FERC grid resilience examination continues

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

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

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

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

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

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

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

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

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.