Coming Up: FERC Conference on Storage Resources in PJM

By Bud Earley on Posted in Electricity, FERC

In its recent landmark Order No. 841, FERC directed Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) to remove barriers to participation by electric storage resources in their wholesale electricity markets.  The expectation is that each RTO/ISO will adopt rules that recognize and compensate physical and operational characteristics of storage resources, including battery storage, boosting their role in the nation’s electricity grid.  Against this policy backdrop, FERC recently issued two orders addressing issues affecting electric storage resources’ participation in one RTO’s regulation service market.

PJM, the RTO operating in the mid-Atlantic region, principally Virginia, Maryland, Delaware, Pennsylvania, New Jersey and Ohio, says its rules are procuring too many dynamic resources such as storage and are causing operational problems.  PJM made market software changes and proposed tariff revisions to address the issues.  Storage entities opposed these changes, claiming discriminatory treatment.  FERC rejected the tariff revisions and directed its staff to hold a technical conference to address the issues raised.  The upcoming technical conference will address the nuts-and-bolts challenges to integrating storage resources into regulation markets in a non-discriminatory manner and its outcome could have implications beyond the PJM market.

Below we summarize some of the complex technical issues presented by participation of  storage resources in PJM’s regulation services market.

Regulation service

As a balancing authority, PJM manages the supply and demand of electricity by economically dispatching generation to meet its load and the scheduled interchange with other balancing authorities.  Real-time imbalances between supply and demand result in an Area Control Error, or ACE, which is the difference between scheduled and actual flows across interconnections with other balancing authorities.  Regulation service is purchased to maintain or return the ACE to zero.

When the ACE indicates an imbalance, a dispatch signal is sent to each regulation resource to raise or lower its output to correct the imbalance.  PJM sends two different types of signals.  One, called RegA, is used to dispatch slower, sustained-output resources, such as steam and combustion resources. A faster signal, called RegD, is used to dispatch faster, dynamic resources, such as battery storage.

PJM experienced problems in its dispatch of resources to supply regulation service and proposed tariff changes to FERC.  Also, PJM took some dispatch actions on its own to alter the dispatch of storage resources.

Tariff order

PJM proposed changes to its tariff to address the following stated problems in its regulation market:

  • The algorithm it uses to establish the tradeoff between RegA and RegD resources to place them on a comparable basis for market clearing purposes was stated to be inflating the procurement of RegD service.[1]
  • The performance, or “mileage,” component of the market settlement equation was stated to result in a higher financial signal for new RegD market entry, contributing to an over-procurement of those resources.[2]

PJM proposed changes to its tariff to address these problems, among them were adopting a different algorithm that determines the tradeoff between RegA and RegD resources and removing the mileage component from the settlement equation.

Storage entities opposed the removal of the mileage component from the settlement equation. The storage entities argued that the proposal violates FERC policy and is unduly discriminatory.  In Order No. 755, FERC required, among other things, that regulation service compensation should be based on the actual service provided and include a performance payment that reflects the quantity of regulation service when following the dispatch signal.   Protests asserted that PJM’s proposal ignores the actual performance of regulation resources, and that under the new algorithm RegD resources will always be under-compensated.

FERC agreed and rejected PJM’s tariff proposal because it does not comply with the requirement of Order No. 755 to compensate all regulation resources based on the quantity of regulation service provided.  FERC found that the proposal does not account for actual mileage in settlement and does not accurately reflect the contribution of RegD resources when they operate.  Because PJM stated that it proposed reforms are interdependent and a change in one area will impact other areas, FERC did not address other aspects of the proposal.

Complaint order

PJM originally designed the RegD dispatch signal to be “unconditionally energy neutral,” within a 15-minute period; in other words, 7.5 minutes of input followed by 7.5 minutes of output.  According to PJM, however, this feature of the signal was causing operational problems.  Because it always signals RegD resources to maintain power balance over a 15-minute interval regardless of the direction PJM needs regulation resources to  move, the signal sometimes causes the RegA and RegD signals to work against each other, i.e., signaling the two types of resources to move in opposite directions, thus impeding efficient regulation control.  According to PJM, at times, hundreds of megawatts of RegD resources were performing in a way that respected their energy neutrality but inhibited PJM’s ability to control the ACE.

To address this issue, PJM had made the following unilateral changes in its dispatch practices over the last few years:

  • Revised a business manual such that the algorithm used to establish the tradeoff between RegA and RegD resources caps the amount of RegD resources that could be procured at 40 percent of the total (down from 62 percent under current rules) and at 26.2 percent during certain hours.
  • Revised its regulation signal software so that the RegA and RegD signals move together in the direction that minimizes ACE and that the RegD signal is “conditionally neutral” over a 30-minute period (instead of 15 minutes). Under “conditional” neutrality, managing ACE is the first priority and neutrality for energy-limited resources such as storage is honored only when system conditions permit.

Storage resource entities filed complaints against PJM’s revisions, arguing that both changes are unduly discriminatory against RegD resources and that both must be submitted for Commission review because they significantly affect the terms of service and thus must be included in a tariff accepted by the Commission rather than in business practice manuals.

With respect to the signal software revisions, storage resources argued that the original energy-neutral signal respected RegD resources’ limited-energy characteristics.  Since the revisions, those resources have been directed to operate outside of their design parameters, making responding to the dispatch signal more difficult and resulting in performance issues, reduced compensation, and adverse impacts on equipment.

FERC found that both the algorithm used to establish the tradeoff between RegA and RegD resources and the parameters of the signals to regulation resources significantly affect the rates, terms, and conditions of regulation service and thus should be included in the PJM tariff .  However, the Commission did not direct PJM to submit a compliance filing but instead directed staff to convene a technical conference to address the issues raised in the complaints.

Technical conference

In the complaint order, FERC says the technical conference should address the issues raised in the complaints, and, given the related issues raised in the tariff case, the conference should also examine PJM’s two-signal regulation market design with respect to the requirements of FERC’s compensation policy.  FERC directed staff to request data and information from PJM and the complainants prior to the technical conference to help inform the discussion,

FERC will issue a separate notice establishing dates and technical conference details.  The conference will be convened under Docket EL17-64 and EL17-65.

[1] PJM purchases regulation service in a bid-based auction market.

[2] A performance payment reflects the quantity of regulation service, or work done, when following the dispatch signal. It is sometimes referred to as “mileage” as it is based on the MW changes from both increasing and deceasing generation.

Covington CleanEquity Conversations

By W. Andrew Jack on Posted in Sustainability

On March 8-9, 2018, a bespoke group of approximately 200 leading entrepreneurs, investors and advisors focused on deploying and commercializing cutting edge technologies gathered in Monte Carlo from across the globe for the 11th annual CleanEquity® Monaco Conference. Complementing other plenary sessions and emerging company presentations, the conference initiated a new feature — Covington CleanEquity Conversations — intended to capture and memorialise the unique thought leadership opportunity presented by the gathering in Monaco. On the first day, conference participants separated into three breakout groups for Chatham House Rule discussions curated by partners from the international law firm Covington & Burling LLP of three critical issues confronting cleantech deployment and commercialisation:

  • AI and IoT – Benefits, Risks, and the Role of Regulation
  • Sustainability – What goals should businesses prioritise and what are the right metrics?
  • Will market driven innovation alone save us from climate change?

On the second day, the Covington team reported during the conference’s final plenary session key takeaways from the three breakout group discussions. Covington and CleanEquity organizer and specialist investment bank, Innovator Capital, are pleased to share brief summaries of the thought leadership developed by the proceedings of conference participants on each of the three topics.

Sustainability -What goals should businesses prioritise and what are the right metrics?

Many global corporations have embraced corporate sustainability and carbon reduction goals. Large equity funds also are examining corporate sustainability practices and using a variety of proprietary or third-party environmental, social and governance or “ESG” ratings to assess corporate progress. But this proliferation of goals and array of often indecipherable ratings systems challenges societal measurement of “sustainability progress.” In a session led by Covington’s Clean Energy Industry Group Chair Andrew Jack, conference participants grappled with the following questions:

  • Do investors need better, more comparable, information about corporate sustainability efforts?
  • What sustainability goals should businesses prioritize?
  • How should sustainability be measured, incentivised and rewarded?

Improving Sustainability Disclosure is Essential

There was strong consensus for the view, from the perspective of both investors and companies, that mere compliance with current government disclosure mandates is insufficient to satisfy investor demands for corporate sustainability disclosures. For example, in the United States, corporations are not legally required to publish sustainability reports. Yet, prompted by investor and other stakeholder needs, at least 82% of the Standard & Poor’s 500 companies publish such reports.

There was equally strong consensus that it is a daunting task for corporate managers to sort through and select among the growing thicket of guidelines and voluntary reporting frameworks. Proliferating disclosure standards promulgated by the Global Reporting Initiative (GRI), Carbon Disclosure Project (CDP), Sustainability Accounting Standards Board (SASB), Task Force on Climate-Related Financial Disclosures (TCFD) and other organizations provide wide latitude for sustainability disclosures. One participant noted that these standards are so diverse and loose that sustainability reports can say just about anything. Another participant commented that this diverse guidance landscape means that ESG rankings and metrics are not sufficiently comparable and thus are not terribly meaningful. Efforts to winnow the goals and metrics surrounding sustainability reporting to a more discrete core set of comparable measures would be beneficial.

Core Sustainability Goals and Priorities

To aid in this winnowing, participants in this breakout session responded to a brief survey rank ordering five separate sustainability goals by assigning 1 to the highest priority and 5 to the lowest. The survey also prompted participants to offer suggestions for other sustainability goals that businesses should pursue. The group prioritised the five enumerated goals as follows:

Rank Average Score Sustainability Goal
1. 2 Reduction of greenhouse gas emissions
2. 2.38 Reduction of fresh water consumption
3. 2.77 Energy efficiency
4. 3.15 Reduction of solid waste disposal
5. 3.38 Avoided deforestation / reforestation

These results reflect quick responses of a relatively small group of cleantech investors and entrepreneurs and therefore may not be representative of the rank ordering of sustainability goals that would be revealed in a survey of a broader segment of the business community. Moreover, within this small group the conversation revealed a fair amount of debate among priorities. One participant suggested that all five goals were equally important to society. This sentiment was echoed by others who observed that the overall objective of corporate sustainability efforts should be to promote human health and well-being, which necessarily requires the simultaneous pursuit of multiple goals. Some in the group suggested that corporations should be guided by the seventeen Sustainable Development Goals adopted by the United Nations that collectively focus on ending poverty, protecting the planet and ensuring prosperity for all. Other specific goals provided by participants included:

  • reducing inequality within societies through inclusive and equitable quality education
  • affording and strengthening gender equality
  • training and upskilling of workers
  • ubiquitous deploying of IoT devices; and
  • enhancing transparency and accountability regarding corporate actions

Measuring Progress
The group encountered some challenge developing metrics that could assess progress toward the sustainability goals. There was consensus that corporations need to establish reliable, transparent baselines against which to measure change and that metrics surrounding generalized goals such as the U.N. SDGs need to measure quantifiable impacts. For the goal of reducing greenhouse gas emissions, the group discussed the feasibility of using GHG emissions per unit of revenue as a metric. Participants generally regarded this as a reasonable tool, provided that it is used to compare performance of companies within specific sectors. For example, the airline industry has a different level of carbon intensity than the consumer electronics industry. Hence the group thought it could be useful to compare the GHG-intensity performance of one airline versus another airline, or one consumer electronics company versus another. But many in the group thought it would be unfair to measure the GHG-intensity of an airline against a consumer electronics company. Some participants, however, argued that it might be reasonable to compare GHG emissions per unit of revenue across different sectors. They observed that industries that are profitable by outsourcing to society the costs of their negative externalities tend over time to face societal pressure to retrench and compensate society for the negative externalities. In this sense, cross-sector comparability of GHG emissions per unit of revenue could be meaningful to accelerate the reduction, and minimize societal costs, of GHG emissions.

Incentives and Rewards

One participant staked the position that sustainability goals provide their own incentives and rewards, in that they are like Maslow’s hierarchy of needs. Corporations taking a long-term view are motivated to achieve all of the sustainability goals, but some take precedence over others. In this vein basic needs for sustainable clean air, water, and food must be met before the higher needs of social equality can be achieved. Another participant noted — as should be self-evident from the gathering of investors and entrepreneurs at the conference — that climate change presents a tremendous business opportunity that more enterprises should embrace. In this respect, businesses that demonstrate the greatest improvement on disrupting and addressing the problem of free riders on negative externalities should receive the greatest rewards. The discussion concluded by returning to the theme that many sustainability goals are linked together and should be considered holistically, keeping in mind the overall purpose to promote human health and social welfare.

FERC Requires Generators to Provide Primary Frequency Response

By Bud Earley on Posted in Electricity, FERC

FERC has approved a final rule requiring generating facilities that interconnect to the grid to provide primary frequency response.[1]  Primary frequency response actions are needed to stop extraordinary deviations from the grid’s target frequency that could cause grid instability.  The North American Electric Reliability Corporation, the group responsible for grid reliability standards, said that “(f)requency response is among the essential reliability services critical to the reliability of the bulk power system.”  FERC notes declining frequency response performance and the impact the evolving generation resource mix on frequency response.

Background

The reliable operation of the alternating current North American electric grid depends on maintaining a frequency near 60 Hertz (Hz).  Frequency variations, however, can occur due to sudden changes in the balance between load and generation and can cause instability, and possibly load shedding, if the frequency deviates too far from 60 Hz.  Frequency responsive control equipment in a generating facility can sense changes in system frequency and, through turbine-governors, autonomously adjust a generator’s output to help move the system frequency back toward 60 Hz.

The final rule is aimed at two problems. First, there are indications that some generator owners and operators within the Eastern Interconnection disable or otherwise set their controls such that they provide little or no primary frequency response.

Second, synchronous generating facilities with standard governor controls have historically been the predominant sources of frequency response service.  However, those generators are being replaced, in part, with non-synchronous variable energy resources such as wind and solar.  FERC observes that variable energy resources have not typically had primary frequency response capabilities.

The final rule

Newly interconnecting generating facilities are required to install, maintain, and operate equipment capable of providing primary frequency response as a condition of interconnection to the grid.  Accordingly, FERC is modifying the standard interconnection agreements to reflect this requirement.

The final rule adds the following obligations to the standard interconnection agreements:

  • Requires generating facilities to install and operate equipment that can sense changes in system frequency and autonomously adjust the generating facility’s output.
  • Sets minimum uniform operating requirements for primary frequency response and prohibits generating facilities from limiting the provision of primary frequency response, except under certain conditions.
  • Requires generating facilities to respond to frequency deviations immediately and sustain the response at least until system frequency returns to a value within an acceptable deviation range.

The new rule does not require generators to operate with headroom, i.e., operate below their maximum operating capability so that there is additional energy to provide primary frequency response.  In addition, the rule does not mandate that a generator receive compensation for providing primary frequency response.  FERC observes that the cost of installing, maintaining, and operating a governor or equivalent controls is minimal but the rule does not prevent a public utility from requesting compensation.

The new interconnection agreement conditions apply to:

  • Newly interconnecting generating facilities, including distributed energy resources, that execute interconnection agreements on or after the effective date of the final rule; and
  • Generating facilities that already have an executed or filed interconnection agreement but that take any action request that results in an interconnection agreement filed on or after the effective date of the final rule.

The final rule provides exemptions or accommodations for the following types of generation resources:

  • Combined heat and power. Newly interconnecting CHP facilities that are sized to serve on-site load and have no material export capability are exempt from the operating requirements of the rule but must install control equipment capable of providing primary frequency response.
  • Electric storage resources.  Interconnection agreements must include specific accommodations for storage resources and limitations regarding when they will be required to provide primary frequency response, such as identifying an operating range within which storage resources will be required to provide primary frequency response and identifying  circumstances when storage resources will not be required to provide primary frequency response.
  • Nuclear facilities. Nuclear generating facilities are exempt from the final rule due to their unique operating characteristics and the regulatory requirements of  the Nuclear Regulatory Commission.

The final rule is effective 70 days from publication in Federal Register.

[1] This blog reported on the Commission’s proposal as well as its call for additional comments to address certain issues.

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

By John Mizerak and Ingrid Rechtin on Posted in Infrastructure Development, NEPA

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?

By Jake Levine on Posted in California, Energy Storage, Renewables

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

By Bud Earley on Posted in Electricity, FERC

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

By David Miles and Christoph Schulz on Posted in English Law, Middle East, Oil & Natural Gas

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

By Jason Kornfeld, Jake Levine and Ingrid Rechtin on Posted in California, Renewables

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

By W. Andrew Jack on Posted in Climate Change

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

By Bud Earley on Posted in Electricity, FERC

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.

LexBlog