New England winter electricity costs decreased

New England's total estimated wholesale market cost of electricity in winter 2020 was 32% lower than during the previous winter, according to the ISO New England Internal Market Monitor, largely due to lower costs for electric energy and capacity and low natural gas prices. According to a recent report, one effect was that oil-fired generators in New England were "uneconomic, on average, every day during Winter 2020."

On May 4, 2020, ISO New England’s Internal Market Monitor released its Winter 2020 Quarterly Markets Report, assessing the state of competition in the ISO-NE wholesale electricity markets during the period from December 1, 2019 to February 28, 2020. According to the Winter 2020 Quarterly Markets Report, the total estimated wholesale market cost of electricity in Winter 2020 was $1.78 billion. This cost represents a 32% reduction relative to last year's total estimated wholesale market cost of $2.59 billion.

Breaking the total costs down into energy, capacity, and other components, the report notes that regional wholesale energy costs totaled $1.01 billion, a 36% reduction relative to Winter 2019 costs as "a result of lower natural gas prices, which decreased by 41% relative to Winter 2019 prices." Capacity costs totaled approximately $751 million, a 24% reduction relative to Winter 2019. This reduction was driven by lower capacity clearing prices from the tenth Forward Capacity Auction which began contributing to to lower wholesale costs in summer 2019, with capacity payment rates generally falling from $9.55/kW-month in all capacity zones except Southeastern Massachusetts/Rhode Island, to $7.03/kW-month. (Future capacity payment rates, determined earlier this year through the fourteenth Forward Capacity Auction, will fall even further to $2.00/kW-month.)

The report also cites warmer weather, an absence of cold spells, and "historic lows" for natural gas prices at supply basins: "Henry Hub natural gas prices averaged $2.03/MMBtu, the lowest average winter price since at least 2005. Together, the warmer New England weather and lower supply basin prices led to the lowest average winter New England natural gas prices for,at least,the past 10 years." According to the report, low regional natural gas prices contributed to lower prices for electric energy, "which caused oil-fired generators to be uneconomic, on average, every day during Winter 2020."

Maine comments on international dam jurisdiction

The State of Maine has sponsored a study supporting its position that federal regulators can relinquish jurisdiction over a dam spanning the St. Croix River and the U.S.-Canada border, based on the argument that the Forest City Dam can be operated such that it makes only an insignificant contribution to downstream hydropower generation.

At issue is the Forest City Dam, which is part of a hydropower project licensed by the Federal Energy Regulatory Commission as Project No. 2660. Because the dam is located on the East Branch of the St. Croix River which forms the international boundary, the project operates under conditions set by the International Joint Commission (IJC) pursuant to the Boundary Waters Treaty of 1909. The Forest City Dam has also been licensed by the U.S. Federal Energy Regulatory Commission, most recently receiving a 30-year license by order dated November 23, 2015, even though the project does not include any generating facilities, because it forms part of a headwater storage system for downstream power generation.

In 2016, the licensee applied to surrender the license, citing conditions imposed in the 2015 license order as rendering project operations "uneconomical." That surrender application remains pending as of mid-May 2020. Meanwhile, in 2017, then-Governor Paul LePage proposed authorizing a Maine state agency to assume ownership of the Forest City Project, but the legislation did not lead to that outcome. The same day, the licensee requested a ruling that no licensure would be required if the licensee transferred ownership of the U.S. portion of the project to the Maine Department of Inland Fisheries and Wildlife -- a ruling the Federal Energy Regulatory Commission ultimately declined to give, finding instead that the Forest City project requires licensure because it contributes to downstream electricity generation.

In October 2019, Maine Governor Janet Mills and New Brunswick Premier Blaine Higgs co-signed a letter filed with the Commission, noting that their respective governments "are discussing alternative models for ownership and management of the dam, which would support the long-term plan for preserving the natural, historical heritage and recreation and fishing interests of East Grand and the St. Croix system." In that letter, the leaders proposed a path forward involving third-party ownership of the dam, project operations consistent with applicable water quality standards and policy concerns, and development of an operations plan to ensure "reducing the facility's contribution to generation to an insignificant level".

Now, Governor Mills has sent a follow-up letter to the Commission, presenting a report commissioned by the state and prepared by a hydropower consulting firm. According to the letter dated May 13, 2020, the report supports the position that the Forest City project's contribution to downstream power generation "should be analyzed as a separate stand-alone project rather than in the aggregate with other St. Croix drainage projects", and moreover that its contribution is "insigificant for purposes of FERC jurisdiction and licensing."

The May 13 letter also highlights "other new information for FERC's consideration", including the exploration by Maine and New Brunswick of options for new third-party ownership and management as well as alternative operational regimes. It also expresses a desire to address concerns that removing the project from the FERC regulatory licensing process would reduce oversight or public involvement with respect to future operations, noting that the project would remain subject to regulation by the International Joint Commission and Maine Department of Environmental Protection, as well as a commitment to cross-boundary collaboration with New Brunswick.

The letter suggests that this report and information "should be adequate for FERC to reconsider its jurisdiction and licensing requirement", and expresses Maine's willingness to collaborate with the federal agency "for a positive outcome to preserve the heritage of the St. Croix International Waterway."

FERC schedules COVID impact technical conference

U.S. energy regulators have scheduled a two-day virtual technical conference "to consider the ongoing, serious impacts that the emergency conditions caused by COVID-19 are having on various segments of the United States’ energy industry."

On May 20, 2020, the Federal Energy Regulatory Commission issued a Notice of Technical Conference in Docket AD20-17-000, announcing that the Commission will convene a Commissioner-led technical conference on July 8 and 9, to "serve as a public forum for the Commission and energy stakeholders to discuss a wide range of energy issues that the country faces going forward as it recovers from the COVID-19 emergency."

The Commission and its staff have already adopted several measures to provide the public and regulated entities with short-term regulatory relief during the emergency caused by the coronavirus pandemic, including orders and notices issued on March 19 and April 2, and the designation of a Pandemic Liaison for the energy industry. According to the technical conference notice, "the Commission now wants to explore the potential longer-term impacts on the entities that it regulates in order to ensure the continued efficient functioning of energy markets, transmission of electricity, transportation of natural gas and oil, and reliable operation of energy infrastructure today and in the future, while also protecting consumers."

The notice describes the conference as providing the public "an opportunity to hear high-level discussions of how COVID-19 has impacted the energy industry" from speakers serving on multiple panels. According to the notice, topics discussed will include:

(1) the energy industry’s ongoing and potential future operational and planning challenges due to COVID-19 and as the situation evolves moving forward; (2) the potential impacts of changes in electric demand on operations, planning, and infrastructure development; (3) the potential impacts of changes in natural gas and oil demand on operations, planning, and infrastructure development; and (4) issues related to access to capital, including credit, liquidity, and return on equity issues.

The July 8-9 technical conference will be open for the public to attend remotely; the Commission encourages members of the public to preregister online.

Maine sets FY2021 electric efficiency procurement cap at about $49 million

Maine utility regulators have set the upper limit of possible ratepayer funding for electric efficiency resources under the state's energy efficiency procurement program, at approximately $49 million for fiscal year 2021. These amounts are in addition to other energy efficiency costs, such as for greenhouse gas emission credits under the Regional Greenhouse Gas Initiative or the costs of compliance with other Maine efficiency programs. The Public Utilities Commission's establishment of the FY 2021 electric efficiency procurement cap is one step in the sequence under a state law requiring transmission and distribution utilities to procure the maximum achievable cost-effective amount of electric energy efficiency and conservation resources, subject to a rate impact limitation capping ratepayer assessments at 4% of total retail electricity and transmission and distribution sales.

Maine's energy efficiency policy is largely governed by the Efficiency Maine Trust Act, initially enacted in 2009 and subsequently amended several times. As it stands in May 2020, the Efficiency Maine Trust Act requires the Public Utilities Commission to "ensure that transmission and distribution utilities on behalf of their ratepayers procure all electric energy efficiency resources found by the commission to be cost-effective, reliable and achievable . . . except that the commission may not require the inclusion in rates under this subsection of a total amount that exceeds 4% of total retail electricity and transmission and distribution sales in the State as determined by the commission by rule." This electric efficiency procurement mandate is sometimes described as targeting "MACE", or Maximum Achievable Cost-Effective, energy efficiency procurement, subject to the "4% of sales" cap.

The Commission's Rule Chapter 396 presently provides a four-step process for determining the dollar figure associated with the "4% of sales" cap on ratepayer funding. First, the Commission determines the total retail electricity and transmission and distribution sales for a given year, based on utility revenue data from the U.S. Energy Information Administration. For 2018, the Commission used Form EIA-861 data to determine total retail sales for 2018 of $1.26 billion. Second, the Commission deducts amounts collected during the same year pursuant to prior procurement orders or other electric energy efficiency assessments. Third, the Commission multiplies the resulting "sales figure" by 4% to calculate the "gross utility procurement cap". Finally, the Commission subtracts funds expected to already be included in rates during the upcoming fiscal year for electric energy efficiency programs, to yield the "net utility procurement cap". According to the Commission, "Based on the EIA sales level and this adjustment, the 4% of sales cap on funding provided by electric ratepayers during the second year of the Fourth Triennial Plan is approximately $49 million."

Separately, the Commission will determine the final budget for electric energy efficiency resources for fiscal year 2021, also known as the second fiscal year of the Efficiency Maine Trust's Fourth Triennial Plan, and will specify a total amount to be included in electricity rates. Once the Commission determines this funding level from electric ratepayers for FY2021, it will issue a further order determining whether the funding is below the "4% of sales" cap.

New England behind-the-meter solar sets record

Behind-the-meter solar panels in New England recently set a new record for generating electricity earlier this month, according to the region's grid operator.

Regional transmission organization ISO New England tracks the generating resources connected to the New England electric grid. According to ISO-NE, "Solar power systems are rapidly being installed across the six states of New England and noticeably reducing the electricity drawn from the regional power system."

All solar photovoltaic projects use sunlight to generate electricity, but beyond this superficial similarity the category holds much diversity. Some utility-scale solar projects are relatively large and participate in wholesale electricity markets. By contrast, typical behind-the-meter distributed generation systems are located at retail customer sites, and have historically been electrically interconnected on the customer's side of the utility meter or to local distribution utilities.

Federal and state policies favoring distributed generation have led to significant behind-the-meter solar development in New England. As of December 2019, the grid operator reported more than 180,000 behind-the-meter photovoltaic installations in the region. ISO-NE has noted that while these resources have a combined nameplate generating capability of more than 3,400 MW, they typically do not all generate their maximum output at the same time.

During the hour between noon and 1 p.m. on May 2, 2020, ISO-NE reports that the region's behind-the-meter solar installations generated approximately 3,200 megawatts, a record level of behind-the-meter solar generation.

ISO-NE says it expects this record to be broken again, likely repeatedly, given its projections of nearly 8,000 MW of solar power installed in New England by 2030.

ISO-NE projects EV, heat pump load growth

New England's annual use of electricity and peak demand will increase slightly over the next 10 years, according to the latest forecast issued by the operator of the region's electric grid. In its 2020-2029 Forecast Report of Capacity, Energy, Loads, and Transmission or CELT Report, grid operator ISO New England Inc. cites the additional energy and loads resulting from the new electrification forecast for beneficial electrification of electric vehicles (EVs) and air-source heat pumps (ASHPs) as the primary drivers of the projected increases.

ISO-NE develops an annual report providing a snapshot of the New England power system, including key information on generators, transmission projects, and long-term forecasts for energy consumption and peak demand. To develop projections of future electricity demand, ISO-NE first models gross energy consumption by considering state and regional economic forecasts, regional weather history, and forecasts for adoption of electric vehicles and heat pumps, then applies modeling of energy-efficiency solar photovoltaic resources to yield a net long-term forecast.

According to the latest CELT report, ISO-NE projects that overall electricity use in New England (not including energy efficiency or behind-the-meter solar PV) will grow 1.4% annually over the 10-year period, from 145,882 gigawatt-hours (GWh) in 2020 to 165,603 GWh in 2029. Meanwhile, peak demand under typical summer peak weather conditions (called a “50/50” forecast) is expected to rise annually at a rate of 0.9%, from 29,224 megawatts (MW) in 2020 to 31,550 MW in summer 2029; peak demand under an extended heat wave or other extreme summer peak weather (called a “90/10” forecast) increases the gross forecast for peak demand to 31,182 MW in 2020 and 33,760 MW in 2029.

Considering overall electricity usage, including energy efficiency and behind-the-meter photovoltaic resources, ISO-NE projects total use to increase by 0.4% annually, from 124,184 GWh in 2020 to 128,781 GWh in 2029. Notably, last year's 2019 CELT Report projected an average annual decrease of -0.4% to overall electricity use.

According to ISO-NE, beneficial electrification of transportation and heating largely explain this projected shift from declining electricity use to increasing use. Transportation electrification from EVs is forecasted to contribute 282 MW to peak demand in 2029, or 414 MW to the winter peak in 2029. Heating electrification through heat pumps is forecasted to contribute 661 MW to the winter peak in 2029. Many states are increasingly recognizing that transportation is the largest contributor to energy-related greenhouse gas emissions, with space heating also a major contributor, and are now focusing efforts on reducing emissions from these sectors by displacing fossil fuel use through electrification.

Section 45Q carbon capture tax credits and EPA reporting

Over $893 million in U.S. federal tax credits claimed for carbon capture and sequestration between 2010 and 2019 were claimed by taxpayers who failed to report sequestration activities to the Environmental Protection Agency, according to an investigation by the U.S. Treasury Department. The findings could lead to changes in how IRS administers and enforces its tax credit programs, and could also have implications for the enactment of future tax credits.

At issue is the federal tax credit under Section 45Q of the Internal Revenue Code, available for certain projects that capture, use, and sequester carbon emissions. Interim guidance issued by the Internal Revenue Service in 2010 required any taxpayer claiming a credit under section 45Q to adhere to the EPA's Greenhouse Gas Reporting Requirement under subpart RR, Geologic Sequestration of Carbon Dioxide. Subpart RR requires facilities that conduct geologic sequestration by injecting CO2 for long-term containment in subsurface geologic formations to report basic information on carbon dioxide received for injection, develop and implement an EPA-approved site-specific plan for monitoring, reporting, and verification (MRV), and report the amount of carbon dioxide geologically sequestered using a mass balance approach and annual monitoring activities.

But on November 19, 2019, U.S. Senator Bob Menendez, a Democrat from New Jersey who sits on the Senate Finance Committee, asked the office of the U.S. Treasury Inspector General for Tax Administration to undertake a review of "discrepancies" between the amount of Section 45Q tax credits that have been claimed and the amount of sequestered carbon reported to the EPA under subpart RR.

In a reply dated April 15, 2020, J. Russell George addressed six questions posed by Senator Menendez, replying in part:

The reason for the discrepancy is that some taxpayers have claimed the I.R.C. § 45Q credit on tax returns without complying with the EPA’s monitoring, reporting, and verification (MRV) requirements." The reply notes that out "of 672 taxpayers that reported carbon dioxide sequestration to the IRS, 10 taxpayers (one and a half percent) claimed over $1 million each, with their claims totaling over $1 billion (99.9 percent) of all of the I.R.C. § 45Q credits. We reviewed these 10 taxpayers and determined that three currently have an approved MRV plan with the EPA [and] that for TYs 2010 through 2019, a total of $893,935,025 (87 percent) worth of I.R.C. § 45Q credits were claimed by these 10 taxpayers when they were not in compliance with the EPA (i.e., they did not have an approved MRV Plan in place at the time the credit was claimed)."

Senator Menendez forwarded this report to IRS Commissioner Charles Rettig on April 29, noting that the report demonstrates "the apparent failure of the fossil fuel industry to act in good faith when claiming Section 45Q credits", asking for greater auditing and enforcement, and calling the findings an "apparent failure of the fossil fuel industry to act in good faith." He therefore asked the IRS to audit every taxpayer claiming more than $10,000 worth of 45Q credits by May 13 and to retroactively deny credits to taxpayers that did not comply with the EPA's requirements.

Maine Public Interest Payphone program

A small Maine town has petitioned the Maine Public Utilities Commission for approval to remove a "public interest phone" that was installed at the local volunteer fire department under a state program supporting telecommunications in rural and remote areas. According to the petition filed by the Town of Reed Plantation, a town of less than 200 people located in Maine's northernmost county (Aroostook), reasons for removing the phone include its infrequent use in "this day of cell phones", confusion over the phone's location, and a request by the fire department to replace it with a vending machine as the "closest store is 40 miles away."

The Maine State Legislature enacted a law in 2005 creating a Public Interest Payphone program to provide telephones in areas where traditional public telephones would not otherwise be deployed and in which a telephone will further public health, safety and welfare. For context, 2005 was the year Apple released its first iPhone, and also the year when the number of homes with broadband internet service first exceeded those with dial-up modems.

As cell phone service was increasing its penetration into rural Maine, landline companies removed many payphones from rural areas, noting that the cost of maintaining the phones exceeded their revenues. In response to concerns that this trend could isolate some people, the PIP program was created to use money from Maine’s Universal Service Fund (ultimately paid by ratepayers) to fund applications for the installation of coinless phones that allow free local calls as well as the ability to place 911, prepaid calling card, collect, or credit card long distance calls. A list maintained by the Commission shows about 35 PIP locations in Maine.

By rule, the Commission may, at its own discretion or upon petition of an interested person, order the removal of a PIP, such as the Town of Reed Plantation has requested. As technology and culture have continued to shift since 2005, will other Maine communities follow the Town of Reed Plantation's lead in asking for the removal of currently installed public interest phones?

Maine PUC examines pandemic effect on utility customers

The Maine Public Utilities Commission has opened an inquiry into the effect of the coronavirus pandemic on customers’ ability to pay their bills from transmission-and-distribution utilities and natural-gas local distribution companies, as well as any newly available federal resources to help customers manage their utility payments or to assist the utilities themselves with meeting their ongoing obligations.

On April 28, 2020, the Commission issued a Notice of Inquiry in Docket No. 2020-00136, a new docket opened to house the inquiry. The Notice describes the "sea change in daily life" wrought by the pandemic and resulting national and state-level emergency declarations, as well as previous Commission action in response including the March 16 announcement of a moratorium on utility disconnections until further notice.

The Notice then frames two issues:

Rapidly rising levels of unemployment in Maine and other adverse effects of the coronavirus pandemic raise questions about customers’ ability to pay their utility bills, the effect of that and of closed businesses on utilities’ accounts receivable, and the potential for significant future rate adjustments from these circumstances. Also, it is possible that federal legislation could be adopted, federal agencies’ rules amended, or policies adopted that directly affect customers’ ability to pay and utilities’ management of their operations. 

The Notice lists specific information requested by the Commission to assist it in understanding the scope of this problem and available resources. One set of questions relates to "the changing landscape of federal resources available to T&D utilities, LDCs, and their customers" including new federal legislation or changes in federal regulations or policies to assist customers in managing their utility bills or utilities in their ongoing operations and obligations under the present circumstances.

Another set of questions addresses the effect of the coronavirus pandemic on customers’ ability to pay and utilities’ accounts-receivable balances. The Commission directed electricity transmission and distribution utilities and natural gas local distribution companies to begin providing monthly reports, within 15 days, of data including accounts receivable, charge-offs, and sales and billing information.

Further regulatory action in response to the pandemic is broadly expected, whether under executive orders issued by Governor Mills, or under state and federal laws.