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.

*    *    *

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.

Suniva Requests Global Safeguards For U.S. Solar Industry Under Section 201

On April 26, 2017, the U.S.-based solar manufacturer Suniva, Inc. filed a petition for global safeguards with the U.S. International Trade Commission (“ITC”). In particular, Suniva requests the imposition of tariffs on solar cells and the establishment of a minimum price for solar modules imported into the United States. The petition was filed under Section 201 of the Trade Act of 1974, as amended, which authorizes global safeguards investigations, also known as “escape clause” investigations. Throughout the proceedings, affected parties will have multiple opportunities to submit their views not only to the ITC but also to the Trump Administration, which will have the final say on any relief recommended by the ITC.

The Suniva Petition

Suniva is a manufacturer of high-efficiency solar cells and panels based in Georgia, with production facilities in Georgia and Michigan. Earlier this year, Suniva laid off nearly 200 employees; in mid-April, it also filed for Chapter 11 bankruptcy protection. The company’s ITC petition claims that unless global safeguards are imposed, Suniva will be forced to shutter its remaining production operations permanently.

Suniva is filing its Section 201 petition against a backdrop of existing trade remedy measures in the solar industry. Specifically, the ITC and the U.S. Commerce Department previously imposed antidumping and countervailing duties against solar cells and modules from China and Taiwan, and those tariffs remain in effect.

The Suniva petition goes beyond the existing antidumping and countervailing duty orders because the requested safeguards are not limited to imports from specific countries; rather, the remedies under Section 201, if granted, would be global in scope and would affect all solar cells and modules imported into the United States, regardless of origin. The scope of the petition is limited to crystalline silicon photovoltaic cells and modules; it expressly excludes competing thin film photovoltaic products. The petition also excludes modules, laminates, and panels produced in other countries using cells manufactured in the United States.

In terms of duration, Suniva asks the ITC to recommend that the President impose global safeguards for four years—the maximum statutory period. The requested relief is an initial duty rate on imported solar cells of $0.40/watt, along with an initial minimum price on solar modules of $0.78/watt. These initial rates would be reduced slightly over the course of the proposed four-year schedule. Reports suggest that under current market conditions, the price of imported solar modules would roughly double if Suniva’s request were granted.

Section 201 Investigations

In a Section 201 investigation, the ITC must determine whether an article is being imported “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.” If the ITC issues an affirmative injury determination, it recommends a remedy to the President, who ultimately decides what remedy, if any, will be imposed.

The ITC is currently reviewing Suniva’s petition to determine whether it was “properly filed” in accordance with its rules. By regulation, petitions must contain specific supporting information including import data, domestic production data, and data showing the alleged injury. Once this initial review is complete, the ITC will decide whether to institute the investigation and will publish a notice of its decision in the Federal Register.

If the ITC institutes an investigation, stakeholders will have various opportunities to present their views. Public hearings are held during the ITC’s consideration of injury (or threat of injury) to the domestic industry and during any subsequent remedy phase. “All interested parties and consumers, including any association representing the interests of consumers,” may attend, present evidence, and cross-question other presenters at hearings.

The injury phase must be concluded within 120 days after the petition’s filing, though the ITC has an extra 30 days to complete “extraordinarily complicated” investigations. Then, in the event of an affirmative injury determination, the ITC submits a report to the President at the conclusion of the remedy phase containing its findings and recommendations. This report must be submitted within 180 days after the petition’s filing.

In determining what relief to provide, if any, the President must take into account the ITC report, the domestic industry’s efforts to make a positive adjustment to import competition, the economic and social costs and benefits of the proposed relief, U.S. economic and security interests, and other statutory factors. Additionally, an interagency trade group must make a recommendation to the President about any action to be taken. This interagency group—chaired by the U.S. Trade Representative and including the Secretaries of Commerce, State, Agriculture, Labor, and the Treasury—will request public comments following an affirmative injury determination by the ITC.

*           *           *

In his recently released 2017 Trade Policy Agenda, President Trump emphasized that the “safeguard” provisions of Section 201 “can be a vital tool for industries needing temporary relief from imports to become more competitive.” While it remains to be seen what actions the Administration may take in response to the results of the ITC’s Section 201 investigation, Suniva’s petition appears designed to capitalize upon the Administration’s stated interest in strictly enforcing U.S. trade remedy laws, strengthening the nation’s manufacturing base, and protecting against domestic job losses. Depending upon the outcome, the beneficiaries could include not only Suniva but also traditional energy sectors that compete with the solar industry.

Windstream v. Canada: How Regulatory Winds of Change Affected a Clean Energy Project

A recently-published NAFTA arbitration award in Windstream Energy LLC v. Government of Canada illustrates the perils of investing in clean energy projects in jurisdictions with ever evolving regulatory and policy frameworks.  The case is also a good reminder of the importance of investing in foreign jurisdictions through vehicles incorporated in countries that have adequate investment-protection treaties with the host country, including access to international arbitration in the event of disputes.

Windstream Energy LLC, a U.S. company dedicated to the development of renewable energy, was awarded more than $20 million in compensation and $2.9 million in legal costs after a NAFTA tribunal found that Canada failed to provide Windstream fair and equitable treatment as required by NAFTA Article 1105(1).  (Windstream had sought damages of $500 million approximately.)  Notably, the tribunal determined that Article 1105(1) requires “fair and equitable treatment” consistent with the minimum standard of treatment under customary international law, and rejected the notion that breach of such standard can arise only from egregious conduct, as set forth in the 1926 Neer decision.


The case involved an offshore wind electricity generation project in Ontario designed by Windstream under the Feed-in-Tariff Program (FIT Program) implemented by the Ontario Power Authority (OPA), a corporation established by the Government of Ontario and responsible for, inter alia, the procurement of new generation capacity through long-term power purchase agreements.  To attract investors, the FIT Program established a 20-year fixed-premium price to be paid by OPA to producers of energy from renewable resources, including onshore and offshore wind, hydroelectric, solar, biogas, biomass, and landfill gas.  The goal of the FIT Program was to help energy project developers secure financing for their projects.  To that end, OPA developed so called FIT Contracts, which were long-term fixed-price contracts that provided standard terms and conditions applicable to all FIT projects.

In 2010, OPA offered Windstream a FIT Contract for its offshore wind energy project.  The FIT Contract required Windstream to begin commercial operations by May 4, 2015 (the Milestone Date for Commercial Operation).  Although the FIT Contract permitted delays due to force majeure events, the contract could be unilaterally terminated by either party if those events delayed the project for more than two years beyond the Milestone Date for Commercial Operation.

In February 2011, the Government of Ontario announced a moratorium on offshore wind projects until further research on the potential environmental impact of those projects was completed and an adequate policy framework was developed.  OPA recognized that the delays imposed on the Windstream project as a consequence of the moratorium constituted a valid force majeure event as of November 2010, when Windstream was notified that it could not carry out wind testing while the government’s policy review was ongoing.

Windstream complained that the government’s moratorium on offshore wind projects had rendered Windstream’s project worthless and not financeable.  According to Windstream, even if the moratorium was lifted, the project could no longer be built by the Milestone Date for Commercial Operation, exposing Windstream to the potential unilateral termination of the FIT Contract by OPA.  Windstream further alleged that even if OPA were to waive its right unilaterally to terminate the contract, none of the strategic partners and banks would be willing to finance the project, given the legal uncertainty created by the moratorium, which appeared to be motivated by the impact these projects would have on the then-upcoming 2011 elections.

Canada denied that the moratorium was politically motivated and argued that the delay was needed to allow sufficient research to be completed for the government to develop an adequately informed policy framework.  Canada also asserted that while OPA tried to accommodate Windstream in the context of the deferral (by offering a five-year extension of the Milestone Date for Commercial Operations), Windstream rejected those offers, and made unreasonable and unrealistic demands.

Windstream’s Fair and Equitable Treatment Claim

Windstream contended, inter alia, that Canada breached Article 1105(1) of NAFTA by (i) imposing the moratorium on the development of offshore wind projects, which was in breach of its legitimate expectations, which were based on the representations and commitments Canada had made when it encouraged Windstream to invest in its project; and (ii) by failing to respect its promise to ensure that Windstream would not be penalized by the moratorium.  Canada denied these allegations.

Canada contended that a breach of Article 1105(1) required evidence of egregious conduct, as set forth in the 1926 Neer decision by the Mexico-United States Claims Commission.  Canada argued that, at most, the legitimate expectations of Windstream would only be one factor in assessing egregious behavior under customary international law.  Canada further noted that the development of offshore wind projects was deferred to ensure that the regulatory framework would be backed by solid research.

The Tribunal’s Analysis and Conclusions

The Tribunal observed that the parties had the burden of proving the content of the “minimum standard of treatment” through evidence of state practice and opinio juris.  The Tribunal rejected Canada’s suggestion that the 1926 Neer decision was direct evidence of state practice, noting that it did not deal with treatment of foreign investors.  Because the parties failed to submit evidence of actual state practice and opinio juris, the Tribunal relied on “indirect evidence,” including decisions of other NAFTA tribunals and relevant legal commentary, to determine the minimum standard of treatment.

The Tribunal observed that Article 1105(1) expressly requires “fair and equitable treatment,” and that the Free Trade Commission of NAFTA interpreted “fair and equitable treatment” to mean only the “customary international law minimum standard of treatment.”  Accordingly, the Tribunal observed, the treatment required under Article 1105(1) is “fair and equitable treatment” consistent with the minimum standard of treatment under customary international law.  The Tribunal further stated that the determination of whether Canada’s conduct was unfair or inequitable under the customary international law minimum standard of treatment had to be determined based on the facts of the case, not in the abstract.

The Tribunal found that the government of Ontario’s moratorium on offshore wind development was not, in itself, wrongful, because, inter alia, the decision was driven by a genuine policy concern.

But the Tribunal found reproachable, however, that, following the moratorium, the government did little to address the scientific uncertainty surrounding offshore wind projects that it had relied upon as the main publicly-cited reason for the moratorium.  Many of the research projects that the government planned to conduct did not go forward and, during the arbitration proceeding, counsel for Canada confirmed that the government did not plan to conduct any further studies.  More importantly, according to the Tribunal, Canada did little to address the “legal and contractual limbo” in which Windstream found itself after the moratorium.  The Tribunal also found that the government failed either promptly to complete the scientific research required to develop its policy framework or exclude offshore wind as a source of renewable energy and terminate Windstream’s FIT Contract.  The Tribunal concluded that the government’s failure to take the necessary measures within a reasonable time after the imposition of the moratorium to bring clarity to the regulatory uncertainty pertaining to the Windstream project constituted a breach of Article 1105(1) of NAFTA.

The decision of the Windstream v. Canada tribunal is consistent with other tribunals that have recognized that the minimum standard of treatment under customary international law has evolved towards granting greater protection to investors.  See Bilcon v. Canada, PCA Case — NAFTA/UNCITRAL No. 2009-04, Award on Jurisdiction and Liability, paras. 435, 438 (17 March 2015).  In Merrill & Ring, for instance, the tribunal concluded that “today’s minimum standard is broader than that defined in the Neer case and its progeny” and “the standard protects against all such acts or behavior that might infringe a sense of fairness, equity and reasonableness.”  Merrill & Ring Forestry L.P. v. Canada, NAFTA/UNCITRAL, Award, paras. 210, 213 (31 March 2010).  And in ADF v. United States, the tribunal also noted the dynamic nature of the minimum standard of treatment under customary international law, which is “constantly in a process of development,” and rejected the view that “the Neer formulation is automatically extendible to the contemporary context of treatment of foreign investors.”  ADF Group Inc. v. United States, ICSID Case No. ARB(AF)/00/1, Award, paras. 179-181 (9 January 2003).

Large Equity Funds Are Demanding Greater Boardroom Attention to Sustainability and Climate Risks

While the direction of Trump Administration policymaking on climate risk appears to deny concern, the largest U.S. public equity funds are sharpening their focus and concern about this subject.

Last week BlackRock, the Nation’s largest funds group with $5.1 trillion in assets under management, updated its investment stewardship guidance and highlighted climate risk management as a priority for engagement with public company boards in 2017.   This follows on similar ESG Guidelines released in late January by the Nation’s third largest funds group, State Street Global Advisors, which manages over $2.4 trillion in assets.   These policy statements borrow from the December 2016 Recommendations Report of the Financial Stability Board’s  Task Force on Climate-Related Disclosures (TCFD) that was chaired by Michael Bloomberg.

The following is a key statement from BlackRock’s guidance:

Climate risk awareness and engagement has advanced over the past several years and just as our thinking on climate risk continues to evolve, we believe that companies are also increasingly more aware of its business relevance. Climate risk will be one of the key engagement themes that the Investment Stewardship team will prioritize in 2017 and the team’s recent work on this issue and its engagement and contributions to external initiatives such as the TCFD will inform our assessment of shareholder proposals on the topic. Over the course of 2017 we intend to engage companies most exposed to climate risk to understand their views on the recommendations from the TCFD and to encourage such companies to consider reporting against those recommendations in due course. For directors of companies in sectors that are significantly exposed to climate risk, the expectation will be for the whole board to have demonstrable fluency in how climate risk affects the business and management’s approach to adapting and mitigating the risk. Assessments will be made both through corporate disclosures and direct engagement with independent board members, if necessary.

State Street’s guidelines offer the following:

[I]n 2017 we will be increasingly focused on board oversight of environmental and social sustainability in areas such as climate change, water management, supply chain management, safety issues, workplace diversity and talent development, some or all of which may impact long-term value. While none of us can state definitively “the answer” for a particular company, and we acknowledge that certain industries will face different issues, we believe that over time these areas can pose both risks to and opportunities for long-term returns. Therefore, as stewards we are convinced that addressing ESG issues is a good business practice and must be part of effective board leadership and oversight of long-term strategy.

To help investors better understand how companies are addressing climate risks, the TCFD report suggests four categories of recommended disclosures:

  1. Disclose the organization’s governance around climate-related risks and opportunities;
  2. Disclose the actual and potential impacts of climate-related risks and opportunities on the organization’s businesses, strategy, and financial planning;
  3. Disclose how the organization identifies, assesses, and manages climate-related risks; and
  4. Disclose the metrics and targets used to assess and manage relevant climate-related risks and opportunities.

The TCFD’s recommended disclosures inform State Street’s analytical framework for evaluating the degree to which company boards are adequately addressing climate and sustainability in company strategies.   The State Street framework reviews and categorizes a company’s approach to sustainability according to three criteria:

  1. Has the company identified material environmental and social sustainability issues relevant to its business?
  2. Has the company assessed and, where necessary, incorporated the implications of relevant environmental and social sustainability issues into the company’s long term strategy?
  3. Has the company adequately communicated its approach to sustainability issues and its influence on strategy?

State Street then classifies companies into three tiers — Tier One companies have satisfied all three criteria, Tier Two companies have satisfied one or two of the criteria, and Tier Three companies have not satisfied any of the criteria.  State Street will focus its active stewardship engagement on Tier Three companies and incorporate its assessment of company progress in proxy voting decisions.

While it is unlikely that the Securities and Exchange Commission will adopt any new climate risk or carbon disclosure rules during the Trump Administration, it appears that there may be growing demands by institutional investors for greater climate risk and carbon disclosure and active strategic management of these issues.   CEOs, CFOs and board members should be prepared to address these subjects in their investor relations activities.

Blockchain Goes Solar

A recent New York Times article reported on an early-stage, solar energy microgrid being formed in Brooklyn, called the Brooklyn Microgrid, that relies on blockchain technology, the innovative database technology used by cryptocurrencies like Bitcoin that promises to transform industries as diverse as financial services, health care, retail, and manufacturing.  The blockchain-based microgrid enables neighboring residents and businesses to join an electronic trading platform and allows residents with solar rooftop panels to sell their excess electricity directly to neighbors within the microgrid.  The use of blockchain technology facilitates secure and verifiable peer-to-peer energy trading, without involving the local electric utility in administering the microgrid.

Blockchain is a type of distributed ledger technology that creates and maintains a complete sale-purchase-delivery transaction history for a commodity, such as currency or, in this case, electricity.  With a blockchain distributed ledger, identical, immutable copies of the ledger are available to multiple participants in the network, not just to a single intermediary, such as the local utility.  The use of blockchain in an electricity microgrid gives participants the ability to meter surplus electricity production from rooftop solar panels and to document securely the sale and use of that electricity by other members of the connected microgrid.  The transaction chain would omit the local utility, which would account for net flows in or out of the collective microgrid, but not for the real-time purchase and sale of surplus solar energy.  The ultimate goal for blockchain-based microgrids may be to build a microgrid with energy generation and storage components that can function largely independently of the local electric utility company’s system, even during widespread power failures.

The project is one example of how the marriage of solar energy and blockchain distributed ledger technologies can redefine the relationship between energy producers and energy consumers, promote solar energy, and create alternatives to the traditional centralized power grid.  That said, creative, light-handed regulatory solutions may be needed from public service commissions to allow blockchain-based sales and purchases of surplus solar electricity, within a microgrid, to occur without causing each seller to become a regulated retail seller of electricity.

FERC Gets Comments on Electric Storage Proposal

Electric storage resources such as batteries and flywheels are shaping the grid of the future. The ability of these resources to absorb and discharge electricity gives the resources operational flexibility that allows them to provide a variety of services to help keep the power grid in balance.  Energy storage installations in the U.S. grew 100% in 2016Most of the new resources were utility scale but 25% were commercial and residential systems.

As discussed previously in this blog, FERC issued a Notice of Proposed Rulemaking (NOPR) intended to knock down barriers to storage resource participation in the organized wholesale electricity markets administered by Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs).[1]  FERC’s proposal would require each RTO to revise its tariff in two ways:

  • Establish market rules that recognize the physical and operational characteristics of storage resources and accommodate their participation. Storage resources that participate in wholesale markets must do so under rules designed for other types of resources.
  • Allow distributed energy resource aggregators to participate in the markets. Individual distributed energy resources may be too small to meet minimum size requirements or have difficulty satisfying operational performance requirements of the markets. Allowing these resources to participate through aggregations can enable them to satisfy requirements that they could not meet on a stand-alone basis.

FERC received comments on its proposal from more than seventy entities across a broad  spectrum of the industry.  This post summarizes the major issues raised in the comments.

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NY ISO Outlines Steps For Integrating Distributed Resources

The NY Independent System Operator recently issued a plan for addressing the nuts-and-bolts issues associated with integrating distributed energy resources (DERs) into the wholesale electricity market.  The NYISO says its Distributed Energy Resources Roadmap for New York’s Wholesale Electricity Markets is “the first step in building (the) grid of the future” and seamless transition “from a primarily central station-based grid to a diverse bi-directional grid.”


New York is implementing a sweeping “Restoring the Energy Vision” initiative (REV) aimed at a substantial transformation of electric utility practices to empower customer choice and encourage greater penetration of clean generation and behind-the-meter resources.  To help accomplish these objectives, the NY Public Service Commission  adopted a comprehensive policy framework for a reformed retail electric industry aimed at increasing distributed energy resources and dramatically changing the role of utilities.  DERs will become integral tools in the planning, management and operation of the electric system, placing them on a competitive par with centralized options.  The current retail utilities will serve as a platform to provide uniform market access to customers, distributed resources and aggregators.

 The NYISO Roadmap 

The Roadmap’s primary goals are to integrate DERs into the NYISO’s wholesale electricity markets and to align with the goal of New York’s REV initiative.  The document sets out a framework for developing market design elements, functional requirements and tariff language to integrate dispatchable (i.e., controllable) DERs into the wholesale electricity market.

The Roadmap identifies the following concepts and issues to be addressed through the NYISO’s  stakeholder process and offers initial proposals on some of them.

            Aggregation.  Individual DERs  will be allowed to aggregate so they can meet wholesale market eligibility and performance requirements.  The rules related to DER aggregation will be the foundation upon which the remaining rules are built, and will be the first concept developed in the market design process.

  • Aggregation rules will be technology agnostic. A single DER aggregation could include a heterogeneous mix of different technologies, such as load reduction, generation, and storage technologies that, when combined, can meet dispatch instructions. However, the NYISO will explore whether homogenous aggregations can provide additional or different services than heterogeneous aggregations and therefore be valued differently.
  • The geographical footprint of DER aggregations will be limited to those resources connected to the same bulk transmission node. This limit will help ensure DER compensation in the wholesale markets reflects the aggregation’s locational and temporal value on the bulk power system.
  • Aggregations must be a minimum of 100 kW in total size. However, the NYISO is not proposing a minimum size restriction for individual DERs that are part of an aggregation.
  • The market participant interfacing with the NYISO on behalf of an aggregation will be a DER Coordination Entity (DCE), which may be customer, a third-party aggregator, or a distribution system platform provider. Coordination practices among the DCEs, the utilities and the NYISO will be developed.

            Measurement and verification.  DERs will be scheduled and dispatched in a manner comparable to traditional generators. DERs will also be held to compliance obligations comparable to those of traditional generators. The NYISO will develop performance criteria and compliance metrics for dispatchable DERs.

  • Aggregations must provide real-time telemetry data for operations and monitoring, and after-the-fact meter data for settlement and billing on the same basis as traditional generators. However, the NYISO may allow small aggregations (of less than 1 MW) to provide real-time data from a sample set (at least 30%) of DERs in the aggregation.

            Performance obligations.  In general, DERs will be expected to have the same obligations as traditional generators.

  • In capacity markets, DERs desiring full capacity payments will be expected to be capable of delivering capacity for a full 24 hour period, comparable to what is expected of traditional generators. However, some DERs are unable to deliver capacity in all 24 hours due to their physical characteristics but are still valuable to the system.  The NYISO intends to develop additional service tiers for those DERs.
  • DERs selected in the day-ahead market auction will have an obligation to offer into the real-time market, just as do traditional generators.
  • Performance obligations will be set at the aggregation level, not at the individual resource level. Thus, an aggregation will be allowed to meet its obligations from various resource types.  For example, if an aggregation is scheduled for four hours, the aggregation may meet its obligation by discharging storage devices for two hours and by load curtailment for the remaining two hours.

            Dual participation in retail and wholesale markets.  Many DERs will be connected to the distribution networks and would like to provide both wholesale service and retail service, thereby accessing multiple revenue streams.  However, except for certain existing demand response programs, simultaneous participation is a new concept to the NYISO.  According to the Roadmap, the issues that need to be addressed include:

  • Whether the NYISO or the distribution system platform provider has operational control over a DER in a given interval, and whether that changes depending on the services provided.
  • The appropriate communications paths for a DER when participating in wholesale and retail programs.
  • How do the NYISO and utilities address conflicting market signals? A market signal from NYISO may conflict with the market signal from the distribution system platform provider and vice versa.  The DER’s response to multiple signals could lead to operational and reliability issues.
  • Can individual DERs in an aggregation participate in both wholesale and retail markets, or is participation on an aggregation-wide basis?
  • If a storage resource charges at a wholesale rate and discharges to an end-use customer through a retail program, does the electric storage resource become an LSE by engaging in sales for resale? What regulatory issues are implicated by occasional sales for resale?
  • What is the FERC’s view of simultaneous participation in wholesale and retail markets?

            Pilot program.  The NYISO has a 2017 initiative to develop a framework to enable small, limited scope pilot projects to be tested in the wholesale markets.  These will help the NYISO understand how integrating various new technologies will affect NYISO systems.  The pilot projects will not be eligible to set market prices.

            Granular pricing.  Accurate prices are a critical element of encouraging efficient decision-making.  The NYISO now delivers real-time price signals at a zonal level.  However, areas within a zone may experience conditions that are not fully reflected in the zonal price. Thus, pricing at the zonal level dilutes incentives for DER to locate in areas that could provide significant benefits to the grid and the market.  Accordingly, in a pilot project, the NYISO currently posts more granular price signals reflecting location specific system conditions at select locations.

According to the Roadmap, market designs for all of these concepts are expected to be completed in 2018, to be followed by software development and implementation.  A target date of 2021 is set for implementing dispatchable DER rules.

NYISO’s CEO, Brad Jones, said the Roadmap would help to  “highlight opportunities for more emerging resources to participate in our markets. It will guide developers, communities and others as they seek to invest in a more flexible and dynamic grid.”

FERC Addresses Electric Storage Complaint

A previous post on this blog reported a complaint by an electric storage resource owner that FERC must reform a Regional Transmission Organization’s (RTO’s) tariff with respect to the treatment of storage batteries.  In response, FERC issued an Order that requires the RTO to adopt rules that allow storage resources to participate in all of its markets and that account for those resources’ physical and operational characteristics.  The Order is significant because it breaks down barriers to the participation of storage resources in energy, capacity and ancillary services markets in an RTO whose rules are shown to violate the policies proposed in FERC’s Storage NOPR.

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