California Utility Regulators Open Public Inquiry on High Winter Natural Gas Prices

March 17, 2023

by Paul Ciampoli
APPA News Director
March 17, 2023

The California Public Utilities Commission on March 16 launched a proceeding to investigate the causes and impacts of the winter 2022- 2023 natural gas price spikes and the potential for recurrence and the impact of the price spikes on natural gas and electric prices and customer bills.

The proceeding will also look at the potential threats to natural gas and electric reliability and price volatility in summer 2023 and beyond, and potential mitigations and utility communications to customers to determine whether they were sufficient or require modifications.

The wholesale price of natural gas in California, and throughout the Western U.S., has been extraordinarily high this winter, starting in late November 2022.

In February 2023, natural gas prices trended downward but are still high compared to February 2022. As a result, customers have seen higher bills from their utility company, which pass on the cost they pay for natural gas directly to the customer without a mark-up, the PUC said.

The examination in the proceeding opened March 16 will include whether factors beyond normal market forces were at play, determine whether action by the CPUC may prevent or mitigate future price spikes, and consider whether other entities have jurisdiction to mitigate high natural gas prices.

The proposal voted on is available here.

Heartland Energy Says it is Well Positioned to Help Minn. Cities Comply With New Carbon-Free Law

March 16, 2023

by Paul Ciampoli
APPA News Director
March 16, 2023

Heartland Energy, which provides wholesale electric power to six cities in Minnesota, recently said that it is well positioned to meet new climate standards in Minnesota on behalf of the municipal utilities it serves in the state.

Officials with Heartland Energy say its diverse power supply portfolio, which includes the output from a 51-megawatt wind farm, will help Minnesota customers meet the carbon requirements.

Electric utilities in Minnesota are facing new climate standards under a law recently signed by Governor Tim Walz. By the year 2040, utilities must meet a goal of having 100% of their electricity come from carbon-free sources.

Opponents of the mandate said it will be costly for smaller, rural utilities that may be unable to meet the requirements.

In addition to the carbon-free deadline, the new law requires utilities to show 55% of their energy sales come from renewable sources, such as wind and solar, by the year 2035.

Utilities that rely on other sources for the majority of their power supply do have options to meet this goal. They can instead pay for renewable energy credits, or RECs, which are proof that electricity was generated by a renewable energy source and delivered to the electric grid.

Each time one megawatt-hour of electricity is generated from a qualifying resource, such as wind or solar, one REC is created. If you own the resource, you own the REC generated. Once a REC is created, it may be sold or claimed and retired. Retiring a REC allows a utility to officially validate the amount of renewable energy supplied to customers.

Heartland Energy’s qualifying resource is the Wessington Springs Wind Energy Center located in Jerauld County, South Dakota. Heartland Energy purchases the full output of the 34-turbine wind farm through a long-term purchase power agreement with NextEra Energy. 

Heartland Energy already retires the appropriate number of RECs supplied by the WSW Energy Center to meet Minnesota’s current renewable standard of 25% by the year 2025.

Heartland Energy Chief Operations Officer Nate Jones said the WSW Energy Center produces enough RECs to meet Minnesota’s new mandate as well.

“We are well-prepared to adequately supply our customers in Minnesota with renewable energy to meet the new standard of 100% by 2040 and beyond,” said Jones.

Based in Madison, SD, Heartland Energy also provides a suite of customer service programs including economic development, energy efficiency, cybersecurity and more.

Federal Budget Proposal Includes Excise Tax on Cryptocurrency Mining

March 13, 2023

by Paul Ciampoli
APPA News Director
March 13, 2023

President Biden is proposing a 30 percent excise tax on electricity used to mine for cryptocurrency as part of his Fiscal Year 2024 budget submission to Congress released on March 9.

“An excise tax on electricity usage by digital asset miners could reduce mining activity along with its associated environmental impacts and other harms,” the Treasury Department wrote in an explanation of the President’s revenue proposals.

Under the Digital Asset Mining Energy Excise Tax any firm using computing resources, whether owned by the firm or leased from others, to mine digital assets would be subject to an excise tax equal to 30 percent of the costs of electricity used in digital asset mining.

The proposal would be effective for taxable years beginning after December 31, 2023. The excise tax would be phased in over three years at a rate of 10 percent in the first year, 20 percent in the second, and 30 percent thereafter. The Treasury Department estimates it would raise approximately $3.5 billion over the next decade.

Firms engaged in digital asset mining would be required to report the amount and type of electricity used as well as the value of that electricity, if purchased externally. Firms that lease computational capacity would be required to report the value of the electricity used by the lessor firm attributable to the leased capacity, which would serve as the tax base. Firms that produce or acquire power off-grid, for example by using the output of a particular electricity generating plant, would be subject to an excise tax equal to 30 percent of estimated electricity costs.

The President is also proposing expanding the Low Income Home Energy Assistance Program to allow for the provision of water assistance. To help pay for the expanded scope of the program, the budget would increase regular annual funding by $111 million to $4.1 billion. The budget does not propose repeating emergency appropriations for the program.

Texas Grid Operator Expects Capacity Will be Sufficient to Meet Spring Forecasted Peak Demand

March 13, 2023

by Paul Ciampoli
APPA News Director
March 13, 2023

Assuming that the Electric Reliability Council of Texas region experiences typical spring grid conditions, ERCOT anticipates that there will be sufficient installed generating capacity available to serve the system-wide forecasted peak demand for the upcoming spring season, the grid operator said on March 8.

The forecasted April and May peak demands are 59,505 megawatts and 69,921 MW, respectively. These
forecasts are based on average weather conditions at the time of the spring peaks for years 2007
through 2021.

The Seasonal Assessment of Resource Adequacy report does not contain a weather forecast for the spring season. The forecasts also incorporate expected load increases during the peak demand hour due to interconnection of large loads (such as crypto-mining facilities) to transmission service provider networks.

Almost 99,800 MW of spring-rated resource capacity is expected to be available for the spring peak
demand. One thermal generation resource — a coal-fired unit with a 610 MW spring rating — is out of
service for the duration of the spring season. Also, a gas-fired unit with a spring capacity rating of
568 MW has changed its operating period to summer-only.

The total resource amount also includes 844 MW of battery storage capability assumed to be available for dispatch prior to the highest spring net load hours. 

This capacity estimate serves as a proxy for the amount expected during a tight reserve hour for the upcoming spring and is an interim availability assumption to be used until a formal capacity contribution method is adopted for future reports, ERCOT noted.

The report also identifies the aggregate amount of installed generation capacity where large loads,
such as crypto-mining facilities, are directly interconnected, and the expected peak reduction in
available generation capacity attributable to these loads during spring hours with the highest risk of
insufficient reserve capacity.

The spring SARA includes a typical thermal generating unit outage assumption of 19,536 MW for
the spring generator maintenance window (March-April) and 15,979 MW at the time of the
forecasted spring peak load in May. These outage assumptions are based on historical outage data
for the last three spring seasons excluding 2021 (2019, 2020, 2022).

Spring 2021 outages were excluded to avoid including Winter Storm Uri-related outages that extended into the spring season.

The spring SARA includes two risk scenarios — base and moderate risk scenarios, and extreme
risk scenarios. The most severe risk scenario assumes a forecasted May peak load with extreme
unplanned thermal plant outages based on historic observations, combined with extreme low wind
power production.

Parties Execute Funding Agreements Tied to Development of SPP Market

March 11, 2023

by Peter Maloney
APPA News
March 11, 2023

Several parties, including two public power utilities, have executed funding agreements for the development of Markets+, Southwest Power Pool’s western energy market.

The parties signing funding agreements are Arizona Public Service, Bonneville Power Administration, Chelan County Public Utility District, NV Energy, Powerex Corp., Puget Sound Energy, Salt River Project, and Tucson Electric Power.

The next phase of Markets+ development will begin immediately, ahead of the planned April 1 start date, SPP said.

SPP also executed stakeholder agreements with participants that do not serve load or own generation but, while not contributing to funding Markets+ in phase one, will participate in the development of the Markets+ stakeholder process.

Together, the participating entities operate a diverse mix of generating resources and serve more than 250,000 gigawatt-hours per year in the Western Interconnection, representing more than 40 gigawatts of peak demand.

During the initial development phase, stakeholders and SPP staff will collaborate to develop the market protocols, tariff and governing documents for Markets+, as well as major components of Markets+ governance structure, including the Markets+ Participants Executive Committee, Market Design Working Group, Transmission Working Group, and Seams Working Group.

For more than a year, SPP has worked with western stakeholders to develop a proposed day-ahead and real-time market that meets the needs of western utilities to centralize unit commitment and dispatch, bring additional savings to customers, and pave the way for the reliable integration of a rapidly growing fleet of renewable generation.

“The Bonneville Power Administration’s contribution to phase one funding of SPP Markets+ is an investment that we expect to provide multiple benefits to BPA and its customers,” John Hairston, BPA Administrator and CEO, said in a statement. “Markets such as this are the future of operations in the West, and this ensures BPA and its customers will keep pace and help shape these important initiatives.”

BPA announced its commitment to funding phase one development of Markets+ Feb. 24.

SPP released the proposal for its western energy market Nov. 30, 2022. Additional parties interested in committing to funding further market development must sign a Markets+ Market Participant Phase One Funding Agreement by April 1, 2023.

PJM Begins Expedited Process for Reform of Capacity Auction

March 8, 2023

by Peter Maloney
APPA News
March 8, 2023

PJM Interconnection and its stakeholders have begun an expedited process to address capacity market design issues related to maintaining resource adequacy.

The PJM Board implemented the Critical Issue Fast Path process by letter on Feb. 24, citing a PJM report, Energy Transition in PJM: Resource Retirements, Replacements and Risks.

The letter noted that while PJM “currently has a healthy reserve margin, Winter Storm Elliott demonstrated that PJM is not immune to reliability challenges as the system was stressed, even with a reserve margin in excess of the target and a lower level of renewable penetration than other regions.”

Although PJM maintained grid reliability throughout Winter Storm Elliott, “we believe this event demonstrates a need to focus on PJM’s rules and processes to ensure reliability is maintained both now and throughout the transition,” the letter said.

PJM has “healthy reserve margins,” but that “cannot be taken for granted into the future,” PJM said in the letter, noting that up to 40 gigawatts of capacity in the regional transmission organization, whose territory includes a large swath of Mid-Atlantic and Midwestern states, is at risk of retirement by 2030.

The PJM report also highlighted “significant uncertainty around the pace of resource additions, which at current completion rates would be inadequate to maintain resource adequacy.” In addition, the potential also exists for “significant load growth in the future, driven by data center additions and electrification of transportation, heating and industry,” PJM said.

In initiating the Critical Issue Fast Path process for resource adequacy, PJM’s board of directors identified four areas for stakeholders to focus on in the CIFP process:

• improvements in the way PJM accounts for winter risk and correlated outages in reliability planning,
• evaluation of changes to PJM’s capacity performance construct to ensure market seller offers may properly reflect the risk of taking on a capacity obligation,
• enhancement of resource accreditation to ensure resource reliability attributes are accurately determined and compensated, and
• means of ensuring comparable treatment of resources by aligning capacity market changes with appropriate adjustments to PJM’s Fixed Resource Requirement.

These areas are considered as “must haves,” Adam Keech, PJM vice president of market design and economics, said during a Feb. 28 meeting of PJM’s Resource Adequacy Senior Task Force. “These will be the centerpiece of the PJM proposal,” Keech said, adding, “the board is open to solutions across the spectrum that align with their objectives.”

This fast-track process will inform a decision by PJM’s board by late summer, and the organization aims to file its proposal with the Federal Energy Regulatory Commission on Oct. 1.

Capacity auctions normally occur three years before the capacity delivery date, but the reforms under way in PJM have caused delays for several capacity auctions. PJM hopes to have its capacity auction schedule back on track for the 2027/2028 auction, which is now scheduled for May 2024, but PJM’s board is seeking stakeholder feedback on whether prior year auctions that have not been run, the 2025/2026 and 2026/2027 auctions, should be adjusted or pushed back.

NREL Report Sums Up Benefits of a Broader RTO for California And The West

March 7, 2023

by Peter Maloney
APPA News
March 7, 2023

California could benefit from a widespread electric power grid in the West, according to a new report from the National Renewable Energy Laboratory.

The study, The Impacts on California of Expanded Regional Cooperation to Operate the Western Grid, is the final report in a series of studies authorized by California’s legislature.

The studies reviewed for the report “demonstrate that California’s goals for renewable energy and greenhouse gas reduction can be achieved more quickly and with less cost to Californians through expanded regional cooperation,” the authors wrote. “The magnitude of those benefits will vary based on the mode of cooperation and on the states and utilities that elect to participate,” they added.

As an example, the authors noted that the total benefits to California of a West-wide extended day-ahead energy market operated by the California Independent System Operator were less than the estimated benefits of a West-wide regional transmission organization, an option that was identified by the California legislature.

RTOs tend to yield “greater cost savings and grid flexibility than more limited forms of cooperation,” the report’s authors said. In addition, the RTO option would not remove the jurisdiction of California, or any other state, over its retail rates, resource planning, resource siting, transmission siting, renewable energy policies, or emissions reduction policies, the report noted, but it would very likely require changes to CAISO’s governance.

For the rest of the western United States, however, an extended day-ahead market retained a slightly larger portion of expected benefits of a full RTO, according to the report. Some of the technical studies reviewed in the report suggest the benefits of more comprehensive forms of regional cooperation such as a West-wide RTO might not be spread evenly across participating states and utilities, the authors noted.

Transmission planning across a region, rather than by individual utilities, can reduce transmission congestion costs and the cost of operating reserves required to maintain reliability, leading to more efficient use of the transmission system and greater reliability for customers, the report found.

Other benefits include less curtailment of solar and wind resources because of congested transmission paths and the ability to move excess wind and solar power elsewhere in the region when local production is high and demand is low, the authors said, adding that regional cooperation also can yield more operational flexibility to manage the variation in solar and wind output and better grid resilience. In addition to reducing production costs, regional cooperation can also offer “significant savings in the cost of resource adequacy,” the authors noted.

However, regional cooperation can take many other forms, some of which have been or are being implemented, “demonstrating a general momentum towards greater regional cooperation,” the authors said.

Policymakers must weigh the benefits of various regional cooperation solutions, but experiences in other parts of the country suggest regional cooperation is not one single decision but an evolutionary progression, the authors said. They noted that CAISO has operated a voluntary real-time Western Energy Imbalance Market since 2014 that has saved participants more than $3 billion and formed the foundation for CAISO’s approval in February 2023 of the Extended Day-Ahead Market that utilities may join without becoming full CAISO members.

Besides CAISO, other balancing authorities involved in preparing the report included the Balancing Authority of Northern California, the Turlock Irrigation District, the Western Area Power Administration, the Los Angeles Department of Water and Power, NV Energy, PacifiCorp, and the Imperial Irrigation District.

Moves to Expand Public Power in Michigan Grow in Wake of Recent Outages

March 3, 2023

by Paul Ciampoli
APPA News Director
March 3, 2023

In the wake of recent power outages affecting parts of Michigan, communities in the state recently took steps to explore the option of municipalization.

The steps were spurred by power outages in the service territories of investor-owned utilities DTE Energy and Consumers Energy.

On March 1, Washtenaw County residents gave public comments asking the County Commission to investigate the creation of a public power utility, arguing that public power utilities provide better reliability, lower rates, and the ability to reduce fossil fuel use.

Washtenaw County Commissioners unanimously approved a resolution directing the County Administrator to investigate alternative options to DTE and Consumers Energy within Washtenaw County.

County Commissioner Yousef Rabhi cited the Michigan Revenue Bond Act of 1933, stating that it gives public corporations like Washtenaw County the right to acquire infrastructure necessary to distribute power and establish its own publicly owned electric utility. 

Meanwhile, in late February, the Pontiac, Mich., City Council approved a resolution that, among other things, calls for the Michigan Legislature to start a committee that would research the feasibility of creating a state-run utility.

In early 2022, Ann Arbor, Michigan’s City Council unanimously adopted a resolution initiating a feasibility study for a public power utility.

Ann Arbor for Public Power, a nonprofit grassroots citizen group, has been leading the municipalization effort. DTE Energy currently serves Ann Arbor.

Ann Arbor for Public Power last summer said that a request for proposals for a municipalization feasibility study fell short on several fronts.

Ann Arbor for Public Power noted that it supports a thorough and unbiased municipalization feasibility study. “However, this RFP is flawed, and could lead to a study that does not provide the information to accurately determine the technical and economic feasibility of an Ann Arbor municipal electric utility,” the group said.

The American Public Power Association offers resources related to municipalization. Click here for additional details.

Federal Energy Regulators Accept PJM Proposal Tied to Base Residual Auction

February 27, 2023

by Paul Ciampoli
APPA News Director
February 27, 2023

The Federal Energy Regulatory Commission recently accepted a PJM Interconnection proposal addressing a unique set of circumstances discovered during the clearing process for PJM’s 2024/2025 Base Residual Auction conducted as part of the capacity market administered by PJM.

The Feb. 21 order will allow PJM “to complete the auction in a manner that ensures just and reasonable results consistent with the reliability requirements of each Locational Deliverability Area in PJM,” the grid operator said.

FERC found PJM’s proposed tariff revisions to be just and reasonable and did not require PJM to reopen the bidding window.

As a result, PJM will post the Base Residual Auction results for the 2024/2025 Delivery Year on Feb. 27 after 4 p.m.

In the 2024/2025 Base Residual Auction, which closed Dec. 13, a large amount of planned generation with signed interconnection service agreements did not offer in the auction in one small Locational Deliverability Area of Delmarva South (DPL South), resulting in a supply and demand condition that did not reflect underlying fundamentals, according to PJM.

As a result, PJM estimated that customers in DPL South would be required to pay four times more for capacity for the 2024/2025 Delivery Year absent updating the Locational Deliverability Area Reliability Requirement.

In late December, PJM sought narrow tariff revisions to ensure a just and reasonable outcome for consumers in DPL South for the 2024/2025 Base Residual Auction in particular. PJM’s proposal to update the Locational Deliverability Area Reliability Requirement would also apply to future RPM Auctions where the requirement increases by more than one percent from the prior auction.

PJM’s proposed Tariff revisions, prevent “consumers from being charged unnecessarily high capacity prices that do not reflect actual reliability needs or supply and demand fundamentals,” the FERC order stated. “That exorbitant price increase would not be the result of supply and demand fundamentals – or an actual reliability need – meaning that there is no economic or reliability justification for those additional costs.”

FERC accepted the PJM tariff changes over the objection of a number of protestors, including merchant generators, who argued that PJM was improperly changing the auction rules retroactively.  In a dissent, FERC Commissioner Danly agreed with the protestors, likening FERC’s action to a casino where the house changes the rules of blackjack in the middle of a game.  He suggested that the order would reduce generators’ willingness to participate in the PJM capacity market.

While accepting the PJM proposal, the FERC order directed the convening of a forum in the near future to consider generally the PJM capacity market and “how best to ensure that it achieves its objective of ensuring resource adequacy at just and reasonable rates.”

FERC Order Clears Path for Implementation of Western Reliability Program

February 13, 2023

by Paul Ciampoli
APPA News Director
February 13, 2023

The Western Power Pool on Feb. 10 announced that the Federal Energy Regulatory Commission has approved the tariff for the Western Resource Adequacy Program, clearing the way for full implementation of the region’s first West-wide reliability program.  

In its ruling, FERC underscored the importance and potential benefits of a regional program and the enhanced reliability and resource adequacy that WRAP would bring. “Through increased coordination, we find that the WRAP has the potential to enhance resource adequacy planning, provide for the benchmarking of resource adequacy standards, and more effectively encourage the use of western regional resource diversity compared to the status quo,” the order noted. 

The WPP board of directors will meet this week to review the order and to officially clear the final hurdle for WRAP operations under the tariff. In short order, the WPP will make the governance changes required by the tariff, which includes seating a new independent board of directors identified in 2022.  

 In December and January, WPP received formal commitments from 20 utilities to move forward with the WRAP. Representatives from several of those utilities also applauded FERC’s ruling. 

 WRAP participants engaged in the first non-binding forward showing program as part of program implementation in 2022, and the first non-binding operational phase of the program will kick off this summer as scheduled. 

Utilities from the northwest, parts of the desert southwest, Canada and northern California are expected to be part of the WRAP’s overall footprint. 

A number of public power entities are participating, including Bonneville Power Administration, Chelan County PUD, Clatskanie PUD, Douglas County PUD,  Eugene Water and Electric Board, Grant County PUD, Salt  River Project, Seattle City Light, Snohomish County PUD, Tacoma Power, and Turlock Irrigation District.