Search
`
November 1, 2024

Posted on

FERC Approves PG&E’s Proposal to Spin off Generation

FERC on Wednesday approved Pacific Gas and Electric’s transaction to spin off its non-nuclear generation to a new subsidiary called Pacific Generation (EC23-38).

The firm plans to sell off up to 49.9% of the generation subsidiary so it can raise capital more efficiently than through the sale of additional stock in parent company PG&E.

Pacific Generation will become a certificated, cost-of-service public utility regulated by the California Public Utilities Commission in the same franchise territory as PG&E after the deal closes, providing cost-based generation to customers and selling some power into the CAISO market under a market-based rate tariff the firm will file with FERC.

The generators being spun off include 3,848 MW of hydro, 1,400 MW of natural gas units, 152 MW of solar and 182 MW of storage.

The proposal led to protests from the California Community Choice Association, the Transmission Agency of Northern California (TANC), Northern California Power Agency (NCPA) and Public Citizen. (See Parties Protest PG&E Plan to Spin Off Generation.)

The community choice aggregation association argued that without detailed information on which firm will buy the generation, its impact on vertical market power cannot be determined. FERC sided with PG&E, saying that spinning off the generation to a new subsidiary that does not provide any inputs to electricity products will not lead to vertical market power concerns.

While the utility promised to hold its customers harmless in the transactions, the city of Santa Clara, TANC, Public Citizen and NCPA said that was not enough to ensure that outcome. PG&E should look into less disruptive ways to raise capital, Public Citizen said.

TANC noted that PG&E wants to issue up to $2.1 billion in debt for the new firm, whose assets will value about $3.5 billion. It argued that FERC should require the company to show its accounting treatment and whether the deal would alter PG&E’s equity ratio. The utility provided no information on which costs transmission customers will be held harmless, which makes it impossible to determine whether that will actually happen, TANC said.

FERC determined that the deal would not affect rates. When it comes to wholesale rates, the assets will be bid at market prices, which will not be impacted by the seller’s cost-of-service retail rates.

Pacific Generation has yet to file a request for market-based rate authority; FERC said its approval is based on the new firm getting that authority before the deal closes.

“Failure by Pacific Generation to obtain market-based rate authority as PG&E represents in its application would constitute a material change in circumstances that we rely on in making our findings herein,” FERC said.

The commission also said the protesters failed to show the deal would impact PG&E’s cost of capital or transmission rates. The deal would not impact the firm’s return on equity, its credit rating or its capital structure, so claims to the contrary lack a factual basis, the commission said. It noted, however, that if those change, then that would also represent a material change to the facts relied upon in its approval.

FERC also found the deal would not affect rates, as the new subsidiary and the utility will still be regulated by it on the wholesale side, and the CPUC on the retail side.

Public Citizen argued that the transfer of generation to private equity could impair state oversight, but FERC said that is beyond the scope of the proceeding because it focused on the spinoff, not any later sales.

The deal would not lead to any cross-subsidization issues, where benefits are transferred from captive customers to shareholders, because both the utility and Pacific Generation will be regulated by the CPUC, FERC said.

“A debt issuance by Pacific Generation for the benefit of its utility affiliate, PG&E, is not analogous to a situation where the assets of a franchised public utility with captive customers are used to finance its market-regulated utility affiliates or nonutility affiliates or their activities, which the commission has stated may raise concerns,” FERC said.

Many of the protests argued that FERC should consider the spinoff and the subsequent sale of a minority interest in the generation at the same time, but the commission disagreed, saying expanding the proceeding to cover the second deal would be inappropriate.

Posted on

W.Va. Coal-fired Plant May Experiment with Hydrogen to Avoid Demo

The continued operation of a 1,300-MW West Virginia coal plant may depend upon whether the boilers can be modified to burn a portion of hydrogen to reduce emissions, an engineering challenge and controversial experiment Japanese power plants have been investigating.

Pleasants Power Station, on the West Virginia side of the Ohio River, now owned by Texas-based Energy Transition and Environmental Management (ETEM), is to shut down June 1 in preparation for demolition. Its previous owner, Energy Harbor, this year sold the plant to ETEM for demolition and leased it back in order to operate it through May 31.

At the urging of the West Virginia Legislature, the state’s Public Service Commission in April ordered Monongahela Power and Potomac Edison, subsidiaries of Ohio-based FirstEnergy, to negotiate with ETEM with the goal of purchasing Pleasants and continuing to operate it.  

FirstEnergy asked for a $3 million/month surcharge to continue operating the plant if the subsidiaries were able to purchase the plant, a request the PSC also approved.

But ETEM was recently approached by Omnis Fuel Technologies, a California company that opened a Morgantown, W.Va., office this month to purchase the power plant, according to a filing last week by Monongahela Power and Potomac Edison.

“ETEM is particularly focused on a proposed transaction with Omnis Fuel Technologies, LLC. If consummated, the [companies’] understanding [is] that the ETEM/Omnis transaction would result in continued operation of Pleasants to generate energy using the hydrogen byproduct of Omnis’s graphite production operations — an outcome that would not involve Mon Power’s acquisition or operation of Pleasants,” the FirstEnergy filing noted.

But Omnis must sign a purchase agreement by June 10 and close the transaction by July 31, according to the filing.

In the meantime, FirstEnergy said it is willing to continue to negotiate with ETEM should talks with Omnis break down.

“The companies are willing to work toward completion of the [letter of intent] in order to protect the continued viability of the plant if the ETEM/Omnis transaction is not consummated. If an LOI is reached, it will be presented to the commission as soon as possible with a request for expedited action in light of the urgent circumstances,” FirstEnergy wrote.

Posted on

Wash. Looks to Sell 11M Allowances in 2nd Cap-and-Trade Auction

Washington is aiming to auction off enough cap-and-trade credits Wednesday to cover more than 11 million metric tons of carbon emissions. 

The state’s Department of Ecology plans to auction 11.035 million allowances, with each entitling the holder to emit 1 metric ton of carbon. Of that amount, 8.585 million credits will go into effect this calendar year and another 2.45 million in 2026.

This will be the state’s second quarterly auction since the cap-and-trade law went into effect in January.  The results of Wednesday’s auction will be announced on June 7.

The first auction held on Feb. 28 sold all 6,185,222 allowances at $48.50 each to raise almost $300 million for the state’s coffers. (See Washington Confirms $300M Take for Cap-and-Trade Auction.) In April, the state legislature divided that $300 million into 188 appropriations for solar farms, climate planning, pumped storage projects, developing a hydrogen industry, installing solar on buildings, constructing infrastructure for electric vehicles, producing hybrid fuel-electric ferries and tackling other projects.

Revenue from the Wednesday auction will be appropriated in the legislature’s spring 2024 session, along with proceeds from auctions in August and November, and February 2024. In January, the Ecology Department made preliminary estimates that the auctions would raise $484 million in cap-and-trade revenue in fiscal 2023 and $957 million in fiscal 2024. (See Washington Estimates $1.5B in Cap-and-Trade Revenue Through 2024.)  

If today’s auction raises more than the Feb 28 auction, the state will be on its way to exceed its preliminary estimates.

The minimum bidding price is $22.20 per credit, the same as on Feb. 28. The allowances will be sold in bundles of 1,000 credits.

Posted on

California Bill to Speed Transmission Development Passes State Senate

A bill to accelerate the development of new transmission lines in California passed the state Senate Tuesday on a vote of 36-0 and is now headed for the lower house.

Senate Bill 619 would expand the authority of the California Energy Commission (CEC) by extending the agency’s existing “opt-in” permitting process to include new transmission lines that require a capital investment of at least $250 million over five years — although many such projects would still be excluded.

While not part of Gov. Gavin Newsom’s recently introduced legislative package to expedite the development of clean energy resources through looser permitting, SB 619 falls in line with the governor’s efforts, which last week took on a new sense of urgency. (See Newsom Stresses Role of Permitting in Calif. Energy Transition.)

“California’s efforts to build the clean energy supply of the future will fall flat if we rely on the grid of the past,” bill sponsor Sen. Steve Padilla (D) said in a statement Tuesday. “We must act now, to approve new projects and expand our transmission capacity. The state needs to triple the size of our grid over the next decade, and we are falling behind every single day.”

The CEC’s opt-in process is the product of a 2022 law (AB 205) that authorized the agency to create a new certification and permitting program that allows developers of non-emitting energy resources and related facilities — including transmission — to optionally seek approval from the CEC instead of a local permitting authority.

To be eligible for the process, a project must qualify under California’s Environmental Leadership Development Project program, which entails stringent environmental and labor provisions. SB 619 would expand the CEC permitting process to also include point-to-point transmission lines that function as more than just tie-ins for generating or storage resources.

‘Substantial Delays’

Under current California law, developers of point-to-point lines are prohibited from beginning construction before obtaining a certificate of public convenience and necessity (CPCN) from the California Public Utilities Commission — or, in the case of publicly owned utilities (POUs), a permit from a local authority.

The CPUC’s CPCN process includes both an environmental review under the California Environmental Quality Act (CEQA) and an evaluation of project need and costs. Critics — including Padilla — have blamed that process for the lack of needed new transmission in California.

“Despite the overwhelming need to expand our electrical grid, the California Public Utilities Commission has not authorized a new transmission project in over a decade,” the senator’s office said in its statement. “The current process requires multiple agencies, duplicative analyses, and permitting processes that take years to complete and create unnecessary cost overruns and substantial delays.”

SB 619 would allow a subset of transmission developers to circumvent those processes by opting into CEC review. But even if it passes, the bill might have a limited role in spurring construction of new transmission. That’s because it explicitly states that it will not contravene the CPUC’s oversight over transmission lines proposed by any utility falling under CPUC jurisdiction, which includes Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — the investor-owned utilities that serve more than half the state.

“The supporters of this bill acknowledge this limitation and recognize that additional work would be needed to make any changes to the existing CPUC’s authority related to permitting transmission projects,” said a bill analysis provided to senators before the floor vote. “Instead, this bill would capture a more limited set of transmission projects, those serving publicly-owned utilities (POUs), which would otherwise be permitted by local governments.”

According to the analysis, bill supporters include Clean Air Task Force, Clean Power Campaign, 350 Humboldt: Grassroots Climate Action, Elders Climate Action and San Diego Community Power.

“SB 619 is a much-needed reform to expedite approvals of badly needed new transmission, to expand solar, wind, and batteries, and enhance affordability and reliability,” V. John White, legislative director for Clean Power Campaign, said in a statement after Tuesday’s vote.

The Senate’s advancement of SB 619 could herald the passage of similar bills from Newsom’s legislative package. Those include proposals to streamline judicial review of certain clean energy and transportation projects by requiring that challenges under the CEQA be resolved within 270 days and a related measure to streamline procedures for the preparation of the public record for court review of CEQA challenges.

Posted on

FERC Accepts MISO’s Pledge for Annual Capacity Ratio Calculation

FERC on Tuesday accepted a MISO tariff revision that promises an annual update of unforced capacity-to-intermediate seasonal accredited capacity ratio the RTO uses to determine supply ahead of its capacity auction (ER23-1223).

The ratio disrupted MISO’s first seasonal capacity auctions and delayed the opening of its offer window by about a month. (See 1st MISO Seasonal Auctions Yield Adequate Supply.)

FERC said the grid operator’s pledge to calculate the ratio on an annual basis is reasonable and “provides greater notice to market participants regarding the timing” of its calculation.

“We expect that the schedule MISO develops with its stakeholders will incorporate sufficient time to work with market participants to validate and confirm [seasonal accredited capacity] values before finalizing the ratio,” the commission said. “We encourage MISO to continue working with its stakeholders to improve its processes from lessons learned.”

The grid operator’s calculation of the systemwide ratio in December produced an incorrect value. A computer error that counted previously excused maintenance outages against some planning resources undervalued their contributions.

This year, MISO and its Independent Market Monitor decided against reworking the ratio ahead of the spring capacity auction. They reasoned that the oversight wouldn’t harm reliability, there wasn’t enough time to rerun numbers, and market participants had already relied on the inaccurate ratio to enter bilateral supply contracts outside of the voluntary auction.

However, FERC found MISO in violation of its tariff and issued a show-cause order that had staff rehashing the calculation and delaying its first seasonal capacity auctions. (See FERC Terminates MISO Show-cause Order.)

After the ordeal, the grid operator updated its tariff to state that it will calculate the ratio on a standardized timeline, despite the determination requiring multiple rounds of market participants’ data submission and staff’s review and confirmation. MISO said its pledge to run the ratio annually is part of its lessons learned in moving to a seasonal capacity environment. It didn’t specify when it plans to publish the ratio, saying it will settle on dates with stakeholders and include them in a business practice manual.

Commissioner James Danly said in a partial dissent that MISO should commit to a more specific timeline in its tariff and name dates.

“Given that there is so much at stake in the inputs to the Planning Resource Auction (PRA), the date of the annual establishment of the systemwide … ratio for each planning year is fundamental to the mechanics of the market,” he wrote. “This ratio ultimately informs load serving entities and resources of their accredited capacity in advance of the [PRA]. While there could be debate on this, I believe that the rule of reason compels us to require the date’s inclusion in the tariff rather than the business practice manual.”

Posted on

Personnel, Meeting Costs Drive 2024 ERO Budget Hikes

With the North American electric grid experiencing “an alarming increase in reliability, resilience and security risks” — particularly cybersecurity, climate change and the evolving resource mix — NERC and the regional entities plan to raise their budgets and assessments by more than 10% in 2024.

NERC last week posted for industry comment its draft 2024 business plan and budget, along with those of the REs and the Western Interconnection Regional Advisory Body (WIRAB). Every document anticipates a budget increase of about 8% except WIRAB’s, which projects a decrease of $52,028, or 5.9%, from 2023; WIRAB’s assessment is still to grow by 1.6%, or $10,772. The overall ERO Enterprise budget is to grow by $25.2 million in 2024 to $275.4 million, while the collective assessments are to rise by 12.1%, from $214.1 million to $240.1 million.

Lion’s Share to NERC

As always, NERC’s budget is by far the largest contributor to the increase, at $110.6 million, up 9.5% from 2023. Personnel expenses account for the majority of NERC’s planned spending, at $64.4 million, up 11% from the prior year.

NERC plans to add 11.3 full-time equivalent (FTE) positions in 2024. The new employees are to be spread among the ERO’s departments, with the biggest increase of 2.59 FTEs in the Electricity Information Sharing and Analysis Center (E-ISAC). The new personnel will contribute to the E-ISAC’s “analytical capabilities [and] membership support,” along with expansion and enhancement of the Cybersecurity Risk Information Sharing Program, NERC said.

An additional 2.27 FTEs are to be added in the corporate services division, to support NERC’s cloud computing efforts and system administration, along with the publications team, while one open position is to be eliminated and filled with a contractor. Two positions are expected to be created to help with reliability standards development and technical expertise support, and the event analysis and situation awareness departments are to add one position each.

Additional growth in the personnel budget comes from increasing costs of salaries, health insurance and other benefits. NERC’s budget assumes a weighted average salary increase of 5.5%.

Meetings and travel costs are expected to rise 8.3% from 2023 levels, to $3.4 million. NERC said this increase “marks the return to pre-pandemic levels” of activity, though the ERO is also working to de-emphasize in-person meetings — in part to reduce expenses — with the most recent Board of Trustees and Member Representative Committee meetings following a hybrid format. (See NERC Board of Trustees/MRC Briefs: May 10-11, 2023.)

NERC’s operating expenses are to grow by 11.6% to $40.3 million due to additional contractor, consultant and software costs.

RE Budgets Set for Growth

WECC is projecting the largest budget of the REs, with $35.4 million expected in 2024, up $3.6 million from the year before. ReliabilityFirst is next with $31.3 million, a 12% increase, and SERC Reliability close behind at $31 million, up 10% from 2023. The Midwest Reliability Organization is to grow by $1.8 million to $24.9 million — the smallest increase of any RE — with the Northeast Power Coordinating Council rising 13.7% to $23.2 million and the Texas Reliability Entity projecting the smallest budget, at $19.2 million (up 8% from 2023).

2023-2024 ERO Assesments (NERC) Alt FI.jpgERO Enterprise assessments for 2023 (dark purple) and 2024 (light purple). | NERC

 

Like NERC, many of the REs’ budgets are driven by growing personnel, technology and travel costs. All entities reported they plan to add personnel, ranging from two FTEs in the case of MRO to the 12 estimated by NPCC. Meetings and travel are expected to increase for all REs except MRO, despite the entity planning to cohost the GridSecCon security conference next year.

Comments on the draft business plans and budgets are due by June 23.

Posted on

Carbon-capture Plant Coming Back into Service

The Petra Nova carbon-capture facility’s owner has told ERCOT that it plans to bring the plant out of mothballs and into year-round service in June.

Japanese oil and gas company JX Nippon filed a notification May 28 with the grid operator that it intends to bring the world’s largest carbon-capture plant back June 28. The plant has been shut down since 2020, during the height of the COVID-19 pandemic and in the face of slumping oil prices. (See NRG to Mothball Petra Nova CCS Plant.)

Petra Nova has a summer capacity of 71 MW and was retrofitted at a cost of $1 billion to capture carbon from one of the nearby W.A. Parish Generating Station’s coal-fired units. NRG Energy, which operates Parish, must complete repairs on the unit Petra Nova is connected to before it can return to service.

NRG and JX were partners in the carbon-capture project. JX bought NRG’s 50% stake for $3.6 million and closed the deal shortly after Congress passed the Inflation Reduction Act last August. The legislation includes a significant increase for the carbon-capture tax credit.

Petra Nova went online in December 2016. It sequestered more than 3.9 million tons of carbon dioxide in three years, despite frequent outages.

Also last week, Calpine said four gas units at its Deer Park Energy Center near Houston will be converted from generation resources to settlement-only, transmission self-generators as of Oct. 27. The resources each have a summer seasonal rating of 190 MW.

Posted on

NextEra Gets Final OK for Kansas-Missouri Tx Line

The Kansas Corporation Commission (KCC) last week granted a siting permit for NextEra Energy (NYSE:NEE) Transmission (NEET) Southwest’s preferred route for the Wolf Creek-Blackberry 94-mile, 345-kV project, clearing the way for construction to begin.

The KCC said in a May 24 order that NEET Southwest had “met the requirements” for the siting permit, subject to an alternative reroute, micro siting — i.e., minor modifications to the route and infrastructure placement — and other small modifications agreed upon with a landowner (23-NETE-585-STG).

“The [c]ommission finds that the method that NEET Southwest used to select its route and the route proposed by NEET Southwest are reasonable and that the siting permit requested by NEET Southwest complies with all statutory requirements and should be granted,” the KCC wrote. It said the project “is needed and will have a beneficial effect on customers by lowering overall energy costs, removing inefficiency, relieving transmission congestion, and improving the reliability of the transmission system.”

The agency last August issued NEET Southwest a limited certificate of convenience and necessity as a transmission-owning utility for the 94-mile, single-circuit project, which will run from the Wolf Creek Generating Station in Kansas southeast into Missouri. In December, the Missouri Public Service Commission granted Southwest a CCN for the project’s nine-mile portion in Missouri. (See “Missouri PSC Grants CCN for NextEra Project,” MISO, SPP Fall Short in 5th Try for Interregional Projects.)

The project has received pushback from landowners and other critics who say the power will be shipped out of state. Florida-based NextEra is already in county district court litigation over its utility status in Kansas. The company expects the project to be in service by the end of 2024, barring any legal setbacks.

SPP granted the competitive project in 2021 to NEET Southwest over six other bids. The NextEra Energy subsidiary estimated the project will cost $85.2 million. (See “Expert Panel Awards Competitive Project to NextEra Energy Transmission,” SPP Board of Directors/Members Committee Briefs: Oct. 26, 2021.)

Commissioner Andrew French, who sits on SPP’s Regional State Committee comprised of state regulators, joined KCC Chair Susan Duffy in the 2-1 decision. The commission noted a need for SPP to allow state involvement earlier in projects’ design process and said it intended to investigate the principles and priorities for future siting dockets.

Posted on

PJM Urges FERC to Deny Winter Storm Complaints

PJM on Friday issued its first official responses to an onslaught of complaints at FERC from generators over Capacity Performance charges during the cold snap over the holidays, arguing that they knew what risks they were facing when they took capacity payments.

The winter storm led to many nonperformance charges Dec. 23 and 24, which have led to 12 separate complaints filed at FERC. PJM responded to seven of those Friday.

The storm, also known as “Elliott,” led to outages in neighboring grids and nearly did in PJM, though its operators were able to keep the lights on despite the nonperformance of many generators.

“These failures could have had life-and-death consequences had events played out differently,” the RTO said. “As it was, PJM operators preserved reliability while contending with unprecedented difficulties and uncertainties that were exacerbated by complainants’ nonperformance. In short, the lights stayed on despite extremely stressed conditions brought about by capacity resources failing to meet their obligations.”

PJM filed responses Friday to the “Nautilus Entities” (EL23-53); generators in the ComEd zone (EL23-54); a coalition of capacity resources including Competitive Power Ventures and Talen Energy (EL23-55); Lee County Generating Station (EL23-57); Sun Energy (EL23-58); Lincoln Generating Station (EL23-59); and Parkway Generation Keys (EL23-60), though comments came in to all 12 dockets.

The only ways generators can avoid nonperformance charges during emergency events are if they are on a planned outage approved by PJM or the RTO did not schedule them. CP holds resources with restrictive operating limits to the same standards as those without them. Natural gas generators are responsible for procuring natural gas deliveries despite pipeline outages.

“Capacity market sellers should assume that their resources will be needed, at a minimum, any time the PJM region is under a declared emergency for capacity shortages,” PJM said. “If capacity market sellers need to purchase natural gas and self-schedule to ensure that their capacity resources can be available when needed, then sellers of gas-fueled capacity resources should engage in such forward-looking behavior.”

PJM argued that the generators’ failure to perform cannot be excused by claiming the grid operator’s actions were invalid, by asserting there was no emergency or by arguing that their performance was not actually needed to address that emergency.

“Complainants urge the commission to become the Monday morning quarterback and super-operator of the grid, which are both roles the commission has been careful to avoid in the past,” PJM said. “The regulatory process will rapidly unwind with perpetual litigation, and reliability will be undermined, should the commission choose to disregard the real-time flexibility regional transmission organizations must have to manage emergencies and to substitute its judgment with the luxury of perfect hindsight.”

Some of the complaints criticized PJM for helping neighbors that were shedding load; siding with those arguments would chill cooperation between neighboring systems in future emergencies, the RTO argued.

The group of generators in ComEd’s territory argued that their islanded section of PJM lacked any real emergency, but the RTO said they do not get to determine when emergencies exist. PJM declares emergencies, and the 6,110 MW of generation in northern Illinois the generators failed to provide represents 21.5% of the reserves it was relying on during the storm, it said.

“PJM recognizes that there remain valid issues associated with the lack of synchronization between the natural gas nomination cycles and the real-time nature of electric system dispatch,” the RTO said. “This lack of synchronization is not new and existed at the time these unit owners submitted their bids into the capacity Base Residual Auction.”

One of the recommendations from FERC and NERC’s joint report on the February 2021 winter storm that knocked out power in Texas and surrounding states was to improve electric-gas coordination. The North American Energy Standards Board has been assigned that work.

Concerns over electric-gas coordination are national in scope, and FERC should not try to resolve them via proceedings on one winter reliability event in the Eastern Interconnection, PJM said.

Other Parties Weigh In

Sierra Club filed a response to several of the complaints, noting that they arose from the first application of the CP rules, which are also the subject of stakeholder proceedings looking into future changes. The organization said it is important to remember that a central objective of the rules was to get generators to change their behavior and investment decisions in ways that would improve reliability.

“Taking on a capacity obligation in PJM — in exchange for hundreds of millions of dollars in revenue — is not and should not be a risk-free enterprise,” Sierra said. “For the Capacity Performance system to work, suppliers must be held to the rules they agreed to when taking on and accepting payments for capacity obligations.”

Sierra had some sympathy with one of the complainants: SunEnergy1, a solar farm that wants relief going forward to excuse solar from the risk of nonperformance when the resource has little availability — and is paid less to reflect that. But natural gas generators should not be excused from the penalties because of “the inflexible gas supply arrangements” they prefer to make.

“Where penalties cannot drive better performance, a resource’s nonperformance should not incur penalties,” Sierra said. “In contrast, penalties should apply where resources can take steps to improve performance, such as weatherizing equipment or procuring gas in order to fulfil their capacity obligations — as the commission concluded after considerable discussion back in 2015.”

Constellation Energy Generation argued that FERC should dismiss the complaints because customers in PJM pay billions per year to ensure generator availability and the suppliers who failed to show up during Elliott knew what they were risking before the storm.

“PJM’s tariff is clear, unambiguous and strict: Penalties are mandatory when a CP resource fails to meet performance expectations during an emergency action declared by PJM,” Constellation said. “The exceptions are intentionally narrow.”

While generators face risks, they are allowed to include them in their capacity offers, along with the costs of investments to mitigate them. Generators also have the option to only participate in the energy market and avoid CP entirely.

“With full knowledge of the risks and obligations of accepting a capacity commitment, complainants bid into the capacity auction, received capacity commitments and cashed checks from ratepayers,” Constellation said. “But when their capacity was needed, they failed to deliver. Now they don’t want to pay the resulting penalties.”

Vistra told FERC that the markets performed as designed during Elliott, with some generators underperforming and others overperforming, while PJM maintained reliability.

“The complaints invite the commission to second-guess PJM’s operational decisions during emergency conditions and/or disrupt the market outcomes designed to flow from those decisions pursuant to the filed rate,” the company said. “Vistra respectfully submits that both invitations are perilous and, to maintain both the integrity of the market and the proper incentives needed for system reliability, the commission should view the complaints with skepticism.”

Even if FERC sides with the complaints, it should affirm the continued validity of the CP rules, Vistra said.

Posted on

Debt Ceiling Bill Provides ‘Mini-deal’ on Permitting

The debt ceiling compromise hammered out between President Joe Biden and House Speaker Kevin McCarthy (R-Calif.) would cut the time allowed for reviews under the National Environmental Policy Act (NEPA) to two years for a full environmental impact study and one year for a less intensive environmental assessment.

The main text of the Fiscal Responsibility Act (FRA), released Sunday, would raise the debt limit through Jan. 1, 2025; claw back some federal funding, such as billions in unused COVID-19 funding; and cap federal spending at current levels through 2024.

But 27 pages of the 99-page bill are focused on streamlining and accelerating permitting, including the designation of a single lead federal agency for such reviews and an expansion of the use of “categorical exclusions,” or waivers that would exempt projects from NEPA evaluations.

Speaking at press conference on Sunday, McCarthy called these changes “transformational.”

NEPA “hasn’t been reformed in 40 years,” McCarthy said. “It’s a frustration with people all across this country, on both sides of the aisle. [It] doesn’t matter if you want to build a road [or] you want to build a renewable energy project. That all gets stopped and studied for years. It’s a frustration. That’s millions of dollars wasted. That is all changing now so we can build again in America. We can make America strong. We [can] compete with other countries.”

Rep. Garret Graves (R-La.), one of the chief GOP negotiators, described the bill’s NEPA provisions as “shrinking the scope” of federal environmental reviews.

“NEPA has grown to just study all these things that don’t have anything to do with the environment, which I would argue … has worked against the protection of the environment,” Graves said during the Sunday press conference. “So, we’re trying to refocus the scope back on that, on the environmental impacts, and making sure we get the best environmental outcomes.”

But the White House framed the permitting provisions as a win for the key climate provisions of the Inflation Reduction Act, which the Republicans’ original debt ceiling package, the Limit, Save, Grow Act (H.R. 2811), had sought to roll back.

“We secured measures that will harness government efficiencies to accelerate construction projects across the country,” a White House official said during a background press call Sunday. “Specifically, the agreement includes measures aimed at boosting the coordination, predictability and certainty associated with federal agency decision-making. …

“And the agreement, importantly, makes these changes without curtailing the substantive scope of the NEPA statute,” the official said. “It doesn’t cut down the statute of limitations, as was proposed in [the GOP bill], or impose barriers to standing, or taking away injunctive relief or other judicial remedies.”

Republican proposals for changes to NEPA could have cut the window for judicial challenges from six years to as little as 60 days.

Both Biden and McCarthy emphasized that the bill is the result of negotiations in which neither side got everything they wanted. McCarthy also stressed that once the text of the bill was released, the House of Representatives would not vote on it for 72 hours to give lawmakers and the public time to review it.

Amid grumblings on both sides that concessions in the bill are too deep, questions remain on whether Republican and Democratic leaders in the House and Senate will be able to rally the votes they will need to get it to the president’s desk. Biden urged lawmakers in both houses to pass it, and McCarthy expressed confidence that the majority of Republicans would fall in line and vote for the bill.

NEPA Reviews

With Graves as a key GOP negotiator, the FRA’s permitting provisions incorporate many but not all the provisions from his Building U.S. Infrastructure through Limited Delays & Efficient Reviews Act, originally introduced in 2021.

In addition to the time limits on environmental reviews, the FRA would set a limit of 150 pages for EISes and 300 pages for projects of “extraordinary complexity … not including any citations or appendices.” EAs would be similarly limited to 75 pages, plus citations and appendices.

It would also require the designation of a lead federal agency to coordinate and set a schedule for any environmental review. And state, local or tribal agencies could be enlisted as co-lead or cooperating agencies.

If a lead agency did not produce an environmental review within mandated deadlines, the bill would allow a deadline extension, “in consultation with the applicant … that provides only so much additional time as is necessary to complete such environmental impact statement or environmental assessment.”

The bill specifies that the scope of such reviews should focus on “reasonably foreseeable environmental effects of the proposed agency action [or] any reasonably foreseeable adverse environmental effects which cannot be avoided should the proposal be implemented.” A “reasonable range of alternatives” would have to be examined, including negative environmental impacts arising from not completing the project.

It would also expand the use of categorical exclusions by allowing one federal agency to use the categorial exclusion that another agency has issued for a specific project. It would allow the use of “programmatic environmental” reviews, which cover a specific region or corridor in which one or more projects are located. The programmatic review can be used in the permitting of individual projects in the area covered by the review for up to five years or longer, “unless there are substantial new circumstances or information about the significance of adverse effects that bear on the analysis.”

The bill does not define what “reasonably foreseeable” environmental impacts are, and as noted by White House officials, it would not cut back the current six-year time frame for legal challenges to a NEPA environmental review.

More Changes in Offing?

In a major win for Sen. Joe Manchin (D-W.Va.), the bill calls for expedited completion of the embattled Mountain Valley natural gas pipeline (MVP), a provision also included in his permitting bill, the Building American Energy Security Act.

The FRA would declare the 303-mile project “in the national interest” and order the secretary of the Army to complete any final permitting on the pipeline within 21 days of the enactment of the law.

It would also prohibit any further litigation on the project, save for challenges to this provision itself, which could only be heard by the D.C. Circuit Court of Appeals.

This limit raises a question on whether passage of the FRA would retroactively nullify Friday’s decision from the D.C. Circuit overturning FERC’s decision to not perform a new EA of the pipeline. The decision requires FERC to perform the study but does not stop construction on the pipeline, which is 94% complete. (See related story, DC Circuit Partly Vacates FERC Gas Pipeline Approval.)

In a statement released Sunday, Manchin claimed credit for securing the Mountain Valley provisions. “I am pleased Speaker McCarthy and his leadership team see the tremendous value in completing the MVP to increase domestic energy production and drive down costs across America and especially in West Virginia,” he said. “I am proud to have fought for this critical project and to have secured the bipartisan support necessary to get it across the finish line.”

For transmission advocates, the FRA would authorize an “Interregional Transfer Capability Determination Study.” It would task NERC with completing this study in 18 months, looking at current transfer capabilities between “neighboring transmission planning regions” and making recommendations for “prudent additions to transfer capability” to improve reliability. The completed study would be submitted to FERC, which would have another year, plus a public comment period, to finalize and submit the report to Congress.

Rob Gramlich, president of Grid Strategies, an industry consulting firm, said the FRA contained little of significance to accelerate the permitting and construction of interregional transmission. The study could “raise a lot of people’s awareness about the benefits of transmission connecting regional grids,” Gramlich said. “But there’s still some debate about the details, like why does it take 2.5 years” for NERC and FERC to complete the report.

He also noted that FERC is already studying interregional transfers and recently ended a comment period following a technical conference on the subject. In general, stakeholders support the concept of expanding interregional transfer capability on the grid but differ on how to get there. (See Minimum Transfer Capability Between Regions Debated at FERC.)

The FRA would authorize another study to explore “the potential for online and digital technologies to address delays in reviews and improve public access.” Such an “e-NEPA” portal would allow developers to submit and track the progress of permitting applications online and allow federal agencies to collaborate and edit documents in real time. The bill would appropriate $500,000 for the study, which the White House’s Council on Environmental Quality would conduct and submit to Congress in a year.

The bill’s inclusion of energy storage projects in the FAST-41 process provides another small win for clean energy advocates. Originally set up under the Fixing America’s Surface Transportation Act in 2015 and expanded by the Infrastructure Investment and Jobs Act, FAST-41 allows for expedited permitting of certain infrastructure projects and already has an online dashboard for tracking projects. The White House official said that while some of the FRA’s provisions streamlining permitting do overlap with FAST-41, the processes are different.

Industry consultants ClearView Energy Partners characterized the FRA’s permitting provisions as a “mini-deal” that will “not make the holistic changes Republicans laid out in multiple recent proposals or transmission reforms sought by Democrats.”

The question now is whether the modest nature of the provisions will “mean more reforms [are] in the offing.”

“A reopening of debate looks more likely than actual finalization, but we expect lawmakers to try,” ClearView said. Prior to the deal, the Senate committees on Energy and Natural Resources and on Environment and Public Works had each committed to working on bipartisan permitting bills.

However, ClearView said, “the FRA mini-deal is more likely to undercut momentum for such efforts than to stoke it.”