Reforming Permitting Approval Process a Centerpiece of President Trump’s Infrastructure Plan

Earlier this week, President Trump released the outline of his infrastructure plan, which includes over three dozen proposals intended to reduce delay, inefficiency and redundancy in the project permitting process.  The plan contemplates amendments to major federal environmental statutes, including the National Environmental Policy Act, the Clean Air Act, and the Clean Water Act.

The chief goal of the proposed reforms—highlighted in both the President’s recent State of the Union Address and an earlier Executive Order—is to streamline the permitting process so that federal agencies approve projects in two years or less.  The plan establishes a “firm deadline” for lead agencies to complete environmental reviews and issue a Record of Decision (ROD) under NEPA within 21 months, and requires them (or a state agency acting pursuant to delegated authority) to issue or deny any necessary permits within 3 months thereafter.

The plan lacks detail regarding just how such a deadline would be enforced, stating only that “appropriate enforcement mechanisms” would be established.  What these might be appears to be in flux:  an earlier draft plan, made public about two weeks before the President’s official release, outlined a review process by the Federal Permitting Improvement Steering Council for agencies that missed deadlines.  This process was omitted from the final product.

The guiding principle underlying many of the proposed reforms is eliminating overlapping agency authority and duplicative review in the permitting and review process.  For example, the plan establishes a “One Agency, One Decision” environmental review structure, and requires a single environmental review document and ROD to be signed by all involved agencies.  Agencies would be directed to focus only on their areas of “special expertise,” and would be permitted to rely on the determinations of other agencies that certain projects are categorically exempt from environmental review, instead of having to conduct their own independent assessment.  As another example, the authority to issue dredge and fill permits under section 404 of the Clean Water Act would be consolidated in the U.S. Army Corps of Engineers.  The Corps would gain final authority to construe the jurisdictional terms “navigable waters”/”waters of the U.S.” under section 404 of the Act—authority that currently rests with EPA, though both agencies currently exercise it pursuant to a Memorandum of Agreement—and EPA would lose its current ability to veto a 404 permit.

The plan also contains a number of other provisions intended to speed the infrastructure permitting process, including calling for procedures to expedite review for projects likely to result in positive environmental impacts, and limiting the availability of injunctive relief to stop projects that have already been approved pending a court challenge.  The plan also requests that two pilot programs be established which would exempt projects wholesale from environmental review in lieu of performance-based review or negotiated environmental mitigation.

Several of the proposed changes, including the idea of setting deadlines for agency action, draw from the report Two Years, Not Ten Years: Redesigning Infrastructure Approvals, issued by the nonpartisan reform organization Common Good.  Philip K. Howard, Senior Counsel at Covington & Burling LLP, was the lead author of the report, and E. Donald Elliott and Gary Guzy, each a former general counsel of EPA and members of the firm’s environmental practice group, contributed pro bono legal advice.

It remains to be seen which if any of these proposals will be enacted into law.  The President’s plan is merely an outline, and no proposed statutory language implementing these ideas has yet been made public.

Does California Offer a National Model For Energy Storage Rules?

Energy storage has frequently been cited as the critical missing link in an electric infrastructure designed to maximize the benefits of cheap, renewable energy.  Because energy from the sun and the wind is inherently intermittent, it has not been able to satisfy a round-the-clock need for electricity.  And in many places we’ve built more renewable capacity than we can use, when the sun is shining, or when the wind is blowing.  For example, in sun-soaked California and the West, electric grid operators have recently been confronted by the challenge of “over-generation” during peak solar hours of the day, which can result in the curtailment of solar generation to avoid overloading the grid with electrons.  Similarly, in Texas, so much wind blows at night that the electricity off-takers can sometimes get paid through “negative” power prices to use the wind power.

For California, a state that has set its electric grid on a path toward 50% renewable by 2030 (SB 350 (De León)), and one that is considering a 100% RPS by 2045 (SB 100 (De León)), the question of energy storage has taken on a practical significance.  And regulators at the federal and state level have been quite busy taking down barriers that have made the increased adoption of energy storage resources impracticable.

Today Bud Earley of Covington blogged about the recent approval at the Federal Energy Regulatory Commission (FERC) of its 2017 electric storage rulemaking.  That rule set out broad market criteria for the participation of energy storage resources in regional electricity markets, and left the question of distributed energy resources (DERs), for a later date.

Given its innovative policy work on both fronts, California is a natural market to look to for policy models that may be relevant beyond the California ISO (CAISO).  In California, state regulators have already begun seeking comment and setting rules for the participation of both DERs and energy storage in the market.  The CAISO has begun, for example, reviewing applications from some companies, including investor-owned utility companies, to seek approval as distributed energy resource providers (DERPs); and the CAISO has sought and received approval from FERC to seek tariff proposals that allow DERPs to aggregate and sell resources in the grid.  And with respect to energy storage, the state regulator — the California Public Utilities Commission (CPUC) — recently issued a decision for new “multiple-use” applications for energy storage, which allow storage providers to “stack” various services.

This CPUC decision, in combination with FERC’s rule, and adjacent statewide efforts on DERs, will continue to reduce friction in the market for energy storage.  The concept of “stacking” is designed to allow the grid to more completely take advantage of the various services offered by energy storage technologies (as well as allowing storage providers to more completely market and sell the various incremental values storage provides to the wholesale market, the transmission and distribution grids, the customer, and to resource adequacy).  For example, a storage facility that might ordinarily have been under contract for frequency regulation services could, in a stacking scenario, also sell services to provide when it would have otherwise been idling, such as additional capacity, resource adequacy, or peaking.

The CPUC’s decision adopted eleven interim rules outlining how these multiple-use applications should be evaluated, and established a Working Group, to be convened by the CPUC Energy Division, and in coordination with the CAISO, to “develop actionable recommendations.”  For example, the CPUC specifically sought input from the Working Group on possible modifications to Rule 6, which deals with how storage resources may contract for reliability services.  Notwithstanding the work that remains to fine tune the rules in this decision, it holds the promise of providing additional revenue streams to energy storage providers who in turn might develop innovative financing and service agreements to bring projects online.  As California begins to turn toward preferred resources offerings in lieu of traditional “must-run” contracts or to replace traditional energy infrastructure (see, e.g., Aliso Canyon procurement), the prospect of valuing energy storage projects for their various benefits introduces a new degree of financial competitiveness for storage.

In addition to engaging through the forthcoming CPUC and CAISO Working Group, stakeholders have been encouraged to participate in the state’s energy storage process through the CAISO’s Energy Storage and Distributed Energy Resources (ESDER) initiative.  And the state legislature has also been active on this topic in recent years, introducing numerous bills (some of which, such as AB 2868 (2016), have passed) with the intention of deploying additional storage resources into the California grid; this year’s legislation on a 100% RPS (SB 100 (De Leon)) and on a regionalized grid (AB 813) (Holden)) are likely to address energy storage in some capacity.

FERC Lowers Barriers to Electricity Storage

The Federal Energy Regulatory Commission (FERC), with four new Commissioners confirmed during the latter half of 2017, including a new Chairman, is taking a critical next step toward clearing away obstacles to wholesale market participation by storage resources, a key emerging technology.

At its recent public meeting, FERC approved a final rule that largely adopted its 2016 proposed rule aimed at knocking down barriers to electricity storage resource participation in markets administered by Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs).[1]  Four of the FERC commissioners issued separate statements supporting the rule.[2]

As reported on this blog, FERC’s 2016 proposal also would have required RTOs and ISOs to allow distributed energy resource aggregators to participate in the markets.  However, the Commission said it needs additional information on aggregator participation and will hold a technical conference.

The Energy Storage Association said FERC’s new rule “signaled both a recognition of the value provided by storage today, and more importantly, a clear vision of the role electric storage can play, given a clear pathway to wholesale market participation.”

In the wake of this final rule, market observers are expecting a flurry of activity and development in storage.  How FERC manages RTO implementation, and how innovative technology providers respond to the RTO market rules, will continue to shape the nascent market for real-time electric storage resource services.  Energy storage has been a prominent issue among California policymakers, and Jake Levine in Covington’s Los Angeles office has today posted a blog about storage policy developments in California.  A link to his blog is here.

Market rules for storage resources

Current market rules designed for traditional generation resources can create barriers to entry for emerging technologies, such as electric storage resources, and limit the services they can provide.  In its order, FERC finds that better integration of electric storage resources into the RTO markets is necessary to enhance competition and ensure that these markets produce just and reasonable rates.

The new final rule requires each RTO to adopt market rules that recognize the physical and operational characteristics of electric storage resources.  Those rules must do the following:

Ensure that electric storage resources are eligible to provide all services that they are technically capable of providing.  Some organized wholesale market rules now limit the services that electric storage resources may provide.  For example, smaller electric storage resources are  generally restricted to participating in the markets as demand response, which can limit their ability to employ their full operational range and prohibit them from injecting power onto the grid.

Ensure that storage resources can be dispatched and can set the wholesale market clearing price as both a wholesale seller and wholesale buyer.  Storage resource participation as both sellers of services and buyers of energy will improve market efficiency and competition by allowing the RTO to dispatch these resources in accordance with their most economically efficient use.  In addition, participation as dispatchable load will allow storage resources to set the market clearing price, thus better reflecting their value and ensuring they are dispatched based on the highest value service they are capable of providing.

Account for the physical and operational characteristics of storage resources through bidding parameters or other means.  The physical and operational characteristics of a resource must be accounted for so that the RTO can model and dispatch the resource consistent with its operational constraints.  Some characteristics are flexible and can be changed through a resource’s offer or bid while others are static and thus would not change in an offer or bid.  Accordingly, FERC recognizes there may be means other than bid parameters to account for physical characteristics that do not change over time, such as reporting that information when registering as a market participant, and allows RTOs some flexibility.

Set a minimum size requirement not to exceed 100 kW for participation in the organized wholesale markets.  Electric storage resources range in size from 1 kW to 1 GW, and most of them tend to be under 1 MW.  FERC observes that all RTOs already have the modeling and dispatch software capabilities to accommodate the participation of resources that are as small as 100 kW.

Specify that the sale of energy from the market to a storage resource that the resource sells back to the market must be at the wholesale market clearing price. FERC has found that the sale of energy from the grid that is used to charge electric storage resources for later resale into the energy or ancillary service markets constitutes a sale for resale in interstate commerce.  As such, the just and reasonable rate is the RTO market’s wholesale Locational Marginal Price.

The rule applies to resources that voluntarily participate in RTO markets and are capable of receiving electric energy from the grid and storing it for later injection back to the grid, regardless of their storage medium (e.g., batteries, flywheels, compressed air, and pumped-hydro).  FERC clarified that the rule applies to storage resources located on the interstate transmission system, on a distribution system, or behind the meter, and rejected a request to allow states to decide whether storage resources located behind a retail meter or on the distribution system may participate in the RTO markets.

Each RTO must file tariff changes needed to implement the requirements of this final rule within 270 days of its publication in the Federal Register.

Market rules for distributed energy resource aggregators

FERC’s 2016 proposal recognized that individual distributed energy resources may be too small to participate directly in the organized wholesale electric markets on a stand-alone basis.  For example, they may not meet the minimum size requirements to participate or have difficulty satisfying all of the operational performance requirements.  The proposal would have required each RTO to allow distributed energy resource aggregations, including electric storage resources, to participate directly in the wholesale electric markets under rules that best accommodate the physical and operational characteristics of the aggregation.

FERC found that it needs additional information before deciding what action to take regarding distributed energy resource aggregation reforms.  Accordingly, the Commission will hold a two-day technical conference in April.

[1] For brevity, this post will use the term RTO to refer to both RTOs and ISOs.

[2] Separate statements were issued by Commissioners LaFleur, Chatterjee, Powelson and Glick.

Islamic Finance Update on the Dana Gas Case: Sanctity of English law Contract upheld, Notwithstanding Claims of Shari’ah Non-compliance

This post looks at the recent English High Court decision in Dana Gas PJSC v Dana Gas Sukuk Ltd & Ors [2017] EWHC 2928.

Participants in the Middle East (and wider) Islamic finance markets held their breath during much of this year.  This was pending consideration by the High Court in England on some core issues around the enforceability of English governed payment obligations.  Underpinning the decision was whether:

  • non-compliance with Shari’ah principles (the principles which sit behind the structure of an Islamic financing); and
  • unenforceablity as a matter of the law of the purported place of enforcement of English law governed contractual payment obligations (in this case, the United Arab Emirates (the “UAE”)),

would (or should) have any bearing on the enforceability of such obligations, as claimed by the issuer of a sukuk (an Islamic finance bond).

There was an audible sigh of relief when the High Court upheld the sanctity of English law governed contractual obligations, irrespective of these claims.

The decision has not created any new English law precedent. However, it provides welcome clarity on the issues contemplated, for the purposes of sukuk and Islamic finance transactions generally.

For many years, Islamic finance products entered into by Middle East-based entities have commonly governed certain documents containing payment obligations by English law. This was because of the perceived greater certainty of their enforceability, in light of nervousness from creditors about local laws. It is this general principle of enforceability that the High Court upheld and, in doing so, widespread uncertainty about the enforceability of a multitude of Islamic financings in place across the Middle East market has been seemingly abated.

A different decision from the High Court could not only have had implications for creditor confidence in the Islamic finance market going forward, but also could have opened the floodgates for issuers to use the argument that their existing Islamic financings are not Shari’ah-compliant as a precursor to force creditors into financial restructurings on more advantageous terms.

It should be noted that the implications of the claims underpinning this case may still continue, as the sukuk issuer has announced that it will appeal the High Court judgment and the decision of the courts of the Emirate of Sharjah (in the UAE, the sukuk issuer’s jurisdiction of incorporation) on whether the sukuk is enforceable as a matter of UAE law (which will have separate, although related, potential ramifications), is still pending.

The full article on the case is available here.

California Looks Ahead to S.B. 100

California continues to cement its position as a global leader in renewable energy policy and climate change reform.  This session, California State Senate President, Kevin de León, authored Senate Bill 100 (S.B. 100), which would require California utilities to procure 100 percent of their energy from renewable sources by 2045.  S.B. 100 has been approved in the State Senate as well as two key committees in the State Assembly.  The Assembly Appropriations Committee and the full Assembly will vote on it before the legislative session ends for this year on September 15, 2017.

Under the California Public Utilities Code (CPUC), current renewable energy standards require utilities to procure 50 percent of their energy from renewable sources by 2030 (S.B. 350, De León).  S.B. 100 would increase the 2030 target to 60 percent and expedite the 50 percent goal to 2026.  Currently, almost 29 percent of California energy comes from wind, solar and other clean sources.  To achieve the 2030 goal, S.B. 100 maintains the current renewable sources defined in prior state renewable portfolio standards (RPS) legislation (a list of clean energy sources that count toward the state renewable goals).  But, for the 2045 100% goal, S.B. 100 contemplates a different “zero carbon” requirement, which would allow additional sources of clean energy presently excluded from the RPS, such as hydroelectric generating facilities.

S.B. 100 will further test the California Independent System Operator’s (CAISO) ability to integrate renewables onto the power grid.  When renewable sources are incorporated into the grid, variability in renewables—when the sun doesn’t shine, or the wind fluctuates—can create a supply problem unless the grid is engineered to efficiently store renewable energy or adjust (for example, through demand side management or the use of natural gas-fired generation) for inconsistent output.  California uses a “baseload” approach—it continually runs conventional power plants at a minimum baseline—to account for renewable energy variability.  But, over-generation results when renewables are at peak output but the “baseline” is still maintained.  Consequently, this has led to occasional negative pricing of power (when generators pay grid operators to avoid curtailment).  Last spring, California experienced negative pricing due to substantial power generation from the continued expansion of solar farms combined with an increase in hydro reserves from the rainy winter.

Additional efforts outside of S.B. 100 also seek to address variability in renewables generation.  Battery storage companies—from startups to multinational giants—as well as solar and other distributed energy resource providers are offering services to increase grid efficiency and reliability.  Southern California Edison conducted an accelerated procurement of energy storage resources from Tesla, Greensmith Energy, and AES Energy Storage.  Similarly, pursuant to a 2010 state law, A.B. 2514, CPUC has mandated the procurement of 1.3 GW of energy storage, which the state’s utilities are satisfying.  With decreasing prices for renewable energy, and the state’s support of large-scale energy storage deployment, a policy such as a 100% RPS is presumed by some policymakers to be more attainable and affordable than just a few years ago.

S.B. 100 also stipulates that California’s transition to a zero-carbon electric system “shall not increase emissions elsewhere in the western grid and shall not allow resource shuffling.”  This addresses leakage, a concept in which policy changes mandate emissions reductions in California, but could cause emissions increases associated with imported power from outside of California.  Measures that would preclude leakage could have significant implications for increasing grid interconnectivity between California and other Western states, which may remain somewhat dependent upon fossil-fuel generation.  California has historically implemented policies in its RPS and its carbon regulations designed to limit resource shuffling.  S.B. 100 may require additional policies that might limit imports of fossil-fuel generation.

S.B. 100 has a good chance of becoming law.  There is substantial support for S.B. 100 from state legislators, environmental groups, large businesses, and the general public.  However, utility companies have expressed their concern over its ambitious goals.  As a result, it will not be surprising to see amendments considered in the next week designed to address these difficult questions, and to provide assistance to the industries that may bear the economic burdens of a future zero carbon electric grid.

Another Large Equity Fund Sharpens its Focus on Climate Risk Disclosures

Today The Vanguard Group, the Nation’s second largest fund group with over $4 trillion in assets under management, issued three publications — a press release, an open letter by Vanguard’s CEO, and its 2017 Investment Stewardship Annual Report  — highlighting Vanguard’s evolving view that responsible disclosure and management of climate risk is an essential governance responsibility for corporate boards and managements to drive long-term shareholder value.  With these announcements Vanguard has joined the Nation’s first and third largest funds groups, BlackRock and State Street, that as noted in our March 27, 2017 post previously announced policies demanding greater boardroom attention to climate risks.

The Investment Stewardship Annual Report summarizes the board and corporate governance oversight and engagement activities of Vanguard’s Investment Stewardship team for the 12 months ended June 30, 2017, including voting proxies at nearly 19,000 shareholder meetings and direct engagements with more than 950 company leaders and directors.  The report asserts that the stewardship team’s core purpose and mission is “to advocate for a world in which the actions and values of public companies and of investors are aligned to create value for Vanguard fund shareholders over the long term.”

Through this long term value lens, the report includes a three-page section captioned “Risk in Focus: Vanguard’s view on climate risk.”  This section of the report asserts:

“[o]ur approach to climate risk is evolving as the world’s and business community’s understanding of the topic matures.  This year, for the first time, our funds supported a number of climate-related shareholder resolutions opposed by company management. We are also discussing climate risk with company management and boards more than ever before. Our Investment Stewardship team is committed to engaging with a range of stakeholders to inform our perspective on these issues, and to share our thinking with the market, our portfolio companies, and our investors.”

The report also narrates three engagement case studies with boards about climate risk and includes a Q&A with Chief Investment Stewardship Officer, Glenn Booraem explaining:

  • why Vanguard investors should be concerned about climate risk,
  • why Vanguard has shifted its assessment of climate risk, and why now,
  • what most concerns Vanguard when learning that a portfolio company does not have a rigorous strategy to evaluate and mitigate climate risk, and
  • what portfolio companies can expect from Vanguard on this subject now that Vanguard has articulated a clear stance on climate risk.

There is much to commend in Mr. Booraem’s clear-eyed answers to these questions as he acknowledges that the views of Vanguard’s clients on climate risk span the ideological spectrum, but that “our position on climate risk is anchored in long-term economic value—not ideology.”

The open letter from Vanguard’s CEO, F. William McNabb, highlights the importance of good governance and board-driven risk management to promote long-term value.  In that context Mr. McNabb notes:

“[c]limate risk is an example of a slowly developing and highly uncertain risk—the kind that tests the strength of a board’s oversight and risk governance. Our evolving position on climate risk (much like our stance on gender diversity) is based on the economic bottom line for Vanguard investors. As significant long-term owners of many companies in industries vulnerable to climate risk, Vanguard investors have substantial value at stake.”

The press release also includes this from Mr. Booraem:

“You can expect us to speak out when we detect threats to our shareholders’ economic interests. Increasingly, you’ll also see us take more public positions on select governance topics such as climate risk disclosure and gender diversity on boards. Our team and our views have continued to evolve, but our focus on the long-term interests of Vanguard shareholders remains unwavering.”

With the stances of the Nation’s three largest equity funds essentially aligned on the importance of responsible disclosure and management of climate risks, public companies must be attentive to these issues.

FERC Requests More Comments on Grid Service Proposal

In November 2016, FERC issued a Notice of Proposed Rulemaking (NOPR) that would require new generating facilities to install and operate equipment that provides primary frequency response service to the grid.   Based on some of the comments received on the NOPR, FERC issued a request for supplemental comments.

The reliable operation of the alternating current (AC) North American electric grid  depends on maintaining a frequency near 60 Hertz (Hz).  Variations from this frequency can occur due to sudden changes in the balance between generation and load on the system and cause instability.  Frequency responsive power control equipment can sense changes in system frequency and autonomously adjust a generating facility’s power output.

More background on frequency response service and the NOPR may be found in the November 28, 2016 post on this blog.

FERC requested supplemental comments on two topics.  The first topic is whether and when electric storage resources should be required to provide primary frequency response.  The NOPR did not propose provisions specific to electric storage resources.  Some commenters raised concerns that, by failing to address electric storage resources’ unique technical attributes, the new requirements could pose an unduly discriminatory burden on electric storage resources and even result in adverse impacts on those resources.  In light of these concerns, FERC asks a series of detailed questions to obtain additional information regarding:

  • The performance characteristics and limitations of electric storage resources;
  • Possible ramifications of the proposed primary frequency response requirements on electric storage resources; and
  • What changes, if any, are needed to address the issues raised by commenters.

The other topic for supplemental comments is the costs associated with primary frequency response capabilities for small generating facilities.  To avoid setting requirements that could be discriminatory or preferential, the NOPR proposed comparable primary frequency response requirements for both new large and small generating facilities.  FERC concluded that small generating facilities can install and operate the needed equipment at low cost in a manner comparable to large generating facilities.  Some commenters, however, challenged this conclusion and raised concerns that small generating facilities could face disproportionate costs to install primary frequency response capability.  Accordingly, FERC requests answers to a series of questions regarding the ability of small generating facilities to comply with the proposed requirements and their potential economic impacts.

Supplemental comments are due September 14, 2017.


This is the third and final of three posts on this blog providing short summaries of the generic electricity policy initiatives already teed up and awaiting possible action by the newly-constituted FERC.  Together, these three posts describe initiatives that address fundamental market and resource issues spanning a broad range of FERC’s electricity authorities.

Today’s post summarizes FERC initiatives concerning analytic issues in the context of change of control applications pursuant to Section 203 of the Federal Power Act, and with respect to market-based rate evaluations.  The first post addressed initiatives affecting wholesale market rules, and the second summarized initiatives affecting new transmission development, generator interconnection and access to the market by qualifying facilities, also known as QFs.

Modifications to Commission review of transactions under Section 203 of the FPA and market-based rate applications

In September 2016, FERC issued a Notice of Inquiry (NOI) launching a review of the standards used for assessing the impact of mergers or acquisitions on horizontal competition in electricity markets (i.e., the consolidation of generation resources).  Under current policies, an applicant may show that a transaction will not adversely impact competition by: (1) explaining how the transaction does not result in an increase in the amount of generation capacity owned or controlled by the applicant; (2) explaining how the transaction results in only a de minimis change in its market power; or (3) submitting a Competitive Analysis Screen, which assesses a  transaction’s impact on concentration in relevant markets.

The NOI identifies potential ways of modifying these analyses, such as:

  • Establishing a threshold for determining whether the proposed transaction’s impact is de minimis and perhaps applying the threshold to the cumulative impact of serial mergers over a period of time.
  • Adding a demand and supply curve analyses to the Competitive Analysis Screen to determine whether a company has the ability and incentive to withhold capacity from a market.
  • Adding to the merger analysis two metrics used in FERC’s market-based rate analysis: pivotal supplier and market share.  These metrics measure unilateral market power while the current merger analysis measures only concentration in the market.

The NOI also discussed eliminating some generic blanket authorizations now granted for certain transactions as well establishing abbreviated filing requirements for certain categories of transactions.

FERC requested comments and alternative proposals on these issues, which have been filed.  Given the significant volume of acquisitions of securities and facilities in the electricity industry that require FERC review, this NOI may mark the first step in policy changes that would affect a wide range of industry participants.

Data collection for analytics and surveillance and market-based rate purposes

In a July 2016 Notice of Proposed Rulemaking (NOPR), FERC proposed to revise the data it collects from electricity sellers authorized to charge market-based rates (MBR sellers) and from entities trading virtual products[1] or holding financial transmission rights (FTRs)[2] in organized wholesale markets.

The NOPR sets out two categories of information submission requirements.  The first requirements are applicable only to MBR sellers.  This category includes data needed to indicate that the entity satisfies FERC’s standards for selling at MBR, i.e., the seller cannot exercise market power.  Entities that trade solely virtual instruments and/or FTRs are not required to obtain MBR authority, and therefore are not required to submit this information.

The second category of information requirements applies to MBR sellers and to virtual/FTR participants and is referred to as Connected Entity Information.  According to the NOPR, this information pertains to market analytics and surveillance and helps the Commission understand the financial and legal connections among market participants and other entities.

A Connected Entity is any one of the following:

  • An ultimate affiliate owner of a seller or virtual/FTR participant that participates in organized wholesale electric markets, or purchases or sells financial natural gas or electric energy derivative products that settle off the price of physical electric or natural gas energy products.
  • A trader employed or engaged by a seller or virtual/FTR participant that makes, or participates in, decisions and/or devises strategies for buying or selling physical or financial Commission jurisdictional electric products or physical natural gas.
  • An entity that has entered into an agreement with a seller or virtual/FTR participant that confers control over an electric generation asset that is used in, or offered into, wholesale electric markets.

Connected Entities would be required to report certain information regarding these types of connections to a MBR seller or a virtual or FTR participant.

The NOPR also proposes to collect this information in a consolidated and streamlined manner through a relational database, i.e., a database model whereby multiple data tables relate to one another via unique identifiers.  The Commission staff has held two workshops on the data base and the data submittal process.  The Commission’s Connected Entity Information proposals, in particular, are highly controversial with some market participants.

As indicated in the first post of this trilogy, all of these matters are teed up for whatever action, if any, the new Commission chooses to take.

[1] Virtual trading involves sales or purchases in an RTO/ISO day-ahead market that do not go to physical delivery.  Virtual bidding allows entities that do not serve load or control generating resources to make purchases or sales in the day-ahead market.  Such purchases or sales are subsequently sold or purchased in the real-time spot market.  Virtual transactions allow any market participant to arbitrage price differences between the two markets.

[2]  FTRs are financial instruments that entitle the holder to rebates of congestion charges for using the grid.  FTRs provide a potential hedge for market participants, allowing them to offset the price risk of delivering energy to the grid.  They do not represent a right for physical delivery of power.


This is the second post of three on this blog providing short summaries of the generic electricity policy initiatives already teed up and awaiting possible action by the newly-constituted FERC.  Together, these three posts describe initiatives that address fundamental market and resource issues spanning a broad range of FERC’s electricity authorities.

Today’s post summarizes initiatives affecting new transmission development, generator interconnection and access to the market by qualifying facilities, also known as QFs.  The first post addressed initiatives affecting wholesale market rules.  The third post, in a few days, will deal with FERC initiatives concerning analytic issues.

Competitive transmission development

In Order No. 1000, FERC paved the way for new transmission companies that would compete with incumbents for the right to install new transmission resources by directing the RTOs to establish competitive processes.  Since then, market participants have expressed a variety of concerns regarding perceived inadequacies in the competitive processes RTOs have implemented.

To air these concerns,  FERC held a two-day conference in June 2016.  The major issues addressed at the conference included:

  • Cost containment provisions in offers to develop new transmission, including how transmission planning regions evaluate such proposals and whether rates that include cost containment provisions and result from a competitive process should be presumed to be just and reasonable.
  • Incentives and competitive transmission development, including whether incentives are needed to encourage developers to participate in competitive processes, the relationship between cost containment provisions and incentives, and whether there are alternatives to return-on-equity adders for projects subject to competitive development processes.
  • Interregional transmission coordination and competitive transmission development, including how interregional coordination processes interact with regional planning processes.

Post-conference comments have been filed.  The Commission has not indicated how it will address the concerns aired in this conference.

Reform of generator interconnection procedures and agreements   

In a December 2016 Notice of Proposed Rulemaking, FERC found that 1) aspects of the current interconnection process for large generators (larger than 20 MW) may hinder the timely development of new generation; 2) the process for conducting interconnection studies may result in uncertainty and inaccurate information; and 3) interconnection processes may be discriminatory with respect to new technologies entering the generation market.

Accordingly, FERC proposed reforms that fall into three broad categories.

The first category is improved certainty by giving interconnection customers more predictability in the interconnection process.  Proposals include:

  • Require transmission providers to set a schedule for conducting restudies.
  • Allow the interconnection customer to unilaterally exercise the option to build.
  • The transmission owner/provider and an interconnection customer must agree before the transmission owner/provider may elect to initially fund network upgrades.
  • RTOs/ISOs must have dispute resolution procedures that allow a party to unilaterally seek dispute resolution.
  • Set a cost cap to limit an interconnection customer’s network upgrade costs.

The second category is improved transparency by providing more information to interconnection customers.   Proposals include:

  • Require transmission providers to provide detailed information and models used for interconnection studies.
  • Revise the definition of a “Generating Facility” to include electric storage resources.
  • Set timeframes for transmission providers to report on their completion of interconnection studies.

The third category is an enhanced interconnection processes.  Proposals include:

  • Allow customers to request a level of interconnection service that is lower than the generating facility’s capacity.
  • Provisionally allow new generating facilities to interconnect pursuant to existing and updated studies while needed additional studies are completed.
  • Allow interconnection customers to utilize or transfer surplus interconnection service at existing generating facilities.
  • Transmission providers must evaluate if their methods for modeling storage resources for interconnection studies account for the operational characteristics of those resources.

Comments on the proposals have been filed.   Although the timing of further Commission action on this proposal is uncertain, FERC has been engaged in a steady march over several years aimed at perfecting its generator interconnection rules.

Implementation issues under PURPA

In June 2016, FERC held a conference regarding the Commission’s implementation of the Public Utility Regulatory Policies Act  (PURPA).

Two major issues were aired at the conference.  The first was utilities’ obligation to purchase QF power in light of changes in electricity markets since the enactment of PURPA in 1978, long before the introduction of competitive generation and open access to the grid.  A concern of some utilities is that in order to be released from the purchase obligation they must rebut a presumption that QFs sized 20 megawatts and below do not have nondiscriminatory access to competitive organized wholesale markets.

The other major issue was avoided cost calculations that determine QF pricing, including whether an avoided cost methodology may reflect the locational and/or time value of QF output.

Post-conference comments have been filed.   As well-structured wholesale electricity markets have become more prevalent, the Commission’s rules for market access by QFs have continued to evolve as well.  The concerns raised at the conference may lead to further rule changes.


With two new Commissioners confirmed by the Senate and sworn in, FERC’s seven-month period without a quorum is over and it can get back to business.  And with another two nominations now before the Senate with a hearing scheduled for September 7, the agency should be at full strength within the next few months and ready to take on important policy issues.

There are quite a few critical generic electricity policy initiatives already teed up and awaiting Commission action.   Together, the initiatives address fundamental issues spanning a broad range of FERC’s electricity authorities.  Over the course of three posts, this blog will provide short summaries of those initiatives.  Today’s post addresses initiatives affecting wholesale market rules.  The second post, in a few days, will summarize initiatives affecting new resources development and entry issues.  The third post will deal with FERC initiatives concerning analytic issues.

Of course, the new Commission may have other electricity policy priorities in mind.  Hence, it is difficult to predict whether or how the Commission will address these initiatives.  Nonetheless, Commission staff has no doubt already done a good deal of spade work on these policy questions and Commission action is possible over the next few months.

State policies and the eastern organized wholesale markets

New generation resources in the states served by the PJM and New England RTOs and the New York ISO are selected for wholesale capacity and energy payments through competitive auctions in those organized markets.  Those with the lowest-prices offers are selected.  However, states in these regions want certain types of resources developed to meet certain state policy objectives.  These resources may not be the lowest cost and may receive state subsidies, thereby creating tension with the basic RTO market design that is based on least cost principles.

FERC opened a proceeding (AD17-11) to discuss how the competitive wholesale markets, particularly the eastern organized markets, can select resources of interest to state policy makers while preserving the benefits of regional wholesale markets and economic resource selection by the RTOs.  The Commission held a two-day conference in May 2017.  Some of  the issues raised were:

  • The features of the existing RTO market design that should be modified to meet specific state and region policy goals.
  • Ways to achieve state or regional policy objectives within the RTOs centralized energy and capacity markets.
  • The consequences for wholesale markets, as well as for market participants’ ability to make long-term decisions, of continued state financial support for certain resources outside wholesale markets.

One of the thorny issues here is what is known as the Minimum Offer Price Rule that is applied in the RTO auction markets.  This rule, intended to prevent subsidized resources from lowering market prices and driving out other investments, requires supply offers to be no lower than non-subsidized costs.  The problem is that states view this rule, and others, as preventing them from supporting resources that attain their policy objectives.

FERC requested post-conference comments and invited commenters to address five potential “paths forward.”  The paths basically presented  varying degrees of applying the Minimum Offer Price Rule.  FERC also wanted comments on other topics, including the principles and objectives that should guide the selection of a path forward and the degree of urgency for reconciling wholesale markets and state policies.

Intertwined in this proceeding is the boundary between FERC and state jurisdiction.  The Federal Power Act reserves jurisdiction over generation facilities to the states but gives FERC responsibility for prices in wholesale markets.  Last year the Supreme Court set out some guidance on this issue, finding that states may not tread on FERC jurisdiction over wholesale power markets but have some latitude to encourage certain types of generation.  Recently, Federal courts in Illinois and New York found that certain state subsidy programs for nuclear generation facilities did not encroach on FERC’s jurisdiction.

Resolving the question of whether or how FERC should defer to state preferences as it seeks to ensure wholesale market integrity is of critical importance to the power industry and consumers.   This area of policy is likely to play out over several months or years in an iterative process involving decisions by FERC, various states, and the federal courts.

FERC may face an additional challenge of harmonizing policy-driven resource selection in the organized RTO markets.  In April, the Secretary of the Department of Energy directed his staff to prepare a study examining electricity markets and the reliability of the U.S. electric system.  Specifically, the study is to explore whether wholesale energy and capacity markets are adequately compensating attributes such as on-site fuel supply and other factors that strengthen grid resilience and, if not, the extent to which this could affect grid reliability and resilience in the future.  The report, not yet issued, may propose policy changes to protect baseload generation resources (i.e., nuclear, coal and natural gas-fired power plants).   Any such proposals are likely to be controversial.   Given that DOE has limited authority over wholesale electricity markets, it will be left to the new FERC to grapple with whether or how to implement DOE’s proposals in the organized and bilateral wholesale markets.

Electric storage participation in markets operated by RTOs and ISOs

FERC has expressed concern that, as the capabilities of electric storage resources and distributed energy resources continue to improve and their costs continue to decline, such resources may face barriers that limit them from participating in organized wholesale electric markets.  Accordingly, FERC issued a Notice of Proposed Rulemaking in November 2016 intended to knock down barriers to storage resource participation.  The proposed rule would require each RTO and ISO to revise its tariff in two ways:

  • Establish market rules that recognize the characteristics of storage resources and accommodate their participation so that those resources no longer have to participate in the markets under rules designed for other types of resources.
  • Allow distributed energy resource aggregators to participate in the markets so that individual resources can satisfy operational and other requirements that they could not meet on a stand-alone basis.

Because storage and other distributed resources may be located on local distribution systems regulated by state and local authorities, the proposal raises issues regarding the boundaries of state and federal jurisdiction, such as:

  • Whether FERC may force states to allow retail customers to bypass retail programs and participate directly in the wholesale market.
  • Whether states should be able to opt-out of allowing wholesale market participation of electric storage resources.
  • Whether states will lose jurisdiction over storage resources participating in wholesale markets — given FERC’s exclusive jurisdiction over wholesale sales.
  • Given that FERC does not have jurisdiction to regulate local distribution systems, how will local distribution system reliability be maintained?

Comments on the proposed rule have been filed.

Use and compensation of electric storage resources in organized markets

Storage resources can be used to provide both what are traditionally classified as transmission services as well as standard wholesale electricity services, and they may even  provide different types of service simultaneously.  How these services are classified can have important implications for pricing in the markets.  FERC policy now applies quite different pricing policies to these different services.  Transmission service compensation is limited to cost-based rates because such service is usually provided by a monopoly transmission operator.  In contrast, generation services in wholesale markets are generally allowed unlimited pricing flexibility.  Thus, defining what storage-provided services may be classified as transmission, generation, or both, is important.

FERC held a technical conference in November 2016 and then received comments aimed at distinguishing between these services.  The conference also addressed a number of operational and compensation issues associated with storage resources, such as:

  • The operational implications of using storage resources as both transmission assets and as providers of other wholesale electricity services, such as power sales.
  • The types of resources that can provide simultaneous services, and how those services should be priced and considered in grid planning models.
  • The potential for quickly deployable storage resources to compete to supplant uneconomic traditional generators needed to meet reliability needs.

FERC has not indicated how these issues will be addressed in future policy determinations.  Nonetheless,  paving the way for full participation in wholesale markets by innovative storage resources would be an important step by FERC.

Fast-start pricing in markets operated by RTOs and ISOs

A fast-start resource can start up in 10 minutes or less and has a minimum run time of one hour or less. Fast-start resources are valuable because they typically are committed in real-time, very close to when needed, and can respond quickly to unforeseen system needs.

While RTOs and ISOs have developed some elements of pricing for fast-start resources, FERC expressed concern that those practices could produce prices that do not reflect the value of fast-start resources and fail to provide incentives for efficient investments.  Accordingly, FERC issued a NOPR in December 2016 proposing requirements for each RTO and ISO to incorporate in its pricing fast-start resources.  Among other things:

  • Fast-start pricing must be applied to any fast-start resource committed by the RTO/ISO that submits economic energy offers to the market and must be used in both day-ahead and real-time markets.
  • A committed fast-start resource’s commitment costs, i.e., start-up and no-load costs, must be included in energy and operating reserve prices during the fast-start resource’s minimum run time.
  • An RTO/ISO must relax the economic minimum operating limit of fast-start resources and treat them as dispatchable from zero to their economic maximum operating limit for calculating prices.

Comments on the proposal have been filed.

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The initiatives described above are aimed at ensuring that wholesale market policy evolves to keep up with changes in the marketplace.  How FERC should deal with state generation preferences that affect wholesale markets is a question that looms large and cannot be ignored by the Commission.   Clearing out unnecessary barriers to market participation by innovative resources is similarly of critical importance.    The new Commission will have the opportunity to deal with these and other pressing wholesale market policies.