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:

(Project Name)
Storage Technology On-Line Date Discharge Duration
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


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.

Tax Equity Investors Wave Goodbye to FPA Section 203

Tax equity investments, and potentially other passive investments, in renewable energy just became that much easier to make.  Today, in response to a petition for declaratory order filed in January 2017 by a coalition of investors and project sponsors, FERC ruled that tax equity investments in public utilities does not trigger section 203 of the Federal Power Act provided the interests acquired by investors are “passive” according to the test set forth in FERC’s AES Creative Resources order.  But other investments are equally passive, at least according to the AES Creative Resources standard, and so today’s decision would arguably relieve those transactions of having to seek FERC’s approval.

Today’s order is available here.  Ad Hoc Renewable Energy Financing Group

DOE Directs FERC to Enact Special Compensation Rule for Coal Power

By a notice issued yesterday, September 28, Rick Perry, the Secretary of Energy, utilized section 403 of the DOE Act to require FERC to cause organized energy market operators (ISOs/RTOs) to compensate “fuel secure generation”, i.e., coal power, for grid “resiliency”–something that apparently puts Americans at risk despite statements by NERC to the contrary or the existence of RMR resources.  (The term “fuel secure generation” could also include nuclear power, but who are they kidding?  It’s crafted for coal.)  The notice surgically carves natural gas generators out of the money by referring to the natural gas shortages that affected power generation during the Polar Vortex.  This rare action by DOE gives FERC only 60 days to take final action or to issue the proposed rule as an interim final rule.  This of course means the timeline for FERC to solicit feedback is quite short–perhaps intended to allow Interim Chairman Chatterjee and Commissioner Powelson to take action on this notice alone before FERC has a full set of commissioners.  This morning, former NARUC President Travis Kavulla called the notice, if adopted, “the largest change to electricity regulation in decades.”

This is a big deal.  For those interested, the notice is found here:  DOE Grid Resiliency Notice.

5 Things Reflected in the ITC’s Suniva Injury-Phase Vote and What Comes Next

The U.S. International Trade Commission (ITC) voted unanimously on September 22, 2017, for an affirmative determination of injury to U.S. producers of crystalline silicon photovoltaic (CSPV) products, such as solar cells, modules and panels, from increased imports of those products into the U.S. market.  The vote concludes the “injury phase” of the investigation which began on May 17 with the acceptance of a petition for relief from imported CSPV products filed by solar manufacturer Suniva, Inc. (later joined by SolarWorld Americas, Inc.) pursuant to Sections 201-202 of the Trade Act of 1974.  As we reported in an earlier blog post, the ITC held a public injury-phase hearing on August 15, 2017, in which the Commissioners heard testimony and received statements and briefs from petitioners and their supporters and opponents of the petition.  Meanwhile, ITC staff was busy summarizing and analyzing data collected during the investigation, which efforts produced an injury phase report (Staff Report) that runs more than 500 pages.  Here are five key things reflected in the September 22 vote.

1.  The ITC’s Vote Was Directed Toward 13 Existing U.S. Producers – The ITC collected data from the five-year period from 2012 through 2016 and identified 13 operating domestic producers of CSPV cells, including petitioners Suniva and SolarWorld.  The Staff Report noted that three domestic producers, tenKsolar,  Motech and Silicon Energy, had ceased operations during the period.  The Staff Report stated that these 16 (13+3) producers accounted for 100% of domestic CSPV cell production, and 63.9% of domestic CSPV module production during 2015. (See Report pages I-53 to I-55) The remaining domestic module production was contributed from various assembly operations and excluded modules made from imported CSPV cells. (See Report page III-33) U.S. producers are defined as companies with production facilities in the U.S. territory; foreign ownership or control, financial solvency and volume of production are irrelevant for defining U.S. producers under the statutory language.  Further, other industry players are irrelevant to the injury analysis, including investors, utilities, state and local interests, installers and those employed in these downstream and supporting sectors.  Only domestic producers and those directly working for them are protected parties in the injury phase.

2.  Statutory Language Matters – ITC trade investigations are not subject to creative statutory interpretation. The Commission reads and follows the relevant statutory language.  Here, the statute is straightforward.  The ITC mandate is to investigate “whether an article is being imported into the United States in such increased quantities as to be a substantial cause of serious injury, or the threat thereof, to the domestic industry producing an article like or directly competitive with the imported article.”  The statute further defines domestic industry as “the producers as a whole of the like or directly competitive article or those producers whose collective production of the like or directly competitive article constitutes a major proportion of the total domestic production of such article.”  The “article” is the merchandise defined in the petition and deemed to be the scope of the investigation, which was published in the ITC’s notice of initiation of the Section 201 investigation on June 1 (82 FR 25333 2017).  A “substantial cause” is “a cause which is important and not less than any other cause.”  Finally, “serious injury” is “a significant overall impairment in the position of a domestic industry.”   Unlike some statutes with general or undefined language that allows a court or agency significant room for interpretation, Congress provided specific guidance to ITC in this one.  The Commissioners have little room for creative interpretation. Continue Reading