EIA cites record-high carbon prices in RGGI allowance market

Monday, April 5, 2021

As the U.S. federal government and most states seek to reduce emissions of carbon dioxide and other greenhouse gases in an effort to address climate change, the price of carbon emission allowances is rising in the Regional Greenhouse Gas Initiative program, the nation's oldest multistate mandatory carbon allowance market for electric generators.

The Regional Greenhouse Gas Initiative, or RGGI, was the first mandatory market-based program adopted in the United States requiring reductions in greenhouse gas emissions from the electric power sector. RGGI was founded in 2007, with Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont as the original member states. New Jersey withdrew in 2012 but rejoined in 2020, and Virginia joined in January 2021.

RGGI states agree on annual caps on total regional carbon dioxide emissions from covered power plants, with emission allowances available to generators through formal auctions and secondary markets. Fossil-fueled power plants 25MW or larger must generally purchase and hold one allowance for each short ton of CO2 emitted during the three-year control period. States generally use the proceeds of carbon allowance auctions to fund ratepayer benefits and energy efficiency programs.

RGGI.org presents full historic auction data on its website in tabular format. According to the U.S. Energy Information Administration, the auction held on March 3, 2021 "resulted in a clearing price of $7.60 per short ton of carbon dioxide (CO2), surpassing the previous high price of $7.50 per short ton reached in December 2015."

Source: U.S. Energy Information Administration

The cost of obtaining RGGI allowances falls directly on covered fossil-fueled generators. When RGGI allowances prices rise, so too does the cost of producing electricity from covered generators. RGGI allowance prices thus affect power plant economics, including the degree to which wholesale electricity market operators instruct fossil-fueled plants to run. Increased carbon prices tip the scales in favor of generation resources with lower carbon intensity, such as natural gas compared to coal and oil, or renewables or nuclear plants. At the same time, as long as any RGGI-covered generators are needed, the ultimate financial burden of RGGI compliance falls on electricity consumers who pay a price for power which includes these generators' cost of compliance.

FERC issues PacWave South wave energy license

Wednesday, March 10, 2021

US federal hydropower regulators have issued a license to Oregon State University to construct, operate, and maintain a 20-megawatt hydrokinetic wave energy test facility on the Outer Continental Shelf about 6 nautical miles offshore Newport, Oregon, in Oregon territorial waters, and onshore. The Federal Energy Regulatory Commission's March 1, 2021 Order Issuing License in docket P-14606-001 represents a significant step forward for the testing and deployment of wave energy conversion devices in US waters.

Oregon State University applied to the Commission on March 31, 2019, seeking an original license pursuant to Part I of the Federal Power Act, to construct, operate, and maintain the proposed PacWave South Hydrokinetic Project. The project would consist of four offshore test berths containing a maximum of 20 wave energy conversion devices with a maximum total installed capacity of 20 MW, anchoring systems, mooring systems, subsea connectors, five buried subsea transmission cables connecting to five separate onshore landing points, buried terrestrial transmission lines, and other facilities. 

As described in the Order Issuing License:

OSU proposes to develop the PacWave South Project in order to provide a venue for clients to test technologies that generate electricity using wave energy converters (WECs) anchored to the seafloor. Specifically the PacWave South Project would: (1) serve as a facility to allow clients to test the operation of grid-connected WEC devices; (2) refine the deployment, recovery, operations, and maintenance procedures for WEC devices; (3) collect interconnection and grid synchronization data; (4) gather information about environmental, economic, and socioeconomic effects; and (5) provide a source of hydroelectric power. OSU would oversee and manage all activities, and clients deploying WECs at PacWave South would be subject to test center protocols and procedures.

The project would be interconnected to the utility grid of the Central Lincoln People’s Utility District. Up to six WECs will be deployed during initial deployment and a maximum of 20 WECs will be deployed for the full build-out.

Because the Commission considers the Outer Continental Shelf to be "a navigable waterway and reservation of the United States", the Commission views the project as requiring to be licensed under section 23(b)(1) of the Federal Power Act. Through the order, it issued a 25-year license to Oregon State University for the project.

As licensed with mandatory conditions and staff recommended measures, the Commission found that the levelized annual cost of operating the project will be about $11,357,000, or $518.60/MWh. " Based on the same estimated average generation of 21,900 MWh, the project will produce power valued at $3,665,000 when multiplied by the alternative power cost of $167.34/MWh. Therefore, in the first year of operation, project power will cost $7,693,000, or $351.27/MWh, more than the likely cost of alternative power. Although staff’s analysis shows that the project as licensed herein would cost more to operate than the estimated cost of alternative power, it is the applicant who must decide whether to accept this license and any financial risk that entails. Although staff does not explicitly account for the effects inflation may have on the future cost of electricity, the fact that hydropower generation is relatively insensitive to inflation compared to fossil fueled generators is an important economic consideration for power producers and the consumers they serve."

The U.S. Bureau of Ocean Energy Management (BOEM) issued its lease for the PacWave South Project in February 2021, in what has been called the first-ever lease for a wave energy research project in federal waters. The BOEM lease includes 21 general conditions, which are largely administrative in nature. Additionally, the lease includes Addendum A, which describes the leased area, Addendum B, which specifies the amount of financial insurance OSU must provide to meet all lease obligations, and Addendum C, which includes lease-specific terms and conditions related to national security and military operations, archaeological requirements, and reporting and research site access requirements. As described by the Commission:

The lease and its addendums require OSU to: (1) provide and maintain at all times a surety bond or other form of financial assurance; (2) remove or decommission all facility and clear the seafloor of all obstructions within two years following lease termination, in accordance with the Commission license and any subsequent Commission approval; (3) comply with certain requirements pertaining to national security and military operations; (4) ensure that vessel operators, employees, and contractors are briefed on marine trash and debris awareness and elimination; (5) consult with BOEM before conducting any seafloor disturbing activities not authorized by the Commission license; and (6) include BOEM on the distribution of all plans, status reports, monitoring reports, annual reports, incident reports, and other reports required under the Commission license for activities on the OCS.

The project still needs several approvals to advance. OSU reportedly plans to have the facility operational in 2023.

FERC sets conferences on climate change, extreme weather, reliability, and electrification

Tuesday, March 9, 2021

US electricity regulators have scheduled a series of technical conferences to address specific issues, including a two-day event to explore issues related to "threats to electric system reliability posed by climate change and extreme weather events", and a separate event on "electrification" of sectors like transportation and heating and its implications for the grid.

On March 5, the Federal Energy Regulatory Commission issued a notice of technical conference in its "Climate Change, Extreme Weather, and Electric System Reliability" docket (AD21-13-000).  The technical conference will be held on June 1, 2021 and Wednesday, June 2, 2021 via teleconference (over WebEx).

As noted by the Commission, "Reliable electric service is vital to the nation’s economy, national security, and public health and safety, and prolonged power outages can have significant humanitarian consequences, as the nation recently witnessed in Texas and the south-central United States." The Commission's notice cites a recent report from the National Oceanic and Atmospheric Administration which found that "extreme weather events topping $1 billion in estimated damages and costs are occurring with increasing frequency", as well as the 2017 Quadrennial Energy Review which found that the "leading cause of power outages in the United States is extreme weather, including heat waves, blizzards, thunderstorms, and hurricanes."

According to the Commission, it seeks to use this proceeding "to understand the near, medium and long-term challenges facing the regions of the country; how decisionmakers in the regions are evaluating and addressing those challenges; and whether further action from the Commission is needed to help achieve an electric system that can withstand, respond to, and recover from extreme weather events." The technical conference set for June 1-2 will address "concerns that because extreme weather events are increasing in frequency, intensity, geographic expanse, and duration, the number and severity of weather-induced events in the electric power industry may also increase". 

The notice also frames future discussion of "the specific challenges posed to electric system reliability by climate change and extreme weather, which may vary by region." For example, wildfire pose major reliability challenges in some regions, while weather-driven fuel supply interruptions may be more likely to affect other areas.

In a separate docket focused on "Electrification and the Grid of the Future" (AD21-12-000), the Commission issued a notice that it will hold a technical conference on April 29, 2021, "to discuss electrification—the shift from non-electric to electric sources of energy at the point of final consumption (e.g., to fuel vehicles, heat and cool homes and businesses, and provide process heat at industrial facilities)." According to that notice, the purpose of this technical conference is "to initiate a dialog between Commissioners and stakeholders on how to prepare for an increasingly electrified future" including "projections, drivers, and risks of electrification in the United States; the extent to which electrification may influence or necessitate additional transmission and generation infrastructure; whether and how newly electrified sources of energy demand (e.g., electric vehicles, smart thermostats, etc.) could provide grid services and enhance reliability; and the role of state and federal coordination as electrification advances."

These technical conferences have potential to shape the Commission's development of policies responsive to both reliability and electrification concerns.

US electric distribution service outages vary by state

Wednesday, February 24, 2021

Recent widespread power outages in Texas are placing public and regulatory attention on the reliability of the electric grid. According to federal data, in 2019 U.S. electric distribution customers experienced an average of 4.7 hours of service interruptions -- but customers in some areas experienced more extensive outages, such as in Maine where the average total interruption time in 2019 exceeded 15 hours.

The U.S. Energy Information Administration tracks and analyzes data regarding various aspects of the nation's energy sector, including statistics describing the frequency, duration, and extent of electric distribution service outages. EIA's utility outage data can be further segmented to include or exclude outages related to "major events" such as the effects of severe weather. 

For 2019, EIA reports that "U.S. customers experienced an average of 3.2 hours of interruptions during major events and 1.5 hours of interruptions without major events, or nearly 5 hours total." With major events included, EIA reports an average total interruption of 284 minutes, which EIA described as "nearly half the average interruptions experienced in 2017, a year with more hurricanes, wildfires, and severe storms." With major events excluded, EIA reports that the average duration of interruptions customers experienced in 2019 was 92 minutes, which EIA characterized as "relatively consistent with previous years."

Source: U.S. Energy Information Administration, U.S. power customers experienced an average of nearly five hours of interruptions in 2019 (November 6, 2020).
According to EIA, "Many factors cause power interruptions, including weather, vegetation patterns, and utility practices." EIA also identified geographic variation among states with respect to total outage duration in 2019:

Customers in Maine, West Virginia, California, Michigan, and Mississippi experienced the longest total time interrupted in 2019. In these states, the long power interruption durations were caused by major events such as winter storms (in Maine) or wildfires (in California). In addition, Maine and West Virginia are heavily forested states where power interruptions resulting from falling tree branches are common. The average customer interruption time in these five states in 2019 ranged from almost 7 hours in Mississippi to more than 15 hours in Maine. 

Maine has previously ranked at the top of EIA's list of state average customer total outage duration per year; in 2017, EIA data showed that the average Maine customer experienced 42 hours of service interruption.

By contrast, EIA reports that electricity customers in jurisdictions including the District of Columbia, Nebraska, Arizona, Nevada, and Florida had the shortest average total time interrupted in 2019, ranging from 77 minutes in the District of Columbia to 88 minutes in Florida.

Selected 2021 Maine legislation on energy and climate

Thursday, January 28, 2021

Here is a round-up of selected energy- and climate-related legislative bills pending before the 130th Maine Legislature and printed as of January 28, 2021:

LD 9 (SP16) An Act To Promote Renewable Energy by Authorizing a Power-to-fuel Pilot Program 

LD 82 (HP48) Resolve, To Provide for Participation of the State in the Planning and Negotiations for the Atlantic Loop Energy Project

LD 87 (HP53) An Act To Implement the State Climate Action Plan, Reduce Greenhouse Gas Emissions and Enhance Maine's Economy

LD 99 (HP65) An Act To Require the State To Divest Itself of Assets Invested in the Fossil Fuel Industry

LD 101 (HP67) An Act To Prohibit Offshore Wind Energy Development

LD 143 (HP99) An Act To Make the Arrearage Management Program Permanent

LD 170 (HP123) An Act Pertaining to Transmission Lines Not Needed for Reliability or Local Generation

LD 179 (HP132) An Act To Exclude Energy Efficiency Improvements from Property Tax

LD 201 (SP90) An Act To Reduce Greenhouse Gas Emissions and Promote Weatherization in the Buildings Sector by Extending the Sunset Date for the Historic Property Rehabilitation Tax Credit

LD 226 (HP161) An Act To Limit the Use of Hydrofluorocarbons To Fight Climate Change

LD 249 (SP111) An Act To Eliminate the Current Net Energy Billing Policy in Maine

LD 251 (HP172) An Act Regarding Public Utility Assessments, Fees and Penalties

Selected Maine PUC 2021 reports and communications

Wednesday, January 27, 2021

Here's a roundup of selected recent communications from the Maine Public Utilities Commission to the state legislative committee with jurisdiction over energy matters, as of late January 2021. This resource is meant to facilitate finding these documents.

The Maine Public Utilities Commission submitted a report to the Maine State Legislature's Committee, titled, "Report on the Community-Based Renewable Energy Pilot Program", dated January 15, 2021. The report provides information on the status of a "community-based renewable energy pilot program" created by a state law enacted in 2009. That law encouraged the development of small, "community-based" renewable generation by authorizing long-term contracts for the purchase of electricity produced by renewable generators of 10 megawatts or smaller for a term of up to 20 years at a price of up to 10 cents per kilowatt-hour. The program required that 51% or more of the facility must be owned by qualifying local owners. The program was limited in scale and duration, with an aggregate cap of 50 MW for all participating projects, and deadlines requiring contracts to be approved by 2015 and projects to begin generating electricity no later than December 31, 2018. In the end, the Commission reports that seven projects totaling 36.8 MW of installed generating capacity achieved commercial operations by the deadline, with contract pricing terms ranging from 8.45 to 10 cents per kWh, and above-market costs of $14,932,920 for the twelve months ending 11/30/2020.

On January 26, 2021, Maine Public Utilities Commission chair Philip Bartlett delivered two presentations to the Joint Standing Committee on Energy, Utilities and Technology, titled, "Introduction to the Maine PUC" and "Review of the Electric Industry in Maine". The introduction provides an overview of the Commission, its jurisdiction and activities. The electric industry review covers delivery and supply components of electricity service and rates, Maine's retail and wholesale markets, and "recent and emerging issues" related to transmission and distribution utilities and to renewable policies and programs.

The Maine PUC also submitted the Maine Public Utilities Commission 2020 Annual Report, dated February 1, 2021. The Commission's 2020 annual report provides an overview of the agency's work in 2020 administering the laws concerning public utilities in Maine. Highlights noted by the Commission include:

  • Reductions in the cost of standard offer energy supply service for residential and small business consumers;
  • Completion of work on a proceeding relating to utility Central Maine Power Company's metering and billing;
  • A related rate investigation leading to an order reducing the utility's return on common equity (a disallowance which the Commission called "the largest ever imposed by the Commission on a transmission and distribution utility due to poor management" and which the Commission said will likely lead the utility to "have the lowest common equity return of any electric utility in the country"); and
  • Approval of 17 renewable energy projects for long-term contracts pursuant to a recently enacted law.

These reports follow two others dated November 10, 2020, in which the Commission reported to the legislative energy committee on two programs established or modified by the enactment of a 2019 law: a Report on the Effectiveness of Net Energy Billing in Achieving State Policy Goals and Providing Benefits to Ratepayers and a Report on Renewable Distributed Generation Solicitation.

FERC inquires re hydro financial assurance

Tuesday, January 19, 2021

Federal hydropower regulators in the U.S. are considering changes to the way financial assurance measures are incorporated into hydroelectric project approvals, and have requested public comment on whether and how hydro projects should be made to provide financial assurance to cover the costs of compliance with their license terms.

Under the Federal Power Act, the Federal Energy Regulatory Commission has jurisdiction over many hydroelectric developments in the U.S. On January 19, 2021, the Commission issued a Notice of Inquiry seeking public comment on whether and how the Commission "should require financial assurance measures in licenses and other authorizations for hydroelectric projects to ensure that licensees have the capability to carry out license requirements and, particularly, to maintain their projects in safe condition."

In the Notice of Inquiry and a related staff presentation, the Commission notes steps it has taken to protect against the "failure of a licensee's financing planning" such as the inclusion of a "financing plan article" in recently issued licenses which requires licensees to show that they have the necessary funds to complete project construction and to operate and maintain the project. However, most FERC-issued hydro licenses do not include such a clause, because most existing hydropower licenses were issued before the Commission began this practice. Moreover, the Commission has noted that the financing plan requirement focuses on normal project expenses, not unexpected major costs.

The inquiry is prompted in part by dam failures in Michigan in May 2020, events the Commission staff pointed to in observing that "non-operational or non-compliant projects can pose public safety and environmental hazards in the event of a dam failure or breach." Staff noted that while significant dam failures have been rare, "Commission staff is aware of a number of projects that are non-operational or out of compliance with their license conditions and where licensees have stated that they cannot afford to operate or maintain the projects or implement the required environmental or safety measures."

Citing "concern that inadequate financing may result in threats to public safety and environmental resources", the Notice of Inquiry seeks public comment on when the Commission should require financial assurance from licensees -- whether in original licenses, on relicense, or in other authorizations such as transfers -- and whether the Commission should require licensees to reaffirm or recertify that they have adequate financial assurance instruments in place.

The Notice of Inquiry describes three potential options identified by Commission staff:  

(1) requiring licensees to obtain bonds to cover the costs of safety measures and project operation and maintenance; (2) establishing an industry-wide trust or remediation fund or requiring licensees to maintain an individual trust, escrow, or remediation fund; or (3) requiring licensees to obtain insurance policies for unforeseen safety hazards or dam failures.