FERC rules NH biomass energy law preempted

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

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

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

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

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

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

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.