state, whether they are marketing PPAs for residential or commercial property owners. Further, the ruling does not harm homeowners or other property owners or otherwise run afoul of the regulatory purpose of the Business and Professions Code (“BPC”) where the actual physical installation of the system must still be performed by qualified licensed contractors. This decision, if published, would also benefit the state by the further refinement of several California decisions that otherwise seem to restrict “arrangers” unless they carefully craft their contracts and actual activities within a narrow aspect of non-construction services.

The facts leading to the SunRun decision are familiar to lawyers involved with clients in both the energy sector and the heavily regulated licensing scheme under California law: SunRun sought to facilitate the use of solar in California through a PPA structure that enables homeowners to purchase energy from SunRun-owned solar systems installed on the homeowners’ rooftops. SunRun itself was not a licensed contractor prior to February 2012, but worked with a number of licensed contractors for the installation of the systems. SunRun and a licensed contractor would 1) visit the home and evaluate what was optimally required for the system, 2) the contractor would present a design to the homeowner for approval, 3) the contractor would install the system (using SunRun’s “best practices” and SunRun’s modular parts), 4) SunRun would retain ownership of the system (including maintenance and insurance obligations), 5) the homeowner would agree to buy energy from SunRun for 20 years, with an option to buy the system during that time, and 6) if the homeowner breached the agreement, SunRun had reserved its right to remove the system (which would take about one day). SunRun’s agreement with the homeowner provided that SunRun would “arrange for the design, permitting, construction, installation and testing of the” system, but specified that a separate contractor would “furnish all installation and construction services” and that separate contractor was to be “solely responsible” for all aspects of the installation related to construction. Although SunRun could refuse to pay a contractor if the installation was not satisfactory, the approval was fairly superficial and cursory, taking “15 seconds to two minutes.” SunRun did not oversee installation nor was it physically present at the installation sites.

In August 2011, Reed contracted to purchase power from SunRun pursuant to a PPA styled as a “Solar Power Service Agreement.” Reed made only four of the monthly payments under the PPA and then sold his home. The new owner assumed the SunRun agreement. Later in January 2013, Reed sued SunRun and sought to certify a class on the grounds that SunRun was an unlicensed contractor and engaged in unfair competition. Although abandoning the “solar energy claims” and not pursuing the subclass he originally asserted, Reed still sought to pursue the contractor license violation allegations. Motions for summary adjudication/judgment followed by SunRun in 2014 and 2016. Relevant to the license analysis, in April 2016 after further discovery, the trial court ruled that SunRun was not a “contractor” under BPC 7026 because 1) it “did not direct or supervise its licensed installers’ work at any job site” and any approval was limited “exclusively to ensur[ing] the local designer and installer’s design matched the agreement,” and (2) even if SunRun were a contractor, it fell within the exception under BPC 7045 for a finished product that was not a fixed part of the home. An appeal by Reed followed.

On appeal of that aspect of the ruling, the appellate court affirmed in full the trial court’s determination. Importantly for those navigating California’s licensing regulations was the court’s reiteration of the public policy undergirding the BPC, while yet noting that the penalties that Reed sought to enforce hinged on whether or not SunRun was a “contractor” under BPC 7026. The court emphasized that a “contractor” historically had to 1) actually perform construction services, 2) supervise the performance of services, or 3) agree by contract to be “solely responsible” for construction services. Citing The Fifth Day, LLC v. Bolotin (2009) 172 Cal.App.4th 939, 947-950, the court stated that “[h]owever, a license is not required if a person merely coordinates construction services performed by others.” Rejecting Reed’s counter arguments outright, the court did not find it necessary to reach the alternative ground ruled upon by the trial court: whether SunRun’s system was within the non-fixture exception to licensing under BPC 7045.

Another helpful element of this lengthy litigation, although not at issue on appeal, was the initial motion for summary adjudication by SunRun in February 2014 where the trial court ruled that the applicable statute of limitations under BPC 7031 was one year. As the trial court succinctly stated:

This statute imposes forfeitures. The contractor’s work can be perfect and the client delighted. Then there would be neither damages nor any equitable basis for compensation or a remedy. Yet the legislature put in this provision to get contractors’ attention: get your license, or else. It is the financial equivalent of flogging. That is simple and harsh by design, and it is to drive home a point. A simple and harsh punishment serves “the clear statutory policy of deterring unlicensed contract work.” (Hydrotech Systems, Ltd. v. Oasis Waterpark (1991) 52 Cal.3d 988, 992; see also id. 995, 996, 997, and 998.) SunRun’s analysis is correct.

While neither the statute of limitations analysis nor the licensing ruling is published, both still serve as very good guidance using common sense in their application under California law. Nevertheless, entities looking to walk that line should be very mindful of the underlying facts and the points highlighted by the appellate court in this case, and ensure that neither their contract language nor their actual activities move them across the line and therefore potentially under the California contractor regulatory scheme found in the BPC.

FERC Brushes Away Secretary Perry’s “Resiliency” NOPR, Finding It Legally Deficient

In a move that was widely anticipated across the energy industry, the Federal Energy Regulatory Commission (FERC) today issued an order that terminated a notice of proposed rulemaking that had been initiated in October 2017 in response to a demand by Energy Secretary Rick Perry that FERC enact rules to compensate certain resources for what he then termed “grid resiliency.”   Today’s order punts the issue of grid resiliency to the organized energy market operators, who now have 60 days to provide FERC with specific information about how those operators are addressing grid resiliency on their respective systems and whether there remain any gaps to address.  FERC has thus effectively washed its hands of the Secretary’s proposal, leaving it for the market operators to put an end to (or reshape) the issue of “resiliency.”  FERC will consider the information submitted by the market operators, including the public’s response thereto, in taking a more “holistic” look at what “grid resiliency” means and whether anything more must be done about it.  The short of it, though, is that FERC seems intent on not arbitrarily tinkering with market forces, refusing in this instance to prop up uneconomic coal and nuclear facilities using payments for loosely-defined and controversial characteristics.  Instead, FERC reaffirmed its support for markets and market-based solutions, acknowledging that sometimes the market compels retirements simply because a technology has become uneconomic.

And so while the term “grid resiliency” may not yet leave our lexicon and will be given additional consideration in the months or years to come, I think it’s safe to say that what comes of compensating resources for “grid resiliency”, to the extent it occurs, will look little or nothing like what Secretary Perry had intended.

 

House Bill Would Extend the ITC to Standalone Energy Storage Systems

The investment tax credit (“ITC”) plays a major role in driving investment in the U.S. solar energy market. Earlier this month, two members of Congress introduced a bill in the U.S. House of Representatives to provide a similar ITC for energy storage systems.

The bill, called the Energy Storage Tax Incentive and Deployment Act of 2017 (H.R. 4649) (the “Act”), would extend the ITC to energy storage systems with a capacity of at least 5 kilowatt-hours (“kWh”).  The legislation is a companion to an identical bill introduced in the U.S. Senate earlier this year (S. 1868).

The Act is modeled on the existing ITC for solar energy, which enables the owner of a solar energy system to receive a tax credit equal to thirty percent (30%) of the cost of the system. The solar ITC, along with other tax incentives like accelerated depreciation, have been a significant driver of growth in the solar industry over the last decade.

However, under current law, the ITC cannot be claimed for an energy storage system unless it meets certain requirements (primarily, that it is installed and operated in connection with a solar energy system). This contemplates the use of energy storage as a component of a solar energy system. But energy storage systems are capable of functioning as standalone systems entirely separate from solar energy systems. The Act would enable such systems to be eligible for the ITC, thus greatly expanding the universe of eligible energy storage projects. In addition, many industry participants believe the Act would serve an important role in clarifying the complex rules governing the ITC for energy storage, which would provide greater certainty to investors.

In addition to extending the ITC to standalone energy storage systems, the Act would also expand the tax credit for residential energy efficiency property to include the costs of an eligible energy storage system. This will provide the same credit as currently available for solar energy systems. The credit will be limited to battery energy storage technologies and system sizes of at least 3 kWh.

California IOUs Request Approval of 175 MW of New Energy Storage Resources

On December 1, 2017, two of the three major California investor-owned utilities (“IOUs”), Pacific Gas & Electricity (“PG&E”) and Southern California Edison (“SCE”), submitted applications for approval of the results of their 2016-2017 energy storage request for offers.

Background on the Energy Storage Mandate in California

In September 2010, the Governor of California signed AB 2514, which required the California Public Utility Commission (“CPUC”) to determine, by October 21, 2013, appropriate targets, if any, for each load-serving entity to procure viable and cost effective energy storage resources.  Consistent with AB 2514, the CPUC issued D.13-10-040 on October 21, 2013, which adopted the Energy Storage Procurement Framework and Design Program, providing biennial storage procurement targets for each of the three large California IOUs – SCE, San Diego Gas & Electric Company, and PG&E. Overall, the mandate called for the IOUs to procure a total of 1,325 MW of storage capacity by 2020.

The IOUs held their first biennial solicitation for energy storage contracts on December 1, 2014. As a result of those solicitations, SCE executed two contracts totaling 16.3 MW of distribution connected energy storage resources, and PG&E contracted for 74 MW new energy storage resources. Subsequently, the CPUC issued two decisions addressing the results of PG&E’s 2014 Energy Storage Request for Offers (“2014 ES RFO”). In D.16-09-004 the CPUC approved four Energy Storage Agreements proposed by PG&E, and rejected two Purchase and Sale Agreements associated with distribution reliability projects. In D.16-12-004 the CPUC rejected a 4 MW behind-the-retail-meter Energy Storage Agreement proposed by PG&E, determined that PG&E had not met its 2014 energy storage target, and directed that PG&E’s 2016 energy storage target should be increased to account for the identified shortfall.

Results of 2016 Requests for Offer

PG&E issued its 2016-2017 ES RFO on December 1, 2016 to seek new energy storage offers to reach its 2016 goal and cover the shortfall of the 2014 ES RFO.

Following receipt of offers, PG&E has executed six energy storage agreements totaling 165 MW of new energy storage capacity. Five of these agreements (totaling 145 MW) call for the delivery of resource adequacy capacity and one agreement is a purchase and sale agreement for a 20 MW / 80 MWh distribution-connected storage project designed to provide distribution deferral benefits. These projects are summarized below:

Counterparty
(Project Name)
Storage Technology On-Line Date Discharge Duration
(Hours)
Size
(MW)
Connection Level
Calstor, LLC (EDF BTM) Lithium Ion Batteries 11/01/2020 4 10 Customer
Cascade Energy Storage, LLC (Cascade Energy Storage) Lithium Ion Batteries 12/01/2022 4 25 Transmission
Kingston Energy Storage, LLC (Kingston Energy Storage) Lithium Ion Batteries 12/01/2023 4 50 Transmission
Sierra Energy Storage, LLC (Sierra Energy Storage) Lithium Ion Batteries 12/01/2023 4 10 Transmission
Diablo Energy Storage, LLC (Diablo Energy Storage) Lithium Ion Batteries 12/01/2021 4 50 Transmission
Tesla, Inc. (Llagas Energy Storage) (PG&E owned distribution deferral project) Lithium Ion Batteries 11/01/2021 4 20 Distribution

SCE issued its energy storage and distribution deferral request for offers on December 1, 2016 (“ES&DD RFO”). The ES&DD RFO sought offers for up to 20 MW of resource adequacy-eligible energy storage projects in specified locations. This solicitation sought a lower amount of procurement because SCE had already satisfied its 2016 biennial storage procurement target.

In response to the bids, SCE selected one offer from Powin SBI, LLC for a 10 MW lithium iron phosphate battery storage project with a delivery period expected to begin on January 1, 2022 and end on December 31, 2031.

Next Steps

PG&E has sought CPUC approval of the agreements by August 2018, and SCE has sought approval by June 2018. Interested parties are encouraged to submit comments on the applications. Since the energy storage procurement is carried out biennially, the next round of IOU RFOs with regard to energy storage procurements should start around the end of 2018.

Michigan’s PURPA Overhaul – Updating Avoided Cost Calculations And Expanding Standard Offer Contracts

For the first time in almost 30 years, the Michigan Public Service Commission (MPSC) is overhauling its implementation of PURPA. The last time the MPSC evaluated Consumers Energy Company’s (Consumers) avoided cost methodology, the Midcontinent Independent System Operator (MISO) had not been created and the generation market was vastly different than it is today. The MPSC’s changes to Consumers avoided cost methodology and eligibility for a Standard Offer contract are sparking interest in further renewable development in Michigan.

Just before Thanksgiving, the MPSC issued an order approving new avoided capacity costs (of $117,203/MW-year or $140,505/MISO zonal resource credit (ZRC)-year) for qualifying facilities (QF) selling to Consumers.  In addition, earlier this year, the MPSC found that the appropriate method for calculating Consumers’ QF avoided capacity and energy costs is a hybrid-proxy method based on natural gas costs (a shift from the prior methodology based on a coal proxy).  The MPSC also affirmed that any renewable energy credits produced by the QF belong to the QF (regardless of whether the QF is selling to Consumers under the Standard Offer or a negotiated power purchase agreements).

Importantly, the MPSC has also expanded the eligibility for Consumers’ Standard Offer PURPA contract to QFs with a capacity up to 2 MW (from the previous low threshold of 100 kW). At the election of the QF, the Standard Offer contract has a term up to 20 years. Under the Standard Offer, the QF has the option to receive an energy rate based on an as available rate, a LMP Energy Rate Forecast (with specific rates specified in the tariff), or a Proxy Plant Variable Rate Forecast (with specific rates specified in the tariff). Capacity payments are to be based on the number of ZRCs that the QF can supply to Consumers for the applicable MISO resource planning period (June 1-May 31) – whether or not Consumers actually obtains ZRCs for such QF capacity – multiplied by the applicable capacity rate for such units of capacity (as mentioned above, at the rate of $140,505/ZRC-year). The number of ZRCs are determined based on the project’s nameplate capacity as modified by MISO’s effective load carrying capacity (ELCC) calculations (as described in the relevant MISO Business Practice Manual) which credits capacity based on historic on-peak availability. There is still an open issue regarding the early termination provision in the Standard Offer contract regarding the QF’s obligation to reimburse Consumers for replacement capacity costs and the provision of financial security.

The MPSC also announced that it will next review Consumers’ avoided costs in two years, so it won’t be another 30 years before there are Michigan PURPA updates.

The Western States’ Plan for EV Charging Infrastructure – Lessons Learned and Things to Watch

Introduction

On October 4, 2017, the Governors of a number of western states signed a memorandum of understanding (“MOU”) to lay the foundation for work on a regional electric vehicle (“EV”) infrastructure development plan called the Regional Electric Vehicle Plan for the West (“REV West Plan”). The MOU was initially entered by Colorado, Utah, Nevada, Montana, Wyoming, Idaho and New Mexico, and later Arizona. [1]  The MOU calls for the participating states to work cooperatively to establish policies that will support the development of EV charging stations along 11 major transportation corridors that link their states together, spanning a total of 5,000 miles.[2] The MOU mainly focuses on interstate highway infrastructure including East-West Interstate 10, 40, 70 76, 80, 84, 86, 90, 94 and North-South Interstates 15 and 25.

The signatories to the MOU anticipate a future with much higher levels of EV usage. To support this greater EV usage, the MOU calls for efforts by the states to:

  1. Coordinate station locations, thereby maximizing use and minimizing inconsistency across charging station infrastructure;
  2. Develop practices and procedures that will encourage more people to adopt EVs, including addressing “range anxiety”;
  3. Develop operating standards for charging station uniformity;
  4. Explore ways to incorporate EV charging stations in the planning and development processes;
  5. Encourage automakers to stock a variety of EVs in participating states; and
  6. Collaborate on funding and finding opportunities for the network.[3]

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When the Big One Hits, We’ll All Be Thankful for Grid “Resiliency”

Or so Secretary Rick Perry and the DOE would have us believe.  Approximately three weeks ago, the DOE made its pitch to FERC and the energy industry that a lack of “resiliency” threatens the U.S. power grid.  The responses are in.  And the shock and bewilderment that immediately followed the release of the Secretary’s surprising proposal has, in some cases, turned into a Comedy Central Roast of Secretary Perry and this fanciful thing called grid “resiliency.”  In just a matter of weeks, over 500 companies, individuals, industry groups, trade associations, and RTOs/ISOs have filed comments. And aside from the unsurprising positive responses from companies that would see financial benefits from the proposal, the response has been overwhelmingly negative.

Besides the usual suspects that one would expect to come out against a proposal to subsidize nuclear and coal facilities, the ISO/RTO Council argued against the proposal, stating bluntly that DOE’s proposal “would degrade the efficiency and effectiveness of existing organized wholesale markets, would provide improper incentives and disincentives to current and future market participants, would not promote the goals stated in the NOPR (i.e., enhancement of electric reliability and resilience), and would reverse the progress the Commission and the nation’s [RTOs] and [ISOs] have made in developing robust and reliable competitive markets.”  The National Association of Regulatory Utility Commissioners argued that the proposal could usurp state jurisdiction over generation and seeks to push through a significant change in policy without sufficient study. A group of former FERC Commissioners even joined together to question the proposal.  And one individual shed formalities and offered that Secretary Perry had been correct when he once suggested that the DOE should be abolished—ouch.

Even among coal and nuclear interests, there was not uniform agreement on DOE’s grid policy. For example, Exelon (which is already set to receive subsidies from New York and Illinois for its nuclear facilities) attacked the PJM tariff and advocated for changes to RTO/ISO price formation, but did not actually recommend that the DOE’s proposal be adopted. In contrast, FirstEnergy (which has faced rejection from Ohio regarding nuclear subsidies) argued for the DOE proposal to be adopted largely as written.

While FERC followed DOE’s timeline for receiving comments on the proposal, it remains to be seen if FERC will issue a final order on DOE’s timeframe and what would be included in any such final order. Commissioner Powelson (who was previously Chairman of the Pennsylvania Public Utility Commission) has already said that FERC “will not destroy the marketplace” in ruling on DOE’s proposal—a statement that was endorsed by Commissioner LaFleur. Acting Chairman Chatterjee (who was previously an aide to Senator McConnell of Kentucky) has similarly stated that FERC will not “blow up the market.”

 

Reply comments are due on November 7, so stay tuned.

U.S. EPA Moves to Repeal Clean Power Plan

In a much-anticipated move, the U.S. Environmental Protection Agency (EPA) is proposing repeal of the Clean Power Plan (CPP).  The draft proposed rule outlines EPA’s revised interpretation of its authority under Clean Air Act section 111(d) to regulate greenhouse gas (GHG) emissions from power plants only within the fenceline.  EPA concludes in the proposed rule that the CPP “system of emission reduction” for GHGs is inconsistent with section 111(d), given that only one of the three “building blocks” of the CPP directly applies to or at fossil fuel-fired power plants themselves, rather than to the owners or operators of plants, who could take action outside the fenceline to meet the CPP GHG performance standards.

To arrive at the revised interpretation, the proposed rule looks to how certain terms and phrases in section 111, particularly ‘application of the best system of emission reduction’ and similar terms, are used in other sections of the Clean Air Act and related legislative history of the language.  The proposed rule also takes stock of the Agency’s prior “understanding” of section 111 as applying to physical or operational changes to a source, reflected in previous regulatory actions.  EPA noted that the revised interpretation will avoid illogical results in light of other provisions of the Clean Air Act and avoid a policy shift in the relationship between federal and state government and conflicts with other federal legislation and the jurisdiction of the Federal Energy Regulatory Commission.  The proposed rule’s Regulatory Impact Analysis provides a revised accounting of the costs and benefits of the CPP, versus its repeal.  EPA has also proposed the express rescission of the legal memorandum that detailed the Agency’s previous legal analysis in support of the CPP.

Anticipating criticism of its about-face in the legal arguments underpinning the CPP, the proposed rule notes judicial precedent, including Chevron v. NRDC, in support of reconsidering prior decisions “on a continuing basis.”  The draft proposed rule directly addresses several perceived legal flaws with the CPP as it was adopted, but this will not head off legal challenges to the final rule, assuming the repeal goes forward as proposed.  Multiple states, as well as environmental groups that stepped into the fray in the current litigation over the CPP, are expected to bring suit once a final rule is adopted.  Opponents would likely challenge the repeal based not only on the arguments EPA advanced in 2015 on why the Agency is required under the Clean Air Act to regulate GHGs from existing power plants, but they are also expected to take issue with EPA’s unabashed change in stance driven by policy preferences rather than a legislative change or new scientific evidence.  The revised Regulatory Impact Analysis is another anticipated target for lawsuits.  With the likelihood that the Supreme Court would eventually hear any lawsuits challenging a repeal, in one twist of interest to SCOTUS watchers, Justice Gorsuch, the newest member of the Court appointed by President Trump and a strident critic in his appellate decisions of deference to agency action under Chevron, could hear arguments from EPA underpinned by Chevron deference.

EPA is not proposing or taking comment on a CPP replacement, but is considering whether to propose a new rule under section 111(d) to address GHGs from existing fossil fuel-fired power plants.  Per the draft proposed rule, EPA intends to solicit information on systems of GHG emission reductions that would be consistent with EPA’s revised interpretation of section 111(d) in a forthcoming Advanced Notice of Proposed Rulemaking.

The proposed rule notes that the New Source Rule issued under Clean Air Act section 111(b) – that is, the regulation of GHGs from new and modified power plants – is also undergoing review and reconsideration pursuant to President Trump’s March 28, 2017 Executive Order that launched the reexamination of the CPP.

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