International Trade Commission investigates Massachusetts renewable energy commitments, imports

The U.S. International Trade Commission has opened an investigation into the potential economic effects of increased renewable energy commitments in New England and Massachusetts and the role of renewable electricity imports in meeting these commitments.

Section 332 of the Tariff Act of 1930, 19 U.S.C. 1332, gives the U.S. International Trade Commission authority to conduct fact-finding investigations on international trade issues. Whether on its own initiative or by request of the President, the Senate Finance Committee, the House Ways and Means Committee, or the U.S. Trade Representative, the USITC may a hold fact-finding investigation on any subject involving tariffs or international trade, including conditions of competition between U.S. and foreign industries.

Following an initial letter dated December 2019 and a supplemental letter dated January 23, 2020 from House Ways and Means Committee chair U.S. Representative Richard Neal to the USITC, on February 12, 2020, the USITC issued notice of a new investigation under Section 332, Renewable Electricity: Potential Economic Effects of Increased Commitments in Massachusetts.

According to the notice, the USITC expects to provide the following information to the House Ways and Means Committee by January 25, 2021:

an overview of the current situation and recent trends in New England and Massachusetts electricity markets with regard to domestic and imported electricity sources and rates for residential and commercial uses, and the status of the transition from nuclear and fossil fuels to renewable sources, including: a description of Massachusetts’ most recent renewable energy goals and commitments as compared to previous commitments and initiatives, the renewable energy goals and commitments in other New England states, and the potential available resources to meet Massachusetts’ and New England’s goals;

a quantitative analysis of the potential economic effects on Massachusetts and the broader New England region of Massachusetts reaching its goals and commitments for renewable electricity sourcing (including the potential economic effects on residential and commercial electricity consumers);

a quantitative analysis of the likely effects on greenhouse gas emissions of meeting these goals and commitments; and

relevant case studies involving other states, regions, or countries that provide insights into the potential economic effects of imports of hydroelectricity, including on efforts to meet renewable energy targets, the rates paid by commercial and residential consumers, and greenhouse gas emissions.

The USITC has requested public input from all interested parties including written submissions by July 28, 2020, and will hold a public hearing in connection with the investigation at 9:30 a.m. on May 7, 2020.

FERC inquiry re virtualization cloud computing

U.S. utility regulators have asked for public comment on the potential benefits and risks associated with the use of virtualization and cloud computing services in the operation of the nation’s bulk electric system.

On February 20, 2020, the Federal Energy Regulatory Commission issued a Notice of Inquiry asking whether the Commission’s Critical Infrastructure Protection (CIP) Reliability Standards allow for deployment of virtualization and cloud computing services and balance the innovations with security requirements.

As described by the Commission, "Virtualization is the process of creating virtual versions of computer hardware to minimize the amount of physical computer hardware resources needed to perform various functions. It is considered necessary if the functions of grid cyber systems are to be moved to a cloud computing environment. While some entities might use the cloud simply for data storage, others may rely on virtualization and cloud storage in tandem to operate systems that control one or more core functions of the power grid."

In the Notice of Inquiry, the Commission asked questions regarding four broad topics: where virtualization or cloud computing could be used in connection with the bulk electric system; benefits and risks associated with virtualization or cloud computing; barriers within the CIP reliability standards that block their implementation; and potential new and emerging technologies that regulated entities might adopt.

The Commission docketed the inquiry proceeding as RM20-8-000. Comments are due 60 days after publication of the NOI in the Federal Register.

In a related proceeding, the Commission issued an order directing electric reliability organization NERC to make an informational filing describing work on two draft CIP standards addressing virtualization and cloud computing, labeled by NERC as Project 2016-02 (Modifications to CIP Standards) and Project 2019-02 (BES Cyber System Information Access Management). NERC's initial filing in Docket RD20-2-000 is due within 30 days, to be followed by quarterly updates.

FERC technical conference on reliability, inverter-based resources, and cybersecurity

U.S. utility regulators have scheduled a technical conference to discuss policy issues related to the reliability of the Bulk-Power System, in response to shifts in the nation's electric generation fleet away from large, central coal-fired power plants toward more distributed renewable resources. The meeting could inform future policy reforms, such as tighter reliability regulation of smaller-scale solar and wind facilities.

Section 1211 of the federal Energy Policy Act of 2005 amended the Federal Power Act to grant jurisdiction to the Federal Energy Regulatory Commission over all users, owners and operators of the bulk-power system (except in Alaska and Hawaii), for purposes of approving reliability standards and enforcing compliance. The law defines the bulk-power system as including facilities and control systems necessary for operating an interconnected electric energy transmission network as well as electric energy from generation facilities needed to maintain transmission system reliability, but not including facilities used in the local distribution of electric energy.

On February 3, 2020, the Commission issued a Notice of Technical Conference in Docket AD20-7. According to the notice, the Commission will hold a technical conference on Thursday, June 25, 2020, from 9:00 AM to 5:00 PM, "to discuss policy issues related to the reliability of the Bulk-Power System... including: (1) the changing resource mix; (2) inverter-based resources and inverter-connected distributed energy resources; and (3) cybersecurity."

Each of these issues is not novel to the Commission. It has previously noted changes to the nation's portfolio of electric generating resources, including large-scale retirements of coal-fired power plants and additions of new renewable facilities and natural gas-fired power plants. Some generating resources, such as typical solar or wind facilities, use equipment called an inverter to change direct current to alternating current. As electric reliability organization NERC has found, inverter-based resources' response to fluctuations on the grid are typically driven by advanced controls, unlike traditional synchronous generators whose response is driven by the laws of physics and classical mechanics, and many inverter-based generators are small-scale distributed resources that fall below some thresholds for reliability regulation. The Commission's jurisdiction over the reliability of the bulk-power system includes responsibility for cybersecurity, an authority it has used to adopt mandatory cybersecurity reliability standards.

ISO-NE capacity auction yields record low price

The latest annual auction for the New England electric forward capacity market cleared at the record low price of $2.00 per kilowatt-month, for commitments to provide capacity in the future capacity year from June 1, 2023 to May 31, 2024.

Regional transmission organization ISO New England Inc. operates the New England region's wholesale electricity markets, including separate markets for electric energy and capacity products. In the energy market, resources compete on a daily basis to provide power and are paid for the electricity they produce. In addition to this energy market, ISO-NE operates a Forward Capacity Market to procure sufficient resources to meet the future demand for electricity. The grid operator holds annual Forward Capacity Auctions, three years in advance of a future operating period, in which generators and other resources compete to obtain a commitment to supply capacity in exchange for a market-priced capacity payment. Under recently adopted "Pay for Performance" market rules, if a resource has a capacity supply obligation but fails to perform during a shortage event, the resource must refund part of its capacity payment for payment to resources that over-performed during the shortage event.

On February 3, 2020, ISO-NE held its 14th Forward Capacity Auction. Through FCA 14, the grid operator procured 33,956 megawatts of capacity for the 2023-2024 capacity commitment period, including 28,978 megawatts of in-region generation, 3,919 megawatts of demand resources, and 1,059 megawatts of imports into New England from New York, Quebec, and New Brunswick. This procurement results in 1,466 megawatts of surplus supply over the net Installed Capacity Requirement, under a "sloped demand curve" auction rule that allows New England to acquire slightly more or less than its capacity target depending on market prices.

According to ISO-NE, the primary auction clearing price was $2.00 per kilowatt-month for all regional resources and imports. ISO-NE vice president for system planning Bob Ethier described the results as "record low prices". As recently as FCA #8 held in 2015, capacity was priced as high as $15 for new resources and $7.025 for existing resources, but capacity auction clearing prices have tended to decline since then, reaching $4.63 for FCA #12 and $3.80 for last year's FCA #13. Factors that may have driven down the clearing price include a reduction in demand relative to the previous auction, in the form of a reduced Installed Capacity Requirement.

ISO-NE projects the estimated cost of the capacity market in 2023-2024 to be about $980 million, down from its $1.6 billion estimate for the 2022-2023 capacity commitment period. Lower capacity market clearing prices will directly result in reduced future capacity market revenues for participating generators. This could place increased pressure on generators who have historically relied on capacity revenues, such as peaking power plants that seldom run. In theory, lower capacity market prices could result in lower electricity costs for consumers, unless generators demand higher prices in the energy market (or elsewhere, such as for renewable attributes) to make up for reduced capacity market revenues.

Vermont solar update: mixed progress toward goals

Vermont could still meet its target to source at least 20 percent of the state’s electricity from in-state solar by 2025 if the percentage growth rate from the last five years continues, according to a recent report, but uneven growth and a slowdown in new capacity installations since 2016 mean significantly more solar will be required to meet the target than has been installed to date.

In 2016, the Vermont Energy Investment Corporation issued its Vermont Solar Market Pathways report, described as a compendium of (1) a summary report, (2) briefs relating to focus topics, (3) a brief on barriers to substantial amounts of solar installations and integration, and (4) methods and detailed tables of inputs and assumptions. The 2016 report concluded that Vermont is capable of meeting 20 percent of its electricity needs with solar, by 2025, and that meeting that goal would be less expensive than "business as usual."

Now, an updated report released in January 2020, Vermont Solar Market Pathways: Three-Year Update and Status Report, labels Vermont’s progress toward the solar target and projections for complementary technologies as "mixed":

For example,if the percentage growth rate from the last five years continues, Vermont can meet the solar development pathways target. But Vermont has not yet installed solar capacity at the annual installation rate necessary from 2020 to 2025 to meet the target.

According to the updated report, "growth has been uneven over the past five years in response to various market and incentive conditions, and the last three years have not matched the amount of capacity installed in 2016. Current challenges to continuing the pace of solar installation necessary to meet the targets are the possible phase-out of federal tax credits, recently added tariffs on imported equipment, and the addition of fees for new projects in certain areas."

The updated report also notes "increasing technical issues related to siting and integration of new installations" as the total capacity of solar installed on the system increases, along with "increased pressure to make sure the benefits and costs of solar development are equitably shared."

Finally, the report notes that solar is just one component of a holistic solution to address Vermont's “90 percent renewable energy by 2050” target, with significant needs to use "strategic electrification" to displace fossil fuel use in transportation and heating, as well as energy efficiency and non-solar renewables.

EIA projects US energy-related CO2 emissions to decrease

If no new laws or regulations are adopted, a federal report projects that U.S. energy-related carbon dioxide emissions will decrease through the early 2030s, before increasing slightly to 4.9 billion metric tons in 2050, based on changes in the fuel mix for electricity generation and increasing activity in the industrial and transportation sectors.

The U.S. Energy Information Administration publishes an annual report on projections and possible scenarios. The most recent release, Annual Energy Outlook 2020 (AEO2020), includes a "reference case" which assumes that no new laws or regulations are enacted which affect energy-sector carbon emissions. Under that scenario, EIA's modeling shows total U.S. energy-related CO2 emissions decrease until 2031, then resume growth, but remain 4% lower than 2019 levels by 2050.

Source: U.S. Energy Information Administration, Annual Energy Outlook 2020

Transportation contributes more energy-related CO2 emissions than electric power generation, industrial activity, or any other sector tracked in EIA's AEO2020 report. EIA projects decreases in transportation sector emissions through the late 2020s, as fuel efficiency increases faster than does the total distance traveled, but then projects that increased activity in the transportation and industrial sectors will lead to more consumption of petroleum and natural gas.

While the U.S. electric sector formerly emitted more CO2 emissions than did the transportation sector, CO2 emissions associated with electricity generation have fallen significantly in recent years -- a trend EIA projects will continue for the near term. EIA's reference case projects that the largest drop in the U.S. electric power sector’s CO2 emissions experience will arrive by 2025, as coal power plants continue to retire while new renewable generation capacity is added. After 2025, EIA's reference case projects that electric power sector CO2 emissions will remain relatively flat "as the more economically viable coal power plants remain in service."

Meanwhile, EIA projects that residential and commercial energy sector emissions will remain largely unchanged through 2050; each is a relatively small contributor to the nation's total energy-related CO2 emissions budget.

In other scenarios included in AEO2020, EIA notes that U.S. energy-related CO2 emissions projections are sensitive to assumptions regarding variables such as economic activity, oil prices, renewable energy technology costs, and oil and natural gas resource estimates. The report noted that economic growth assumptions can significantly affect emissions projections, with high and low economic growth cases affecting CO2 emissions by +13% and -11% respectively.

Report: Maine must decarbonize transportation and heating to meet climate goals

Maine will need to decarbonize its transportation and building heating sectors to meet newly adopted greenhouse gas emissions limitations, according to Efficiency Maine Trust's final report, Beneficial Electrification: Barriers and Opportunities in Maine.

In 2019, the Maine legislature enacted a series of laws significantly reshaping the state's electricity laws and climate policy, including a doubling of Maine's renewable portfolio standard (RPS) to require 80% of electricity sold at retail to be backed by renewable attributes by 2030, expanded eligibility for net energy billing programs offering enhanced value to participating customers, mandates to procure renewable energy from both large and small distributed generation resources, and the Maine Climate Council law requiring Maine to reduce its gross annual greenhouse gas emissions to at least 45% below the 1990 gross emissions level by 2030 and to at least 80% below 1990 levels by 2050.

The legislature also enacted a law focused on "beneficial electrification", a concept 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." This beneficial electrification law required the Maine Public Utilities Commission to conduct a transportation electrification pilot program, and required Maine's quasi-governmental independent efficiency program administrator Efficiency Maine Trust to study barriers to beneficial electrification in Maine's transportation and heating sectors.

The Trust released its final report under that mandate on January 31, 2020. In the report, the Trust notes, "Maine has thus far focused much of its GHG reduction efforts on increasing renewable electricity supply and improving energy efficiency." The report cites examples such as the Trust's core work under a state law mandating that electric and natural gas utilities assess their customers in an amount necessary to fund “the maximum achievable cost-effective energy efficiency" through the Trust, as well as the recent expansions to the renewable portfolio standard and net metering programs and the recently enacted long-term contract procurement mandates.

As noted by the Trust, "these policies have significantly decarbonized Maine's electric generation sector". Electric power generation contributed just 7% of Maine’s greenhouse gas emissions in 2017 (down from 9% in 2015), and has shown the greatest percentage reduction in carbon emissions relative to its peak compared to any other tracked sector. In 2018, about three-fourths of Maine's electricity net generation came from renewable sources.

The report further observes that despite the substantial progress already achieved and further progress mandated with respect to electricity, direct fossil fuel use in transportation and buildings continues to contribute most of Maine's greenhouse gases emissions:

Notwithstanding the progress in GHG reduction from the policies mentioned above, there remain significant emissions resulting from direct fossil fuel use in buildings (residential and commercial), transportation, and industry as shown in Figure 3. Maine’s RPS and solar policies have limited direct impact on those fossil fuel emissions for all but the electric power sector. 

Figure 3, reproduced below, shows that in 2017, the transportation sector was responsible for 54% of Maine's greenhouse gas emissions from fossil fuel combustion, with buildings responsible for another 30%, while the industrial sector contributed 9%, and electric power just 7%:

The report notes that three "key electrification technologies" -- heat pumps, heat pump water heaters, and electric vehicles -- "can play a significant role in curbing a large portion of the state’s overall emissions." While the report did not attempt to develop a precise estimate of the number of heat pumps, heat pump water heaters, and EVs required to achieve Maine’s emissions reduction targets, it did project that electrifying 90% of light duty vehicles could mean that over 1.2 million passenger EVs would be registered and operating in Maine by 2050, compared to about 3,000 today, and that electrifying 95% of fossil fuel demand for heating in residential buildings could mean installing well over a million heat pumps and 500,000 heat pump water heaters, compared to about 43,000 and 24,500 respectively today.

The report cites Maine's success to date in promoting heat pumps through the Trust's programming, leading to "the highest per-capita penetration of heat pumps in the U.S., with at least 46,000 installed over the past seven years in residential and commercial settings". But the Trust's report suggests that should be viewed as just the tip of the iceberg, with significant more work ahead in the near term to decarbonize the transportation and building heating sectors.

FERC rejects waiver request re capacity and interconnection

Federal electricity regulators have denied a distributed energy resource aggregator's request for a waiver of market rules to allow fourteen distributed energy resource projects to participate in New England's upcoming fourteenth Forward Capacity Auction. The case highlights tensions between state efforts to encourage distributed energy resources and limits on state jurisdiction over interconnection.

At issue was a request by Genbright LLC for a a one-time, limited waiver of Market Rule 1 of ISO New England Inc.’s Transmission, Markets and Services Tariff to allow fourteen projects to participate in FCA 14. According to the petitioner, seven of the projects are solar photovoltaic generating facilities; the other seven are energy storage facilities.

Under ISO-NE's Market Rule 1, each new resource seeking to participate in a forward capacity auction must undergo a qualification evaluation and must have a valid interconnection request under the Tariff by the deadline to submit a "Show of Interest." According to Genbright, it submitted timely Shows of Interest indicating that each project had submitted an Interconnection Request pursuant to a Massachusetts-administered, state-jurisdictional interconnection process. However, the petition claims that ISO-NE issued each project a Qualification Determination Notification denying eligiblity to participate in FCA 14, claiming that "because the point of interconnection for the Projects is under the Commission’s jurisdiction as a facility subject to the Tariff, the Projects should have filed Interconnection Requests in accordance with Schedule 23.9" instead of under a state-administered interconnection process.

Genbright countered that its projects and their interconnections are not jurisdictional to the Federal Energy Regulatory Commission, claiming that the seven solar projects are Qualifying Facilities selling 100 percent of their output to local host utility Eversource, and that at least three of the storage facilities' interconnection requests were erroneously classified by Eversource as FERC-jurisdictional "because there is a pre-existing QF on the distribution line that sells all of its output to Eversource, which Eversource had registered with ISO-NE as a settlement-only generator." Genbright further claimed that neither Eversource nor ISO-NE informed any of the projects that they had filed incorrect interconnection requests, despite the utility's knowledge that the projects intended to participate in the ISO-NE market. For these reasons, Genbright requested waiver of Tariff provisions to allow the projects to participate in FCA 14.

Eversource asked the Commission to deny the waiver request, as did ISO-NE. Eversource argued "that Genbright’s request is not about whether a tariff provision should be waived due to a one-time error, but rather an attempt to seek a substantive ruling related to disagreements over the law as to what causes a distribution-level interconnection to fall under Commission jurisdiction. Eversource states that such issues would be more appropriate in the context of a declaratory order or rulemaking." Eversource noted that Genbright's issues were not limited in scope, but of broader applicability. In an answer, Genbright claimed that Eversource knows, but ignores, ISO-NE’s applicable rules and stated practices.

In the end, the Commission denied the waiver request, finding that Genbright had failed to demonstrate that it was limited in scope. The Commission noted that granting "Genbright’s requested waiver would allow the Projects to avoid ISO-NE’s complex interconnection study process, including the system impact study, which is ISO-NE’s comprehensive reliability evaluation." This result differed from that of a separate order issued in 2019, granting a similar waiver with respect to four facilities where ISO-NE and Eversource both agreed that the interconnection requests had been erroneously misclassified as subject to federal jurisdiction.

The order highlights the growing tension between state programs encouraging or requiring the development of distributed energy resources and federal jurisdiction. The ISO-NE interconnection study process is indeed complex, and typically requires an applicant to wait through a lengthy queue of other study requests before their own study may begin, a process which can take months or longer. State-jurisdictional interconnection procedures can move more swiftly, but are limited to those circumstances where federal jurisdiction does not apply.

Some state programs seeking to encourage or require the development of distributed energy resources run into jurisdictional boundaries on issues other than interconnection. For example, the Genbright order follows a 2019 Commission order ruling that federal law preempts a New Hampshire statute requiring utility procurement of the output of biomass facilities at above-market rates. Developers, advocates for solar and other distributed resources, and policymakers would be wise to understand the boundaries between state and federal jurisdiction over interconnection and wholesale electricity markets.

FERC rules on Natural Gas Act eminent domain and sovereign immunity

U.S. natural gas pipeline regulators have issued an order partially granting a pipeline company's request for a declaratory order interpreting the scope of eminent domain authority under the federal Natural Gas Act.

At issue is a petition by PennEast Pipeline Company, LLC to the Federal Energy Regulatory Commission, seeking a declaratory order. In 2018, the Commission issued a certificate of public convenience and necessity for the PennEast Project, a 116-mile greenfield natural gas pipeline connecting the Marcellus Shale region in Pennsylvania to regional delivery points serving New Jersey, New York, and Pennsylvania.

According to PennEast's subsequent petition for declaratory order, following issuance of the certificate, PennEast was unable to reach agreement with the State of New Jersey to acquire easements for the portions of its proposed pipeline route that would cross state lands and other properties in which the state claims non-possessory property interests such as conservation easements, so the company instituted condemnation proceedings in the United States District Court for the District of New Jersey in order to obtain these and other necessary easements. While New Jersey sought dismissal of the condemnation actions on grounds that the state possesses sovereign immunity, the District Court granted PennEast's application for orders of condemnation, finding that PennEast “has been vested with the federal government’s eminent domain powers and stands in the shoes of the sovereign.”

New Jersey then appealed to the United States Court of Appeals for the Third Circuit, which vacated the District Court’s order, instead holding that the Natural Gas Act does not abrogate New Jersey’s sovereign immunity, and that “the NGA does not constitute a delegation to private parties of the federal government’s exemption from Eleventh Amendment immunity."

PennEast then returned to the Commission, seeking a declaratory order that addresses whether a certificate holder’s right to condemn land pursuant to NGA section 7(h) applies to property in which a state holds an interest; whether NGA section 7(h) delegates the federal government’s eminent domain authority solely to certificate holders; and whether NGA section 7(h) delegates to certificate holders the federal government’s exemption from claims of state sovereign immunity.

In its January 30, 2020 order, the Commission partially granted PennEast's requests. With respect to whether a certificate holder’s right to condemn land pursuant to NGA section 7(h) applies to property in which a state holds an interest, the Commission found that that NGA section 7(h) does not limit a certificate holder’s right to exercise eminent domain authority over state-owned land. The Commission further found that NGA section 7(h) delegates eminent domain authority solely to certificate holders and not to the Commission. The Commission also found that NGA section 7(h) necessarily delegates the federal government’s exemption from state sovereign immunity, but denied PennEast's petition to the extent that it would require the Commission to evaluate the constitutional sufficiency of NGA section 7(h) for purposes of abrogating state sovereign immunity or delegating federal authority under the Eleventh Amendment.

The majority order concludes:

In enacting the NGA, Congress established a carefully crafted comprehensive scheme in which the Commission was charged with vindicating the public interest inherent in the transportation and sale of natural gas in interstate and foreign commerce, in significant part through the issuance of certificates of public convenience and necessity for interstate gas pipelines. A key aspect of this scheme was the remit to natural gas companies of the ability to exercise, where necessary, the power of eminent domain to acquire lands needed for projects authorized by the Commission. We here confirm our strong belief that NGA section 7(h) empowers natural gas companies, and not the Commission, to exercise eminent domain and that this authority applies to lands in which states hold interest. A contrary finding would be flatly inconsistent with Congressional intent, as expressed in the text of NGA section 7(h), which is also supported by the legislative history.

Commissioner Glick dissented on both procedural and substantive grounds and provided a separate statement, arguing that the Commission did not need "to insert itself into what is primarily a constitutional question that is being litigated where those questions belong: The federal courts." Commissioner Glick also disagreed with the majority that Congress unambiguously intended section 7(h) to apply state lands, finding that "the evidence simply is not clear one way or the other."