FERC Order 2222 opens wholesale markets to distributed energy resource aggregators

Friday, September 18, 2020

U.S. electric utility regulators have issued an order requiring the nation's regional organized wholesale electric markets to allow participation by portfolios of solar projects and other distributed energy resources. The Federal Energy Regulatory Commission's Order 2222 finds that existing regional electricity market rules are unjust and unreasonable in light of barriers that they present to the participation of DER aggregations in these markets, and requires regional grid operators to revise their tariffs to accomodate distributed energy resource aggregators. While further process and uncertainty remain ahead, FERC Order 2222 should facilitate the development of distributed energy resources by removing barriers to electricity market participation.

As defined by the FERC, distributed energy resources (DER) encompass a variety of types of technology when installed on the distribution system, a distribution subsystem or behind a customer meter. Typically less than 10,000 kilowatts in capacity for each installation, DER technologies include solar photovoltaic systems and other distributed generation or intermittent generation, electric storage, electric vehicles and their charging equipment, thermal storage, and other consumer-side measures like demand response and energy efficiency. The U.S. is experiencing significant growth in the number and size of DERs installed on the system, due to factors including federal tax incentives and state incentives, as well as considerations of reliability and utility rate design.

Through Order 2222, issued on September 17, 2020, FERC has now found "that existing RTO/ISO market rules are unjust and unreasonable in light of barriers that they present to the participation of distributed energy resource aggregations in the RTO/ISO markets, which reduce competition and fail to ensure just and reasonable rates." As a result, the Commission adopted a final rule requiring regional transmission organizations and other organized wholesale market operators to establish DER aggregators as a type of market participant, to allow them to register their DERs under one or more participation models that accommodate the physical and operational characteristics of those resources and to participate in the regional organized wholesale capacity, energy and ancillary services markets. Order 2222 allows DERs to aggregate together to satisfy minimum size and performance requirements that they might not meet individually.

The boundaries between federal and state jurisdiction over DERs arise as a matter of federal law, and have occasionally been tested -- most recently in connection with FERC Order 841, governing storage. As noted by the Commission, its Order 2222 final rule "builds off the DC Circuit Court’s recent ruling on Order No. 841, in which the court affirmed the Commission’s exclusive jurisdiction over the regional wholesale power markets and the criteria for participation in those markets." Order 2222 prohibits state regulators from broadly excluding DERs from participating in regional markets, but gives state retail regulatory authorities some power by creating a "small utility opt-in", as well as respecting states regulators’ current ability to prohibit aggregators from bidding retail customers’ demand response into regional markets. Regarding interconnection, Order 222 explains that "state and local authorities remain responsible for the interconnection of individual DERs for the purpose of participating in wholesale markets through a DER aggregation."

The final rule largely tracks a 2016 proposed rule developed by FERC staff, with some changes. The regulator appears excited to take this step. According to a fact sheet issued by the Commission under the title, "FERC Order No. 2222: A New Day for Distributed Energy Resources", Order 2222 "will help usher in the electric grid of the future and promote competition in electric markets by removing the barriers preventing distributed energy resources (DERs) from competing on a level playing field in the organized capacity, energy and ancillary services markets run by regional grid operators."

Order 2222's final rule will take effect 90 days after its publication in the Federal Register. Grid operators will then have 270 days within which they must submit to FERC a compliance filing and a plan for timely implementation of the final rule. While Order 2222 and federal laws place some constraints on what the grid operators may propose, each regional transmission organization or independent system operator has some leeway to develop and propose solutions it views as tailored to its own markets and needs. This feature of federalism will likely result in some diversity in terms of regional designs, to be considered through regional stakeholder discussion and the Commission's regulatory processes.

CFTC subcommittee report on climate risk

Wednesday, September 9, 2020

An advisory subcommittee of the U.S. Commodity Futures Trading Commission (CFTC) has released a report, Managing Climate Risk in the U.S. Financial System. Calling itself the first of-its-kind effort from a U.S. government entity, the report finds that "climate change poses a major risk to the stability of the U.S. financial system and to its ability to sustain the American economy" and that "U.S. financial regulators must recognize that climate change poses serious emerging risks to the U.S. financial system, and they should move urgently and decisively to measure, understand, and address these risks". The report offers 53 recommendations to mitigate the risks to financial markets posed by climate change.

CFTC's mission is promoting the integrity, resilience, and vibrancy of the U.S. derivatives markets through sound regulation. Structurally, CFTC's organization includes several Advisory Committees, created to provide input and make recommendations to the Commission on a variety of regulatory and market issues that affect the integrity and competitiveness of U.S. markets.

These committees include the Market Risk Advisory Committee, which "advises the Commission on matters relating to evolving market structures and movement of risk across clearinghouses, exchanges, intermediaries, market makers and end-users. It examines systemic issues that threaten the stability of the derivatives markets and other financial markets, and makes recommendations on how to improve market structure and mitigate risk." The Market Risk Advisory Committee itself includes several subcommittees, including the Climate-Related Market Risk Subcommittee which is composed of over 30 representatives of financial system participants.

On September 9, 2020, the Climate-Related Market Risk Subcommittee unanimously voted to adopt and release its report, Managing Climate Risk in the U.S. Financial System. The report describes various ways in which climate change and related risks represent threats to the U.S. financial system. As summarized in a press release by the subcommittee, the report finds that:
Climate change poses a major risk to the stability of the U.S. financial system and to its ability to sustain the American economy;

Climate risks may also exacerbate financial system vulnerability that have little to do with climate change; including vulnerabilities caused by a pandemic that has stressed balance sheets, strained government budgets, and depleted household wealth;

U.S. financial regulators must recognize that climate change poses serious emerging risks to the U.S. financial system, and they should move urgently and decisively to measure, understand, and address these risks;

Existing statutes already provide U.S. financial regulators with wide-ranging and flexible authorities that could be used to start addressing financial climate-related risk now;

Regulators can help promote the role of financial markets as providers of solutions to climate-related risks; and

Financial innovation is required not only to efficiently manage climate risk but also to facilitate the flow of capital to help accelerate the net-zero transition and increase economic opportunity.
The report presents recommended actions, including establishing an economy-wide carbon price, incorporating climate-related risks into all relevant federal financial regulatory agencies' mandates and strategies, requiring bank and nonbank financial firms to address climate-related financial risks through their existing risk management frameworks in a way that is appropriately governed by corporate management, enhancing climate risk disclosures for various time horizons, and coordination with other regulators to support the development of a robust ecosystem of climate-related risk management products.

Every member of the subcommittee voted to release the report on behalf of the panel, but not all participants expressed endorsement for all of the report's findings. In addition, the report may be influential as a matter of policy, but it is not formally binding on CFTC, and may represent a different perspective than that of the Commissioners or the agency itself.

U.S. coal production declined again in 2019

Monday, August 3, 2020

Recently released federal data shows that U.S. coal production (mining) peaked in 2008, and has declined significantly since then. 2019 U.S. total annual coal production was 706 million short tons, a 7% reduction relative to 2018. According to the U.S. Energy Information Administration, 2019's level of domestic coal production was the lowest since 1978.

Federal coal production data illustrates the recent history of this energy commodity. After modest production declines in the 1950s, total annual U.S. coal production grew steadily decade after decade from about 1963 to 2008. This overall growth curve was marked by minor deviations, such as in 1978 when most coal mining was shut down for several months due to a labor strike by coal miners, but coal's general trend was up for the latter half of the twentieth century and into the present millennium.

But since 2008, U.S. coal production has declined significantly. While some years have shown minor increases in production, most years between 2008 and 2016 were marked by significant decreases in production, and the overall trend has been sharply down.

Source: U.S. Energy Information Administration, Annual Coal Report


According to EIA, its weekly coal production estimates for 2020 suggest continued steep decreases this year, with the agency projecting output "falling to production levels comparable with those in the 1960s." These estimates are based on EIA's coal railcar loading data, which so far show a 2020 year-to-date decline of 27% relative to 2019.

EIA attributes the ongoing decline in U.S. coal production to "less demand for coal internationally and less generation from U.S. coal-fired power plants." U.S. coal exports in the first five months of 2020 were 29% below the comparable period in 2019. Meanwhile, U.S.coal-fired electricity generation declined about 16% in 2019 year-over-year to reach a 42-year low, and EIA data shows coal-fired generation has fallen another 34% through May 2020.

Coal's decline comes at the same time as significant growth in renewable resources. United States consumers used more energy from renewable sources than from coal in 2019, the first time that national renewable energy use has exceeded coal since at least 1885. Some regions, such as New England, have effectively ended coal use for electric power generation (coal provided just 0.1% of ISO New England system power in 2019).

Going forward, EIA projects U.S. coal production for the whole year will be about 29% below 2019 levels: a reduction in coal production of over one-quarter. EIA thinks coal production may rebound by 7% in 2021 "when rising natural gas prices may cause some coal-fired electric power plants to become more economical to dispatch".

FERC dismisses petition challenging state net metering

Thursday, July 16, 2020

U.S. electricity regulators have dismissed a petition that sought to invalidate state net metering programs, under which consumers can use their own generation to offset their electricity purchases. The petition had caused legal uncertainty regarding the rate treatment of solar facilities and other net metered projects by the petition, but its dismissal by the Federal Energy Regulatory Commission leaves state-law net metering intact.

The New England Ratepayers Association, or NERA -- a conservative advocacy group which Politico.com has called "shadowy" -- filed a petition on April 14, 2020 asking the Federal Energy Regulatory Commission to issue a declaratory order that (1) there is exclusive federal jurisdiction over wholesale energy sales from generation sources located on the customer side of the retail meter, and (2) the rates for such sales must be priced in accordance with federal law. According to NERA, these circumstances represent “wholesale sales in interstate commerce” which must either be priced at the utility’s avoided cost of energy (if the sale is being made pursuant to the federal law known as PURPA) or pursuant to a just and reasonable wholesale rate (if the sale is pursuant to Section 205 of the Federal Power Act).

These issues are not novel and have been repeatedly litigated in federal and state forums. Hundreds of interested persons filed comments or protests, asking the Commission to deny NERA's petition. The Preti Flaherty team filed a protest on behalf of our client New England Small Hydro Coalition, arguing that the Commission has the discretion not to rule on the questions NERA posed, and that indeed it should not grant the petition because the validity of state-law net metering is well-settled under prior Commission rulings including the orders known as MidAmerican and SunEdison:

On July 16, the Commission issued a unanimous order dismissing the petition:
We find that the issues presented in the Petition do not warrant a generic statement from the Commission at this time. Therefore, we exercise our discretion to decline to address the issues set forth in the Petition, and, accordingly, we dismiss the Petition.
In reaching this conclusion, the Commission noted comments by New England Small Hydro Coalition and others requesting the Commission to dismiss the petition for a variety of procedural grounds, including the fact "that Commission’s net metering precedent is sound and there is no controversy or uncertainty to resolve." The Commission continued:
The Petition … does not identify a specific controversy or harm that the Commission should address in a declaratory order to terminate a controversy or to remove uncertainty. In contrast, MidAmerican and SunEdison related to the implementation of specific net metering programs or the participation in such programs by specific parties. For this separate reason as well, we decline to issue the requested order.
Commissioners McNamee and Danly each issued separate concurrences to the unanimous order dismissing NERA's petition. Commissioner McNamee emphasized that the order "is not a decision on whether the Commission lacks jurisdiction over the energy sales made through net metering; nor is it a decision on the merits of the issues raised by and contained in the Petition." He expressed his general philosophy, similar to that raised by New England Small Hydro Coalition, that "it is best to decide important legal and jurisdictional questions, like the ones raised in in the Petition, when applying the law to a specific set of facts, such as in a Section 206 complaint, or through a rulemaking proceeding."

Commissioner Danly supported the decision on the grounds that the Commission has discretion to do so, but separately expressed concerns about the consequences of dismissing the petition on procedural grounds. He noted "difficult legal questions regarding the regulatory treatment of facilities (like rooftop solar) used by retail customers primarily, but not exclusively, to serve their own electricity requirements. These questions not only include the rate treatment for excess generation but, more importantly, the boundary between federal and state jurisdiction to address such rate treatment." Given the importance of these issues, he expressed concern:
I am concerned that dismissing the petition on procedural grounds may well result in a patchwork quilt of conflicting decisions if the questions raised in the petition are instead presented to federal district courts across the country. While the federal courts are more than capable of adjudicating preemption claims, they are not steeped in the history of the Federal Power Act nor in matters of national energy policy. Confusion, delay and inconsistent rules—some of which will apply to individual states or parts of states—will be the inevitable result.
Unless NERA seeks reconsideration, rehearing, or appeal, this phase of its campaign against net metering will end with the Commission's dismissal of its petition.

Maine PUC opens net metering inquiry

Monday, July 6, 2020

Maine is approaching or has passed a net metering milestone, as state utility regulators have opened an inquiry triggered by a statute calling for an evaluation when the total amount of generation capacity involved in net energy billing in Maine reaches 10% of the state's transmission and distribution utilities' total maximum electric load.

In 2019, the Maine state legislature enacted a law that substantially reformed Maine's net energy billing (NEB) programs. Major changes included allowing larger projects to participate (less than 5 megawatts, up from 660 kilowatts); removing any limit on the number of meters or accounts that can be associated with an eligible facility; replacing an ownership requirement with a more flexible “financial interest” requirement; and adopting an additional alternative “commercial and institutional” NEB program providing monetary bill credits instead of volumetric bill credits. These changes, in addition to other enactments and broader dynamics in energy markets, have led to a significant increase in interest in Maine net metering.

The 2019 law also included a requirement that the Maine Public Utilities Commission evaluate net energy billing "when the total amount of generation capacity involved in net energy billing in the State reaches 10% of the total maximum load of transmission and distribution utilities in the State or 3 years after the effective date of this Act, whichever comes first." The law requires the Commission to evaluate the effectiveness of net energy billing in achieving state policy goals and providing benefits to ratepayers, and to report its findings to the legislative energy committee.

On May 20, 2020, Maine's largest investor-owned transmission and distribution utility, Central Maine Power Company (CMP), provided notice that, at that time, the cumulative capacity of the generating facilities for which CMP has executed NEB arrangements under Chapter 313 was approximately 10.1% of CMP’s annual peak demand.

In response, on July 6, the Commission issued a Notice of Inquiry to obtain information for an evaluation of the state's NEB programs. The Notice emphasizes that the Commission itself will not alter NEB as a direct result of the Inquiry, but rather that any changes would come from the Legislature:
At the outset, the Commission emphasizes that CMP's 10% notification and the initiation of this Inquiry to gather relevant information for the required evaluation does not implicate any suspension of the programs governed by the existing NEB rules (Chapter 313) which, as noted above, have been authorized by the Act. Any changes to these programs, including to their availability, can only occur through the legislative process. 
The Notice directs Maine's two investor-owned utilities, CMP and Versant Power, to provide a monthly report on NEB projects, categorized in various ways, including by status (operational, non-operational but NEB-agreement-executed, or application-pending), and by program (kWh or monetary). For each project, each utility must provide specific information, including contact person, project location and size, resource type, new vs. previously existing, in-service date, “For NEB kWh Credit projects, estimated lost revenue ($/year)”, “For Tariff Rate projects, estimated costs (gross and net) of the credits ($/year)”, “Estimated incremental administrative costs associated with each of the two programs, by category ($/year)”, and “Information about T&D system benefits, e.g., avoided distribution upgrades, or system costs, e.g., required system reinforcements associated with NEB projects”.

Retail net metering programs such as Maine's forms of net energy billing have been adopted by regulators and utilities in nearly every U.S. jurisdiction. Utilities traditionally argue that net metering imposes costs on the system or on ratepayers. Some net metering proponents have historically countered that net metering provides substantial benefits to the system and to ratepayers, and that any theoretical downsides are nonexistent or minimal at low levels of net metering penetration, while others have argued that the system can safely and reliable handle larger amounts of net metering on the system.

Crypto miner seeks to export US electricity for Canadian servers

Friday, June 26, 2020

In what has been called "a maiden effort by an energy-hungry cryptocurrency-mining industry to import electricity from the United States to Canada to meet its significant power demands", a Canadian company has applied to the U.S. Department of Energy for authority to export power from the U.S. into Canada to power blockchain-related computer servers -- but a nonprofit advocacy group has warned that federal approval of this "first-ever application to export power by a cryptocurrency miner" may result in a rush of similar applications.

Under U.S. federal law, the Department of Energy regulates exports of electricity from the United States to a foreign country, which require authorization under section 202(e) of the Federal Power Act. On May 21, 2020, DMG Blockchain Solutions Inc. filed an application with the U.S. Department of Energy, seeking authority under the Federal Power Act to transmit electric energy from the United States to Canada for a term of five years.

According to the website dmgblockchain.com, "DMG is a diversified cryptocurrency and blockchain platform company that is focused on the two primary opportunities in the sector – mining public blockchains and applying permissioned blockchain technology. DMG focuses on mining bitcoin, providing hosting services for industrial mining clients, earning revenues from block rewards and transaction fees, developing data analytics and forensic software products, working with auditors, law firms, and law enforcement to provide technical expertise, DMG’s permissioned blockchain technology is focused on developing enterprise software for the supply chain management of controlled products."

DMG's application to the Department of Energy describes the company as "a consumer of power, whose primary business is to host servers whose primary function is to ensure the security of public blockchains as well as other high-performance computing applications." DMG's application notes, "This business requires large amounts of power, which DMG is currently consuming approximately 15 megawatts on a steady load basis and has plans to grow to up to 60 megawatts in the next year with potentially larger amounts in the future as DMG may add new facilities." The application requests DOE export authorization over any of a long list of cross-border transmission facilities with Presidential Permits, in states including Maine, Vermont, New York, Pennsylvania, Michigan, Minnesota, North Dakota, Montana, and Washington.

But at least one entity has weighed in to urge the Department of Energy to proceed with caution, as it considers this request to export electricity to power foreign blockchain servers and computers. A Motion to Intervene and Comment filed with the Department of Energy on June 25, 2020, by watchdog organization Public Citizen, Inc. frames that organization's concern:
Despite cryptocurrency mining’s status as a relatively immature industry, its alarming power consumption footprint raises concerns about its sustainability and suitability in localized power markets, resulting in moratoria on new cryptocurrency mining operations issued by select U.S. utility districts and government agencies.
Citing language in Section 202(e) of the Federal Power Act requiring applications to export electricity to neither “impair the sufficiency of electric supply within the United States” nor “impede the coordination in the public interest of facilities subject to the jurisdiction of the Commission", Public Citizen commented:
Cryptocurrency mining is extraordinarily energy-intensive and can lead to major strains on local U.S. power supplies. At the same time, the process of mining is designed in a manner that wastes the overwhelming majority of the energy it consumes. U.S. cryptocurrency miners are struggling to meet their own power demands. This appears to be the first-ever application to export power by a cryptocurrency miner, and approval may result in a rush of similar applications.
Public Citizen's comments assert that this "maiden effort by an energy-hungry cryptocurrency-mining industry to import electricity from the United States to Canada to meet its significant power demands... raises serious, potentially fatal concerns under section 202(e)." Public Citizen concludes that the Department should proceed with extreme caution and "likely should deny the application or, if granting it, place conditions on it."

The pending export authorization proceeding before the U.S. Department of Energy is OE Docket No. EA-482, DMG Blockchain Solutions Inc. Application To Export Electric Energy.

FERC cybersecurity incentives staff white paper

Friday, June 19, 2020

U.S. electricity regulatory staff have issued a “white paper” report discussing a potential new framework for providing transmission incentives to utilities for cybersecurity investments, under federal law. According to the Cybersecurity Incentives Policy White Paper issued by the staff of the Federal Regulatory Commission on June 18, 2020, existing transmission incentives and Critical Infrastructure Protection (CIP) Reliability Standards are sufficient to maintain an adequate level of reliability – but staff suggests that additional “transmission incentives to counter the evolving and increasing threats to the cybersecurity of the electric grid may be warranted.”After summarizing the background history of federal regulation of electric utility cybersecurity, the staff paper presents a “new framework for providing transmission incentives to utilities for cybersecurity investments that produce significant cybersecurity benefits for actions taken that exceed the requirements of the [CIP Reliability Standards].”

The staff paper opens with an overview of staff’s perception of cybersecurity threats to the Commission-jurisdictional Bulk Electric System (BES), along with the work of the Commission and electric reliability organization NERC to adopt and enforce mandatory CIP Reliability Standards pursuant to the Energy Policy Act of 2005. The initial CIP Reliability Standards were approved by the Commission in 2008, and they have been modified several times to address new technologies and “the evolving nature of cyber-related threats to the bulk power system.”

According to the staff paper, as of mid-June 2020, the CIP Reliability Standards “consist of 13 standards specifying a set of requirements that registered entities must follow to ensure the cyber and physical security of the bulk power system” including 10 active cybersecurity standards, 1 active physical security standard, and two cybersecurity standards which will take effect in the near future.

The report next addresses “why there is a need to adopt a new approach to incentivize cybersecurity investments.” According to the white paper, “While the CIP Reliability Standards form an effective technical baseline for cybersecurity practices, they have certain limitations.” According to staff, the standards do not necessarily require covered entities to adopt best practices, and the process through which mandatory standards are developed is poorly suited to agile action in response to emerging or evolving needs.
For these reasons, this staff paper discusses augmenting the current CIP Reliability Standards under FPA section 215 with an incentive-based approach under FPA section 219 that encourages utilities to undertake cybersecurity investments on a voluntary basis. This approach would incentivize a utility to adopt best practices to protect its own transmission system as well as improve the security of the BES. Further, it could allow the industry to be more agile in monitoring and responding to new and (un)anticipated cybersecurity threats, to identify and respond to a wider range of threats, and to address threats with comprehensive and more effective solutions. An incentive-based approach allows a utility to tailor its request for incentives to the potential challenges and responsive actions that it faces. In the future, these voluntary actions taken by utilities, if proven beneficial, could be the basis of future CIP Reliability Standards that are mandatory.
As noted by staff, if the Commission wants to provide transmission incentives for cybersecurity investments, the Commission may need to “establish a new framework for evaluating requests for transmission incentives by utilities for cybersecurity investments.” Staff suggests that “a first necessary step is to establish approaches that examine the effectiveness of cybersecurity investments in enabling the utility to achieve a level of protection that exceeds the CIP Reliability Standards but also enhances the security of its transmission system.”

According to the whitepaper, this kind of evaluation will enable utilities to “identify the cybersecurity investments for which it seeks transmission incentives” and the Commission to “evaluate such transmission incentive requests”. In the whitepaper, staff discusses traditional ratemaking incentives available to transmission projects, and how the Commission could apply these incentives in the context of cybersecurity; two possible ways to evaluate which cybersecurity investments warrant incentives; and a proposed process for utilities to apply for cybersecurity incentives.

Staff invited interested parties to file comments on the staff paper and on 11 sets of specific questions it identifies, with comments due within 60 days of the paper’s issuance and reply comments due within 75 days of its issuance.