2019 in review

Tuesday, December 31, 2019

Here's a roundup of some of the items published on this blog in 2019 that have drawn significant interest:
Will these trends continue in 2020?

2019 FERC staff report on demand response, advanced metering

Monday, December 16, 2019

Wholesale demand response programs -- which generally pay electricity consumers for reducing their consumption of power during times of high demand on the grid if doing so is cost-effective -- experienced increased participation in the U.S. in 2018, according to a recent federal report, but participating capacity in New England fell by nearly half from 2017 to 2018.

Section 1252(e)(3) of Energy Policy Act of 2005 requires the Federal Energy Regulatory Commission to prepare and publish an annual report covering six sets of items:
  • saturation and penetration rate of advanced meters and communications technologies, devices and systems;
  • existing demand response programs and time-based rate programs;
  • the annual resource contribution of demand resources;
  • the potential for demand response as a quantifiable, reliable resource for regional planning purposes;
  • steps taken to ensure that, in regional transmission planning and operations, demand resources are provided equitable treatment as a quantifiable, reliable resource relative to the resource obligations of any load - serving entity, transmission provider, or transmitting party; and
  • regulatory barriers to improved customer participation in demand response, peak reduction and critical period pricing programs.

Commission staff's report, 2019 Assessment of Demand Response and Advanced Metering, presents an updated look at these topics. As with previous reports such as in 2011, the 2019 report notes a  continued increase in advanced meter penetration rates, with advanced meters now account for most meters installed in the U.S.

According to the 2019 report, overall demand response participation in the wholesale markets increased by approximately eight percent from 2017 to 2018, to a total of 29,674 megawatts, with the greatest regional increases in California ISO (CAISO) and Midcontinent Independent System Operator (MISO). Overall, demand response registration in the wholesale capacity, energy, and ancillary services markets increased to six percent of peak demand in 2018.

At the same time, participation decreased most in ISO New England, declining from 684 megawatts of enrolled demand response capacity in 2017, to 356 megawatts. According to the report:
ISO-NE reported the greatest percentage change in demand resource participation, a 48 percent decrease, from 2017 to 2018. The reason for the decrease in demand resource participation in ISO-NE is unclear. However, the decrease coincides with the implementation of ISO-NE’s Pay-for-Performance program, which places more stringent requirements on resources – including demand resources – participating in ISO-NE’s forward capacity market. Pay-for-Performance was introduced concurrently with the full integration of demand response into ISO-NE’s price-responsive demand program in June 2018, which replaced the real-time demand response program.
While the FERC staff's 2019 report on demand response and advanced metering does not contain policy recommendations or conclusions, the data it presents informs future decisions about energy policy.

New England prepares for competitive transmission solicitation

Thursday, December 12, 2019

U.S. utility regulators have accepted another round of "transmission planning improvement" tariff revisions proposed by New England's regional transmission organization as a measure to enhance the competitiveness of a new process for soliciting proposals for certain transmission improvements. The Federal Energy Regulatory Commission's December 10, 2019 Order Accepting Tariff Revisions filed by ISO New England Inc. brings the region one step closer to its first competitive solicitation for transmission solutions.

New England's path to regional competitive procurement of transmission solutions has been lengthy. In 2001, the Federal Energy Regulatory Commission issued its Order No. 1000, which reformed how public utilities plan and pay for transmission upgrades. Much of the impetus behind Order No. 1000 ultimately derives from shifts in the nation's portfolio of electric generation resources, which helped spur transmission development, but not always in the most cost-effective ways. As a result, the Commission directed public utility transmission providers to revise their tariffs in certain ways with respect to electric transmission planning and cost allocation requirements.

One of the revisions called for in Order No. 1000 is the removal of "provisions from Commission-jurisdictional tariffs and agreements that grant incumbent transmission providers a federal right of first refusal to construct transmission facilities selected in a regional transmission plan for purposes of cost allocation." As described by the Commission, this reform "allows, but does not require, public utility transmission providers in a transmission planning region to use competitive bidding to solicit transmission projects or project developers."

New England's regional grid operator ISO New England Inc. filed a series of tariff revisions implementing changes in response to Order No. 1000, as did other public utility transmission providers. Other regional transmission organizations have subsequently conducted a number of competitive transmission solicitations under the processes created by these tariff revisions. To date ISO-NE has not, but in July 2019 the grid operator gave notice of its intent to initiate the region's first competitive procurement of transmission for the Boston area, and in October it filed further proposed tariff revisions to enhance the competitiveness of the procurement process.

In a December 10 order, the Commission has accepted the October 2019 tariff revisions. In so doing, it found that comments and a protest by the Massachusetts and Connecticut Attorney Generals (respectively) regarding the role of non-transmission alternatives (NTA) in ISO-NE's competitive solicitation process were "outside the scope of this proceeding".

The order paves the way forward for New England's first competitive solicitation of transmission, scheduled for initiation later this year or early in 2020.

Maine Executive Order 13 on sustainability

Saturday, December 7, 2019

Maine Governor Janet T. Mills has issued an executive order calling for state agencies to "lead by example through energy efficiency, renewable energy and sustainability measures." Signed on November 26, 2019, her Executive Order 13 sets a state policy goal and directs state agencies to take various actions addressing sustainability.

The preamble to Executive Order 13 cites context including the negative impacts of climate change on Maine; Maine's pledges to be carbon neutral by 2045 and to reduce greenhouse gas emissions 45% below 1990 levels by 2030 and by at least 80% by 2050; Maine's expanded renewable portfolio standard which now requires 80% renewable energy by 2030 and a goal of 100% by 2050; opportunities for beneficial electrification of heating and transportation; and the work of the newly formed Maine Climate Council. It concludes with the philosophy that "state government should lead by example and invest in renewable energy, increase energy efficiency and resiliency, encourage waste reduction, and strive to reduce operational costs."

Operationally, Executive Order 13 contains seven core sections. Section 1 establishes a state policy goal:
Maine state government will lead by example in investing in energy efficiency, renewable energy, and emissions reductions; promoting health and sustainability in the workplace; and building resilient infrastructure. State government operations will strive to equal or exceed Maine's emissions reduction targets and seek cost efficiencies. State facilities will be designed with greater resilience to new climate conditions. These efforts aim to reduce waste, promote employee health and increase operational efficiency.
Section 2 calls for the Governor's Energy Office and the Governor's Office of Policy Innovation and the Future to convene a Sustainability Leadership Committee with representatives from the Department of Environmental Protection, Efficiency Maine Trust, Department of Administrative and Financial Services, and Department of Transportation, to develop a baseline of energy use and greenhouse gas emissions from state operations by February 1, 2021, and for subsequent biannual reporting.

Section 3 requires state agencies to by February 1, 2021 coordinate with the Leadership Committee to develop and implement a sustainability plan to meet or exceed the state's renewable energy and greenhouse gas reduction timelines and targets.

Section 4 focuses on responsible procurement, requiring state agencies to "reduce their impact on the environment and enhance public health by procuring environmentally preferable products and services whenever such products and services are readily available, perform to satisfactory standards, and represent best value to the State of Maine."

Other sections require state agencies to encourage practices that lead to healthier and less wasteful workplaces; to promote the resiliency of new state facilities, other construction projects, and leased space; and to designate a state sustainability coordinator to facilitate and support activities across agencies.

Maine municipal street lighting inquiry opened

Monday, November 25, 2019

Maine utility regulators have opened an inquiry into issues related to municipal ownership of street lighting. The case could reshape the rights and responsibilities of Maine cities and towns with respect to municipally owned street lighting.

In 2013, the Maine Legislature enacted An Act to Reduce Energy Costs, Increase Energy Efficiency, Promote Electric System Reliability and Protect the Environment. Part E of the Act required that Maine's transmission and distribution (T&D) utilities must provide options to municipalities to purchase street and area lighting from the T&D utilities. In 2015, the Maine Public Utilities Commission issued an order directing the state's two investor-owned T&D utilities to file rate schedules and Terms and Conditions consistent with the law, and directed the utilities to work with a group of municipalities interested in street lighting issues to develop standard form agreements to be used when municipalities choose to purchase street lighting equipment from the utilities.

Earlier this year, utility Central Maine Power Co. proposed revisions to its municipal street lighting terms and conditions. CMP said its intent was to clarify that the maintenance obligations for underground equipment used to feed street lights does not change once a municipality takes ownership of any street lights that are fed by such underground equipment. Various municipalities opposed CMP's proposed revisions. CMP ultimately withdrew its proposed revisions, and asked the Commission to convene a meeting of a working group established by the Commission in 2015.

On November 22, 2019, the Commission issued a Notice of Inquiry into municipal street lighting issues, docketed as 2019-00315. The Commission says the inquiry "will examine issues related to municipal ownership of street lights in both the CMP and Emera Maine territories." The Commission requested comments from municipalities, interested persons, and the utilities on the following topics by Friday, December 13, 2019:
  1. Appropriate responsibilities of the municipalities and the utilities for performing maintenance, and appropriate allocation of associated costs, particularly those applicable to underground equipment;
  2. Street light safety issues, including compliance with safety standards; and
  3. Any other issues the parties would like the Inquiry to address.
Following receipt of comments, the Commission says it will schedule a conference to discuss the issues raised.

FERC accepts ISO-NE Order 841 storage compliance filing

Friday, November 22, 2019

U.S. utility regulators have issued an order largely accepting ISO New England Inc.'s revisions to its electricity market tariff as compliant with Order No. 841, designed to remove barriers to the participation of electric storage resources in the capacity, energy, and ancillary service markets operated by Regional Transmission Organizations and Independent System Operators (RTO/ISO markets).

In 2018, the Federal Energy Regulatory Commission issued its Order No. 841, requiring each organized power market to revise its tariff to establish a "participation model" for electric storage resources in the capacity, energy and ancillary service markets. Order No. 841 requires each market's participation model to include market rules that recognize the physical and operational characteristics of electric storage resources and facilitate their participation in those markets. The Commission later affirmed the rule, through its Order No. 841-A, and in October 2019 issued orders accepting the first round of compliance filings by Southwest Power Pool, Inc. and by PJM Interconnection.

For New England, ISO-NE submitted its proposed compliance filing on Order No. 841 on December 3, 2018, citing preexisting tariff provisions governing markets, services and resources; a number of market rule revisions that ISO-NE and NEPOOL jointly filed on October 10, 2018; and "limited additional Tariff revisions needed for full compliance with Order No. 841" including allowing any qualifying technology type to participate as a Binary Storage Facility, allowing electric storage resources as small as 0.1 megawatts to provide energy, reserves, and regulation; and eliminating the allocation of transmission charges to electric storage resources in certain circumstances.

On November 22, 2019, the Commission accepted ISO-NE’s Compliance Filing, to become effective December 3, 2019, with a limited number of revisions to become effective on December 1, 2019, and January 1, 2024, subject to a further compliance filing.

Maine PUC adopts RPS rule reforms

Friday, November 8, 2019

The Maine Public Utilities Commission has adopted an updated rule governing the state's electric renewable portfolio standards, following the enactment of a law that significantly expanded the renewable mandate.

During its 2019 session, the Maine State Legislature enacted a variety of laws designed to address climate change and promote renewable resources. These laws included a significant expansion of Maine's renewable portfolio standards, which generally require retail electricity suppliers to demonstrate that defined portions of the power they sell came from renewable resources by obtaining credits known as RECs. As amended, Maine law now contemplates four separate renewable portfolio standards -- the preexisting 30% Class II and 10% Class I standards, plus the newly enacted Class IA and thermal standards. The new Class IA requirement increases from 2.5% of retail sales in 2020 to 40% in 2030; the thermal REC mandate increases from 0.4% in 2021 to 4% in 2030.

The law required the Commission to adopt rules implementing the new standards. In August 2019, the Commission issued its notice of rulemaking, proposing to amend its rule Chapter 311 governing the renewable portfolio standards, along with a draft revised rule. After receiving public comment, the Commission deliberated on November 8, 2019 and issued an order adopting the final rule. Issues addressed in the final rule include a process through which most Class I resources may also qualify as Class IA resources, and setting the alternative compliance payment rate at the maximum $50 level.

The 2019 RPS reform law also requires the Commission to conduct a series of solicitations to procure long-term contracts for an annual amount of energy or RECs from Class IA resources equal to 14% of Maine’s annual retail electricity sales, with contracts from the first procurement round to be approved no later than December 31, 2020. Separately, the Legislature also enacted laws expanding net metering and creating utility procurement programs for distributed generation.

U.S. withdrawal from Paris Agreement climate treaty

Tuesday, November 5, 2019

Following up on President Trump's 2017 statement that the United States would withdraw from the 2015 Paris Agreement on climate change, this week the U.S. began the formal process of withdrawal from the international climate accord.

On December 12, 2015, the Parties to the United Nations Framework Convention on Climate Change adopted Decision 1/CP.21, adopting the Paris Agreement under that convention. The Paris Agreement requires all signatory nations "to undertake and communicate ambitious efforts" as "nationally determined contributions to the global response to climate change." In 2016, the United States and other nations signed the agreement and became parties, for a total of 195 signatory nations as of mid-2017.

But on June 1, 2017, U.S. President Donald J. Trump announced that the country would withdraw from the Paris Agreement. Under Article 28 of the Paris Agreement, a signatory may withdraw from the agreement one year after sending a withdrawal notification to the depositary, but can only give notice at least three years after joining. On August 4, 2019, the U.S. representative to the United Nations gave official notice that "that the United States intends to exercise its right to withdraw from the Agreement... as soon as it is eligible to do so."

This withdrawal process formally began on November 4, 2019, with an official notice that withdrawal shall take effect for the United States of America on November 4, 2020, the earliest date possible for withdrawal under the Agreement.

As described in a contemporaneous press statement from Secretary of State Mike Pompeo, "On the U.S. Withdrawal from the Paris Agreement", "President Trump made the decision to withdraw from the Paris Agreement because of the unfair economic burden imposed on American workers, businesses, and taxpayers by U.S. pledges made under the Agreement.  The United States has reduced all types of emissions, even as we grow our economy and ensure our citizens’ access to affordable energy.  Our results speak for themselves:  U.S. emissions of criteria air pollutants that impact human health and the environment declined by 74% between 1970 and 2018.  U.S. net greenhouse gas emissions dropped 13% from 2005-2017, even as our economy grew over 19 percent."

FERC grid resilience examination continues

Thursday, October 31, 2019

Nearly two years after opening a proceeding to evaluate the resilience of the nation's bulk power system in organized wholesale markets, the Federal Energy Regulatory Commission's evaluation of resiliency matters remains pending.

In 2017, U.S. Secretary of Energy Rick Perry directed the Commission to consider a proposed rulemaking to ensure that "traditional baseload resources, such as coal and nuclear" are rewarded for their reliability and resilience attributes. As proposed, the rule would have required grid operators to set rates for compensation paid to certain "grid reliability and resiliency resources" with a 90-day fuel supply on site and capable of providing "essential energy and ancillary reliability services, including but not limited to voltage support, frequency services, operating reserves, and reactive power."

But on January 8, 2018, the Commission terminated its consideration of the Department of Energy's proposed rulemaking, finding that "the Proposed Rule did not satisfy those clear and fundamental legal requirements under section 206" of the Federal Power Act. Instead, the Commission opened a new proceeding to take additional steps to explore resilience issues in organized wholesale electricity markets. The Commission described the goal of this proceeding as: "(1) to develop a common understanding among the Commission, industry, and others of what resilience of the bulk power system means and requires; (2) to understand how each RTO and ISO assesses resilience in its geographic footprint; and (3) to use this information to evaluate whether additional Commission action regarding resilience is appropriate at this time."

In its order, the Commission directed six regional transmission organizations and independent system operators to respond within 60 days with comments on the definition of resilience, plus how they assess and mitigate threats to resilience, and requested public comment within 30 days of the grid operators' due date. In March 2018, the Commission extended the deadline to allow stakeholders to develop and file comments creating "a robust record and as much relevant information and thoughtful input as possible". The Commission has since received over 200 motions to intervene, comments, and other filing in the docket.

Meanwhile, the Foundation for Resilient Societies filed a timely request for rehearing of the Commission's order terminating the rulemaking proceeding regarding the Department of Energy's proposed rule, in response to which the Commission granted rehearing for further consideration.

In its January 2018 order opening the proceeding, the Commission said it would review the additional information requested from each RTO and ISO, and that it expected to "promptly decide whether additional Commission action is warranted to address grid resilience." In a separate concurring statement, Commissioner Glick expressed full support for the initiation of the new resilience examination proceeding, concluding, "If the RTOs and ISOs demonstrate that the resilience of the bulk power system is threatened we should act. If not, we should move on."

As of October 29, 2019, the resiliency proceeding remains pending before the Federal Energy Regulatory Commission, as does the rehearing request.

Massachusetts gas regulator opens Merrimack Valley investigations

Monday, October 28, 2019

Following a 2018 Massachusetts natural gas incident resulting from the overpressurization of gas distribution lines owned by utility Bay State Gas Company d/b/a Columbia Gas of Massachusetts, state utility regulators have opened a pair of investigations into the utility's responsibility for and response to the incident, as well as into its efforts to prepare for and restore service following the event.

As summarized by the Massachusetts Department of Public Utilities, on September 13, 2018, Bay State’s low-pressure natural gas distribution system serving the city of Lawrence and the towns of Andover and North Andover in the Merrimack Valley became overpressurized, allowing high-pressure gas to enter the low-pressure distribution system, which "resulted in the damage or destruction of 131 homes and businesses, the hospitalization of 22 individuals, and the death of one person".

The incident prompted a variety of investigations, including a federal probe by the National Transportation Safety Board which determined "that the probable cause of the overpressurization of the natural gas distribution system and the resulting fires and explosions was Columbia Gas of Massachusetts’ weak engineering management that did not adequately plan, review, sequence, and oversee the construction project that led to the abandonment of a cast iron main without first relocating regulator sensing lines to the new polyethylene main. Contributing to the accident was a low-pressure natural gas distribution system designed and operated without adequate overpressure protection." NTSB adopted its Pipeline Accident Report on the incident on September 24, 2019, and the report became final therafter.

Acting one day after NTSB's report became final, Massachusetts utility regulators have now initiated a pair of further investigations. In one docket, D.P.U. 19-140, the Department opened a "public investigation into Bay State’s responsibility for and response to the September 13, 2018 overpressurization incident, as well as its restoration efforts following the incident." The Department said this investigation will focus on Bay State’s compliance with federal minimum safety regulations and with the Department’s own state-level pipeline safety regulations.

In a separate docket, D.P.U. 19-141, the Department opened an "investigation into efforts by Bay Stateto prepare for and restore service following the September 13 Event", including its preparation for the incident and the utility's implementation of its emergency response plan (“ERP”). The Department said its inquiry will focus on Bay State’s compliance with the Department’s performance standards for emergency preparedness and restoration of service, including "(1) preparation for and management of the restoration efforts, including safe and reasonably prompt restoration; (2) public safety; (3) allocation of resources to affected municipalities; (4) timely and accurate communication with state, municipal, and public safety officials and with the Department; (5) dissemination of timely information to the public; and (6) identification of restoration practices that require improvement, if any."

In each docket, the Department said it would separately issue an order defining the procedures and opportunities for public participation in the investigation. According to a Department press release accompanying the orders, based on its findings, "DPU could impose multimillion-dollar financial penalties and take additional steps to improve the overall safety and reliability of the gas pipeline system."

FERC issues mine pumped storage guidance, list of potential projects

Friday, October 25, 2019

Implementing a 2018 federal law designed to facilitate the development of new facilities capable of storing electric energy, U.S. regulators have issued guidance to assist applicants for licenses or preliminary permits for closed-loop pumped storage projects at abandoned mine sites. The Federal Energy Regulatory Commission also issued a list of existing non-powered federal dams that the Commission and other agencies agree have the greatest potential for non-federal hydropower development.

A pumped storage facility can consume electricity to pump water from a lower reservoir to an upper reservoir, from which the water can flow back down through turbines to recover most of the stored energy. In a closed-loop configuration, the reservoirs are constructed features (such as surface mine pits or underground mines), rather than natural waterways, lakes, or wetlands. While battery storage capacity is increasing rapidly, pumped storage represents the vast bulk of U.S. electricity storage capacity, with about 40 projects contributing about 22 gigawatts of capacity.

In 2018, President Trump signed the America's Water Infrastructure Act of 2018 into law. The law amended several portions of the Federal Power Act which govern how the Federal Energy Regulatory Commission issues preliminary permits and licenses for hydropower projects. It also contained specific provisions requiring the Commission to establish expedited processes for issuing and amending licenses for qualifying facilities at existing nonpowered dams as well as for closed-loop pumped storage projects.

Based on the potential for development of abandoned mine sites into pumped hydropower storage facilities, the law also required the Commission to hold a workshop to explore potential opportunities for development of closed-loop pumped storage projects at abandoned mine sites, and to issue guidance within one year to assist applicants for licenses or preliminary permits for closed-loop pumped storage projects at abandoned mine sites.

On October 17, 2019, the Commission issued its Guidance for Applicants Seeking Licenses or Preliminary Permits for Closed-Loop Pumped Storage Projects at Abandoned Mine Sites, in Docket No. AD19-8-000. This 49-page document provides basic information on pumped storage, abandoned mines in the U.S. (of which there are as many as 500,000), and licenses and preliminary permits for closed-loop pumped storage projects at abandoned mine sites. It also reviews best practices and considerations, including typical environmental issues, site selection considerations, and regulatory processes.

Separately, the Commission also issued a list of 230 non-powered federal dams, sorted by potential capacity, identified by the Commission and the Secretaries of the Departments of the Army, the Interior, and Agriculture as having the greatest potential for non-federal hydropower development. Facilities included on the list range from the Melvin Price Locks & Dam on the Mississippi River (listed as having 299.3 megawatts of potential capacity), down to dozens of dams with less than 2 megawatts of potential.

Interior Department policy statement on OCS workplace safety jurisdiction

Thursday, October 24, 2019

The United States Department of the Interior has published a policy statement clarifying that the Interior Department -- and not OSHA -- will will act as the principal federal agency for the regulation and enforcement of safety and health requirements for renewable energy facilities located in ocean waters on the Outer Continental Shelf or OCS. In an October 17 press release, the Department's Bureau of Ocean Energy Management described the policy statement as "a major milestone in advancing the renewable energy program on the OCS."

Under the federal Outer Continental Shelf Lands Act, as amended by the Energy Policy Act of 2005, the Secretary of the Interior is authorized to oversee renewable energy activities on the OCS, including issuing leases, rights-of-way, and rights-of-use and easements on the OCS for activities that produce, or that support the production, transportation, or transmission of, energy from sources other than oil and gas, not otherwise authorized by other laws. The Secretary is also authorized by statute to issue regulations; the Department interprets this authorization as extending to regulating the safety of activities conducted on renewable energy leases.

Acting under this authority, the Department has already adopted regulations that include safety-related requirements. For example, its rules require regulated entities to implement a Safety Management System (SMS) for activities conducted on renewable energy leases on the OCS, and require self-conducted and agency-conducted inspections, incident and equipment failure reporting, and give the Department enforcement tools including stop-work orders, cancellation of the lease or grant, and civil penalties. In the recent policy statement, the Department clarifies that it "will act as the principal Federal agency for the regulation and enforcement of safety and health requirements for OCS renewable energy facilities."

Crucially, the statement articulates the Department's position that its regulatory program preempts the applicability of Occupational Safety and Health Administration (OSHA) regulations, because the Department considers its regulation "to occupy the field of workplace safety and health for personnel and others on OCS renewable energy facilities". At the same time, the Department asserted that it will "collaborate and consult with OSHA on the applicability and appropriateness of workplace safety and health standards for the offshore wind industry and other offshore renewable energy industries", and "continue to collaborate with the USCG to share relevant safety and training information and promote safety on the OCS."

The public notice of the policy statement notes that it "does not apply to workplace safety and health requirements for OCS marine hydrokinetic (i.e., wave, tidal, and ocean current) energy projects, for which operational requirements are within the jurisdiction of the Federal Energy Regulatory Commission, or OCS renewable energy facility support vessels, which are under the authority of the United States Coast Guard (USCG)."

However, for offshore wind or other renewable energy facilities located on the Outer Continental Shelf, the Department's policy statement provides increased regulatory certainty as to which workplace health and safety standards apply.

FERC approves energy storage tariffs

Wednesday, October 23, 2019

U.S. utility regulators have approved the first two regional implementations of a landmark 2018 order designed to remove barriers to the participation of electricity storage in wholesale markets.

In 2018, the Federal Energy Regulatory Commission issued its Order No. 841, requiring each organized power market to revise its tariff to establish a "participation model" for electric storage resources in the capacity, energy and ancillary service markets. The rule requires each market's participation model to include market rules that recognize the physical and operational characteristics of electric storage resources and facilitate their participation in those markets. The Commission later affirmed the rule, through its Order No. 841-A.

Last week, the Commission issued two orders approving Order No. 841 compliance filings by Southwest Power Pool, Inc. and by PJM Interconnection. The Commission generally found that the SPP and PJM tariff revisions complied with the new rule, and largely accepted their filings. For example, the Commission found that both proposals "generally enable electric storage resources to provide all services they are capable of providing; allow electric storage resources to be compensated for those services in the same manner as other resources; and appropriately recognize the unique physical and operational characteristics of electric storage resources."

However, the Commission also provided directives for further compliance filings by SPP and PJM to be made within 60 days. The Commission found that while both filed tariffs generally satisfy Order No. 841’s directive allowing electric storage resources to de-rate their capacity to meet minimum run-time requirements, neither tariff included minimum run-time requirements for resource adequacy and capacity, respectively. Because "such requirements affect rates, terms and conditions of service," the Commission initiated proceedings under section 206 of the Federal Power Act to address the specific issue of minimum run-time requirements.

In a pair of separate statements (on SPP and on PJM), Commissioner McNamee concurred with the orders insofar as they found compliance with the Commission's orders and regulations. But Commissioner McNamee said, "I write separately, however, to express my continuing concern that the Commission exceeded its statutory authority under the Federal Power Act, and should have, at the very least, provided states the opportunity to opt-out of the participation model created by the Storage Orders." Commissioner McNamee also reiterated jurisdictional concerns he had previously raised in a partial concurrence to and partial dissent from Order No. 841-A, "to the extent the Commission’s Storage Orders exercised authority over the distribution system and behind-the-meter."

Other organized wholesale market operators, such as ISO New England, Inc., are also adopting tariff revisions to comply with Order No. 841, to enhance the ability of electric storage facilities to participate in regional wholesale electricity markets.

FERC staff report on cybersecurity lessons learned

Wednesday, October 16, 2019

Most of the cyber security protection processes and procedures adopted by entities subject to U.S. electric grid reliability regulation meet those reliability standards' mandatory requirements when audited, according to a recent federal report -- but recent audits also found "potential compliance infractions", as well as voluntary cybersecurity practices that could improve security.

During the Federal Energy Regulatory Commission's 2019 fiscal year, its staff conducted a series of non-public audits of a number of "registered entities" subject to the North American Electric Reliability Corporation's mandatory Critical Infrastructure Protection (CIP) standard. Staff from the Commission's Office of Electric Reliability and Office of Enforcement conducted the audits, in collaboration with staff from the North American Electric Reliability Corporation and its regional entities.

On October 4, 2019, Commission staff issued a report, "Lessons Learned from Commission-Led CIP Reliability Audits". According to a press release accompanying the report, "most of the cybersecurity protection process and procedures adopted by the entities met the mandatory requirements of the standards."

The staff report also identifies voluntary actions, learned from the report, that regulated entities and other users, owners and operators of the bulk-power system could take to improve their compliance with mandatory CIP standards and their overall cybersecurity posture. These recommendations include:
  • Considering all generation assets, regardless of ownership, when categorizing bulk electric system cyber systems associated with transmission facilities;
  • Ensuring that all employees and third-party contractors complete the required training and that the training records are properly maintained;
  • Verifying employees’ recurring authorizations for using removable media;
  • Reviewing all firewalls to ensure there are no obsolete or overly permissive firewall access control rules in use;
  • Limiting access to employee’s PIN numbers used for accessing Physical Security Perimeters using a least-privilege approach;
  • Ensuring that all ephemeral port ranges are within the Internet Assigned Numbers Authority (IANA) recommended ranges; and
  • Clearly marking Transient Cyber Assets and Removable Media. 
NERC registered entities, as well as other businesses with cyber assets, might consider these recommendations in strengthening their overall cybersecurity posture.

Massachusetts Clean Peak standard regulations proposed

Thursday, October 10, 2019

Acting under a 2018 law, Massachusetts energy regulators have proposed a Clean Peak Energy Portfolio Standard regulation that is designed to provide incentives to clean energy technologies that can supply electricity or reduce demand during seasonal peak demand periods.

Last year, the Massachusetts legislature enacted An Act to Advance Clean Energy. The law requires the state Department of Energy Resources to develop a program requiring retail electricity providers to provide a minimum percentage of kilowatt-hour sales to end-use customers in the commonwealth from "clean peak resources." This newly defined category of resources includes qualified renewable portfolio standard resources, qualified energy storage systems, or demand response resources that generate, dispatch or discharge electricity to the electric distribution system during seasonal peak periods, or alternatively, reduce load on the system. Retail suppliers would procure "clean peak certificates", similar to RECs, representing the attributes of qualified generation.

The law requires DOER to establish seasonal peak periods, defined as “the daily time windows during any of the 4 annual seasons when the net demand of electricity is the highest; provided however, that a seasonal peak shall be not less than 1 hour and no longer than 4 hours in any season, as determined by the department.” It also requires DOER to establish a metering and verification protocol, as well as a value for clean peak certificates for each megawatt hour of energy or energy reserves during the seasonal peak period, through the imposition of an alternative compliance payment rate and other possible approaches.

The law also required DOER to establish a baseline minimum percentage of kilowatt-hours sales to end-use customers that shall be met with clean peak certificates in 2019; after DOER determined that "approximately 0 MWh were being served by existing clean peak resources during peak load hours as of December 31, 2018," DOER established the Minimum Standard percentage requirement for retail electricity suppliers in the 2019 compliance year at 0%.

Following two stakeholder meetings, three public hearings, presentation of a straw proposal, and a consultant report presenting modeling of the effect of the clean peak standard market design changes, on September 20, 2019, DOER filed its proposed Clean Peak Energy Portfolio Standard regulation with the Secretary of State. DOER has requested public comment on the proposed regulation by 5:00pm, October 30, 2019.

FERC allows utility recovery of canceled nuke plant costs

Monday, October 7, 2019

U.S. regulators have allowed an electric utility serving customers in North Carolina and South Carolina to recover half of the wholesale portion of the costs of a canceled nuclear power plant through wholesale formula rates contained in 14 power purchase agreements with wholesale customers.

At issue is Duke Energy Carolinas, LLC, a vertically integrated utility with generation, transmission, and distribution facilities used to serve its retail customers. DEC also provides long-term requirements service to a number of electrical cooperatives and municipal utilities whose service territories are within the DEC balancing area.

In 2006, DEC proposed to develop the William States Lee III Nuclear Station Units 1 and 2 in Cherokee, South Carolina. In 2007, DEC applied to the Nuclear Regulatory Commission for a combined construction and operating license, which the NRC granted in 2016. The utility ultimately incurred actual costs for the project's development that exceeded $558 million. But DEC subsequently decided to cancel the project, citing circumstances outside its control which negatively impacted its ability to initiate construction, and which led DEC to conclude that it would no longer be beneficial to its customers to construct and commence operation of the Lee Nuclear Project.

With respect to state retail rates, DEC obtained approvals from both the North Carolina Utilities Commission and the Public Service Commission of South Carolina to recover certain project costs in rates, finding that (with limited exceptions) the costs DEC incurred for the development of the project were reasonable and prudent, and allowing DEC to amortize and recover each state's retail portion of those costs over a twelve-year period.

With respect to federal rates, DEC negotiated with its wholesale customers to recover half of the wholesale portion of the canceled project's costs, based on a load-ratio share, from the wholesale customers through the formula rates in their power purchase agreements. Under this approach, some customers would make a one-time payment, while others would pay over a twelve-year amortization period.

DEC then applied to the Federal Energy Regulatory Commission for approval to recovery these amounts in rates. The Commission cited its Opinion No. 295, in which it found that prudently incurred costs from a utility's investment in a nuclear unit which was canceled prior to completion should be equitably allocated between ratepayers and shareholders. It accepted DEC's filing to recover the wholesale portion of 50 percent of the $516.5 million of eligible cancelled Lee Nuclear Project costs from the wholesale customers. Noting that Commission policy generally requires recovery of these costs over the "life of the plant" (40 years for the Lee Nuclear Plant), the Commission accepted the abbreviated twelve-year amortization method.

The process highlights the challenges of planning, permitting, and developing centralized power plants, in an environment where regulatory approvals can take nearly a decade, during which time markets and technologies may have shifted so much that the project no longer makes sense. While a stranded cost or stranded asset may be more costly than the cost of a canceled project, these forces highlight how ratepayers can bear financial risks associated with utility megaprojects.

Maine executive order: carbon neutral by 2045

Tuesday, October 1, 2019

Maine shall strive to achieve a carbon neutral economy no later than 2045, according to an executive order recently signed by Governor Janet Mills.

On September 23, 2019, Governor Mills signed her Executive Order 10: An Order to Strengthen Maine’s Economy and Achieve Carbon Neutrality By 2045. The order notes the negative impacts of climate change on Maine, as well as related educational and economic opportunities in clean energy development, energy efficiency, innovation and carbon sequestration through the state’s natural resources. It cites recent state action, including the enactment of a law requiring the Department of Environmental Protection to adopt mandatory, declining, economy-wide greenhouse gas emissions limits, the creation of the Maine Climate Council, and Maine's decision to join the United States Climate Alliance.

Operationally, the executive order provides, "To further the work that is recently underway, Maine shall strive to achieve a carbon neutral economy no later than 2045." It requires the Maine Climate Council to provide recommendations required to meet these goals in its first report to be issued no later than December 1, 2020, and in every report thereafter.

The order also requires that all policies and programs undertaken to achieve carbon neutrality "be implemented in a manner that aims to grow the state’s economy, protect natural resources, and achieve positive impacts for the people of Maine."

It also requires the Maine Department of Environmental Protection to develop a framework for accounting and tracking progress on greenhouse gas reduction, and report on such progress every other year.

FERC rules NH biomass energy law preempted

Friday, September 27, 2019

U.S. energy regulators have granted a petition for a declaratory order, ruling that a recently enacted New Hampshire statute mandating a purchase price for wholesale sales by certain biomass generators in the state is preempted by federal law. The ruling casts doubt on state programs that seek to support renewable or other resources by specifying the price for wholesale sales of electric energy in interstate commerce.

At issue is the 2018 enactment of New Hampshire Senate Bill 365, which added a new Chapter 362-H to New Hampshire law. The bill expresses a legislative finding that "the continued operation of the state’s 6 independent biomass-fired electric generating plants and the state’s single renewable waste-to-energy generating plant are at-risk due to energy pricing volatility," and requires New Hampshire's major regulated electric distribution company to offer to purchase the net energy output of eligible biomass and waste-to-energy facilities located in its service territory, at a rate based on 80 percent of the retail rate for default energy service.

The bill was controversial before the Legislature for issues including whether or how these resources should be subsidized; it was ultimately enacted over the veto of Governor Sununu. In November 2018, an activist group called the New England Ratepayers Association (NERA) filed a petition to the Federal Energy Regulatory Commission seeking a declaratory judgment that the New Hampshire law is preempted by the Federal Power Act (FPA) and section 210 of the Public Utility Regulatory Policies Act of 1978 (PURPA).

Citing a 2016 Supreme Court case invalidating a Maryland state energy contracting program, NERA argued SB 365 violated the FPA by setting wholesale energy rates, which are within the Commission’s exclusive jurisdiction. Specifically, NERA claimed that New Hampshire  impermissibly established a wholesale rate in violation of the FPA by (1) requiring utilities to purchase the net output of the eligible facilities at a rate based on 80 percent of the retail rate for default energy service; and (2) after selling into the ISO New England, Inc. (ISO-NE) market at the ISO-NE market clearing price, allowing utilities to recover from ratepayers the difference between the state-established rate for the purchase and the ISO-NE real-time market clearing price. NERA also noted that New Hampshire had not invoked PURPA as a basis for setting the rates for these facilities, but that even if the legislature had invoked PURPA, SB 365 does not conform to PURPA because it does not establish an eligible facility’s rate based on the utility’s avoided costs.

In a September 19, 2019 order, the Commission granted NERA's petition. The Commission concluded that SB 365 is preempted by federal law:
SB 365 requires utilities to offer to purchase the net output of eligible biomass and waste facilities at a state-established rate. As explained below, this requirement establishes a rate for wholesale sales of electric energy in interstate commerce, which intrudes on the Commission’s exclusive jurisdiction over wholesale sales of electric energy in interstate commerce. We therefore conclude that the rate established by SB 365 is preempted by the FPA... SB 365 establishes a wholesale rate by requiring purchasing utilities to offer to purchase electricity from eligible facilities at a specific state-established rate (i.e., 80 percent of the retail default energy rate). In so doing, SB 365 “sets an interstate wholesale rate, contravening the [FPA’s] division of authority between state and federal regulators.
On PURPA matters, the Commission found that the seven generators in question are Qualifying Facilities under PURPA, and therefore focused on the issue of "whether the state-established rate in SB 365 (i.e., 80-percent-of-the-default-energy-rate) exceeds the purchasing utilities’ avoided cost." The Commission noted that the SB 365 rate is not based on the purchasing utilities’ avoided cost,
but rather is based on the state’s retail default energy rate, and that the New Hampshire Commission had found that the SB 365 rate will likely exceed the current avoided cost rate based on ISO-NE wholesale market prices. Finally, the Commission noted that nothing in SB 365 limits the rate
to a rate equal to or less than the avoided cost rate, or otherwise allows the New Hampshire Commission to limit the eligible facilities’ rate so that it would not exceed the avoided cost rate. For these reasons, the Commission found that SB 365 is also inconsistent with PURPA.

The Commission's ruling on NERA's petition for a declaratory order highlights a key tension between state policymakers seeking to pursue state goals (such as supporting renewable generators or other kinds of resources) and federal law which generally reserves to Congress and to the Commission the right to regulate the price of electric energy sold at wholesale in interstate commerce. While the Commission is considering reforms to how it implements PURPA that could give states more leeway or control over the pricing of sales by QFs, the bottom line is that despite the best intentions of state policymakers, the basic issue of federal preemption will remain a barrier to some programs.

FERC proposes PURPA rule reform

Friday, September 20, 2019

U.S. energy regulators have proposed revised regulations implementing a 40-year-old law that was designed to encourage domestic cogeneration and renewable energy production. The Federal Energy Regulatory Commission's notice of proposed rulemaking regarding its implementation of the Public Utility Regulatory Policies Act of 1978 could significantly reshape the Commission's approach to this law.

PURPA was enacted by Congress in 1978 to promote goals including energy conservation and greater production of domestic and renewable energy.  It established a new class of generating facilities called Qualifying Facilities or QFs, to receive special rate and regulatory treatment, and the Commission adopted regulations governing QFs in 1980.

But the Commission has recently noted changed circumstances since its adoption of PURPA regulations, including "sweeping changes that have taken place in the natural gas industry, and the resulting greater availability of natural gas"; improved outlook for the development of alternatives to natural gas and oil-fired resources, such as renewable resources; and the development of significant non-QF independent power production and organized competitive markets.

In light of these changed circumstances, the Commission has explored "PURPA modernization" or reform several times. For example, in 2016, the Commission held a technical conference to address PURPA implementation issues, and Commissioners have hinted at the prospect of reform in recent remarks.

Now, the Commission has issued a notice of proposed rulemaking based on a preliminary finding that its PURPA regulations should be modernized "to rebalance the approach adopted in the 1980s." Notably, the Commission describes its proposal as allowing states more flexibility in setting prices, such as the use of "competitive market forces in setting QF rates." Other changes proposed by the Commission including allowing electric utilities relief from PURPA's "must purchase" obligation to the extent their supply obligations are reduced by a state's retail choice program; making it easier for others to challenge whether multiple claimed QFs are actually part of a single development; and reducing the capacity level at which a rebuttable presumption of nondiscriminatory market access applies from 20 MW to 1 MW for small power production facilities (but not cogeneration facilities); among others proposed in the rulemaking.

Commissioner Glick issued a separate statement dissenting in part "because it would effectively gut the Public Utility Regulatory Policies Act (PURPA) ... Whether PURPA’s goals remain relevant is a decision for Congress, not an administrative agency. The Commission should not be seizing the reins from Congress in order to isolate an important debate about national energy policy within an independent regulatory agency."

Public comments are due 60 days following the notice of proposed rulemaking's publication in the Federal Register.

NERC issues cyberattack lessons learned report

Tuesday, September 17, 2019

The electric reliability organization for the U.S. has issued a white paper describing lessons learned from what has been described as the first publicly disclosed disruptive cyberattack on the U.S. power grid. The incident -- and the report -- shed light on cybersecurity vulnerabilities and how companies can protect themselves from risk.

A September 2019 report by the North American Electric Reliability Corporation describes an incident on March 5, 2019 in which a cyberattack resulted in brief communications outages between the grid control center and several remote generation sites in the western U.S. According to the report, a flaw in the attacked utility's firewalls allowed "an unauthenticated attacker" to reboot them repeatedly, effectively breaking them. The firewalls served as "perimeter devices" -- devices connected directly to the internet, which serve as an outermost security layer, and regulate data traffic flowing between the generation sites and the utility's control center. Each time the devices rebooted, operators would lose communications contact with the generation for several minutes before regaining the link.

The report suggests that the hackers appear took advantage of a known flaw in the firewall's interface:
A vulnerability in the web interface of a vendor’s firewall was exploited, allowing an unauthenticated attacker to cause unexpected reboots of the devices. This resulted in a denial of service (DoS) condition at a low-impact control center and multiple remote low-impact generation sites. These unexpected reboots resulted in brief communications outages (i.e., less than five minutes) between field devices at sites and between the sites and the control center.
The NERC Lessons Learned report contains some key recommendations: update and patch all firewalls, and have a means of monitoring vendor firewall firmware releases and their implementation. These actions are key elements of a strong cybersecurity posture.

Protecting cyber systems -- whether for the control of electric generation or other business functions -- helps eliminate downtime, reduce business interruption, limit liability and reputational risks. Consider some of the following lessons learned from the March 5th cyber-attack provided by NERC:
  • Follow good industry practices for vulnerability and patch management. Close monitoring of vendor firmware releases and their implementation is a key element of a strong cybersecurity posture. Firewall firmware updates need to be reviewed as quickly as possible after release for risk and applicability. Testing in a development (or “sandbox”) environment prior to deployment can test the patch’s potential to introduce new problems.
  • Reduce and control your attack surface. Have as few internet facing devices as possible.
  • Use virtual private networks.
  • Use access control lists (ACLs) to filter inbound traffic prior to handling by the firewall; minimize the traffic through a denial by default configuration with whitelisting for the allowed and expected IP addresses. Limit outbound traffic similarly for information security purposes.
  • Layer defenses. It is harder to penetrate a screening router, a virtual private network terminator, and a firewall in series than just a firewall (assuming the ACLs and other configurations are appropriate).
  • Segment your network. Restrict lateral communication to necessary and expected traffic to reduce the impact of a breach.
  • Know your exploitable vulnerabilities so you can pursue fixes. Maintain awareness of vulnerabilities and understanding of those in your environment through product vendor websites and user groups and third party resources, such as the National Vulnerability Database, SANS Internet Storm Center, Exploit Database, or others. Consider asking the Department of Homeland Security under the “National Cybersecurity Assessment and Technical Services (NCATS) program” (or a security vendor) to conduct external vulnerability scanning. Join the Electricity Information Sharing and Analysis Center (E-ISAC).
  • Monitor your network. System performance monitoring increases the likelihood that brief communications outages with little actual impact to generator operations will be more closely investigated. This is how this lesson learned came to be. Use tools for firewall log analysis to detect events and support post-event investigations. This will provide information about the nature of attacks and exploits used. Report attacks and suspicious activity to the E-ISAC.
  • Employ redundant solutions to provide resilience and on-line maintenance capabilities. Of the entity’s sites impacted by the firewall reboot, not all experienced communications disruptions. Following the event, it was discovered that the sites running firewalls in high-availability/redundant pair configuration maintained communications during the reboots. At sites utilizing this design, the secondary firewall maintained communications while the primary firewall rebooted. Firewall redundancy preserves functionality in the event of a single firewall failure. Firewall redundancy reduces impact of firmware updates since each firewall can be updated independently without interrupting communications during the update process.
 This post was co-authored by William Roberts of Preti Flaherty.

FERC grid-enhancing technologies workshop scheduled

Wednesday, September 11, 2019

U.S. energy regulators have scheduled a public workshop to discuss grid-enhancing technologies that increase the capacity, efficiency, or reliability of transmission facilities.

The Federal Energy Regulatory Commission has regulatory authority over various aspects of the U.S. electric power sector, including the rates and services for electric transmission in interstate commerce and electric wholesale power sales in interstate commerce.

On September 9, 2019, Commission staff issued a Notice of Workshop in a newly opened proceeding, announcing the scheduling of a staff-led workshop for November 5-6, 2019, to discuss "grid-enhancing technologies" such as (1) power flow control and transmission switching equipment, (2) storage technologies, and (3) advanced line rating management technologies. According to the notice, Commission staff is soliciting panelists to discuss how these technologies are being used in transmission planning and operations, challenges blocking their deployment and implementation, and steps the Commission can take to address regarding those challenges, including incentivizing or requiring the adoption of grid-enhancing technologies by utilities and regional transmission organizations and independent system operators.

The Commission is expected to release a more detailed agenda in advance of the November 5 and 6 workshop.

Maine distributed generation procurement rulemaking

Monday, September 9, 2019

Following the Maine legislature's enactment of a law creating a new distributed generation procurement program, state utility regulators have issued a proposed rule governing the periodic procurement of distributed renewable resources. Once finalized, the rule will define how Maine implements its new program to procure the output of 375 megawatts from at least 75 new small renewable generating projects.

Earlier this year, the Maine State Legislature enacted An Act To Promote Solar Energy Projects and Distributed Generation Resources in Maine. The act defines "distributed generation resource" as an electric generating facility that uses a renewable fuel or technology and is located in the service territory of a transmission and distribution utility in Maine, and includes various provisions designed to promote the development of these resources.

Part A of the law expands and creates new opportunities for net energy billing, including by:  eliminating the cap on how many customers may share interests in a net metered project;  clarifying that shared interests could include ownership, leases, or power purchase agreements; expanding the maximum facility size to just under 5 megawatts; and creating a new net energy billing program providing monetary credits that could be used by commercial and institutional customers of investor-owned utilities to offset their customer or demand charges (as opposed to providing only volumetric energy credits).

Part B of the law creates a procurement program for distributed generation, requiring the Maine Public Utilities Commission to hold a series of competitive procurements for the output of renewable distributed generation resources with nameplate capacity of less than 5 megawatts.In all, the law requires the Commission to procure 125 megawatts of the output of distributed generation resources associated with commercial or institutional customer accounts and another 250 megawatts from shared distributed generation resources, by July 1, 2024. It requires an initial procurement of 75 megawatts in 2020, followed by four additional procurement blocks, each of which would be priced at 97% of the previous block price.

In response to the enactment of Part B, the Commission has issued a notice of rulemaking proposing to adopt new a rule Chapter 312, and has released a draft of the proposed rule chapter itself. The Commission has requested public comments by September 20, with a public hearing scheduled for October 8, and final written comments due no later than October 18.

The procurement program comes in addition to the implementation of other recently enacted incentives and mandates for clean energy, including a pilot program seeking proposals to support the beneficial electrification of the transportation sector, other reforms to net metering, and a significant expansion of Maine's renewable portfolio standard.

Maine transportation electrification pilot RFP

Thursday, September 5, 2019

Maine utility regulators have asked for proposals for pilot programs to support the beneficial electrification of the transportation sector: substituting electricity for fossil fuels in ways that provide benefits like improved grid efficiency, reduced consumer costs or emissions.

While Maine's electricity generation sector is largely decarbonized (accounting for just 9 percent of the state's greenhouse gas emissions in 2017), transportation and heating lag significantly: Maine's transportation sector was responsible for 53 percent of the state's greenhouse gas emissions in 2017, with heating taking the next greatest share.

Earlier this year, the Maine state legislature enacted An Act to Support Electrification of Certain Technologies for the Benefit of Maine Consumers and Utility Systems and the Environment, P.L. 2019, ch. 365. The law includes several measures designed to support the "beneficial electrification" in Maine's transportation and heating sectors, defined as "electrification of a technology that results in reduction in the use of a fossil fuel, including electrification of a technology that would otherwise require energy from a fossil fuel, and that provides a benefit to a utility, a ratepayer or the environment, without causing harm to utilities, ratepayers or the environment, by improving the efficiency of the electricity grid or reducing consumer costs or emissions, including carbon emissions."

Section 5 of the Act directs the Maine Public Utilities Commission to seek proposals for pilot programs to support the beneficial electrification of Maine’s transportation sector. The law requires the Commission to request proposals from utilities and from entities that are not utilities, including the Efficiency Maine Trust, for pilot programs that are limited in duration and scope to support beneficial electrification of Maine's transportation sector. It provides that proposals may address electric vehicle chargers that make use of load management, utility investment in electricity delivery infrastructure for fast-charge direct-current technology, fees for this service, and recommended opportunities for deployment. It also requires the Commission to complete a review of the implemented pilot program by December 1, 2022.

On August 28, 2019, the Commission issued its Request for Proposals for Pilot Programs to Support Beneficial Electrification of the Transportation Sector. It calls for proposals to be submitted no later than November 20, 2019. The RFP says the Commission will accept or reject proposals by March 1, 2020, based on an evaluation of criteria including the extent to which they are likely to result in information and data that will inform future efforts for beneficial electrification of the transportation sector, the bidder team's relevant experience, the cost and funding source, and the schedule and duration (including the bidder's ability to report on the results sufficiently in advance of December 1, 2022).

Separately, another section of the Act directs the Efficiency Maine Trust to conduct a study of barriers to the beneficial electrification of Maine's transportation and heating sectors. The Trust has issued a Request for Information to inform that study, with written comments requested by September 18, 2019.

New England electric fuel security reform filings delayed

Tuesday, September 3, 2019

Federal electricity regulators have given New England's regional grid operator more time to develop proposed new mechanisms to enhance long-term fuel security, after states and market participants asked for an extension to allow continued stakeholder discussions. At stake are what could be significant reforms to the region's electricity markets, including new opportunities for generators to earn revenue for providing fuel security, as well as the prospect of significant new costs for consumers.

ISO New England Inc. is the regional transmission organization and independent system operator for the electric grid serving nearly all of New England. In this role, it develops and administers markets for electric energy, capacity, and other products. ISO-NE also engages in regional system planning, and manages proposals to retire or close power plants that provide capacity to the region.

In 2018, the owner of the Mystic Generating Station, the largest power station in Massachusetts by nameplate capacity, proposed to retire its units in 2022. But after a study of the remaining electric system, ISO-NE determined that the retirement of Mystic's units 8 and 9 would present "unacceptable fuel security risks" that could lead to rolling blackouts as soon as the winters of 2022 through 2024. In response, ISO-NE asked the Federal Energy Regulatory Commission for waivers to allow the grid operator to retain the Mystic units to meet fuel security needs.

Some stakeholders disagreed that the Mystic units' retirement posed a reliability risk; others argued the costs of retaining them would outweigh any benefits. While the Commission denied ISO-NE's waiver request, it ultimately approved a short-term cost-of-service agreement under which regional ratepayers will pay to keep the Mystic units online. But the Commission also made a preliminary finding that ISO-NE's tariff may be unjust and unreasonable, and directed ISO-NE to file proposed tariff revisions creating a long-term fuel security mechanism by July 1, 2019. At the grid operator's request, the Commission later extended that deadline to November 15, 2019, to allow more time for proposal development and stakeholder discussion.

In the meantime, this spring ISO-NE filed a proposed short-term "inventoried energy program" from December 1 through the end of February during winters 2023/2024 and 2024/2025 as "a bridge to a long-term, market-based solution that more comprehensively addresses the region’s energy security risks" -- but Commission staff identified that filing as "deficient" and requested additional information, which prompted ISO-NE to provide additional information. In the absence of a Commission quorum willing to vote, those revisions became effective by operation of law on August 6, 2019, although parties have sought rehearing regarding the Commission's failure to act.

But even more time may be necessary. On July 31, 2019, the New England States Committee on Electricity (NESCOE) filed a motion requesting an additional six-month extension of time to allow ISO-NE and the region to work through issues related to ISO-NE’s proposed long-term fuel security mechanism. Representing the governors of the six New England states, NESCOE said granting its request would "enable a more complete and holistic filing in response to the directives in the July 2018 Order, allow ISO-NE to address core consumer protection elements that are fundamental to state support, and remove barriers to achieving a greater degree of regional coalescence around a proposal." Several commenters supported the motion.

Ultimately, the Commission granted an extension of time up to and including April 15, 2020 for ISO-NE to file its long-term fuel security mechanism. While New England will soon be forced to address the issue of fuel security for its electric generating portfolio, these short-term and long-term market changes proposed by the grid operator are on hold for now.

Maine considers beneficial electrification of transportation, heating

Wednesday, August 28, 2019

The independent administrator of Maine's energy efficiency programs has issued a request for information to inform a study of the barriers to beneficial electrification in the transportation and heating sectors in Maine. While the electricity sector has largely been decarbonized, transportation and heating lag significantly: Maine's transportation sector was responsible for 53 percent of the state's greenhouse gas emissions in 2017, with heating taking the next greatest share. Meanwhile, electricity generation in Maine accounted for just 9 percent of the state's greenhouse gas emissions. 

Earlier this year, the Maine legislature enacted a law supporting "beneficial electrification", a concept defined in the new statute as "electrification of a technology that results in reduction in the use of a fossil fuel, including electrification of a technology that would otherwise require energy from a fossil fuel, and that provides a benefit to a utility, a ratepayer or the environment, without causing harm to utilities, ratepayers or the environment, by improving the efficiency of the electricity grid or reducing consumer costs or emissions, including carbon emissions." For example, petroleum used as fuel for vehicles and heating could be replaced by electricity generated from cleaner and less costly sources.

The new law also requires Efficiency Maine Trust -- Maine's quasi-governmental independent efficiency program administrator -- to study barriers to beneficial electrification in Maine's  transportation and heating sectors. To inform that study, on August 28, 2019, Efficiency Maine Trust released its Request for Information on Beneficial Electrification Study. It requests that interested parties submit written information, guidance, or comments relevant to the study, including barriers to beneficial electrification of transportation and heating, potential roles of utilities in supporting beneficial electrification, areas or populations where additional policy development or utility intervention are needed to ensure the benefits of beneficial electrification are obtained, and recommended opportunities for beneficial electrification. The Trust has requested written comments by September 18, 2019.

Separately, under another section of the new law, the Maine Public Utilities Commission has issued a request for proposals for pilot programs that support beneficial electrification of the transportation sector. The Commission's August 28 Request for Proposals seeks proposals for "pilot programs and projects that are limited in duration and scope to support beneficial electrification of the transportation sector." It suggests that proposals may address electric vehicle chargers that make use of load management, utility investment in electricity delivery infrastructure for fast-charge direct-current technology, fees for this service, and recommended opportunities for deployment.

FERC/NERC joint white paper on cyber transparency

Tuesday, August 27, 2019

U.S. electricity regulators have asked for public comment on a staff white paper proposing to provide increased transparency and public access to information on violations of mandatory reliability standards governing cybersecurity of the bulk electric system, while protecting sensitive information whose disclosure would be a security risk. If the changes are adopted, the identity of violators would be made public, while detailed information that could be useful in planning an attack on critical infrastructure would remain protected from public disclosure.

At issue is a white paper jointly prepared by staff of the Federal Energy Regulatory Commission and of North American Electric Reliability Corporation (NERC). The Joint Staff White Paper on Notices of Penalty Pertaining to Violations of Critical Infrastructure Protection Reliability Standards was released on August 27, 2019.

The Commission's regulatory jurisdiction includes cybersecurity issues affecting the bulk electric system. NERC, in its role as the nation's electric reliability organization, has adopted a variety of reliability standards, including those governing Critical Infrastructure Protection (CIP) and cybersecurity of the grid. Since 2010, NERC has submitted Notices of Penalty to FERC pertaining to violations of its CIP standards, which typically describe the nature of the violations, potential cyber system vulnerabilities, and mitigation activities, but which do not publicly identify the entity alleged to have violated the standards.

But according to the Commission, since 2018 it has received an "unprecedented number" of Freedom of Information Act requests for non-public information in these Notices of Penalty, such as the identity of the entity alleged to have violated the standard. For example, earlier this year a nongovernmental organization unsuccessfully pressured the Commission to identify an anonymous utility that had agreed to pay a $10 million penalty to settle allegations of violations of cybersecurity and other reliability standards.

To refine the balance between transparency and security, the joint white paper proposes that NERC would submit each notice with a public cover letter that discloses the name of the violator, which reliability standards were violated, and the amount of penalties assessed. Separate non-public attachments would detail the nature of the violation, mitigation activity and potential vulnerabilities to cyber systems, with such information designated as Critical Energy Infrastructure Information and subject to additional protections. According to the Commission, these proposed changes will facilitate distinguishing between public and non-public information.

The Commission has issued a Notice of White Paper, calling for public comments to be filled within 30 days. The Commission has specifically asked for comment on the potential security benefits and risks associated with this approach; difficulties with implementation or other concerns that should be considered; and the level of transparency provided by this proposed change.

U.S. electric utility ownership types

Monday, August 19, 2019

Investor-owned electric distribution companies served 72% of U.S. electricity customers in 2017 according to federal data, even though investor-owned utilities accounted for just 168 out of nearly 3,000 electric utilities.

The U.S. Energy Information Administration categorizes electric utilities into three groups based on their ownership type: investor-owned utilities, publicly owned utilities, and cooperatives. Stock in investor-owned utilities is owned by shareholders; publicly owned utilities include those run by federal, state and municipal entities; cooperatives are not-for-profit utilities owned by their customer-members.

Of the nearly 3,000 electric distribution companies operating in the United States in 2017, just 168 were investor-owned -- but these investor-owned utilities or IOUs tend to be much larger than others, serving an average of 654,600 customers, and in the aggregate providing power to nearly three-quarters of all U.S. electricity customers. According to EIA, IOUs tend to be concentrated in heavily populated areas on the East and West coasts. For example, two California utilities each serve over 5 million electricity customers.

Publicly owned utilities are most numerous, with 1,958 operating in 2017 according to EIA data. On average, each publicly owned utility services 12,100 electricity customers, or about 15% of all U.S. electricity customers in total.

812 electric cooperatives or co-ops are located across 47 U.S. states, serving an average of 24,500 electricity customers each. Interest in cooperative and publicly owned utility forms is increasing, as consumers and policymakers look for structures that balance economic and environmental efficiencies against responsiveness and local control.

NY agencies complain grid rules penalize storage

Friday, August 2, 2019

New York state energy agencies have complained to federal regulators that the New York electric grid operator's market rules are interfering with the state's policies supporting the increased deployment of energy storage resources.

In a complaint filed on July 29, 2019 with the Federal Energy Regulatory Commission, the New York State Public Service Commission and New York State Energy Research and Development Authority assert that the development of energy storage resources in New York is necessary for legitimate state purposes, such as "enhancing reliability, resilience, and fuel diversity, as well as reducing environmental and public health impacts associated with fossil fuel emissions." New York has announced $400 million in funding for energy storage initiatives, and has released an implementation plan for energy storage market acceleration.

However, in their complaint the agencies note that development is frustrated by market rules adopted by the New York Independent System Operator. In particular, the state agencies point to NYISO tariff provisions that require energy storage resources participating in the wholesale installed capacity (ICAP) market to be subject to buyer-side mitigation measures which "would severely limit, or even eliminate, the ability of Energy Storage Resources to be paid for the value they provide."

According to a draft NYISO presentation on buyer side mitigation posted on the grid operator's website, buyer-side mitigation or BSM is one tool NYISO uses to "mitigate the market effects of conduct that would substantially distort competitive outcomes in the ISO Administered Markets, while avoiding unnecessary interference with competitive price signals." Specifically, the presentation describes buyer side mitigation's purpose as "to prevent uneconomic entry from artificially suppressing capacity prices." Resources that are subject to the buyer side mitigation rule will be examined in a two-part test to determine whether a minimum "offer floor" will be imposed.

The complainants request "that the Commission preserve the cooperative federalism approach" by the Federal Power Act and grant a blanket exemption from the buyer-side mitigation measures for all energy storage resources that seek to participate in the NYISO's ICAP auctions, or at least enable up to 300 megawatts to energy storage resources to enter the market each calendar year without the threat of mitigation.

The Federal Energy Regulatory Commission has taken a variety of actions in recent years to accommodate the entry of electric energy storage facilities into the grid and wholesale markets, including Order No. 841 and 841-A which established reforms to remove barriers to the participation of electric storage resources in certain organized wholesale markets. The New York agencies' complaint remains pending as of the end of July 2019, with public comment solicited until 5:00 pm Eastern Time on August 19, 2019.

Maine net metering reformed

Wednesday, July 31, 2019

Maine utility regulators have amended rules governing net energy billing for electricity customers, in the wake of recently enacted laws requiring the rules to be restored to how they read prior to changes adopted in 2017 that cut the value of net metering for customers with solar panels or other distributed generation. The Maine Public Utilities Commission's July 31, 2019 order amending its Chapter 313 net energy billing rules describes the amendments as intended to make the rules "substantively equivalent to the rules in effect on January 1, 2017." Further reforms will follow, as a new law taking effect on September 19, 2019 requires further changes to net metering that significant expand customers' opportunities to participate in distributed generation projects.

Since the 1980s, Maine has allowed electricity customers who install their own small generating facilities to "net meter" or offset their electricity bills with electricity they inject into the grid. In 2017, the Commission approved amendments to its rule that reduced the amount of energy that could be used to offset a customer's transmission and distribution bill.

But those amendments were controversial for a variety of reasons, including their requirement that net energy billing customers install a costly second meter, their imposition of transmission and distribution charges for electricity that a customer both produces and consumes in real-time within its own facilities, and for their overall reduction of the value to customers of operating distributed generation.

In 2019, the Maine State Legislature enacted a law directing the Commission to amend its net energy billing rules to be substantively equivalent to the rules in effect on January 1, 2017, and, further, that the amended rules must apply to all customers that entered into a net energy billing arrangement between March 29, 2017 and the effective date of the new rules. On July 31, the Commission took that step. It amended Chapter 313 to define net energy as the difference between the energy produced by the generating facility and the energy used by the customer or shared ownership customers, required that customers be billed on this basis, and made a handful of other changes the Commission described in its statement of factual and policy basis as "non-substantive."

Separately, the 2019 Maine legislature enacted a law significantly expanding net energy billing. This law expands the maximum size of a generating facility eligible for net energy metering, from 660 kilowatts to 5 megawatts. It also eliminates any limit on the number of customers in the territories served by investor-owned utility who may “share ownership” and net meter against a given project’s output. The new law allows a customer with a power purchase agreement to be considered a "shared owner", in addition to those who own or lease a facility. A new variation on net energy billing provides additional value specifically for nonresidential customers of an investor-owned utility: a voluntary tariff rate providing a monetary bill credit for any electricity delivered to the electric grid from a distributed generation resource, equal to the applicable standard offer service rate for that customer receiving the credit plus 75% of the effective transmission and distribution rate for the rate class that includes the smallest commercial customers of the investor-owned transmission and distribution utility. The law requires the Commission to develop tariffs and rules implementing these additional reforms, which the Commission is expected to do in the coming months.