Search
`
August 1, 2024

Posted on

DC Circuit Vacates Pipeline Approval FERC Issued over NJ’s Objections

The D.C. Circuit Court of Appeals on July 30 vacated and remanded an order by FERC approving a natural gas pipeline in New Jersey that state regulators said was unneeded (23-1064).

FERC last year approved Transcontinental Gas Pipe Line Co.’s Regional Energy Access Expansion Project to boost gas delivery by 829,400 dekatherms/day to bring gas from Pennsylvania into New Jersey over the objections of New Jersey regulators and others (CP21-94). (See FERC Approves Pipeline Expansion Despite New Jersey’s Worries.)

Before the gas project came to FERC for approval, the New Jersey Board of Public Utilities opened a proceeding on the future of natural gas in the state, which determined it did not need more pipeline capacity through at least 2030. That proceeding was opened in February 2019; Transco applied to FERC in March 2021; the BPU issued a final order in the proceeding in June 2022; and FERC approved the pipeline expansion in January 2023.

About 73.5% of the project’s gas was destined for customers who signed contracts in New Jersey, but the rest was for Delaware, Maryland and Pennsylvania.

The New Jersey Conservation Foundation, New Jersey Division of Rate Counsel, New Jersey Attorney General’s Office and others challenged FERC’s approval after the commission upheld it on rehearing.

The court found that FERC failed to make a significance determination when it came to the project’s greenhouse gas emissions and failed to discuss mitigation measures.

FERC quantified the emissions associated with the project, finding construction could add 43,548 metric tons of CO2 equivalent, while operation would add 562,044 metric tons per year. Using the fuel downstream from the pipeline would add just over 16 million metric tons. The higher estimates are the project would use 39% of the total annual emissions budgets of New Jersey and Maryland.

The commission said counting the emissions was enough and it did not have to weigh their significance for the project as it had an open proceeding looking into such issues generically.

FERC “did not explain, however, how the pendency of that generic proceeding affects its ability in the meantime to make a case-specific determination here, when it was able to do so in Northern Natural,” the court said, referencing the first time the commission assessed the greenhouse gas emissions of a proposed natural gas infrastructure project and its impact on global climate change. (See FERC Assesses Climate Impact of Gas Project for 1st Time.)

“The anticipated emissions from this project are more than a hundredfold higher than the 100,000 metric tons per year of CO2e that the commission’s interim guidance suggests as a significance threshold,” the court said. Even if FERC was not obliged to make a determination, choosing not to do so on the basis of an arbitrary explanation is a violation of the Administrative Procedure Act, it said.

The court also found FERC acted arbitrarily in granting the certificate under the Natural Gas Act because it failed to explain why it discredited New Jersey’s study finding no need of new pipelines for the rest of the decade. It also failed to give weight to the state’s climate law that requires sizeable and continuous cuts in natural gas use by utilities.

FERC criticized the New Jersey study for relying on the continued availability of 619 million dekatherms/day of off-system peaking resources that are not under long-term, firm contracts.

“The commission did not, however, identify any past event in which such resources — despite being subject to short-term contracts — were unavailable when needed,” the court said. “In fact, the commission recognized that ‘downstream capacity has been available to New Jersey shippers in the past through short-term peaking contracts and may be available in the future on the same short-term basis.’”

The project had contracts for the new capacity. Normally such precedent agreements are used to show a market need, but the court faulted FERC for failing to respond to challenges to its reliance on those. While New Jersey local distribution companies signed up for capacity, it is not guaranteed they will use it to serve their customers.

“If ratepayers assume the cost even when they do not need the capacity, LDCs can afford to contract for additional unneeded capacity, which they can then resell at a profit, even in a soft capacity market,” the court said. “Because the commission failed to respond to that challenge to its reliance on precedent agreements with LDCs who subscribed to a majority of the pipeline’s capacity, the commission acted arbitrarily.”

Posted on

NREL Examines Gulf of Mexico OSW Transmission Needs

A National Renewable Energy Laboratory report offers insight on transmission infrastructure needs for future offshore wind development in the Gulf of Mexico. 

NREL said the needs are significant but have not been researched previously.  

Offshore wind development in the Gulf presents challenges beyond those facing present-day efforts along the northeast U.S. coast. And developers so far have shown little willingness to meet those challenges — the Gulf wind lease auction planned for later this year was canceled for lack of interest. 

But the Gulf is believed to hold 37% of the nation’s potential offshore wind generation capacity, and federal leaders hope to exploit it. 

NREL’s report looks at some of the steps that would need to be taken well in advance of wind turbine construction so their megawatts of power could be brought ashore. 

A key takeaway: The oil and gas industry already has infrastructure and personnel in the Gulf. Shared transmission systems and workforce could support offshore wind. 

Also, about 18,000 miles of abandoned pipelines remain on the seabed and could be used to transmit clean hydrogen — generation of which is a potential use of offshore wind energy. 

But the NREL report also suggests that offshore wind transmission planning in the Gulf is not so different from other regions: Planners will have to limit the impact of their projects on existing communities, industries and ecosystems while navigating local, state, federal and tribal regulations and sensibilities. 

The report’s authors identify some gaps in existing planning and knowledge needed for buildout: 

    • RTOs and utilities have not incorporated Gulf of Mexico offshore wind power in their long-term transmission planning. 
    • Siting considerations for offshore wind transmission routing in the region have not been identified in published literature. 
    • Focused community and workforce engagement on stakeholder priorities has been lacking. 
    • Engagement and research would inform how offshore wind transmission would fit into the region’s energy generation portfolio and how it serves the needs of industries in the Gulf Coast states. 

The NREL report recommends the Department of Energy and Bureau of Ocean Energy Management convene a Gulf Coast version of the Atlantic Offshore Wind Transmission Study workshop series they began hosting in 2022. 

The Biden administration, as part of its push to build a new emissions-free power sector, envisions fixed-bottom wind turbines in shallower parts of the Gulf and floating turbines in deeper areas. 

But slower average wind speeds punctuated by severe winds from hurricanes and tropical storms present a significant engineering challenge for designers of the wind turbines to be placed in the Gulf. (See Hurricane Threat to OSW Turbines Quantified.) 

In 2023, the first of four planned Gulf wind energy area auctions drew only three bids from two bidders on one of the three areas offered. The single sale came at a rock-bottom price. (See Gulf of Mexico Wind Energy Auction Falls Flat.) 

The planned 2024 auction drew early interest from only one potential bidder and was called off. (See BOEM Cancels Gulf of Mexico Wind Lease Auction.) 

As the 2024 auction was heading to cancellation, however, another developer submitted an unsolicited request to BOEM for two other lease areas off the Texas coast. 

And Louisiana has been advancing offshore wind development in state waters closer to shore. The Climate Action Plan developed during the administration of Gov. John Bel Edwards (D) set a goal of 5 GW of offshore wind capacity by 2035, and the state signed agreements with two developers in late 2023, during the closing days of his administration. 

A previous NREL study identified 25 plausible points of interconnection for offshore wind export cables but concluded that, as in other regions, many of them would need significant upgrades to handle gigawatt-scale injections. 

The new NREL report was funded by the DOE’s Wind Energy Technologies Office and Grid Development Office. 

Posted on

AEP Planning for 15 GW of Data Center Load

American Electric Power executives say they’re embracing large loads and, fortunately for them, they say they have firm commitments for more than 15 GW of load coming from just data centers by 2030.

AEP told financial analysts during its July 30 second quarter earnings call with financial analysts that it’s seeing “unprecedented” load growth, split primarily between Texas and its PJM footprint. Commercial load has increased 12.4% over the second quarter of last year as new data processing facilities came online, the company said.

“We continue to see strong interest in Ohio and Texas, as well as several of our vertically integrated states, from customers looking to develop new data processing facilities,” interim CEO Ben Fowke said during the company’s call. “Affordability remains top of mind, and we’re working to ensure that the investments made in the grid to support this increased demand are allocated fairly and provide benefits to all customers.”

Noting AEP’s system-wide peak at the end of last year was 35 GW, Fowke said the company continues working with data center customers to meet their increased demand, but also ensuring contracts and new initiatives are “fair and beneficial” for all customers. He said AEP would provide details on its generation and transmission capital investment necessary to meet demand later this year.

“I want to emphasize that it’s critically important that costs associated with these large loads are allocated fairly and the right investments are made for the long-term success of our grid,” Fowke said.

AEP subsidiary Public Service Co. of Oklahoma (PSO) in June announced it will seek regulatory approval of an agreement to purchase Green Country, a 795-MW natural gas facility. Peggy Simmons, executive vice president of utilities, said the transaction will help PSO meet SPP’s higher planning reserve margin, which was increased to 15% from 12%.

“This was a very proactive approach that the team took to go out and find some affordable assets that we can bring onto the system,” she said.

AEP reported second-quarter earnings of $340 million ($0.64/share), down from 2023’s second quarter earnings of $521 million ($1.01/share). The company reaffirmed its 2024 operating earnings guidance range of $5.53-$5.73/share and its 6%-7% long-term growth rate.

Incoming CEO Bill Fehrman, who takes over AEP’s top job Aug. 1, did not participate in the call. Fehrman replaced Julie Sloat in June after his predecessor parted ways with AEP in February following just one year as CEO. (See AEP Selects Industry Veteran as Next CEO.)

“With Bill’s expertise and diverse background, you can anticipate a smooth transition and continuity of strategic direction. Expect more focus on execution,” said Fowke, who served as interim CEO and will advise Fehrman during a transition period.

The company’s share price rallied late July 30 to close at $98.14, up $1.07 from its previous close.

Posted on

ISO-NE Capacity Accreditation Reforms Spur Energy Storage Concerns

As ISO-NE undertakes major capacity market accreditation reforms, New England storage developers are voicing concerns that potential flaws in the RTO’s modeling methodology could discourage new investments in storage resources. 

The resource capacity accreditation (RCA) project has been in motion for more than two years, and the development process could continue into 2027 following the RTO’s three-year delay of its 19th capacity auction, which applies to the 2028/29 capacity commitment period. (See NEPOOL Markets Committee Restarts Work on Capacity Market Changes.) 

The RCA project is intended to better align the capacity procurements with real-world reliability benefits, mirroring similar reform efforts in MISO, NYISO and PJM.  

Prior to FERC’s approval of the full three-year delay — which will give ISO-NE time to reform the timing of the capacity auction process along with accreditation — the RTO published RCA impact analysis results that painted a dire picture for storage resources. (See FERC Approves Additional Delay of ISO-NE FCA 19.) 

While the analysis indicated that the accreditation changes would increase the overall pool of capacity revenue by 11%, it showed a 37% revenue reduction for storage resources, equivalent to about $58 million. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11%.) 

While these results are subject to change as ISO-NE refines the methodology and accounts for the transition from a forward annual capacity market to a prompt-seasonal capacity market, the analysis served as a wakeup call for many of storage companies participating in the capacity market. (See ISO-NE Moving Forward with Prompt, Seasonal Capacity Market Design.) 

The concerns about storage accreditation derating come as several New England states are looking to rapidly ramp up the deployment of storage resources; Connecticut, Massachusetts, Maine and Rhode Island all have storage targets in the hundreds of megawatts. 

State programs also are a key revenue component for storage developers, as the current levels of revenue from ISO-NE wholesale markets alone are not enough to support the resources, said Alex Chaplin of New Leaf Energy, adding that “storage provides significant reliability benefits to New England which need to be adequately measured and compensated for in the ISO-NE markets.” 

Chaplin noted that most storage in the region is concentrated in Connecticut and Massachusetts due to their state incentives for storage. Massachusetts’ clean peak energy standard, which is aimed at cutting emissions and air pollution from fossil peaker plants, is a key revenue source for storage resources in the state. (See Panel Provides Update on Energy Storage in Mass.) Decreasing capacity revenue could lead to more pressure on states to support the resources to hit their storage deployment goals and cut emissions. 

“Capacity market revenues are typically an irreplaceable and indispensable source of revenue for the financeability and viability of resources, and storage is no exception,” said Alex Lawton of Advanced Energy United. He added that the energy market and ancillary services market do not provide “the scale or certainty needed for investors to back storage projects.” 

The crux of the issue, Lawton said, appears to stem from how ISO-NE is artificially scaling up load in its model to evaluate the reliability benefits of different resource types, which ultimately will determine how much capacity each resource can sell into the market. This modeling shows capacity scarcity events that significantly exceed the duration of events historically experienced in the region.  

While the longest capacity scarcity condition New England has experienced since the implementation of pay-for-performance rules in 2018 lasted two hours and 40 minutes, the RCA project is modeling events that typically exceed four hours, and — according to a March presentation — 36% of modeled shortfall events lasted more than eight hours.  

“As soon as you exceed four hours in duration — because most storage is between two and four hours — the marginal reliability impact (MRI) of storage just tanks,” Lawton said. 

There is broad consensus that the region’s power grid will face longer-duration periods of shortfall risk in the future as it trends toward a winter peaking system, but there is uncertainty around when these longer-duration risks will show up, and how they should be weighed against higher-likelihood, shorter-duration events.  

Over the long term, ISO-NE has stressed the need for dispatchable resources that can balance intermittent generation over extended periods of time. (See ISO-NE Outlines Economic Challenges of Decarbonization.) 

Frank Swigonski of Jupiter Power said the weighting of extreme winter storms in the methodology compared to more frequent, shorter-duration events “is an open question … that stakeholders should explicitly discuss in this process.” 

Swigonski noted the stakeholder engagement process for PJM’s accreditation reforms did not spend significant time discussing this question, which led to rehearing requests with FERC. 

“It ultimately had a massive impact on the final accreditation numbers,” Swigonski said. “We’re hoping that we don’t have the same experience in New England.” 

Swigonski also disagreed with the notion that shorter-duration storage resources are unable to provide significant resource adequacy benefits during longer-duration events. Storage resources likely still will be able to recharge off-peak during extended events, and operators eventually will gain experience with dispatching storage to avoid depleting all available storage in the first hours of an event, he said. 

Responding to questions about the RCA methodology, ISO-NE spokesperson Mary Cate Colapietro emphasized that the methodology is still a work in progress and that stakeholder engagement is ongoing. ISO-NE recently solicited comments on the scope of its Capacity Auction Reform (CAR) project, which included requests from storage companies for ISO-NE to evaluate the underlying modeling methodology. 

“Establishing a durable capacity market that provides the necessary reliability services as the power system evolves is a vital component of New England’s clean energy transition,” Colapietro said. “While we plan to continue pursuing an accreditation design based on capacity’s marginal reliability impact, the additional time afforded by the delay gives us time to work with stakeholders on possible improvements to that design.” 

Bruce Anderson of the New England Power Generators Association declined to comment on the treatment of specific resource types but stressed the need for ISO-NE to prioritize implementing a “sound market design” that provides efficient signals for resources to enter and exit the market. 

Posted on

ERCOT Evaluating RMR, MRA Options for CPS Plant

ERCOT has issued a request for proposal seeking alternatives to a reliability-must-run contract with CPS Energy, compensating for the utility’s planned retirement of a power plant. 

The ISO said in a July 25 market notice that CPS Energy’s decision to retire three aging coal-fired units, with a combined summer seasonal net maximum sustainable rating of 859 MW, would have a “material impact on identified ERCOT system performance deficiencies.” The grid operator’s staff has said the units’ retirement would load existing transmission facilities above their normal ratings under pre-contingency conditions.  

ERCOT’s determination triggered the grid operator’s obligation to issue an RFP for must-run alternatives (MRAs) and begin RMR negotiations with CPS Energy. The San Antonio utility has proposed suspending the three V.H. Braunig units after March 2025. (See CPS Energy Plans to Retire 859 MW of Gas Resources.) 

Qualified scheduling entities (QSEs) can submit proposals for one or more MRA resources to address system performance deficiencies more cost effectively than by committing one or more Braunig units through a more expensive RMR contract. QSEs can offer the resources for one or more seasons during April 1, 2025, through March 31, 2027. Eligible resources include types of generation, storage and demand response. 

RFP offers are due Sept. 9. ERCOT will host a workshop Aug. 15 to discuss the RFP and answer questions. After reviewing all proposals, staff will make a recommendation to the ISO’s board during its October meeting. 

An RMR contract would be ERCOT’s first since 2016. The grid operator entered into an agreement with NRG Texas Power over a previously mothballed gas unit near Houston. The RMR contract ended in 2017, thanks partly to transmission facilities that increased imports into the region. (See ERCOT Works to Address Loss of San Antonio Units.) 

$24.4B in Energy Fund Requests

The Public Utility Commission said July 29 it has received 72 applications for loans through the Texas Energy Fund’s in-ERCOT Generation Loan Program. The applications request $24.41 billion to finance 38.37 GW of proposed dispatchable, or thermal, power generation. 

Lawmakers have set aside $5 billion for this TEF program, one of four. 

“Texans have made it clear that they expect reliable electricity today and well into the future, and I am pleased to see industry leaders responding to that call and planning for major investments in dispatchable power for the state,” PUC Chair Thomas Gleeson said in a news release. 

Commission staff will evaluate the applications before the commission determines which projects will proceed to due diligence during the PUC’s Aug. 29 open meeting. The in-ERCOT program will provide low-interest loans to finance up to 60% of new construction or upgrades to existing dispatchable facilities. A proposed project must add at least 100 MW of new generation to the ERCOT grid to be eligible. Approved loans’ initial disbursements will be issued by Dec. 31, 2025.  

The in-ERCOT program and three other TEF programs were established in March because of state legislation passed last year. The PUC says the program can support up to 10 GW of new or upgraded generation capacity in ERCOT. (See Texas PUC Establishes $5B Energy Fund.) 

Posted on

Electric Sector Added just 55 Miles of New Transmission in 2023

The U.S. electricity industry added just 55 miles of new high-voltage transmission to the grid last year, despite estimates the system will need to expand rapidly in the near future, Americans for a Clean Energy Grid said in a report released July 30. 

“Fewer New Miles: The US Transmission Grid in the 2020s” was prepared by Grid Strategies with support from ACEG. 

“The findings of this report are a wakeup call. With only 55 new miles of transmission built in 2023, we are not keeping pace with the growing demand for power,” ACEG Executive Director Christina Hayes said in a statement. “The slowdown in new construction not only impacts our ability to meet future energy needs, but also risks increasing costs for consumers and reducing grid resilience. It is essential that we address these challenges to ensure a secure, reliable and affordable energy future for all Americans.” 

The U.S. Department of Energy’s Transmission Needs Study found the grid should expand by 57% by 2035, while Princeton University’s “Net-Zero America Study” found it would need to double or 80% of the potential greenhouse gas cuts from the Inflation Reduction Act would not be met, said the ACEG report. (See Will DOE’s Transmission Needs Study Spur New Regional, Interregional Lines?) 

While 2023 saw few miles of new lines built, the industry spent $25 billion on the grid (a record high), with 90% driven by reliability upgrades and the replacement of aging equipment. The decline has been felt for years, with the country building only 20% as much transmission so far this decade as it did in the early 2010s. 

“This trend began over a decade ago, when the average of 1,700 miles of new high-voltage transmission built per year from 2010 to 2014 dropped to only 925 miles from 2015 to 2019, and has fallen further to an average of 350 miles per year from 2020 to 2023,” the report said. 

So far this year up to May, the industry has completed one major transmission line, adding 125 new miles from completion of the 500-kV Delaney-Colorado Transmission Project that links Arizona and California. 

About 50% of recent spending is based on local planning criteria, which is usually below 345 kV and does not go through regional planning processes. Such lines focus only on reliability, ignoring maximized ratepayer benefits from multivalue projects, the report said. 

The 2010s saw massive greenfield projects, especially in Texas and the Midwest. Texas’ Competitive Renewable Energy Zone program saw $7.5 billion invested in ERCOT lines to bring wind power to population centers, cutting wind curtailment from 17 to 0.5% and leading to unexpected benefits like solar development in West Texas and electrification of oil and gas drilling in the regions. 

MISO’s Long Range Transmission Planning (LRTP) Tranche 1 Portfolio is another example, investing $10.3 billion to build out 2,000 miles of lines that offer at least 2.6:1 benefits to load. 

Recent federal action like FERC Order 1920 and DOE’s Transmission Facilitation Program to help finance new transmission lines should help, but the report said private capital needs to be invested to expand the grid. 

“Utilities are still currently incentivized to prioritize low- voltage upgrades focused on reliability and asset replacement,” the report said. “Both policymakers and regulators must capitalize on FERC’s issuance of Order No. 1920 to ensure the momentum brought about by federal action truly changes the incentives for transmission investment and helps spur a massive investment in the construction of new high-voltage transmission lines to ensure a reliable and affordable transition to a cleaner grid.” 

Posted on

Federal Briefs

Campaign Official: Harris Does not Support Fracking Ban

Vice President Kamala Harris will not seek to ban fracking if she’s elected president, an official with her campaign said last week. 

While she was one of several Democrats vying for the 2020 nomination, Harris said, “There’s no question I’m in favor of banning fracking.” However, since that time, she joined the Biden campaign and administration, neither of which supports a ban on fracking. 

More: The Hill 

Republicans Ask Supreme Court to Pause New EPA Rules on Emissions

More than 20 Republican state attorneys general have asked the Supreme Court to temporarily block the EPA from enforcing new rules that aim to curb carbon emissions from power plants. 

The filing came days after a federal appeals court turned down a similar emergency request from the officials and industry groups. They want the new rules shelved while their legal challenge plays out. 

The EPA’s new rules compel existing coal and new natural gas power plants to either cut or capture 90% of their emissions by 2032. The rules are expected to reduce carbon dioxide emissions from the sector by 75% compared to a peak in 2005. The challengers say the rules would be too costly for power plants and could force them to close. 

More: CNN 

DOI Advances Clean Energy Projects on Western Public Lands

The Department of the Interior has announced that the Bureau of Land Management will advance nine solar projects on public lands. The actions follow the department’s April announcement that the BLM has permitted more than 25 GW of clean energy projects – surpassing a major milestone ahead of 2025. 

More: Department of Interior 

Posted on

State Briefs

FLORIDA 

Duke Energy Cuts Rate Hike Request, Won’t Shut off Power at 95 Degrees

Duke Energy has agreed to a settlement with the Public Service Commission to drastically decrease its rate increase request. 

Originally, Duke asked for an increase of about $820 million over the next three years. Now, the company is requesting an increase of $262 million, plus charges for solar plants that only will be added once the projects are completed. The costs of those projects would total $141 million if all are finished on schedule, the company said. 

Duke also agreed to add language to its policy so that no customers will have their power disconnected if temperatures reach at least 95 degrees. Previously, it stopped shutoffs when the heat index was 105 degrees. 

More: Tampa Bay Times 

MICHIGAN 

Ann Arbor Ballot Proposal Promises Affordable Access to Renewable Energy

Ann Arbor residents will vote this November on establishing an optional public utility that would use renewable energy exclusively. The project is part of the city’s A2Zero program, which aims for carbon neutrality by 2030. 

A report calculated cost savings based on how much money it will cost the city to set up the utility and how many customers participate. The report said residents could save on their electricity bills by opting in to the utility. 

Unlike a full-scale public utility, the sustainable utility would be supplemental, as residents and businesses would need to opt in to use it. 

More: Michigan Public Radio 

MINNESOTA 

PUC Approves CenterPoint’s Clean Energy Plan

The Public Utilities Commission has approved CenterPoint Energy’s $106 million clean energy plan. CenterPoint said the five-year program will cost its average residential customer about $1.50 a month. The plan will include clean energy pilot projects such as renewable natural gas and geothermal heating. 

The largest of CenterPoint’s 17 pilot projects calls for $40 million in purchases of renewable natural gas. After RNG purchases, CenterPoint’s next largest proposal, costing $13.6 million, is retrofitting residences for electric heat pumps with gas backups. 

More: Star Tribune 

NEW HAMPSHIRE

Law Provides New Solar Incentives for Cities

A recently signed law has made significant changes to the state’s Renewable Energy Fund, directing money to help towns and cities develop municipal solar projects. 

The fund, created in 2007, is a pool of money the state uses to support renewable and thermal energy initiatives through grants and rebates. More recently, revenue has hovered around $7 million. The money then is allocated across several programs. The new legislation calls for funding to be allocated to a new municipal solar program in 2024, with the sum likely to be announced in late August or early September. 

The bill also terminated the state’s rebate program for residential solar and wind installations. 

More: Energy News Network 

NORTH CAROLINA

Police: Man Shoots Utility Tree Workers

A man shot three tree workers while they were clearing trees for a power company before being shot himself by police officers during his arrest, police said. 

The incident began near Murphytown when 36-year-old Lucas Wilson Murphy confronted contract workers clearing the right of way for a utility, according to a statement from the Yancey County Sheriff’s Office. Authorities did not release any possible motives in the case. 

All three workers sustained serious injuries. Their conditions are unknown. 

More: ABC News 

TEXAS 

CPS Energy Plan to Shut Braunig Units Could be Stopped by ERCOT

ERCOT will begin seeking replacement power for the gas-fired units at CPS Energy’s Braunig Power Station, which the company planned to shut down by March, and failure to do so could halt the utility’s plans. 

The plan proposed by CPS, which is working to transition away from carbon generation, would take 859 MW off the grid. However, it’s unclear where the replacement power could come from. To offset the Braunig loss, CPS recently bought existing gas-powered plants from Talen Energy. But because those plants already were part of ERCOT’s capacity before the purchase, Braunig’s closing would still result in a net loss on the grid. 

ERCOT is scheduled to decide by October. 

More: Houston Chronicle 

VERMONT 

Conservation Law Foundation to Sue State over Alleged Failure to Comply with Climate Law

The Conservation Law Foundation (CLF) has announced plans to sue the state, alleging the Agency of Natural Resources has failed to comply with a law that requires Vermont to reduce climate emissions.  

In 2020, Vermont enacted the Global Warming Solutions Act, which requires the state to implement programs that cut greenhouse emissions in specific amounts by 2025, 2030 and 2050. The CLF plans to use a pathway included in the law that allows organizations or individuals to sue the secretary of the Agency of Natural Resources to force compliance if evidence shows the state is not on track to meet those benchmarks. Under the law, the entity suing the state must give the agency 60 days’ notice before filing a lawsuit. 

The CLF alleges the agency has used faulty modeling to assert the state is on track to meet the law’s first deadline on Jan. 1, 2025. The CLF conducted its own analysis and said the analysis showed the state is not likely to meet the deadline. 

More: VTDigger 

VIRGINIA 

DEQ Fines Mountain Valley Pipeline for Environmental Violations

The Department of Environmental Quality has fined Mountain Valley Pipeline $30,500 for violating environmental regulations during a three-month period before the pipeline began operating, marking the fourth consecutive fine of this type.

The DEQ levied the penalty after it found nearly two dozen violations of erosion and sediment control rules, according to a report. Nearly all problems were corrected within a day. 

Before the latest penalty, the DEQ had fined Mountain Valley $68,000 over the previous three quarters since construction resumed last summer. 

More: Cardinal News 

Dominion Customers’ Bills to Rise for Offshore Project Costs

The State Corporation Commission has approved an 80% increase in the surcharge on Dominion Energy bills that finances an offshore wind project off Virginia Beach. The increase, which goes into effect Sept. 1, will raise the average monthly bill by $3.89. Dominion plans to erect 176 giant wind turbines in the Atlantic and expects to have the project operational by the end of 2026. 

More: Richmond Times-Dispatch 

WASHINGTON 

Initiative to Halt Phaseout of Natural Gas Makes Ballot

State election officials have certified an initiative for the November ballot that seeks to reverse the state’s attempt to phase out natural gas use in homes and other buildings. 

The measure targets the state’s combination of regulations and laws to move swiftly away from natural gas toward technology like electric heat pumps. It will appear first on ballots, followed by three other citizen initiatives that seek to repeal the state’s cap-and-trade system and capital gains tax and make the state’s new long-term care services program voluntary. 

If passed, the initiative would repeal provisions of a new law meant to hasten Puget Sound Energy’s transition away from natural gas. It also would bar cities and counties from prohibiting, penalizing or discouraging “the use of gas for any form of heating, or for uses related to any appliance or equipment, in any building.” And it would roll back recent changes to energy requirements in building codes that are designed to get more electric heat pumps installed in newly built buildings. 

More: Washington State Standard 

Posted on

Company Briefs

EQT, Equitrans Merge in $5.45B Deal

EQT Corp. has agreed to a deal with former subsidiary Equitrans Midstream Corp., closing on a $5.45 billion acquisition. EQT, the nation’s largest natural gas producer, announced its intention to reunite with Equitrans in March. The two were part of the same company until Equitrans spun out in 2018 as a pipeline and compression provider. 

More: Pittsburgh Post-Gazette 

Tesla’s Net Income Falls 45% in Q2

Tesla last week reported a second-quarter net income of nearly $1.5 billion, a 45% decline from the $2.7 billion a year earlier, as sales of its core cars dipped 5%. Total revenue was $25.5 billion in the quarter ended, a record, up 2% from $24.9 billion a year earlier. 

More: Houston Chronicle 

Nexamp, Starbucks Partner on Community Solar Projects

Nexamp and Starbucks have announced a partnership to deploy 40 MW across six Illinois community solar farms. Starbucks will receive a portion of the project’s RECs for its support of Nexamp’s Illinois operations. Construction has begun on the solar projects, which are expected to come online next year. 

More: Solar Industry Magazine 

Posted on

PJM MRC Briefs: July 24, 2024

Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility

VALLEY FORGE, Pa. — PJM’s Markets and Reliability Committee endorsed one of two proposals to revise how PJM uses reserve resources, approving a deployment scheme where instructions are sent by basepoints, while rejecting a parallel proposal to grant operators the ability to dynamically increase market procurements. (See “First Read on 2 PJM Proposals to Revise Reserve Markets,” PJM MRC/MC Briefs: June 27, 2024.)  

PJM’s Emily Barrett said updating basepoints with reserve instructions provides more clarity around how resources are expected to respond and allows for units to be dispatched for less than their full reserve assignment. Resources being asked to respond at less than their assignment will be committed at the greater of their economic minimum parameter or the pro rata instruction. 

Stakeholders rejected a second proposal to determine the amount of 30-minute reserves PJM commits using a formula rather than the static 3,000-MW figure. The equation would select the greater of the load forecast error and forced outage rate together multiplied by the forecast peak load, the primary reserve requirement or the largest active gas contingency. 

The package also would have allowed operators to increase one of the three reserve categories without having to increase all three. Under the status quo language, any out-of-market increase in the 30-minute, primary or synchronized reserve requirement must be mirrored across all three. Barrett said the language tying the three reserve products together is viewed by staff as an oversight. 

Prior to the vote, PJM’s Executive Director of System Operations Dave Souder said the static reserve threshold is not sufficient and does not account for risks identified by dispatchers. The proposal would revert to the reserve procurement formula in place before the reserve price formation redesign. 

Paul Sotkiewicz, president of E-cubed Policy Associates, said outages experienced in Alberta, Canada, in April demonstrated the importance of having dispatchers able to match reserves with expected risk. 

“The Alberta outage a few months ago shows why this is needed. The renewable forecast was inaccurate, energy commitments were too low and firm load had to be shed. That provides a cautionary tale that lends support for the ability to commit more reserves available,” Sotkiewicz said. 

According to the PJM summarized voting report, the reserve procurement package had little support among electric distribution companies, which were 93.1% opposed, and end-use consumers, who voted 82.4% against. The Other Suppliers sector was split at 57.1% support, while generation and transmission owners were united in support. 

Responding to a stakeholder question about whether PJM would consider moving forward with the proposed tariff changes without stakeholder endorsement, PJM Vice President of Market Design and Economics Adam Keech said staff had not envisioned the vote failing and will have to consider next steps. 

Schedule Selection Formula Endorsed

Stakeholders endorsed a proposal to use a formula to sift through market sellers’ energy offers into the real-time market and select one schedule for each resource to be modeled in the market clearing engine (MCE). (See “Stakeholders Discuss Path Forward on Multi-Schedule Modeling,” PJM MIC Briefs: June 5, 2024.) 

PJM brought the issue before stakeholders as part of its effort to implement multi-schedule modeling in the real-time market, which staff have said would result in a significant increase in computation times, in part due to the number of configurations combined cycle units can operate under. The introduction of multi-schedule modeling is one part of a larger overhaul of the engine under PJM’s Next Generation Markets (nGEM) initiative. 

An earlier schedule selection proposal was endorsed by stakeholders but rejected by FERC in March. The commission cited a “crossing-offer-curves” scenario the Independent Market Monitor raised, under which PJM’s proposed formula would select market-based offers based on its dispatch cost at EcoMin even if it would be notably more expensive than a cost-based offer at higher outputs.  

The proposal endorsed July 24 is built around the same formula but aims to address the crossing curves issue by selecting price-based offers only when a resource passes the three pivotal suppliers (TPS) test and mitigating resources to their cost-based offers should they fail the TPS test. The tariff and operating agreement (OA) revisions are set to go before the Members Committee on Aug. 21 for an endorsement vote. 

The proposal was sponsored by PJM and the GT Power Group at the Market Implementation Committee and received the second-highest amount of support at the MRC in December. (See “Stakeholders Endorse Multi-schedule Modeling Solution,” PJM MRC/MC Briefs: Dec. 20, 2023.) 

Monitor Joe Bowring said the joint proposal would not resolve an issue with how dual-fuel units are committed. Since only one schedule is considered, the Monitor has argued that dual fuel units may be selected to run on a schedule using a fuel that is not economical for a portion of the day. 

Stakeholders had discussed waiving truncated voting rules and widening the vote to include a joint proposal from the Monitor and GT Power, which would allow generators to determine which of their offers would result in the lowest production cost and should be modeled in the MCE. 

Vote on Enhanced Know Your Customer Deferred

The committee delayed voting on a proposal to tighten PJM’s “know your customer” (KYC) requirements to require more due diligence checks on principals and key decision makers among member entities. (See “First Read on Expanded ‘Know Your Customer’ Rules,” PJM MRC/MC Briefs: June 27, 2024.)  

The proposal would require PJM background checks on beneficial owners, board of director members and principals of non-publicly traded members. Those entities would be responsible for providing a list of names for each of those categories and government-issued identifications, though the latter does not apply to boards unless requested by PJM. The proposal is aimed specifically at collecting more information on non-public members not required to report ownership information to the Securities and Exchange Commission. 

The beneficial owner definition is applicable to those who own, control or hold 10% or more voting power of an entity, either directly or with family. Since the June 27 first read, Assistant General Counsel Eric Scherling said the definition of family members was clarified to state that ownership split across spouses, domestic partners, parents, children or siblings counts toward triggering the requirement. 

The proposed definition of “principals” also was revised to add the phrase “corporate-level strategy” regarding the control individuals have over the member entity’s operations. Scherling said the change is meant to address feedback that the definition could be too broad and capture staff with day-to-day operational control over assets. 

Several stakeholders said they would need more time to review the changes and expressed continued concerns about the scope of the requested information. 

Sotkiewicz said the principal definition remains nebulous when considering parent corporations and subsidiaries with split ownership. He motioned to defer voting until the Aug. 21 MRC meeting to provide more time to review the revised language.

“This is an arduous process for people [who] happen to be partners but don’t necessarily have full decision-making authority. … This could turn into a paperwork nightmare and for what reason we’re not entirely sure” when the parent company is publicly traded and the ownership is clear, he said. 

John Horstmann, senior director of RTO affairs for Dayton Light and Power, said some members have widespread operations that go far beyond PJM markets and that principals managing activities unrelated to PJM could be captured in the KYC requirements. He gave the example of an international corporation that does business in the U.S. and overseas, questioning whether information about corporate staff overseeing activities in Bulgaria or Vietnam would be requested by PJM. 

Scherling said PJM’s focus is on its markets and intends to take a closer look at individuals who are high enough in the corporate structure they would have a hand in all operations, including PJM. 

PJM Chief Risk Officer Carl Coscia said the KYC structure is about following where PJM revenues are going, what they’re being used for and where investments are coming from, so it does need to go to the highest corporate-level strategy. 

“We want to make sure these markets are being used for good. That’s the good we’re talking about, not having money that shouldn’t be here,” he said. 

Scope for Deactivation Task Force Widened

Stakeholders endorsed a wider scope for the Deactivation Enhancement Senior Task Force (DESTF) to include proposals to establish cost-effective alternatives to reliability-must-run (RMR) agreements and technologies that could expedite resolution of transmission violations prompted by resource deactivations. The proposal passed with 89% support. (See “Consumer Advocates Seek Wider Scope for Deactivation Task Force,” PJM MRC/MC Briefs: June 27, 2024.)  

The revisions to the issue charge also include education on the alternatives to RMR contacts that other RTOs have developed to keep generators operating past their desired deactivation date and a follow-up to ongoing discussion on proposals to allow capacity interconnection rights (CIRs) to be transferred from deactivating generators to planned resources. The proposal is sponsored jointly by the Illinois Citizens Utility Board (CUB) and Maryland Office of People’s Counsel (OPC). 

The issue charge language includes education around using grid-enhancing technologies (GETs) and storage as a transmission asset (SATA) to expedite transmission upgrades necessary to allow a generator to retire. 

Souder said PJM is neutral toward the technology that resolves an identified violation and it’s up to project proposers to submit solutions, including GETs. 

Clara Summers, of CUB, said the proposed language was revised from the draft presented at the June 27 first read to allow partial solutions, with the goal of avoiding any interruption to the existing discussions on compensation and deactivation notification timelines. 

Vistra’s Erik Heinle said he is concerned about having too wide of a scope for the task force, stating that the wide-ranging issue charge governing the Resource Adequacy Senior Task Force (RASTF) caused the group to die under its own weight while the Reserve Certainty Senior Task Force (RCSTF) has benefited from a narrower scope. 

“I want to make sure these important issues get the consideration they deserve but don’t slow down the ongoing work,” he said. 

Bowring questioned whether the advocates believe the issue charge should be phased to focus on deactivation notification requirements and compensation first before initiating work on the newly added items. 

Phil Sussler, of the Maryland OPC, responded that stakeholders may be too optimistic that the deactivation notification changes will be approved in August and said the overall work areas of the DESTF may take longer than expected to complete. 

Reserve Requirement Study Updated with ELCC Accreditation Values

The committee voted by acclamation to endorse revised installed reserve margin (IRM) and forecast pool requirement (FPR) values for the 2023 Reserve Requirement Study (RRS) to reflect the implementation of PJM’s marginal effective load carrying capability (ELCC) approach to accrediting resources. The proposal also was endorsed by the Members Committee on July 24.  

The reanalysis recommended increasing the installed reserve margin (IRM), which sets the targeted capacity level above expected loads, to 18.6%, up from the 17.6% stakeholders endorsed last year for the 2023 RRS. The forecast pool requirement (FPR), which accounts for generator accreditation, would decrease from 11.65% to 9.37.  

The shift to marginal ELCC accreditation was part of a package of capacity market redesigns approved by FERC in January (ER24-99). The RRS figures are used to set the supply curve for the 2026/27 delivery year. (See PJM Presents Revised Reserve Requirement Study Values.) 

In addition to the ELCC accreditation values, the reanalysis updated the expected resource mix to include planned resources that submitted a notice of intent to offer into the 2026/27 Base Residual Auction. Gas generators that submitted dual fuel attestations were sorted into the corresponding ELCC classes, and resources that are scheduled to deactivate prior to the start of the delivery year were removed from the analysis. Generators expected to operate on reliability-must-run (RMR) contracts through the delivery year were included in the resource mix. 

Greg Carmean, executive director of the Organization of PJM States Inc. (OPSI), questioned how PJM would incorporate nuclear capacity being removed from the market to serve data center load, referring to a FERC filing from Talen Energy to reduce the amount of energy the Susquehanna nuclear plant sells into PJM. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.) 

PJM’s Andrew Gledhill said the megawatt value of that unit would be effectively derated to the new CIR amount. 

Bowring asked how PJM considers the reliability impact of amending interconnection service agreements (ISAs) with generators to reduce their maximum output and whether it considers not approving revisions if there are reliability impacts identified.  

PJM’s Pat Bruno said reliability analysis is conducted like generation deactivation studies. 

PJM Proposes Increased CONE Parameters

PJM’s Skyler Marzewski presented a first read on a proposal to revise two financial parameters used to calculate the cost of new entry (CONE) input to the 2027/28 Base Residual Auction (BRA). (See PJM MIC Briefs: July 10, 2024.) 

After consulting with The Brattle Group, PJM recommended increasing the after-tax weighted average cost of capital (ATWACC) from 8.85 to 10% and using a 0% bonus depreciation rate for the 2027/28 delivery year and beyond. The original quadrennial review included a 20% bonus depreciation value for the 2026/27 year. The proposed changes to the quadrennial review also would update the Bureau of Labor and Statistics (BLS) indices used in capital cost escalation rates. 

The changes increase values for all five CONE areas by an average of $79/MW-day, with CONE Area 5 seeing the largest increase at $90/MW-day and Area 4 increasing by $65/MW-day. 

The review was triggered by market participants reaching out to PJM regarding the impact of high interest rates since the quadrennial review was approved last year. (See FERC Approves PJM Quadrennial Review.) 

Greg Poulos, executive director of the Consumer Advocates of PJM States (CAPS), said some advocates are frustrated that components of the review are being cherry-picked in a manner that increases consumer costs, both in terms of the financial parameters and the creation of an additional CONE area for Illinois. (See PJM Stakeholders Approve New CONE Area for ComEd over Consumer Opposition.) 

Summers questioned how PJM determines when it is appropriate to make changes to CONE outside of the quadrennial review. 

Marzewski said PJM and Brattle opted to not include automatic adjustments to the quadrennial review financial parameters to account for changing market conditions, instead leaving that discussion for the next quadrennial review. 

Sotkiewicz said the adjusted figures would be a short-term fix, but major issues remain with the CONE inputs, namely the use of a combined cycle generator as the reference resource at a time when few such units are under construction within PJM and none have been financed in recent years. 

New Economic DR Parameters Discussed

PJM presented a proposal to add two new parameters for demand response resources offering into the energy market, allowing providers to set a maximum dispatch period and a minimum interval before they can be committed again after being released from a previous dispatch. The Market Implementation Committee endorsed the proposal last month. (See “Additional Parameters for Demand Response Endorsed,” PJM MIC Briefs: June 5, 2024.) 

PJM’s Pete Langbein said the proposal would allow DR providers to enroll consumers that are only economic for set periods of time and need a recharge before being committed again. While some of that capability exists under the existing market structure using hourly updates, it is administratively difficult. 

Bowring questioned whether a DR resource could submit an offer into the capacity market even if it can operate only according to the proposed parameters. Langbein said such a resource would be subject to capacity performance (CP) penalties if it did not deliver during a performance assessment interval (PAI).