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November 13, 2024

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Competitive Power Ventures Entering Retail Market

Competitive Power Ventures (CPV) announced Friday that it is launching CPV Retail Energy, a subsidiary to sell power from its “low-emitting” combined cycle plants within the PJM grid to commercial and industrial customers.

“CPV is excited to launch this new platform, which will enable the company to share the benefits of its renewable and world-class low-carbon fleet directly with customers,” Qadir Khan, president of CPV Retail Energy, said in an announcement of the launch. “The retail team has decades of experience in building successful retail platforms, and we look forward to developing this new customer-focused platform.”

Matt Litchfield, director of external and regulatory affairs, told RTO Insider that CPV has a unique generation fleet in that most of its traditional thermal assets have come online since 2016, meaning its units have some of the most efficient and low-emission technology. The company also has more than 4,000 MW of renewables in its development queue across the nation, which brings its total generation to 7,000 MW in development, construction and operation.

“There’s other companies out there that offer renewable options, which we will as well, but there’s not a lot of other companies out there offering a low-carbon product as well,” Litchfield said of the company’s reasons for entering the retail market.

The company is also embarking on a $3 billion development of an 1,800-MW combined cycle facility equipped with carbon capture technology in West Virginia, in part using tax credits under the federal Inflation Reduction Act. Litchfield said the project is indicative of the type of low- and zero-carbon emitting generation options the company will offer to consumers.

With the majority of the company’s assets based within the PJM footprint, CPV Retail Energy will begin by focusing its operations in Delaware, Illinois, Maryland, New Jersey, Ohio, Pennsylvania and D.C. The company has plans to expand into New York and New England.

“With plans and products from CPV Retail Energy, customers will have access to reliable electricity sourced from a company that is not only committed to the environmentally responsible production of electricity, but that also places a strong emphasis on being a good corporate citizen and operating with integrity,” Khan said in the announcement. “We can’t wait to get started growing CPV Retail Energy into a premier ‘Greentailer’ in the retail electric power industry and offer customized pricing plans including 100% renewable options.”

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Regulators File Emergency Motion in Ongoing Grand Gulf Battle

The convoluted and long-running clash over refunds due from years of alleged mismanagement and performance issues at Entergy’s Grand Gulf Nuclear Station took another twist last week when regulators accused the utility of publicizing a false narrative.

The Arkansas and Louisiana commissions and New Orleans’ city council filed an emergency motion Jan. 3 after an Entergy press release one week before.

The utility claimed FERC’s recent decision on Grand Gulf tax maneuvers meant it owed no additional refunds to ratepayers. The regulators, who were expecting hundreds of millions in refunds, asked FERC to correct the press release immediately (EL18-152, et al.).

The regulators and New Orleans have complained for years about mismanagement and substandard operations at the nuclear plant and sought refunds and rate reform on more than $1 billion in costs passed on to Entergy customers in their states and Mississippi. They said that despite expensive upgrades, the plant has been plagued by frequent outages at the expense of customers. (See Entergy Regulators Ask FERC to Settle Grand Gulf Dispute.)

The uproar centers on Entergy subsidiary System Energy Resources Inc. (SERI), majority owner and wholesaler of Grand Gulf’s output to Entergy’s Arkansas, Louisiana, Mississippi and New Orleans subsidiaries. In a pair of December orders concerning the nuclear plant, FERC ruled that SERI excluded decommissioning liability accumulated deferred income tax (ADIT) balances in rate bases from 2004 into the present, violating FERC’s tax normalization requirements (ER18-1182).

The commission also decided that SERI overcharged on the $17 million in Grand Gulf annual lease payments it collected from 2015 through 2022, ordering $149 million in ratepayer refunds (EL18-152).

FERC said the refund amount “appropriately captures the revenue requirement impact resulting from the exclusion of all ADIT amounts resulting from SERI’s decommissioning uncertain tax positions during the entire 2004 to present period of noncompliance.”

Entergy CEO Drew Marsh said in the company’s press release that the utility was “pleased that FERC’s remedy results in no additional refunds due to customers beyond those already provided in 2021 on the uncertain tax positions taken by SERI.”

Entergy said FERC’s refund ruling means that the issue will be completely addressed through its previously enacted $69 million rate base credit to customers for Grand Gulf’s expected lifetime and its one-time credit of $25 million in 2021 to remedy 2015’s decommissioning tax deduction.

The company said the commission’s decision stipulated that the refunds must not “re-establish” SERI’s ADIT balances for tax positions that were denied by the IRS and therefore didn’t benefit the company. The utility explained that except for a $100 million partial acceptance of its 2015 tax position, the IRS didn’t permit any of SERI’s other uncertain decommissioning tax positions.

“Under the remedy specified by FERC, for uncertain tax positions that the IRS fully disallowed, and for which SERI received no tax benefits, no refunds are due. We therefore calculate the remaining refund for the uncertain tax positions issue to be $0,” Entergy said.

“The position Entergy asserts in its press release is a blatant and perhaps intentional misrepresentation of the commission’s orders,” the state and city regulators told FERC. “Unless corrected, it may cause substantial damage to Entergy investors and at the least will mislead those investors and the consuming public. A clarifying statement from the commission can diminish these consequences.”

Entergy released a statement on Thursday addressing regulators’ emergency motion. It said it was “following FERC’s regulatory process” and plans to file compliance “detailing the refunds that we believe are required by the FERC order.”

However, the utility doubled down and said SERI owed no additional refunds stemming from its ADIT tax positions.

“As we’ve consistently said, SERI’s tax strategy was conducted in the best interest of our customers and ultimately saved millions of dollars in operating expenses. Those cost savings have already been passed on to our customers, and we believe we have already paid the refunds due under the remedy FERC outlined on the uncertain tax positions taken by SERI,” the company said.

Entergy added that a global settlement of all SERI dockets is in the “best interest of all parties.”

The state regulators and New Orleans also allege Entergy recovered the costs of lobbying, image advertising and private airplane use in rates through the plant’s sales agreement.

Entergy has offered its regulators nearly $600 million to resolve the Grand Gulf complaints, with $235 million to the Mississippi Public Service Commission, $142 million to the Arkansas Public Service Commission, $116 million to the New Orleans City Council, and $95 million to the Louisiana Public Service Commission. Only the Mississippi PSC has taken Entergy up on its offer. (See Entergy Offers Regulators $588M to End Grand Gulf Complaints.)

Entergy also said last week that it will seek a rehearing of FERC’s decision that SERI owes nearly $150 million in refunds because it improperly billed the costs of Grand Gulf’s sale leaseback renewals in its formula rate. The utility said the sale leaseback renewal “was entered into to lower costs to customers, which is a benefit that FERC previously recognized.”

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Cap-and-trade Revenues Still an Unknown for Wash. Lawmakers

Washington lawmakers won’t know until mid-March how much cap-and-trade revenue they will be able to spend during the 2023-25 budget period.

That will be five to six weeks prior to the end of the 2023 legislative session, which is scheduled to finish April 24. Traditionally, both the Washington House and Senate unveil their individual biennial budget proposals in early March to begin talks to reconcile the two measures. The 2023 session begins Jan. 9.

The bottom line is that a mid-March unveiling of cap-and trade figures will create a time crunch in Washington’s budget deliberations.

Following a brief introduction by Gov. Jay Inslee, officials from the state’s Ecology and Commerce department on Wednesday briefed the press on what is next in implementing the state’s new cap-and-trade and low-carbon fuels laws. Both went into effect on Jan. 1.

“It’s a happy day when the state can take a huge bite out of climate change,” Inslee said.

Ecology Director Laura Watson and Commerce Assistant Director Michael Furze said they don’t know how many of the initial 6.185 million allowances will actually be sold during the program’s first auction on Feb.28. “We have seen businesses positively responding here,” Watson said. Watson also said her agency cannot provide an estimate on final prices in the auction.

Revenue figures will be provided to the legislature a couple weeks after the auction, Watson said. Initial speculation is that the figure could be in hundreds of millions of dollars. Last year, Ecology officials told legislators the program should yield about $500 million in annual revenues. (See Cap-and-trade Projected to Provide Wash. $500M Annually.)

Some lawmakers are seeking to use cap-and-trade money to fund proposed tree-planting programs to replace trees lost to development and shade rivers and streams that provide routes for migrating salmon. Republicans want to use a portion of the funding to create an Office of Puget Sound Water Quality to provide help and supervision to municipal sewage treatment plants to decrease the amount of nitrogen-laden nutrients dumped into the sound, which harm fish. (See Climate Still on Wash. Agenda After Landmark Legislative Sessions.)

No dates have been set yet for the second, third and fourth auctions in 2023.

Meanwhile, state officials contended Wednesday that the new low-carbon fuel standard (LCFS) that went into effect on Jan. 1 will have little effect on gasoline prices. Watson said no gas tax increases are expected from either cap-and-trade or the LCFS. 

“The price impacts are pretty minimal,” said Joel Creswell, climate policy section manager at the Ecology Department.

They were responding to contentions by critics that California’s low-carbon fuel standard increased gas taxes — or fees — there by 40 to 50 cents per gallon.

Washington’s new LCFS requires that carbon emissions from gasoline and diesel fuel sold in Washington motor vehicles to be cut by 10% below 2017 levels by 2028 and by 20% by 2035. The bill excludes from these goals fuel that is exported out of state, and fuel used by vessels, railroad locomotives and aircraft. The goals apply to overall vehicle emissions in the state and not to individual types of fuels. 

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Texas Petitions SCOTUS to Review ROFR Ruling

Texas has petitioned the U.S. Supreme Court to review the 5th U.S. Circuit Court of Appeals’ 2022 ruling that the state’s law giving incumbent transmission companies the right of first refusal to build new power lines is unconstitutional.

In a Dec. 28 filing, with Texas Public Utility Commission Chair Peter Lake as the lead petitioner, the state asked the high court for a writ of certiorari, a formal request to review a lower court’s judgment against the petitioning party.

The petition comes after the 5th Circuit’s August decision in NextEra Energy’s challenge to a 2019 Texas law (Senate Bill 1938) that set up ROFR within state lines.

The appeals court ruled that Texas’ ROFR law violated the U.S. Constitution’s dormant Commerce Clause. It remanded the case back to the U.S. District Court for Western Texas, saying it should proceed beyond the lawsuit’s pleading stage (20-50160). (See 5th Circuit Finds in Favor of NextEra’s ROFR Appeal.)

The district court in 2020 rejected NextEra’s claim that the Texas law violated the clause because it only allowed the incumbent state owners of a transmission line’s end points to build, own and operate new lines. The court said the legislation doesn’t discriminate against interstate commerce because it “regulates only the construction and operation of transmission lines and facilities within Texas.” (See District Court Dismisses Texas ROFR Repeal.)

Texas said the question in the proceeding is whether “consistent with the Commerce Clause, states may exercise their core police power to regulate public utilities by recognizing a preference for allowing incumbent utility companies to build new transmission lines … or if such a preference necessarily violates the Commerce Clause, as the 5th Circuit held.”

Noting that the Supreme Court has said regulating utilities is “one of the most important of the functions traditionally associated with the police power of the states,” Texas said it exercises this power by regulating electric transmission throughout the state.

“For decades, the accepted view across the nation was that system reliability, efficiency and cost for ratepayers are all best served when new transmission lines are built by the owners of the endpoint facilities to which the new lines would connect,” Texas said in its petition. “Even when [FERC] changed course [in Order 1000], it expressly preserved states’ ability to maintain that policy.”

Lake was joined as a petitioner by his four fellow commissioners. The respondents include NextEra Energy Capital Holdings, NextEra Energy Transmission (NEET), NextEra Energy Transmission Midwest, Lone Star Transmission, NextEra Energy Transmission Southwest, Southwestern Public Service, Entergy Texas, Oncor, LSP Transmission Holdings II and East Texas Electric Cooperative.

The high court says it receives about 10,000 petitions requests for writs of certiorari each year. Only 100 or so eventually receive the writ and have oral arguments before the court.

NextEra subsidiaries were involved in two projects in Texas’ non-ERCOT footprint that ran afoul of the ROFR law. NEET Midwest won a competitive bid in 2018 for a $130 million, 500-kV project in East Texas. MISO said last year that planned capacity in the region had negated much of the project’s economic benefits. (See MISO on Verge of Cancelling Hartburg-Sabine Tx Project.)

NEET Southwest also applied to the Texas PUC in 2018 to transfer ownership of 30 miles of 138-kV facilities from Rayburn Country Electric Cooperative in SPP’s East Texas footprint. That application was withdrawn in 2020 after SB 1938 became law (48071).

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New Mission Means New Name for Advanced Energy Economy

Advanced Energy Economy has started 2023 with a new name, Advanced Energy United, reflecting both the progress the group has made since its founding and the challenges ahead.

The group’s original name reflected its goal of creating an economy powered by advanced energy. Now, although there is broad consensus around its objective, the group says, the challenge is harmonizing the technologies needed to achieve it and breaking down the barriers in the way.

“It’s a recognition of the moment in time,” President Heather O’Neill said in an interview with NetZero Insider. With $369 billion — or more — in clean energy tax credits, incentives and new programs available under the Inflation Reduction Act, the group’s goal is “having the industry come together to accelerate the energy transition and take advantage of the massive opportunities in front of us,” she said.

Advanced Energy was founded in 2011 by two early clean energy investors, the hedge-fund manager and philanthropist Tom Steyer and venture capitalist Hemant Taneja. Neither is currently involved with the organization, but, O’Neill said, “they came together with the belief that there was a need for a national entity that could serve as the bipartisan, data-driven business voice for clean energy to change the landscape and market opportunity.”

The organization numbers more than 70 corporate members, including independent power producers and technology companies. In addition to its federal advocacy, the organization works with a range of state and local officials and regulators in 12 states: Arizona, California, Colorado, Florida, Illinois, Indiana, Michigan, Nevada, New York, Pennsylvania, Texas and Virginia.

Advanced Energy said it hopes to expand its state advocacy in the West and Northeast this year, targeting Connecticut, Maryland, Massachusetts, New Jersey and Rhode Island, as well as New Mexico. The organization’s PowerSuite database tracks energy policies in all 50 states.

In anticipation of the IRA rollout, the group released three “toolkits” for state officials with information on how to plan for and access the law’s various programs and incentives: one for governors and other state administrators; one for legislators; and one for regulators.

Advanced Energy’s shift is the latest rebranding among energy-related trade groups, often reflecting mergers or the evolution of their missions as technologies and markets also evolve. In 2021, the American Wind Energy Association revamped as the American Clean Power Association, which absorbed the U.S. Energy Storage Association last year and claims more than 800 members. (See Unity Touted at American Clean Power’s First Conference.)

The American Coalition for Clean Coal Electricity (ACCCE) renamed itself America’s Power in 2018, according to its IRS form 990. In a 2016 cost-cutting move, the American Petroleum Institute absorbed America’s Natural Gas Alliance, which represents independent natural gas exploration and production companies. (See API, ANGA Merge in Cost-Cutting Move for Oil Gas Lobby.)

The same year, the Solar Electric Power Association became the Smart Electric Power Alliance, later merging with SGIP — Smart Grid Interoperability Panel — an industry consortium focused on grid modernization.

Advanced Energy United is hoping to avoid any abbreviation of its name, at least for the time being, said Adam Winer, the group’s strategic communications director. As inevitable as they seem to be in D.C., abbreviations don’t help people understand an organization’s mission, and most wouldn’t recognize the new name if it is abbreviated, he said.

O’Neill answered other questions about Advanced Energy’s rebrand and the group’s priorities for the new year in the interview below, which has been edited and condensed.

NetZero Insider: In your announcement of the new name, you talk about Advanced Energy being a “unifying voice” for the industry. How un-unified is the clean energy sector? Why does it need a unifying voice?

O’Neill: Traditionally our industry has been siloed by technology, and there’s increasing recognition that working together, there are tremendous benefits. It’s going to take all our technology solutions ― grid-scale, distributed energy resources of all types ― if we’re accelerating this transition to 100% clean energy in the U.S. It’s a recognition, I think, of the opportunities presented at this moment … [for] really bringing all of our technologies together and presenting systemwide solutions to policymakers.

We’re able to unlock solutions that are market-transforming, market-wide transformations, because we’re not looking at problems or identifying solutions from one narrow technology, but really looking across the energy system and looking for wins that will scale clean energy writ large.

Advanced Energy is one of the cohort of clean energy trade and advocacy groups in D.C., many with overlapping missions and priorities. How are you different? What are you offering that that the others aren’t?

We do represent all clean energy technologies and clean transportation technologies together; so really looking at an integrated approach, ranging from demand response, energy efficiency, storage, traditional renewables ― both utility-scale and distributed ― and into the transportation space. So really [it’s] a broad swath across what are the technologies and the companies that are going to accelerate this energy transition in the U.S.

The other thing that I think is relevant — and again, not new, but certainly part and parcel of who Advanced Energy United is — is that we’re deeply rooted in the states, as well as in key wholesale markets. So, even when we’re focused on work in Washington, D.C., it’s a virtuous cycle with the work in the states.

The incentives and programs in the IRA come with a lot of money but also a lot of requirements; the law has a lot of moving pieces. What are you hearing from your members? What are the challenges you see ahead?

What we’ve seen is just that there’s a tremendous appetite from folks on the ground in the states to understand what is available and how they can help unlock some of this massive transition. And so, what we’ve done and what we’ll be continuing to do, we put out toolkits right towards the end of the year … to really articulate all of the various energy provisions that were contained [in the law] and the ways in which they should be thinking about setting up programs really unlocking the potential here.

Toolkits are fine in and of themselves, but really, then, the work is spending the time in the states, with decision makers, and working through whatever their particular structure is set up to afford them to do. That’s the work that will be ongoing for our teams in this early part of the new year.

Big question: How are you going to work with the Republican majority in the House of Representatives?

I think [we will be] really focused on not just IRA implementation but also looking at critical minerals, at domestic manufacturing. How can we expand domestic manufacturing and advanced energy technologies? I think that is a bipartisan issue. That’s a priority for us in this coming year ― to really think about how do we both enhance access to critical minerals and support recycling that builds on some of the provisions in the Inflation Reduction Act.

I don’t want to put words in your mouth, but what I’m hearing is you’ll be looking to find the issues where you think there is good bipartisanship.

Yes, both good bipartisanship and [issues that] are important to our industry. If we’re going to scale the clean energy transition, we need to expand domestic manufacturing; we need to be thinking about where we’re getting some of the critical minerals from and how we’re improving the processes around those. So absolutely thinking about both what are issues that will resonate across the aisle, and what are issues that are incredibly important for our industry in order for it to scale.

Dare I ask, what’s your take on permitting reform?

For us as an organization, we’re thinking about working on, acting on [it] in states and regions. How can we help build things? And that includes issues related to transmission; that includes issues related to interconnection and to siting. All of those pieces are part and parcel of the work that we do and the work we’re focused on in the states.

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Massachusetts Floats FCEM Proposal

The energy department of outgoing Massachusetts Gov. Charlie Baker left behind a gift on the governor’s last day in office: a Forward Clean Energy Market proposal.

The document, put together by Massachusetts Department of Energy Resources officials along with Brattle Group and Sustainable Energy Advantage, is intended to be a first draft that could eventually make its way into the NEPOOL stakeholder process.

It will add new weight to longtime discussions about creating a clean energy market in the region for the purpose of encouraging the buildout of more renewable and non-emitting energy sources.

FCEM is the preferred regional decarbonization solution of the states, which are wary of the political implications of carbon pricing. But ISO-NE has warned that FERC or the courts could find the proposal discriminatory.(See NE States, ISO-NE Start to Wrestle with Next Steps on Pathways.)

“Massachusetts views the FCEM as a critical, and presently missing, institutional pillar that will be required to support equitable, affordable, and reliable clean energy transition,” the proposal says.

Structure and Governance

The proposal calls for creating a new independent nonprofit to administer the FCEM, led by representatives of each of the six New England states. Whether it would be FERC jurisdictional is up for debate. Under the main proposal it would, but the proposals’ authors also acknowledge that they might need an alternative structure separate from ISO-NE and overseen exclusively by state officials.

The FCEM’s auctions would line up with ISO-NE’s existing capacity market, taking place every three years. Buyers in the market (such as state agencies, competitive retailers, utilities, municipalities and private companies), taking part voluntarily, could procure one of a number of types of clean electricity certificates.  

The FCEM would include several other mechanisms that the proposal says are designed to “facilitate the financing of large volumes of new clean electricity resources.”

Those include a new resource price lock-in that guarantees new resources a clearing price for a term of 15 years at the rollout of the FCEM, the option for buyers to specify that their demand must be fulfilled by new resources and the option for buyers to submit a “phased entry” demand bid that offers greater flexibility in the startup date for projects that can offer a more competitive price if they initiate operation in future years.

Multiple certificates on offer 

The system would be designed to handle both several region-wide products and whatever certificates states want to put forward on their own, the proposal says.

The first region-wide product would be a New England Renewable Energy Certificate that would be comprised of onshore and offshore wind, solar, hydroelectric and some distributed energy resources.

The second would be a Clean Energy Attribute Certificate, representing “energy generated by any non-emitting energy resource,” including renewables as well as nuclear.

The third is a GHG Marginal Abatement Certificate that includes all of the above, as well as storage and demand response.

And the fourth is a Clean Capacity Certificate that represents all of the above plus clean capacity imports.

States could then list their own products, with no limits on scale or technology types.

“These state-defined rules need not match the rules applicable to similar regional FCEM-defined products. However, over time, the experience with innovative product offerings within the FCEM and across participating New England states may be mutually informative, improving the economic efficiency and efficacy of both state policies and the FCEM products,” the proposal says.

Buyers would have the option to procure their certificates from any combination of the products listed.

The FCEM would use the NEPOOL Generation Information System to track certificates.

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Southern Board Taps Womack as New CEO

Tom Fanning (Southern Company) Content.jpgTom Fanning, outgoing CEO at Southern Co. | Southern Co.

Southern Co. (NYSE:SO) announced a major executive reshuffle Thursday, with CEO Tom Fanning set to step down from most of his roles and the head of its biggest subsidiary tapped as his successor.

The company’s board of directors named Chris Womack, current CEO of Georgia Power, to take over as CEO of the overall organization; he will also succeed Fanning as president. Womack has also been elected as a member of the board, though Fanning — the board’s current chair — will remain with the company as executive chairman after ceding the CEO’s office to Womack.

Fanning plans to remain as president until the end of March and step down as CEO after Southern’s annual meeting this year. The date for the meeting has not been announced, though the gathering has been held in late May for at least the last five years.

Along with Womack’s ascension, the utility announced the following executive appointments:

  • Kimberly Greene to succeed Womack as CEO, president and chair of Georgia Power;
  • Jeff Peoples as CEO, president and chair of Alabama Power;
  • James Kerr II as CEO, president and chair of Southern Company Gas; and
  • Peter Sena III as president of Southern Nuclear.

Peoples will step into his new role immediately; the other moves are effective March 31. Sena will remain as chief nuclear officer of Southern Nuclear, while Stephen Kuczynski, the subsidiary’s chairman and CEO, will also keep his positions.

Womack has worked at Southern since 1988; prior to joining the utility, he worked for the U.S. House of Representatives. He became president of Georgia Power in 2020 and added the chair and CEO duties in 2021.

“Chris’s leadership, vision and integrity during his career with Southern Co. have uniquely prepared him to guide Southern … into a new era,” Fanning said in a media release. “I have confidence that Chris will continue our progress and deliver on [our] commitment to providing clean, safe, reliable and affordable energy and customized solutions to customers across the United States.”

Southern Active Under Fanning’s Leadership

Fanning became president of Southern in August 2010, assuming the roles of chair and CEO just a few months later. Under his tenure the utility has played an active role in the industry, spearheading influential, though sometimes controversial, initiatives.

Among Southern’s recent efforts is the launch of the Southeast Energy Exchange Market (SEEM). Southern — as part of a consortium of electric utilities including Duke Energy, the Tennessee Valley Authority, Dominion Energy South Carolina and Louisville Gas & Electric — proposed the market in 2021, suggesting that the planned expansion of bilateral trading in 11 Southeastern states would reduce trading friction while promoting the integration of renewable resources.

The project faced criticism from the start, with opponents skeptical the market would live up to its proponents’ promises. FERC only passed the SEEM agreement on a technicality in 2021, when the commission — down a member because of the departure of Neil Chatterjee — deadlocked 2-2 and the agreement took effect automatically in accordance with Section 205 of the Federal Power Act (ER21-1111, et al.). (See SEEM to Move Ahead, Minus FERC Approval.)

Since then SEEM has moved ahead despite ongoing attempts by various activist groups to reverse FERC’s approval: The market began operation in November, and utilities have continued to adopt the market. Most recently the commission approved the requests of Tampa Electric and Duke Florida to join SEEM, effective Jan. 1 (ER23-323, et al.). FERC still faces an ongoing lawsuit over its SEEM decision in the D.C. Circuit Court of Appeals filed last year. (See Environmental Groups Appeal SEEM in DC Circuit.)

Vogtle Units 3 and 4 (Georgia Power) Alt FI.jpgVogtle Units 4 (left) and 3 in November, with the cooling towers for Units 1 and 2 in the background | Georgia Power

 

Fanning also leaves unfinished the construction of Units 3 and 4 at the Vogtle nuclear power plant in Waynesboro, Ga. The two reactors — which Southern calls the first new nuclear units built in the U.S. in the last 30 years — have drawn much criticism over their frequent delays and cost overruns, including an inspection by the Nuclear Regulatory Commission in 2021 into Unit 3’s safety systems. (See Southern Faces NRC Inspection over Vogtle Repair Work.)

Southern began fuel load for Unit 3 in October and says the reactor should come online in the first quarter of this year. Unit 4 is scheduled to be completed in either the third or fourth quarter.

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ERCOT Board Member Resigns over Business Conflict

ERCOT’s Board of Directors has begun the year with one new member and a vacancy, leaving it with eight voting members.

The Texas grid operator Wednesday notified the market and membership that Zin Smati resigned from the board on Dec. 29 to comply with state rules after Boralex, a Quebec-based renewable operator where he is a director, completed the acquisition of a 50% ownership in five Texas wind farms.

According to the Public Utility Regulatory Act, “a person does not qualify for selection as a member of the governing body of [ERCOT] … if the person has a fiduciary duty or assets in the electricity market for that region.”

The ISO’s ethics agreement for directors also prohibits any direct business relationship with any market participant or its affiliates. Three of the wind farms are ERCOT market participants: Longhorn Wind Project, Spinning Spur Wind Three, and TX Hereford Wind.

Courtney Hjaltman 2022-12-20 (RTO Insider LLC) FI.jpgCourtney Hjaltman, OPUC | © RTO Insider LLC

ERCOT said Smati indicated that he planned to remain on the Boralex board and that he resigned his position to address the conflict.

Smati fully disclosed in a timely manner all applicable information, the grid operator said.

The ERCOT Board Selection Committee will work with an outside consulting firm to fill the vacancy. The committee consists of three members selected by Texas’ governor, lieutenant governor, and the state House speaker.

Earlier in December, Gov. Greg Abbott appointed Courtney Hjaltman, his deputy legislative director, as CEO of the Office of Public Utility Counsel. The position, which expires Feb. 1 but will likely be extended, comes with a voting seat on the ERCOT board.

Hjaltman replaces Chris Ekoh, who was serving as interim CEO.

The ISO’s board consists of eight independent directors, OPUC’s CEO, the Public Utility Commission’s chair and ERCOT’s CEO. The latter two positions do not hold voting powers.

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FERC, PacifiCorp Reach $4.4M Settlement in Tx Ratings Probe

FERC last week approved a $4.4 million settlement with PacifiCorp that ends an enforcement probe into the utility’s transmission line rating practices.

The deal includes a $1.9 million payment to the U.S. Treasury and $2.5 million that PacifiCorp will use to improve its transmission line rating capabilities, subject to FERC enforcement staff approval. The utility neither admitted nor denied the allegations in the case (IN21-6).

The allegations in the settlement cover 2009 until 2017, during which time enforcement staff found clearance violations on at least 215 transmission lines, which is 58% of PacifiCorp’s total transmission lines.

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The National Electrical Safety Code sets minimum clearances from any obstacle to conductors that must be maintained under the “maximum conductor temperature for which the line is designed to operate.”

PacifiCorp allegedly violated a NERC mandatory standard, FAC-009-1 RI, which requires utilities to document their “Facilities Ratings Methodology” in writing. The FRM contains the guidelines for transmission owners to develop their facility ratings and they are supposed to be followed.

Facility Ratings dictate how much power can flow across a facility, such as a transmission line. PacifiCorp developed its FRM in 2009 and it has been updated four times since then.

NERC issued a recommendation to the industry in October 2010 that it and regional entities had become aware of discrepancies between the design and actual field conditions of transmission lines that might be widespread. The reliability organization recommended that transmission owners, such as PacifiCorp, review their FRMs to ensure the written methodology is based on actual field conditions.

PacifiCorp spent $132 million fixing 4,725 clearance conditions, with the work wrapping up in 2017. Enforcement found that the clearance issues clashed with NERC’s requirements and did not fix all the violations until that work was completed.

The $2.5 million will go to reliability enhancements above and beyond NERC’s requirements for transmission line ratings. It will pay for a new single-source transmission facility ratings database management system that will promote enhanced accuracy in the development, updating and communication of facility ratings.

PacifiCorp will also install 60 new weather monitoring stations throughout its transmission system, which will feed information about ambient conditions directly into the data management system to further improve transmission line ratings. PacifiCorp agreed to make those investments within two years of the agreement.

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North Carolina Regulators Approve Duke’s 1st Carbon Plan

The North Carolina Utilities Commission on Friday approved Duke Energy’s first “carbon plan” to comply with the state’s law requiring carbon neutrality by 2050.

The plan does not include any major requirements to invest in new resources, but rather calls on the firm to update its modeling and file a plan with actual investments later. The order discusses different ways of achieving the law, from investing in renewables, to keeping existing nuclear plants running another 20 years, expanding batteries, and even building new natural gas plants to replace coal-fired ones.

“The guidance the General Assembly provided to the commission for this task is clear: The commission must find the least-cost path to compliance with the carbon dioxide emissions-reduction requirements while maintaining or improving the reliability of the electric system,” the NCUC said in its order. “Developing the path to least-cost compliance with the carbon dioxide emissions reductions that the law requires is complex and will, necessarily, be an iterative process given the rapid pace of change of the electric industry.”

The law also requires continued reliability of the system, with the NCUC noting that the transformation of the electric system will present new challenges for system operators as resources dependent on weather grow while new demand such as home heating must be met. The outages some customers saw over the holidays during cold weather underscores the vigilance the regulator will have to employ while overseeing that transition, the commission said.

Duke called the decision “constructive,” noting that the plan will be updated every two years going forward under state law.

The commission’s decision “advances our clean energy transition, supporting a diverse, ‘all of the above’ approach that is essential for long-term resource planning,” Duke said. “We’ve already made incredible progress, retiring two-thirds of our aging coal plants in North Carolina and South Carolina and reducing emissions by more than 40% since 2005; we will continue this ongoing work of lowering carbon emissions to reduce risk for our customers while balancing affordability and reliability.”

The utility said it will file an integrated resource plan with South Carolina regulators this August, which will take into account the carbon plan from its neighboring state, recent federal legislation on infrastructure and clean energy, and other factors relevant to clean planning. Customers in both states deserve a clean energy plan that keeps rates as low as possible, Duke said.

The commission drew fire from environmentalists, with climate advocacy group NC WARN calling its decision to allow Duke to build new natural gas plants “tragic.” It noted that in a quantitative analysis of the plan, Duke called for more than doubling its gas generation by building another 11,700 MW, but opponents have argued that the same capacity needs can be met with solar, wind, energy storage and efficiency.

“Duke Energy is required to obtain permits from the NCUC before it actually builds any more gas-fired power plants,” the group said. “NC WARN and others have vowed to vigorously oppose those applications.”

All of Duke’s modeling showed that new combined cycle natural gas plants would be needed as part of a least-cost energy transition and to help retire the utility’s existing coal plants, the NCUC said in its order. Replacing coal with new natural gas would eliminate the need for additional transmission at certain sites.

The delivery of natural gas to new natural gas plants is uncertain with Mountain Valley Pipeline’s construction still under litigation, but the commission said Duke would be able to pivot to an alternate plan if that pipeline does not go forward. The utility will have to use the most up-to-date information on natural gas prices and pipeline capacity into North Carolina to justify the construction of new natural gas plants under its climate plan, it said.

Without new natural gas plants, the utility said it would not be able to speed up the retirement of its dispatchable coal plants, with its plans to retire 8,400 MW of coal by 2035. New combined cycle plants produce 60% less carbon dioxide than the coal plants they would replace, the NCUC said.

The NCUC determined that planning for 1,200 MW of new combined cycle capacity and 800 MW of combustion turbines makes sense, but the utility needs to file a separate application to actually build such assets.