The non-utility owner of a Washington gas-fired power plant can receive an initial allocation of free cap-and-trade allowances from the state, a government board decided Tuesday.
Washington’s Energy Facility Site Evaluation Council (EFSEC) unanimously approved extending the allocation to the 620 MW Grays Harbor Energy Center, which is owned by independent power producer Invenergy. The council’s discussion was limited to tweaking the language of the approval document.
The Grays Harbor plant is the only gas-fired facility in Washington that is not owned by a public utility, which means it did not receive the same no-cost carbon allowances granted to utility-owned power plants under the state’s new cap-and-trade program, which goes into effect on Jan. 1, 2023. Carbon emissions are calculated the same way for both utility- and non-utility-owned plants under the program.
The plant’s officials protested this discrepancy to the Washington Department of Ecology in June. “All the state’s power plants need to be on the same footing,” Grays Harbor Energy representative Torey Mielke said during a June 21 public hearing. (See Independent Power Producer Sees Risk from Wash. Cap-and-trade.)
Invenergy officials also expressed concern about their plant having to compete with out-of-state power producers that don’t have to spend money on the carbon-combating measures now required in Washington.
Under cap-and-trade, carbon emitters must acquire allowances for specific amounts of carbon dioxide pollution, which they can buy, sell or trade with other businesses. The maximum volume of statewide emissions would decrease over time.
The Ecology Department’s plan calls for an undetermined number of emissions allowances to be auctioned four times a year to smokestack industries. The first two auctions are scheduled for the first half of 2023, and the state will set the number of allowances 60 days prior to the auctions.
Companies would bid on the allowances in clusters of 1,000 individual allowances. The number of allowances will be decreased over time to meet 2035 and 2050 decarbonization goals. If Washington chooses to join the Western Climate Initiative, which includes California and Quebec, participants would expand their purchase and trading territory to those two areas.
For each auction, a specific number of allowances would be made available to bidders. All bids must be above a certain price level set in advance by the state. The highest bidder would get first crack at the limited number of allowances, while the second highest bidder would get the second crack, followed by additional iterations. The auction ends when the last of the designated number of allowances is bid upon. Then all the successful bidders pay the same clearing price set by the lowest successful bid.
Bidding companies are limited to acquiring 4-10% of the total number of allowances, depending on various criteria.
FERC last week revoked Tri-State Generation and Transmission Association’s market-based rate authority in the Western Area Power Administration’s Colorado-Missouri balancing authority area (WACM), but it found the cooperative may retain that authority in other BAAs (ER20-681, EL22-28).
The commission said information provided by Tri-State “failed to rebut the presumption of market power” in WACM. “As a result, we find that it is not just and reasonable for Tri-State to continue to have market-based rate authority in the WACM balancing authority area,” it said.
The data showed consistent screen failures across measurements, season/load periods and price sensitivities in the BAA, FERC said. It directed the cooperative to submit within 30 days a revised market-based rate tariff limiting sales at market-based rates to areas outside of WACM in which it retains MBRA.
The commission also ordered Tri-State to respond with a separate tariff to provide for the default cost-based rates in WACM or to make clear its intent to use its current cost-based tariff on file.
FERC opened an investigation into Tri-State under Federal Power Act Section 206 after it submitted its triennial updated market power analysis and a change-in-status notice last December.
The commission allows power sales at market-based rates if the seller and its affiliates do not have, or have adequately mitigated, horizontal and vertical market power. An applicant that fails one or more of the indicative screens is provided with several procedural options, including the right to challenge the market power presumption by submitting a delivered price test (DPT). However, the revised DPT indicated the consistent screen failures.
FERC did find that Tri-State passed the horizontal market power indicative screens for the Public Service Company of New Mexico and Public Service Company of Colorado BAAs and CAISO’s Western Energy Imbalance Market.
The commission on Thursday also rejected SPP’s proposed tariff revision to include an annual transmission revenue requirement (ATRR) for certain GridLiance High Plains facilities in Oklahoma’s Panhandle, affirming in part and reversing in part a decision by an administrative law judge in hearing and settlement procedures (ER18-2358).
FERC said that SPP’s 2018 filing to revise the tariff and allow recovery of the ATRR for GridLiance’s facilities was unable to prove the change was just and reasonable. It said that in protesting the filing, Xcel Energy Services (NASDAQ:XEL) was able to show “adequate evidence” that the facilities should be declassified as transmission under the commission’s seven-factor test.
FERC rules GridLiance’s Oklahoma facilities do not qualify for rate recovery. | GridLiance
Xcel also said GridLiance’s inclusion of its Oklahoma Panhandle facilities in its ATRR would result in a cost-shift to its Southwestern Public Service subsidiary, which shares the same transmission pricing zone (Zone 11). (See GridLiance, Xcel Battle over Tx Qualifications.)
The commission reversed an ALJ decision last year that the transmission facilities were eligible for recovery in transmission rates under SPP’s tariff. FERC directed GridLiance and SPP to issue refunds within 45 days to customers in GridLiance’s ATRR in Zone 11.
“We find, among other things, that … SPP and GridLiance failed to meet their burden to prove by a preponderance of the evidence that the GridLiance facilities are transmission facilities eligible for recovery,” the commissioners wrote.
FERC said that because it resolved the case’s central issue, it did not reach the merits of the rate impact, cost causation, prudent decision-making, and other arguments raised by Xcel and other intervenors.
The commission also dismissed a pair of Xcel’s formal challenges to GridLiance’s 2021 and 2022 annual formula rate updates as moot, citing the 2021 order over Xcel’s previous informal contention that GridLiance’s inclusion of the Oklahoma assets’ costs in its updates was improper (ER21-1438, ER22-1353).
It said that given the decision in the earlier proceeding and GridLiance’s implementation of the Zone 11 ATRR in the 2021 and 2022 annual updates, Xcel’s formal challenges were moot.
Just Energy OK’d for MBRA
FERC also granted power marketer Just Energy’s authority to make wholesale sales of energy and capacity at market-based rates and found it met the criteria to be a Category 1 seller in all regions (ER22-2044, ER22-2044-001).
The commission determined that because Just Energy does not own or control generation or transmission facilities, it satisfies FERC’s requirements for market-based rates regarding horizontal and vertical market power.
The ruling allows Just Energy to supply retail power in competitive markets, as one affiliate already does in ERCOT. It will contract with third parties to procure supply for its other affiliates and to provide them scheduling, settlement and bid/offer submission services once it registers with grid operators.
MISO continues to suss out a new availability-based capacity accreditation method for renewable generation, despite some stakeholders’ qualms with the early design.
The grid operator held a workshop Wednesday to dissect its proposed methodology for wind and solar resources. It will dole out capacity credit based on a unit’s availability during times of system need.
Jordan Bakke, MISO’s director of policy studies, said the goal is to fit renewable-resource accreditation into the “mold” of thermal units’ recently approved availability-based accreditation. He said MISO must make some assumption adjustments for a “different resource type with different characteristics.”
The RTO is creating “different swim lanes” between thermal, renewable and load-modifying resources, Bakke said.
The grid operator will use a modified effective load carrying capability (ELCC) calculation for renewable resources, then adjust those values for availability based on what it calls “resource adequacy hours,” or historical hours over a year that contain tight supplies and reliability risks.
MISO introduced the concept of resource adequacy hours when it overhauled its ELCC for thermal resources. They represent the top 3%, or 65, riskiest hours per three-month season and include the hours spent in maximum generation events. (See FERC OKs MISO Seasonal Auction, Accreditation.)
“Our bias is to remain somewhat close to what we filed at FERC” for thermal units, MISO planning adviser Davey Lopez said.
Bakke said ELCC is a “comparable method” when compared to thermal generation’s unforced capacity calculation (UCAP).
Clean Grid Alliance’s Natalie McIntire said she didn’t see how the calculations are comparable because UCAP relies on units’ forced outage rates but ELCC doesn’t.
Bakke said the divergence is necessary because wind and solar performance contain a lot of “availability variability” during tight operating periods. On the other hand, thermal output is steadier.
“The performance is much more uniform over time,” he explained.
Bakke said PJM and ISO-NE have made similar arguments to FERC when getting their renewable capacity accreditation designs approved. He said MISO could pursue a more complex calculation only to end up with a “comparable outcome” to the simpler ELCC method. He said MISO isn’t convinced that more labor-intensive number crunching would be worth the effort.
MISO plans on tweaking its current ELCC computation to apply to its ever-expanding renewable fleet.
Renewable energy accreditation will move from being derived using an individual, unit-level ELCC based on peak hour contribution to a resource portfolio-based standard ELCC that will be applied to a unit’s availability during pre-defined resource adequacy hours. Staff said they will create separate portfolio-level ELCCs for wind and solar generation and said they might adjust those based on whether units are located in MISO Midwest or MISO South.
Some stakeholders called the proposed ELCC method difficult to understand. Others said using a fleet-based average is too broad to apply to diverse wind units and will condemn renewable generators to lower capacity values.
Bakke said the portfolio-wide ELCC is “not a wholesale change” but necessary for MISO to have sustainable and consistent renewable accreditation moving forward.
Whether the ELCC should remain an average of unit performance across the portfolio or a become a marginal value, reflecting the capacity value of the most recent renewables additions, remains an open question.
MISO Independent Market Monitor David Patton advocated for a marginal value because he said renewable capacity contributions become less valuable from a reliability perspective as more are added.
“Every conceivable loss of load risk compounds when the wind isn’t blowing; therefore, building more wind at the margins is futile,” Patton explained. “You need more and more capacity for every megawatt you build of an already saturated technology.”
MISO hasn’t yet settled on a marginal versus average approach.
The renewable accreditation won’t cover battery storage or hybrid resources that pair a renewable energy resource with a storage facility. Bakke said MISO wanted to tackle the large amounts of wind, solar and load-modifying resources first before evaluating next year the accreditation of the “more emergent” resource types.
The grid operator has proposed using historical availability data collected from its existing demand-side resource interface to accredit LMRs. It said its control room operators “see a significant reduction in LMR availability when compared to what clears in the PRA.”
Stakeholders have asked MISO to compare the amount of LMRs’ load reduction that is weather dependent during the workday with weekend dependent.
As its on-demand, dispatchable resources shrink, MISO held its first stakeholder discussion on how it can better value generators’ services to the grid.
Senior Vice President Todd Ramey said the RTO is experiencing firsthand the global push to cut greenhouse gas emissions.
“We’re seeing a very similar story, interest in decarbonization, which in the power sector is a very tall ask,” he said during the Wednesday workshop.
Ramey said MISO is changing the way it thinks about power system operations as it grapples with a more decarbonized fleet. He said units that can ramp up or down on MISO instructions are in short supply.
MISO is expecting a 40% renewable energy penetration by the end of the decade.
Ramey said planning reserve margins “have all but disappeared at this point.” He said this is occurring against a backdrop of increasingly severe and unstable weather and electrification’s growing demand.
“Reserve margins might be set daily on what our risk posture is,” Ramey said. “Planning to get through a worst week is really not something the electric industry has focused on until recently.”
During the workshop, MISO proposed a handful of essential reliability attributes for resources that included black start, rapid start up, ramp up and down capability, sustained high output, voltage stability, and fuel assurance.
Zakaria Joundi, director of resource adequacy coordination, said the grid operator is attempting to figure out how much of each attribute it should maintain in its resource portfolio. He invited stakeholders to suggest other essential attributes staff need to consider.
If an aggressive resource transition plays out in the footprint over the next 20 years, Joundi said MISO will need about 366 GW worth of installed capacity on hand to maintain a one-day-in-10-years reliability standard. More than 83 GW of that would have to be capable of providing output for several days in a row.
The RTO also thinks it will require 5 GW of resources capable of ramping up within 10 minutes and 28 GW that can ramp up within an hour.
“Based on public plans that are out there, we feel that we may fall short on these attributes,” Joundi said
Jordan Bakke, director of policy studies, said staff isn’t presupposing an answer on attributes. He said MISO is asking stakeholders what “signals, requirements and facilities” it might need to improve the short-term operational horizon and its long-term resource adequacy.
“First we need to understand what attributes of resources are becoming at risk of being scarce,” he said.
Michelle Bloodworth, CEO of coal lobbying group America’s Power, asked that MISO extend attribute incentives to its current portfolio so that more thermal units don’t retire prematurely. She said a focus on the fleet’s existing attributes will ensure the RTO “doesn’t throw out the old with the new.”
“I think some utilities are making decisions based on political and environmental pressure rather than reliability and logic,” MidAmerican Energy’s Dennis Kimm said. He said utilities’ planning processes don’t include voltage stability and regulation, and they might benefit from MISO telling them which attributes to focus on.
Joundi said the attributes discussion will be “one of many” MISO plans to hold.
CHARLOTTE, N.C. — At Thursday’s meeting of SERC Reliability’s Board of Directors, CEO Jason Blake — reflecting on the fact that it was the first day of fall — reminded attendees “to celebrate our successes” in maintaining grid reliability during a challenging summer.
“I think sometimes within this industry we’re really good at focusing on where we fall short and wanting to take lessons learned,” Blake said. “But if you look at this summer, it was a hard one. We had seasonal peaks coming in earlier than ever, and occurring more frequently: extreme heat, extreme weather generally, whether it be extreme flooding [or] tornadoes. … And the thing I’d really like to take note of is the way the operators in our footprint generally have performed throughout the season. I think it’s been very laudable what they [have] achieved.”
Blake also reminded board members — and those attending virtually — that the challenges facing the grid from the growing adoption of renewable energy, the effects of climate change, electrification of transport and other trends “are not lessening.” He said that SERC and the rest of the ERO Enterprise have an important role to play in educating regulators and policymakers on the relevant issues.
NERC CEO Jim Robb has been instrumental in helping organization the leadership of the regional entities to advance these goals, Blake said, citing a “truly unprecedented” amount of “information and dialogue in this space” over the last year through the ERO Executive Committee, a gathering of the CEOs from each RE to discuss high-level reliability issues. Blake told attendees how SERC has worked to expand this engagement by hosting more meetings for lower-level staff from other REs to discuss the problems they face every day.
“The key point to take away there is that there’s alignment; there’s an understanding. We understand the broader picture, and we’ve had a strong voice,” Blake said. “I can tell you with great appreciation that the SERC team has been actively engaged in these discussions and really coming up with some awesome ideas to help advance the broader ERO Enterprise. So that alignment is key to our success — we need a strong NERC, just like NERC needs a very strong SERC to be successful.”
More Independent Directors a Possibility
SERC’s Nominating and Governance Committee is preparing to begin the process that could lead to a search for new independent directors, Chair Tim Lyons told directors on Thursday. The three independent directors currently serving on the board — Shirley Bloomfield, Lonni Dieck and Deborah Wheeler — are SERC’s first, having joined in 2021 after the RE implemented new bylaws in 2020 that required at least three, and no more than five, independent directors. (See SERC Appoints 1st Independent Board Members.)
Lyons said the committee is currently considering “whether … we are lacking skillsets on the board” that a fresh director could add. Areas of expertise that could be sought by the committee include the natural gas system, battery technology and human resources, along with “various other topics.”
The committee will first develop surveys — one for “stakeholder directors,” one for the current independent directors, and one for SERC’s leadership team — to determine the organization’s views on what skills might be needed. Lyons said the surveys should be sent out within the next six weeks, which would ensure enough time for respondents to return them and for results to be available by the next board meeting in December.
Board Chair Todd Hillman called for a “robust discussion” during the selection process for new directors, which Lyons said would likely take more than a year.
“As you all know, we [won] the lottery with our first set of independent directors,” Hillman said. “We want to continue to have the level of quality, insight and experience, and so we want to go into that conversation knowing full well that that quality is going to stay high.”
Strategic Plan Approved
The sole approval item at Thursday’s meeting was SERC’s long-term strategic plan, which the organization created to outline its contribution to fulfilling the goals of the ERO Enterprise Long-term Strategy. Members voted unanimously to approve the document.
The plan identified three key focus areas, according to which SERC should strive to be a:
credible and trusted expert organization;
leader in reliability and security across the industry; and
highly desirable place to work for all.
Jeni Belew, a senior program manager for strategic development at SERC who introduced the strategic plan, explained that to support the first area, the RE will “provide growth and development opportunities so that our talent is equipped to tackle the challenges facing the evolving electric grid,” along with “gold standard training opportunities [including] continuing education hours” and other credits that can encourage industry stakeholders to see SERC as a valuable source of expertise.
Belew explained that the second area requires building out SERC’s communications ability so that, as policymakers, regulators and other stakeholders learn of its expertise, it can deliver the information they need. To become a desirable place to work, the organization will “continue focusing on our culture and environment … to prioritize diversity, equity, inclusion and allyship … so that everyone finds purpose and value in the work that they do.”
SERC’s next board meeting is scheduled for Dec. 14 in Charlotte.
WASHINGTON — FERC’s members opened their monthly meeting Thursday by soliciting feedback on their forum with New England stakeholders on the region’s winter fuel security problems, once again highlighting the philosophical divide along party lines among the commissioners.
All agreed that the situation in New England is urgent, and any extreme weather this winter could result in a loss in electric reliability.
But Republican Commissioners James Danly and Mark Christie were more pessimistic, going so far as to suggest that the role of RTOs in general in ensuring resource adequacy should come to an end.
Each of the commissioners urged stakeholders to submit suggestions in the docket on what the commission should do about New England.
Chairman Richard Glick noted that the region is “still heavily reliant on LNG imports, and that’s just not sustainable. In the short term it might be necessary to continue that reliance, but in the long term, it’s just not sustainable.” He noted other “opportunities” to maintain resource adequacy, including more transmission and the coming offshore wind farms.
He also said ISO-NE needs to consider market changes, such as a seasonal capacity construct “to incentivize generators to make arrangements to provide more assurance that there’s going to be fuel supply when it’s needed on the coldest days of the year.”
But Danly reiterated his view, expressed at the forum, that “the situation is bad enough, both in terms of the actual fact of reliability challenges on the one hand and, second, the fact that there is no conceivable way to me that a capacity market can have rates that are J&R [just and reasonable] if the capacity market doesn’t actually deliver the promise of the resources that are to be drawn upon when necessary down the road.”
He recalled that ISO-NE CEO Gordon van Welie had pushed back on his suggestion that FERC should institute a proceeding under Federal Power Act Section 206 to remove their responsibility over resource adequacy and return it to the states. He said he understood that the RTO would not want “a free-wheeling 206 in which we say, ‘You have a problem; go fix it.’”
But “I think we have an unjust and unreasonable market, probably; obviously that would be what the 206 hearing would be for.”
Danly also lamented a recent ruling by the D.C. Circuit Court of Appeals that found ISO-NE’s Inventoried Energy Program, to go into effect for winter 2023, to be unjust because it would unfairly pay nuclear, coal, biomass and hydroelectric resources for fuel storage (ER19-1428-005). (See Court Strikes a Blow to ISO-NE Winter Plan.) The court left the rest of the IEP in place, allowing the RTO to compensate oil, natural gas and refuse generators.
FERC on Thursday issued an order on remand implementing the D.C. Circuit ruling. (The order had not been published as of press time.) “I’m concurring because the court has spoken, and we will do what the court says,” Danly said. “But that got rid of, effectively, one of the possible solutions to the fuel security problem this winter, and I am quite sorry that we’re in a position where … the strategy to get through this winter is to cross our fingers and hope for mild weather. That is not a good plan. …
“If anybody can come up with a short-term fix that would help with fuel assurance this winter, I for one would solicit a 206 filing,” Danly said.
Speaking about a different ruling involving NYISO, Danly also argued that “when you consider how this experiment in markets began, that we were going to use the markets to deliver the least-cost energy generation for the region in which they operate … it’s becoming harder and harder to believe in the premise upon which these markets were originally developed as we have greater and greater price suppression through state subsidies.
“It is getting to the point where I believe that these markets are so manifestly not J&R, given the price warpings, that it is difficult for me not to consider abandoning the entire experiment as long as it’s being conducted this poorly.”
Gradually, Then Suddenly
“I didn’t hear the perspective that markets cannot work, but I certainly share the perspective that at this moment, the markets may not be delivering just and reasonable rates,” Commissioner Allison Clements said. “To me, exerting commission leadership to move this ball forward does not suggest that we know better than the New England states, or that we have the right to override the states’ perspectives. Nor does it suggest that the entire solution set rests in the commission’s jurisdiction.”
She noted that ISO-NE had proposed undertaking a comprehensive study of the problem and potential solutions, with a number of state officials at the forum concurring.
“I, though, did not come away with a level of specificity around what this study should actually look like,” she said. “We know that the root of New England’s winter electric system reliability challenge is the significant dependence on natural gas in these extreme conditions, along with gas supply constraints. Shoring up or adding more natural gas supply capability is one way to address these constraints, [but] it is only one way. The region can also diversify away from reliance on natural gas for electric generation and can reduce both electric and gas demand.”
“When it comes to RTO markets … whether they’re still providing reliability and, more importantly, whether they’re providing it at just and reasonable rates, I think is a serious question,” Commissioner Christie said.
He quoted “The Sun Also Rises” by Ernest Hemingway, in which a character asks another how he went bankrupt. He answers “gradually, and then suddenly.”
“I think [RTOs are] moving from the ‘gradually’ phase to the ‘suddenly’ phase, and I think we’re going to have to grapple with that as we look at the future.”
“I want to hear from people [about] what more can FERC do, both under our FPA authority” and its ability to facilitate discussions, Commissioner Willie Phillips said. “Will additional meetings help? Could we establish a task force? Is there another forum that FERC could use to help bring people to the table? I’m very interested in that.”
On the other side of the extreme weather spectrum, Chairman Glick also complimented CAISO for getting through a weeklong, record-breaking heat wave earlier this month. (See California Runs on Fumes but Avoids Blackouts.)
“California ISO had a number of challenges and did an amazing job of getting through it without having to engage in rolling blackouts.” He reported that, based on a conversation with the ISO last week, the state’s energy storage resources performed very well and were key to maintaining reliability. He also highlighted demand response and California’s ability to import power.
But Commissioner Danly responded: “It is true that various resources played a part, especially on the margins, in keeping the system operating, but a clear-eyed, accurate assessment — if we actually look at where the power came from, natural gas is the reason those lights stayed on. That is the simple fact of the matter.”
The Department of Energy Thursday announced the opening of applications for $7 billion in funding for six to 10 clean hydrogen hubs.
“These hubs are going to be located in different regions all across the country,” Energy Secretary Jennifer Granholm said in announcing the solicitation at the Global Clean Energy Action Forum in Pittsburgh. “They’re going to use a variety of feedstocks — abated fossil fuel, renewables, nuclear — and they’ll focus on different end uses, for example, electricity generation, industrial production, residential, commercial heating [and] transportation.”
The report is the next step in the Hydrogen Energy Earthshot announced in June 2021, which set a goal of reducing the cost of clean hydrogen by 80% to $1/kilogram within a decade.
Granholm said the document projects “that by 2030, that our country’s clean hydrogen market might be twice as large as we projected originally: 10 million metric tons [MMT] by 2030, 20 million by 2040 and 50 million metric tons by 2050.”
The U.S. currently produces about 10 MMT of hydrogen per year — mostly for the petroleum refining, ammonia and chemicals — but that production generates greenhouse gases.
The report says clean hydrogen could reduce U.S. emissions by 10% by 2050 relative to 2005 levels, “based on achieving cost competitiveness to enable demand in specific sectors and where there are fewer alternatives, such as direct electrification or the use of biofuels.”
“Specific markets include the industrial sector, heavy-duty transportation and long-duration energy storage to enable a clean grid,” the road map says. “Long-term opportunities include the potential for exporting clean hydrogen or hydrogen carriers and enabling energy security for our allies.”
Sen. Joe Manchin (D-W.Va.) revealed the text of a much awaited proposal to streamline the permitting process for electric transmission and natural gas pipeline projects Wednesday for inclusion in legislation to keep the federal government operating past the end of its fiscal year Sept. 30.
The plan was controversial even before Manchin made the details public, drawing opposition from some Democrats for its benefits to the fossil fuel industry and from some Republicans because it was a bargaining chip in the recent Inflation Reduction Act.
The unlikely combination makes passage an uncertain prospect in the narrowly divided Senate.
The Energy Independence and Security Act of 2022 would speed and simplify siting of regional and interregional transmission lines viewed as indispensable to the Biden administration’s electrification and decarbonization goals. It would also mandate federal authorization for completion of the Mountain Valley Pipeline, which would boost natural gas exports from Manchin’s home state.
Among other key details, the act would:
set a two-year target for National Environmental Policy Act review of major energy and natural resource projects that require a full environmental impact statement and reviews from more than one federal agency, and a one-year target for projects that require an environmental assessment;
require issuance of all other permits within 180 days of finishing the NEPA process;
designate a lead agency to coordinate project reviews and expand the use of shared interagency environmental review documents and concurrent agency reviews;
set a 150-day statute of limitations for court challenges; require random assignment of judges; and require courts to set and enforce a “reasonable” schedule (no more than 180 days) for agencies to act on remanded or vacated permits; and
establish procedures for resolving project disagreements without delay.
Manchin has been a pivotal figure in the evenly divided Senate, a Democrat voting with Republicans against some measures that were priorities for his own party.
But he sided with the Democrats on the Inflation Reduction Act in August, in return for a guarantee that his bid to streamline the approval process for transmission projects would be included in a continuing resolution to fund the federal government.
FERC Role
Of particular interest to the electric transmission sector, the act would:
clarify that FERC has authority to promote and encourage the construction or modification of electricity transmission facilities within and between regions of the country to ensure an abundant supply of electric energy throughout the U.S.;
allow FERC, upon application by a state or utility, to direct the construction of transmission determined to be in the national interest;
give the secretary of energy, on application by FERC, authority to designate an electric transmission facility to be necessary in the national interest, which would allow the commission to issue a construction permit for a project;
allow eminent domain to be exercised on state land;
direct FERC to allocate the costs of projects it determines to meet certain criteria in accordance with its cost allocation principles and roughly commensurate with the estimated project benefits;
clarify that FERC is the lead agency for environmental reviews for transmission projects except where approvals are issued by the secretary of the interior; and
allow FERC to approve cost recovery payments to jurisdictions impacted by a transmission project.
Uncertain Prospects
Manchin and his bill face opposition from multiple directions, starting in his home state.
Sen. Shelley Moore Capito (R-W.Va.) is promoting an alternative streamlining measure that many of her fellow Republicans are lining up behind.
Many Democrats find the proposal’s benefit for fossil fuel projects and removal of environmental balances unpalatable; Sen. Bernie Sanders (I-Vt.) said earlier this month that he would vote against a measure to keep the government operating if it contained Manchin’s proposal.
And many Republicans are angered at Manchin for supporting the Inflation Reduction Act.
Manchin himself noted at a news conference Tuesday that there might be vindictive Republican votes against something the party has sought for years, simply because it was his plan.
Senate Majority Leader Chuck Schumer (D-N.Y.) pledged to put Manchin’s proposal in the continuing resolution in return for Manchin’s earlier vote, but he presides over a 50-50 split in the Senate and cannot easily force measures through.
The measure applies to projects that entail construction of infrastructure to produce, generate, store or transport energy; capture, remove, transport or store carbon dioxide; and mine, extract, beneficiate or process minerals that require preparation of an environmental document under NEPA.
“Major” projects are defined as those that require multiple federal actions and an EIS under NEPA, or those for which the project sponsor requests treatment as a major project, though only an EA is required.
The act would also require the president to designate 25 energy and mineral projects of strategic importance as national priorities for the American public; energy producers, consumers and workers; and international allies of the U.S.
Reaction
“We applaud Sens. Schumer and Manchin for moving forward with legislation to improve the nation’s outdated system for permitting critical energy infrastructure,” Heather Zichal, CEO of the American Clean Power Association, said in a statement Wednesday. “Making common-sense reforms to our current permitting process will help us unleash the full potential of the clean energy investments spurred by the Inflation Reduction Act and keep us within striking distance of the emissions-reduction targets and climate goals we need to achieve.”
Gregory Wetstone, CEO of the American Council on Renewable Energy, said: “We know we need to expand and upgrade the nation’s electrical grid to fully realize the renewable energy growth expected under the Inflation Reduction Act. … Sen. Manchin’s bill includes provisions that will help streamline the transmission approval process, improving our ability to meet our nation’s decarbonization goals by better connecting our key renewable resources to our largest population centers.”
And Grid Strategies President Rob Gramlich said, “This bill is a massive step forward for permitting and paying” for large-scale transmission projects. “The bill allows broad benefits of transmission to be reflected in how costs are recovered and speeds up approval timelines for siting while preserving the important environmental and public participation protections in NEPA.”
The Western Power Pool discussed the results of its first regionwide analysis of the Western Resource Adequacy Program (WRAP) with stakeholders Tuesday, including a look at the changing resource mix through 2027 and the need for higher planning reserve margins in the Desert Southwest.
“We are going to be an inch deep and a mile wide, so you should think about this as a survey or 101 overview of the metrics,” Ryan Roy, WPP director of technology, modeling and analytics, said while introducing the webinar.
“We’re going to talk a little bit about the loads and resources in the WRAP footprint,” Roy said. “We’re going to provide an overview of the installations and nameplate [capacity] for wind and solar, give you a feel for the number of units and number of plants that are out there.”
The WPP also provided an overview of the qualified capacity contributions (QCC) and effective load-carrying capability (ELCC) values for each resource class and of planning reserve margin values by region and month.
“This is relatively new for the Western Power Pool,” Roy said. “We’re working our best to ensure that the data is accurate, informative and timely. We’ve made a strong commitment to transparency. So, this is our first opportunity to talk about the broader regional results that we’re seeing in our modeling.”
For the Northwest, from 2023/24 through 2026/27, additional hydroelectric output will compensate for the retirement of most remaining coal plants, which will make up 2.07% of the resource mix in 2023 but .06% a few years later.
The Southwest, with a much different supply stack, will add solar and short-term battery storage from 2023 to 2027. The region will see a reduction in coal generation but still retain coal as a sizable portion of its resource mix, going from 24% in 2023/24 to 17% in 2026/27.
“The Northwest has planned resource retirements that can impact the capacity available to meet that one event day in a 10-year loss-of-load expectation, and the Southwest [will see a] significant increase in [solar and battery] resources.” Roy said. “They have very aggressive plan-to-build targets.”
An assessment of resource classes showed the WRAP footprint has a total of 146 wind plants with a nameplate capacity of 12,688 MW and 267 solar plants with 11,162 MW of capacity.
Peak loads in the Northwest top out at 41,502 MW during winter and in the Southwest at 37,434 in summer.
Planning reserve margins in the Northwest will not alter significantly in the four-year period covered in the analysis, but the Southwest will need to increase its PRM values to compensate for the infusion of variable solar resources, WRAP said. PRMs in the Southwest, for instance, will need to increase from 20% in November 2023 to 32% in November 2026, a slide in the presentation showed.
The webinar also included a detailed discussion of the ELCC and QCC of various resource classes by region and month.
‘Above the Line’
The presentation was a milestone for WRAP, the first broad-ranging resource adequacy program in the West.
WPP, formerly the Northwest Power Pool, started work on the effort two years ago amid concerns that Northwest utilities were increasingly and unknowingly drawing on the same shrinking pool of reliability resources.
Interest in the effort spread quickly to other areas of the West, and in a move that signified its expanding reach across the Western Interconnection, the Northwest Power Pool rebranded itself as the Western Power Pool earlier this year.
The program now has 26 participants from British Columbia to Arizona and east to South Dakota, including major players such as Arizona Public Service, the Bonneville Power Administration and PacifiCorp. CAISO, however, is not involved.
WPP’s WRAP program has 26 participants covering much of the Western Interconnection. | NWPP
WPP and SPP plan to launch a “nonbinding” iteration of WRAP soon, one that lacks enforcement and penalties, and a binding phase in 2024, in which participants will be held accountable for failing to meet their expected resource contributions.
WPP’s board approved a tariff for WRAP last month and is hoping for FERC approval by the end of the year.
SPP, which WPP chose last year as a program operator, provided the modeling and metrics discussed Tuesday.
“Current WRAP participants are completing the non-binding Winter 2022-2023 and Summer 2023 forward-showing submittals using the just-released metrics as a guide to meet program requirements,” WPP said in a news release. “Participants will turn in workbooks to SPP for evaluation and feedback. WPP and SPP intend to release aggregate performance information from these non-binding submittals once complete.”
Stakeholder comments in Tuesday’s webinar included a question from Fred Heutte, senior policy associate at the Northwest Energy Coalition, asking organizers why they had not summarized data by participant, showing those that have or lack sufficient qualifying capacity, and whether participants will have access to that data going forward.
“Who’s above the line?” Huette said. “Who’s not, for example?”
Rebecca Sexton, WPP director of reliability, responded that public release of the data could impact purchase negotiations between parties.
“There’s just too much sensitivity about that,” Sexton said. “You can imagine that if someone is being shown to the region as slightly deficient, that that just opens a whole can of worms with respect to how their conversations with folks go who might have some capacity they are willing to sell them.
“So, that sensitivity is one we want to be really aware of. We don’t want to have a negative impact on their participation in any market, bilateral now, certainly, or bilateral in the future as well, as we think about this forward procurement, so we will not be sharing that information.”
FERC reluctantly issued a Notice of Proposed Rulemaking on Thursday to consider a 200-basis-point incentive for utilities that make voluntary cybersecurity investments, an initiative directed by Congress in last year’s Infrastructure Investment and Jobs Act (RM22-19).
Expenses and capital investments in advanced cybersecurity technology that “materially improve” a utility’s cybersecurity posture and are not already mandated by NERC’s Critical Infrastructure Protection (CIP) reliability standards, or local, state or federal law, would be eligible for the incentives. Also included would be expenses for participating in cybersecurity threat information-sharing programs.
‘FERC Candy’
Chairman Richard Glick and Commissioner Mark Christie said they were reluctantly supporting the NOPR because of Congress’ directive.
Glick said NERC’s mandatory reliability standards have “proven to be a pretty effective approach,” although he acknowledged that it can take too long to respond to emerging threats by amending the CIP standards.
“I think that, if it is important that utilities make investments, or if it’s important that utilities participate in these information-sharing groups, we need to explore whether we need to utilize our mandatory reliability standards approach to get there,” Glick said. “And that that was my preferred option.”
He cited the commission’s 2019 technical conference on cybersecurity incentives, where he said numerous utilities said they had not encountered problems recovering their costs from FERC or state regulators. (See Mixed Reaction for ‘Resilience Incentives’.)
“I’m not totally sure the incentives approach is the way to go, given the significance of these types of investments,” he said.
The NOPR proposes that utilities choose between a return on equity (ROE) adder of 200 basis points or deferred cost recovery, allowing it to add the unamortized portion of the expenses to its rate base.
The commission acknowledged that a 200-basis-point adder exceeds the ROE incentives for transmission facilities. But it said that “given the relatively small cost of cybersecurity investments compared to conventional transmission projects, a higher ROE may be necessary to affect the expenditure decisions of utilities, without unduly burdening ratepayers.”
“Two hundred basis points — that is a lot,” said Christie. “As you know, the ROE already is supposed to represent the market cost of equity capital, and now you’re going to give them 200 basis points on top of that for doing what they ought to do anyway? I mean, there’s a reason why these adders over the years have come to be known as ‘FERC candy.’ They’re really sweet for those who get it, but not to consumers who have to pay for it. Pretty sour for consumers. …
“I acknowledge the statute says create an incentive,” he added. “One might make the case that the rate treatment itself is a pretty good incentive.”
Commissioner James Danly said that because of the time it takes to enact new mandatory reliability rules, “of all of the challenges that NERC faces, maybe cybersecurity is the one for which NERC is the least apposite.”
FERC Commissioner Willie Phillips | FERC
“So the question becomes, if that is an inapposite tool — and I would argue that it probably at least partially is — is the provision of FERC candy the proper way to incentivize the rapid immediate response that I think is the policy that is being driven at here? And the fact of the matter is, I do not know. We have to see what the comments are.”
Commissioner Willie Phillips, a former NERC assistant general counsel, said the CIP standards are “a great foundation. The problem is, as everyone has pointed out, they just take too long. …
“We absolutely need to make sure that our utilities don’t do the bare minimum, but that they’re reaching for the sky,” he continued. “What we don’t want to do … is look back years from now, in the wake of some catastrophic, successful cyberattack, and say, ‘If only we had done a little bit more.’”
Prequalified Expenditures
FERC proposed creating a prequalified list of cybersecurity expenditures eligible for incentives with a rebuttable presumption of eligibility. It said it would initially include on the list expenses related to participation in the Department of Energy’s Cybersecurity Risk Information Sharing Program and those for internal network security monitoring, which it said “may better position an entity to detect malicious activity that has circumvented perimeter controls.”
Incentives would generally last as long as the underlying assets are depreciated, with a maximum of five years. Technologies that “may be innovative and/or above and beyond industry standards at one time … may subsequently become conventional, mandatory or even antiquated and therefore may be less deserving of an incentive over time,” the commission said.
The commission also asked for comment on whether cyber incentives should be through performance-based rates. “In particular, we seek comment on whether any widely accepted metrics for cybersecurity performance could lend themselves to be benchmarks needed for performance-based rates, or whether new appropriate metrics could be developed,” it said.
