Maine municipal street lighting inquiry opened

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

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

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

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

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.