Maine PUC opens net metering inquiry

Monday, July 6, 2020

Maine is approaching or has passed a net metering milestone, as state utility regulators have opened an inquiry triggered by a statute calling for an evaluation when the total amount of generation capacity involved in net energy billing in Maine reaches 10% of the state's transmission and distribution utilities' total maximum electric load.

In 2019, the Maine state legislature enacted a law that substantially reformed Maine's net energy billing (NEB) programs. Major changes included allowing larger projects to participate (less than 5 megawatts, up from 660 kilowatts); removing any limit on the number of meters or accounts that can be associated with an eligible facility; replacing an ownership requirement with a more flexible “financial interest” requirement; and adopting an additional alternative “commercial and institutional” NEB program providing monetary bill credits instead of volumetric bill credits. These changes, in addition to other enactments and broader dynamics in energy markets, have led to a significant increase in interest in Maine net metering.

The 2019 law also included a requirement that the Maine Public Utilities Commission evaluate net energy billing "when the total amount of generation capacity involved in net energy billing in the State reaches 10% of the total maximum load of transmission and distribution utilities in the State or 3 years after the effective date of this Act, whichever comes first." The law requires the Commission to evaluate the effectiveness of net energy billing in achieving state policy goals and providing benefits to ratepayers, and to report its findings to the legislative energy committee.

On May 20, 2020, Maine's largest investor-owned transmission and distribution utility, Central Maine Power Company (CMP), provided notice that, at that time, the cumulative capacity of the generating facilities for which CMP has executed NEB arrangements under Chapter 313 was approximately 10.1% of CMP’s annual peak demand.

In response, on July 6, the Commission issued a Notice of Inquiry to obtain information for an evaluation of the state's NEB programs. The Notice emphasizes that the Commission itself will not alter NEB as a direct result of the Inquiry, but rather that any changes would come from the Legislature:
At the outset, the Commission emphasizes that CMP's 10% notification and the initiation of this Inquiry to gather relevant information for the required evaluation does not implicate any suspension of the programs governed by the existing NEB rules (Chapter 313) which, as noted above, have been authorized by the Act. Any changes to these programs, including to their availability, can only occur through the legislative process. 
The Notice directs Maine's two investor-owned utilities, CMP and Versant Power, to provide a monthly report on NEB projects, categorized in various ways, including by status (operational, non-operational but NEB-agreement-executed, or application-pending), and by program (kWh or monetary). For each project, each utility must provide specific information, including contact person, project location and size, resource type, new vs. previously existing, in-service date, “For NEB kWh Credit projects, estimated lost revenue ($/year)”, “For Tariff Rate projects, estimated costs (gross and net) of the credits ($/year)”, “Estimated incremental administrative costs associated with each of the two programs, by category ($/year)”, and “Information about T&D system benefits, e.g., avoided distribution upgrades, or system costs, e.g., required system reinforcements associated with NEB projects”.

Retail net metering programs such as Maine's forms of net energy billing have been adopted by regulators and utilities in nearly every U.S. jurisdiction. Utilities traditionally argue that net metering imposes costs on the system or on ratepayers. Some net metering proponents have historically countered that net metering provides substantial benefits to the system and to ratepayers, and that any theoretical downsides are nonexistent or minimal at low levels of net metering penetration, while others have argued that the system can safely and reliable handle larger amounts of net metering on the system.

Crypto miner seeks to export US electricity for Canadian servers

Friday, June 26, 2020

In what has been called "a maiden effort by an energy-hungry cryptocurrency-mining industry to import electricity from the United States to Canada to meet its significant power demands", a Canadian company has applied to the U.S. Department of Energy for authority to export power from the U.S. into Canada to power blockchain-related computer servers -- but a nonprofit advocacy group has warned that federal approval of this "first-ever application to export power by a cryptocurrency miner" may result in a rush of similar applications.

Under U.S. federal law, the Department of Energy regulates exports of electricity from the United States to a foreign country, which require authorization under section 202(e) of the Federal Power Act. On May 21, 2020, DMG Blockchain Solutions Inc. filed an application with the U.S. Department of Energy, seeking authority under the Federal Power Act to transmit electric energy from the United States to Canada for a term of five years.

According to the website dmgblockchain.com, "DMG is a diversified cryptocurrency and blockchain platform company that is focused on the two primary opportunities in the sector – mining public blockchains and applying permissioned blockchain technology. DMG focuses on mining bitcoin, providing hosting services for industrial mining clients, earning revenues from block rewards and transaction fees, developing data analytics and forensic software products, working with auditors, law firms, and law enforcement to provide technical expertise, DMG’s permissioned blockchain technology is focused on developing enterprise software for the supply chain management of controlled products."

DMG's application to the Department of Energy describes the company as "a consumer of power, whose primary business is to host servers whose primary function is to ensure the security of public blockchains as well as other high-performance computing applications." DMG's application notes, "This business requires large amounts of power, which DMG is currently consuming approximately 15 megawatts on a steady load basis and has plans to grow to up to 60 megawatts in the next year with potentially larger amounts in the future as DMG may add new facilities." The application requests DOE export authorization over any of a long list of cross-border transmission facilities with Presidential Permits, in states including Maine, Vermont, New York, Pennsylvania, Michigan, Minnesota, North Dakota, Montana, and Washington.

But at least one entity has weighed in to urge the Department of Energy to proceed with caution, as it considers this request to export electricity to power foreign blockchain servers and computers. A Motion to Intervene and Comment filed with the Department of Energy on June 25, 2020, by watchdog organization Public Citizen, Inc. frames that organization's concern:
Despite cryptocurrency mining’s status as a relatively immature industry, its alarming power consumption footprint raises concerns about its sustainability and suitability in localized power markets, resulting in moratoria on new cryptocurrency mining operations issued by select U.S. utility districts and government agencies.
Citing language in Section 202(e) of the Federal Power Act requiring applications to export electricity to neither “impair the sufficiency of electric supply within the United States” nor “impede the coordination in the public interest of facilities subject to the jurisdiction of the Commission", Public Citizen commented:
Cryptocurrency mining is extraordinarily energy-intensive and can lead to major strains on local U.S. power supplies. At the same time, the process of mining is designed in a manner that wastes the overwhelming majority of the energy it consumes. U.S. cryptocurrency miners are struggling to meet their own power demands. This appears to be the first-ever application to export power by a cryptocurrency miner, and approval may result in a rush of similar applications.
Public Citizen's comments assert that this "maiden effort by an energy-hungry cryptocurrency-mining industry to import electricity from the United States to Canada to meet its significant power demands... raises serious, potentially fatal concerns under section 202(e)." Public Citizen concludes that the Department should proceed with extreme caution and "likely should deny the application or, if granting it, place conditions on it."

The pending export authorization proceeding before the U.S. Department of Energy is OE Docket No. EA-482, DMG Blockchain Solutions Inc. Application To Export Electric Energy.

FERC cybersecurity incentives staff white paper

Friday, June 19, 2020

U.S. electricity regulatory staff have issued a “white paper” report discussing a potential new framework for providing transmission incentives to utilities for cybersecurity investments, under federal law. According to the Cybersecurity Incentives Policy White Paper issued by the staff of the Federal Regulatory Commission on June 18, 2020, existing transmission incentives and Critical Infrastructure Protection (CIP) Reliability Standards are sufficient to maintain an adequate level of reliability – but staff suggests that additional “transmission incentives to counter the evolving and increasing threats to the cybersecurity of the electric grid may be warranted.”After summarizing the background history of federal regulation of electric utility cybersecurity, the staff paper presents a “new framework for providing transmission incentives to utilities for cybersecurity investments that produce significant cybersecurity benefits for actions taken that exceed the requirements of the [CIP Reliability Standards].”

The staff paper opens with an overview of staff’s perception of cybersecurity threats to the Commission-jurisdictional Bulk Electric System (BES), along with the work of the Commission and electric reliability organization NERC to adopt and enforce mandatory CIP Reliability Standards pursuant to the Energy Policy Act of 2005. The initial CIP Reliability Standards were approved by the Commission in 2008, and they have been modified several times to address new technologies and “the evolving nature of cyber-related threats to the bulk power system.”

According to the staff paper, as of mid-June 2020, the CIP Reliability Standards “consist of 13 standards specifying a set of requirements that registered entities must follow to ensure the cyber and physical security of the bulk power system” including 10 active cybersecurity standards, 1 active physical security standard, and two cybersecurity standards which will take effect in the near future.

The report next addresses “why there is a need to adopt a new approach to incentivize cybersecurity investments.” According to the white paper, “While the CIP Reliability Standards form an effective technical baseline for cybersecurity practices, they have certain limitations.” According to staff, the standards do not necessarily require covered entities to adopt best practices, and the process through which mandatory standards are developed is poorly suited to agile action in response to emerging or evolving needs.
For these reasons, this staff paper discusses augmenting the current CIP Reliability Standards under FPA section 215 with an incentive-based approach under FPA section 219 that encourages utilities to undertake cybersecurity investments on a voluntary basis. This approach would incentivize a utility to adopt best practices to protect its own transmission system as well as improve the security of the BES. Further, it could allow the industry to be more agile in monitoring and responding to new and (un)anticipated cybersecurity threats, to identify and respond to a wider range of threats, and to address threats with comprehensive and more effective solutions. An incentive-based approach allows a utility to tailor its request for incentives to the potential challenges and responsive actions that it faces. In the future, these voluntary actions taken by utilities, if proven beneficial, could be the basis of future CIP Reliability Standards that are mandatory.
As noted by staff, if the Commission wants to provide transmission incentives for cybersecurity investments, the Commission may need to “establish a new framework for evaluating requests for transmission incentives by utilities for cybersecurity investments.” Staff suggests that “a first necessary step is to establish approaches that examine the effectiveness of cybersecurity investments in enabling the utility to achieve a level of protection that exceeds the CIP Reliability Standards but also enhances the security of its transmission system.”

According to the whitepaper, this kind of evaluation will enable utilities to “identify the cybersecurity investments for which it seeks transmission incentives” and the Commission to “evaluate such transmission incentive requests”. In the whitepaper, staff discusses traditional ratemaking incentives available to transmission projects, and how the Commission could apply these incentives in the context of cybersecurity; two possible ways to evaluate which cybersecurity investments warrant incentives; and a proposed process for utilities to apply for cybersecurity incentives.

Staff invited interested parties to file comments on the staff paper and on 11 sets of specific questions it identifies, with comments due within 60 days of the paper’s issuance and reply comments due within 75 days of its issuance.

FERC sets carbon pricing and offshore wind tech conferences

Thursday, June 18, 2020

U.S. federal electricity regulators have scheduled technical conferences for this autumn to discuss issues related to two major policy initiatives: carbon pricing in organized wholesale electricity markets, and offshore wind integration in regional transmission organizations and independent system operators (RTOs/ISOs). The Federal Energy Regulatory Commission's scheduling of two technical conferences on these topics signals its interest in exploring the interplay between state energy and environmental policies and federally jurisdictional markets.

One technical conference regarding Carbon Pricing in Organized Wholesale Electricity Markets (Docket No. AD20-14-000) will be held on September 30, 2020, "to discuss considerations related to state adoption of mechanisms to price carbon dioxide emissions, commonly referred to as carbon pricing, in regions with Commission-jurisdictional organized wholesale electricity markets." The case has its genesis in a request for such an event, filed on April 13, 2020, by a broad coalition including Advanced Energy Economy, the American Council on Renewable Energy, the American Wind Energy Association, Brookfield Renewable, Calpine Corporation, Competitive Power Ventures, Inc., the Electric Power Supply Association, the Independent Power Producers of New York, Inc., LS Power Associates, L.P., the Natural Gas Supply Association, NextEra Energy, Inc., PJM Power Providers Group, R Street Institute, and Vistra Energy Corp. A number of other utilities, RTOs, and state interests also expressed support, prior to the Commission's issuance of a public notice on June 17 scheduling the event.

Another technical conference regarding Offshore Wind Integration in RTOs/ISOs (Docket No. AD20-18-000), to be held October 27, 2020, will be convened "to discuss whether existing Commission transmission, interconnection, and merchant transmission facility frameworks in RTOs/ISOs can accommodate anticipated growth in offshore wind generation in an efficient and effective manner that safeguards open access transmission principles and to consider possible changes or improvements to the current framework should they be needed to accommodate such growth."

Beyond the fact that the Commission issued notices of both technical conferences on June 17, 2020, the proceedings also share a common focus on the effects of state energy and environmental policies on federally-jurisdictional activities. For now, the prevailing carbon pricing mechanisms -- such as the Regional Greenhouse Gas Initiative adopted by many northeastern states -- and the strongest policies favoring or requiring offshore wind development are arising as a matter of state law and policy, as opposed to federal law.

The boundaries between federal and state jurisdiction are viewed by many as long-settled, although a series of federal court and agency decisions have found specific state electricity procurement and subsidy laws to be preempted by federal regulation, and a case pending before the Commission asks it to find that most state net metering programs are preempted by federal law. Whether the Commission grants or denies the pending request, the June 17 notices of technical conferences on carbon pricing and offshore wind integration suggest continued federal interest in exploring the implications of state policies on FERC-jurisdictional markets.

Maine EV utility make ready pilot tariff filed

Wednesday, June 3, 2020

Central Maine Power Company has requested that the Maine Public Utilities Commission approve terms and conditions for a new "Electric Vehicle Charging Station Make Ready Pilot Program", as part of a utility proposal selected by the Commission for inclusion in a beneficial electrification pilot program.

In 2019, 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 focused on beneficial electrification, 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." 

Maine's transportation sector has been responsible for most of the state's greenhouse gas emissions in recent years. As a form of beneficial electrification, electric vehicles have potential to displace petroleum used in the transportation sector with lower-carbon electricity. Maine and other jurisdictions are exploring incentives and other programs to encourage electric vehicle adoption, including utility make-ready programs, tax credits, and favorable utility tariff rates for EV charging service.

Among other measures, the beneficial electrification law required the Public Utilities Commission to solicit proposals for pilot programs to support the beneficial electrification of Maine’s transportation sector. On February 25, 2020, the Commission selected CMP’s proposal to offer CMP-owned infrastructure up to the meter or up to the electric vehicle charging pedestal to customers installing Level 2 electric vehicle charging stations and who meet the qualifications for participation in the program.

CMP has now filed the EV make ready pilot program's terms and conditions for Commission approval. As proposed, the Optional Targeted Service Rate B-DCFC General Service - Electric Vehicle Direct Current Fast Charger program would be open for customer application from July 31, 2020 "until electric vehicle charging stations totaling 60 plugs are selected by the Company for participation and put into service", with a cap of $4,000 per CMP-provided plug.

CMP asks the Commission to approve the Electric Vehicle Charging Station Make Ready Pilot Program tariff by July 1, 2020.

US consumed more renewables than coal in 2019

Monday, June 1, 2020

United States consumers used more energy from renewable sources than from coal in 2019, the first time that national renewable energy use has exceeded coal since at least 1885, according to recently released federal data. Continued significant decreases in coal consumption, combined with increases in renewable energy consumption, largely explain the phenomenon.

The U.S. Energy Information Administration tracks the domestic production and consumption of energy resources. According to EIA, wood dominated historic energy use until the mid-1800s; by the 1880s, hydropower plants and coal-fueled thermal power plants were increasingly used to provide electricity. By 1885, EIA's model shows a higher level of coal consumption than for renewable energy, and coal's share of domestic energy consumption remained above renewables for the following 133 years.

Coal's share of U.S. energy consumption peaked around the first decade of the new millenium, and has generally declined since then. In 2019, EIA data shows U.S. coal consumption decreasing for a sixth consecutive year, reaching 11.3 quadrillion Btu -- the lowest level since 1964. EIA attributes this largely to reductions in the use of coal to generate electricity, which reached its lowest level in 42 years in 2019.

Meanwhile, total domestic renewable energy consumption grew for the fourth consecutive year in 2019, setting a new record of 11.5 quadrillion Btu. EIA says the growth in U.S. renewable energy since 2015 is "almost entirely attributable to the use of wind and solar in the electric power sector", with wind surpassing hydro as the dominant renewable resource for the first time.

The overall 2019 result was preceded by a finding that renewable production exceeded coal production in the month of April 2019. Last year also saw other records set as well, including an excess of U.S. energy production over consumption for the first time since 1957.

New England winter electricity costs decreased

Thursday, May 28, 2020

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."