Search
`
November 19, 2024

Posted on

Diablo Canyon Extension Effort Gears up

The movement to keep California’s last nuclear plant operating beyond its impending retirement has gained new momentum with the prospect of billions of dollars in state and federal funding, support from Gov. Gavin Newsom, and the clearest indication yet that plant owner Pacific Gas and Electric (NYSE:PCG) could go along with the plan.

PG&E has been planning to shut down its 2.2-GW Diablo Canyon nuclear power plant by 2025, a move sought by anti-nuclear activists concerned with seismic safety and by PG&E, largely for economic reasons. In 2016, the state’s largest utility signed an agreement with environmental, labor and anti-nuclear groups to close the plant on California’s Central Coast rather than invest billions of dollars in environmental and safety upgrades.

Now, however, proponents see the continued operation of Diablo Canyon — the state’s largest generator producing about 8.5% of total capacity — as vital to ensuring grid reliability during the state’s transition to 100% clean energy by 2045. Energy emergencies during the past two summers and the likelihood of continued shortfalls caused by wildfires, drought and extreme heat have prompted some who supported the closure to reconsider, including the governor.

Newsom’s office circulated draft legislation Thursday that would lend PG&E up to $1.4 billion in a forgivable loan to keep Diablo Canyon open for an additional five to 10 years beyond its planned retirement date.

“It is a very difficult decision, and it’s a last resort,” Ana Matosantos, Newsom’s cabinet secretary, said in a workshop Friday hosted by the California Energy Commission and CAISO. Supply-and-demand forecasts based on historical data “are not necessarily reflecting our real-term reality and the speed at which the impacts of climate change are being experienced by our people and by our energy system,” she said.

In extreme scenarios, cumulative disruptions from weather and fire could leave the state 7,000 MW short this summer and up to 10,000 MW short by 2025, CEC analysts said in May. The gap could be as little as 1,700 MW this summer and 1,800 MW in 2025 without cumulative crises, they said. (See Heat, Fire and Supply Chain Woes Threaten Calif. Reliability.)

In addition, peak summer demand has shifted later in the day, after solar ramps down on hot evenings, resulting in shortfalls, and demand is expected to increase as millions of electrical vehicles replace gas-powered cars and trucks in coming years.

“The net of all of these pieces is that we are behind where we need to be in bringing our clean resources online to ensure that we can retire these [other] resources,” Matosantos said. “And so, we are meeting to have the very difficult conversation around an extension [of Diablo Canyon], the terms and the conditions under which an extension would be done, and the duration of any extension to make it as short as possible.”

Funding Possible

The availability of billions of dollars in federal aid could make an extension more feasible.

Matosantos wrote to U.S. Energy Secretary Jennifer Granholm in May, asking that the Department of Energy amend its eligibility criteria for the Biden administration’s $6 billion Civil Nuclear Credit Program (CNC), funded under November’s Infrastructure Investment and Jobs Act. The program is meant to assist nuclear plants at risk of closure for economic reasons.

In an April guidance, DOE had said CNC funding is for nuclear plants that participate in competitive energy markets and do not recover more than 50% of their costs from cost-of-service ratemaking. PG&E recovers its Diablo Canyon costs from customers under rate cases approved by the California Public Utilities Commission and would not qualify for CNC funding under that interpretation.

Matosantos requested that DOE’s guidance be changed to exclude the cost-of-service requirement. The department approved the change on June 30 and extended the application deadline for the first round of CNC funding to Sept. 6.

PG&E has said it will apply for the funding. Company CEO Patti Poppe said in a July 28 earnings call that the company was looking to keep Diablo Canyon open — the strongest company statement of its kind — but warned parties that the “clock is ticking” on the time needed to switch from decommissioning the plant by 2025 to operating it through 2035.

State and federal entities, including the U.S. Nuclear Regulatory Commission and the California State Legislature, will need to weigh in to make that happen in an accelerated time frame.

State Sen. John Laird, who represents the district containing Diablo Canyon, said at Friday’s workshop that the speed at which the plant might reverse course would contrast sharply with the effort to close the plant, which took years.

“Endless hours and millions of dollars have been used to plan for the plant’s closure and coordinate with local state and regulatory bodies on the decommissioning effort,” Laird said.

Questions about cost, safety and environmental impacts, including nuclear waste storage, remain unanswered, he said. Laird also questioned the potential effects of keeping the plant open on offshore wind development. Floating wind turbines off the coast near Diablo Canyon, in the planned Morro Bay wind energy area, are expected to connect to CAISO’s grid using transmission lines that now serve the plant.

“I don’t see a pathway to Diablo Canyon’s continued operation unless each of these elements is addressed,” Laird said. “No proposal can be complete without that.”

Posted on

Members Near Vote Over PJM, IMM Black Start Fuel Requirements

VALLEY FORGE, Pa. — Capping four years of discussions and analysis, PJM held a first read of proposed fuel assurance rules for black start resources (BSRs) at the Market Implementation and Operating committee meetings Wednesday and Thursday.

PJM has considered fuel supply capabilities along with other technical, operational and cost factors in awarding black start contracts in the past. In 2017, the RTO increased the weighting of fuel assurance in its evaluation of responses to requests for proposals. But current rules have no fuel assurance requirement other than an existing tariff provision requiring black start units to maintain enough fuel for 16 hours of run time.

PJM’s Janell Fabiano said work on the black start proposals — which included a two-year “hiatus” in stakeholder discussions while PJM conducted analyses of restoration times, costs and benefits, and gas supply risks — was an “epic process.”

In the 2018 problem statement launching the effort, PJM said only about half of the units in its black start fleet were fuel assured “through dual-fuel capability, on-site fuel storage or multiple gas pipeline connections.”

The committees heard presentations on two competing proposals, one from the Independent Market Monitor and a second cosponsored by PJM, Brookfield Renewable and the D.C. Office of the People’s Counsel.

Only 23% of stakeholders supported the Monitor’s proposal in polling in June. Nearly three-quarters of stakeholders said they supported PJM’s proposal before it was combined with one from Brookfield and the OPC, which had received 37% support.

PJM Package

The PJM package would select black start sites based on their fuel assurance, giving top preference to units with on-site fuel storage (e.g., dual fuel), followed by those connected to multiple pipelines and then gas-only sites connected to a single source fed directly from a gas supply basin or gathering system ahead of an interstate pipeline.

After that, PJM ranks fuel-assured hydro units (pump storage and run-of-river), followed by fuel-assured intermittent or hybrid sites. The last choice would be at least two gas-only sites in a transmission owner’s zone connected to two separate interstate gas pipelines.

Additional black start units would be solicited for eight “high-impact” sites in which incremental restoration time would be 10 hours or longer with the loss of a non-fuel-assured black start site.

Mitigation of the eight sites in five TO zones would add $28.2 million to the current annual black start cost of $68.2 million, a 41% jump, according to PJM.

IMM Package

The IMM said existing BSRs lacking fuel assurance should correct the problem or have their black start status terminated, with penalties for nonperformance.

The Monitor also would require predefined emission and effluent waivers to accommodate operations during restoration rather than PJM’s proposal that generators use their “best efforts” to obtain permit modifications or waivers.

For dual-fuel resources, the Monitor would require testing of both fuels annually, including a demonstration of the ability to switch between fuels. PJM proposes separate testing for each fuel in the same year. The IMM also would require concurrent annual tests of all BSRs connected to the same fuel source. PJM would not.

PJM would increase the “Z factor” incentive from 10% to 20% for fuel-assured resources selected via the RFP. PJM said the change would cost $436,000 annually.

The IMM would keep the base formula rate incentive factor for such units at 10%. The incentive is multiplied by the sum of fixed and variable black start service costs plus training and fuel storage costs.

The Monitor would also end PJM’s current practice of allowing transmission owners to provide black start service under a “backstop” process following two failed RFPs. “TOs should not own generation,” the Monitor said.

The IMM also opposed PJM’s proposal to allow intermittent resources to seek black start contracts. The Monitor said intermittent resources, other than run-of-river hydro, should not be considered BSRs because they cannot be assured of being available when needed.

PJM’s Tom Hauske said the RTO wanted to allow intermittent resources with storage to offer as black start and to anticipate future technologies. “It’s not going to be easy” for renewables to qualify, he acknowledged.

In a presentation of the IMM’s proposal, Monitoring Analytics President Joe Bowring took exception to the fact that PJM had decided not to impose penalties on intermittent resources that registered as fuel-assured BSRs but failed to meet the new rules, saying that this was “discriminatory” and “doesn’t make any sense.”

PJM said the penalties would be unfair to intermittent resources because the RTO would be responsible for calculating confidence levels for such generators.

Generators are responsible for their own performance, regardless of whether PJM defines the performance standard, Bowring said.

Zonal vs. Regional Plan

Bowring also challenged PJM’s plan to award black start sites, and allocate their costs, by TO zone.

“From a PJM perspective, the zonal approach is the correct approach,” said Dan Bennett, who presented PJM’s proposal. “No one knows a zone more than the transmission operator. They are the right people to be managing this.”

Bowring said TO zones are anachronisms under PJM’s regional management of the grid and that the RTO should take advantage of cross-zonal benefits.

“The fact that TOs can do it is irrelevant,” Bowring said. “There is no magic to zones. Zones are arbitrary. PJM has unfortunately taken the position that TOs are more capable than itself. It’s PJM’s responsibility to do it.”

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said some advocates are not convinced there is a need for black start units in every TO zone. “We are interconnected, unlike ERCOT,” Poulos said. “We do have the ability to have other resources help us.”

Impact on Existing Resources

Stakeholders voiced confusion and concern over the proposed changes, asking for clarification on how they would impact current BSRs that do not register as being fuel assured.

Paul Sotkiewicz of E-Cubed Policy Associates summarized many of these concerns when asking whether the process would be “voluntary” and whether it “would negatively impact BSRs that do not officially register as being fuel-assured.”

PJM responded that the new rules would not impact existing BSRs and were a voluntary process that sought to give additional compensation to eligible generators. Bennett encouraged stakeholders to continue providing feedback or suggestions that would make the packages “stronger because of teamwork.”

The BSR discussions exceeded the allotted time in both the MIC and OC meetings. PJM has scheduled a special meeting for Aug. 25 on the issue. PJM is targeting a filing to FERC in December and an RFP in April 2023.

Dual Votes

Because both the MIC and OC took part in discussions, both will be involved in voting on the two proposals, PJM’s Fabiano said. Voting will open after the Sept. 8 OC meeting and close at 5 p.m. ET on Sept. 15. Only one representative per voting member may participate; if different representatives vote at the MIC and OC, PJM will consolidate the responses and validate one response per member.

Poulos thanked PJM for its work helping the advocates understand the cost-benefit of the fuel incentives. PJM used a range of probabilities of a coincident blackout and fuel delivery failure and a range of values of lost load to calculate the increase in the expected cost that could result if a black start site were unavailable because of fuel failure.

“I don’t think they’re all going to be for it, but I certainly think there’s going to be more support … than there would have been without PJM’s work,” Poulos said of his members.

Posted on

Washington’s Tri-Cities Lobbies Granholm for Clean Energy Funding

RICHLAND, Wash. — Business and political officials from southeastern Washington lobbied Energy Secretary Jennifer Granholm for a piece of the Biden administration’s clean energy spending last week during her tours of the Pacific Northwest National Laboratory and the nearby Hanford nuclear site.

Leaders from Washington’s Tri-Cities — Richland, Kennewick and Pasco — said the region would be a good place to nurture a center of a clean energy industry.

Washington state officials also want a piece of the $8 billion the federal government plans to award for regional hydrogen hub projects.

“Whether that will happen [in Washington]? I don’t know,” said U.S. Sen. Maria Cantwell (D-Wash.), who joined Granholm during Thursday’s visit to PNNL, where they were briefed on the lab’s clean energy technology projects.

Granholm 2022-08-12 (RTO Insider LLC) FI.jpgEnergy Secretary Jennifer Granholm tours the Hanford Nuclear Site’s B Reactor, which produced the plutonium used in the atomic bomb dropped on Nagasaki, Japan. | © RTO Insider LLC

Granholm, who visited the Hanford nuclear reservation on Friday, said it will be months before the Department Energy decides how to divide up the $8 billion. DOE expects to receive more than 100 proposals to create regional hydrogen production and distribution hubs by September, when the agency will begin winnowing the proposals to four to eight projects. Granholm declined to speculate on how long that selection process will take.

Granholm’s visit came just before the House on Friday approved the Inflation Reduction Act, which includes a long list of clean energy measures. (See What’s in the Inflation Reduction Act, Part 1.)

Implementing the law will be a huge task, Granholm said. “It’s deployment, deployment, deployment of clean energy.”

Granholm said the administration could seek additional legislation in the next couple years, such as tax credits for improvements to the nation’s power grid. “We are always trying to perfect things,” she said.

Washington’s Hydrogen Efforts

Washington’s first hydrogen production plant is expected to go online in central Washington’s East Wenatchee in mid-2023. The Port of Seattle is studying whether it wants to get into the hydrogen fuel business. Paccar, a truck manufacturer in the Seattle suburb of Renton, is testing 10 hydrogen-fueled semitrucks in Los Angeles. And public transit in Chehalis — south of Olympia — expects to start running hydrogen-fueled buses this year.

Fortescue Future Industries of East Perth, Australia, announced its intentions to build a hydrogen production facility next to the TransAlta coal-fired power plant in Centralia, also south of Olympia. So far, Fortescue has not announced any details on that plan. The TransAlta plant is due to close in 2025.

Gov. Jay Inslee has led the state’s lobbying efforts for the hydrogen funding, citing Washington’s intense efforts to shrink its carbon footprint.

The Washington legislature made several decisions this past session to support these efforts. Lawmakers allocated $2 million to lobby for hydrogen projects. They created an office of renewable fuels within the Washington Department of Commerce and some new tax breaks for renewable energy projects.

In 2021, the global hydrogen market was estimated at $130 billion and was expected to expand 6.4% annually, according to a report by Grand View Research, a San Francisco marketing research firm. And a February 2022 report by Goldman Sachs said, “Our global …   hydrogen scenarios all show stellar growth of the clean hydrogen economy.”

‘This is the Place’

Hanford and Tri-Cities leaders also lobbied Granholm and Cantwell hard on the concept of a clean energy development center in  the southeastern high-tech community. The Tri-Cities has pushed on the energy center concept for roughly a quarter of a century, with sporadic progress.

Karl Dye, executive director of the Tri-Cities Industrial Development Council, and others noted the Tri-Cities are within 30 miles of a nuclear power plant, three hydroelectric dams, several proposed solar panel farms and some wind turbines. “We have some of the cheapest, greenest energy in the country,” Dye said.

“If you want a good demonstration on if this could work? Here. This is the place,” said Bob Schuetz, executive director of Energy Northwest, which operates the 1,200-MW Columbia Generating Station north of Richland. Energy Northwest also has a 4-MW solar farm in northern Richland and plans to start building a 145-MW solar farm near the Columbia nuclear plant in January 2023, with completion expected in early 2024.

Another six solar panel farms are being developed in the Yakima River Valley 20 to 40 miles west and northwest of the Tri-Cities.

However, a wind farm proposed for the hills just south of the Tri-Cities has drawn controversy because many Tri-Citians don’t want turbines in their views of the southern skyline.

Energy Northwest is in discussions with small modular reactor developers about getting involved with one of those projects.

“I like this notion of switching from [nuclear] cleanup to power,” Granholm said.

Posted on

Access to Meter Data Holding Back Residential DR, CSPs Say

VALLEY FORGE, Pa. — Demand response programs for residential customers and small businesses are being hampered by difficulties accessing interval meter data, CPower Energy Management said in a proposed problem/opportunity statement presented to PJM’s Market Implementation Committee Aug. 10.

PJM allows the use of sampling to estimate demand response participation for customers lacking interval meters — also known as smart meters — but requires the use of such meter data for customers that have them.

For smart meter-equipped residential customers serving as annual demand response resources, PJM requires not only usage data for settlements and compliance during events and tests, but data from two prior delivery years to establish a winter peak load and peak load contribution (PLC) to set baselines.

Ken Schisler of CPower said electric distribution companies (EDCs) have made it difficult and expensive for curtailment service providers (CSPs) to obtain the data. In some cases, he said, EDCs lack the information. In other cases, the data is cost prohibitive to obtain for small loads.

The introduction of smart meters has not resulted in the expected increase in DR participation, Schisler said. Demand response is an “underdeveloped resource in PJM,” he said. “I submit one reason for that is data access.”

Cleared demand response capacity has dropped by almost half since peaking at 14,833 MW in delivery year 2015/16. In June’s Base Residual Auction, cleared DR totaled only 8,096 MW.

Paul Sotkiewicz of E-Cubed Policy Associates questioned the need for a rule change. “It doesn’t sound like an insurmountable problem,” he said. “… I’m wondering if this is a solution in search of a problem.”

But Aaron Breidenbaugh of Centrica Business Solutions said his company shared CPower’s concerns. The cost of obtaining meter data is not as big a concern for large customers but “creates significantly higher costs of customer acquisition” for small loads, he said.

CPower’s issue charge proposes that stakeholders consider additional use of sampling as an alternative to data from every small customer.

“Do we need data for every single meter?” Schisler asked. “… Is the juice worth the squeeze?”

Posted on

IMM Report Notes Rising Fuel, Congestion Costs in PJM

Real-time load-weighted LMPs averaged $67.77/MWh in the first six months of 2022, a 121.3% increase from a year earlier and the largest such spike in the first two quarters since the PJM markets launched in 1999, the Independent Market Monitor reported in its State of the Market report for the second quarter.

The total price of wholesale power increased almost 70% to $95.93/MWh for the first six months of 2022, with energy, capacity and transmission charges representing 98% of the total. Transmission costs per megawatt-hour have exceeded capacity costs since the third quarter of 2019, the Monitor reported.

Almost half of the $37.15/MWh increase was a result of higher fuel and emission costs, with coal and natural gas prices doubling in eastern PJM, the Monitor said. Average real-time loads also were up, increasing by 1.9% to 87,616 MWh.

Congestion costs — LMP price differences resulting from binding transmission constraints — increased by almost $792 million (223.7%) over the same period. Only 31.5% of congestion costs paid by customers for the 2021/22 planning period ending in May was returned to them through the auction revenue rights (ARRs) and self-scheduled financial transmission rights revenues offset, the lowest offset since ARRs were implemented, the Monitor said.

“Congestion belongs to customers and should be returned to customers,” the Monitor said. “The goal of the FTR market design should be to ensure that customers have the rights to 100% of the congestion that customers pay.”

Generation from coal units dropped 6.4% in the first six months of 2022, while natural gas-fired generation increased by 5.2%.

Energy uplift charges increased by $2.8 million (3.6%) in the first half of the year to $82.1 million.

The Monitor offered three new recommendations in the Q2 report:

  • PJM, rather than the unit owner, should select the time and day that a unit undergoes net capability verification testing, and the timing should not be communicated in advance to the unit owner. The tests, required to demonstrate that a unit has the installed capacity claimed, are submitted for the summer and winter testing periods. The Monitor also said PJM should require actual seasonal tests and that the ambient conditions under which the tests are performed should be defined. PJM currently permits the use of summer test data adjusted for ambient winter conditions in lieu of actual winter test data.
  • If energy efficiency resources remain in the capacity market, PJM should codify eligibility requirements for claiming capacity rights and institute a registration system to track and document such claims. The Monitor contends EE should not be included on the supply side of the capacity market because PJM’s load forecasts now account for future EE.
  • PJM should use a nodal approach for distributed energy resources participating in RTO markets. “The PJM market is a nodal market because nodal markets provide efficient price signals to resources in an economically dispatched, security-constrained market,” the Monitor said. “Allowing DER aggregation across nodes is not necessary and would distort market signals indicating where capacity and energy are needed.”
Posted on

SPP Briefs: Week of Aug. 8, 2022

RTO, SaskPower Agree to Expand Interconnection’s Capacity

Canadian utility SaskPower said on Wednesday that it has signed a 20-year agreement with SPP to more than quadruple transmission capacity between the province of Saskatchewan and the U.S., effective 2027.

The utility and SPP will expand the 150-MW tie line that connects them to 650 MW. SaskPower said expanding the transmission capacity between the two countries will also improve reliability on its side of the border and allow the utility to export excess power to SPP, creating revenue opportunities.

“Access to this large market ensures reliable energy is available to Saskatchewan to support our own generating facilities,” SaskPower CEO Rupen Pandya said. “This will help to manage the integration of more intermittent renewable power such as wind and solar while keeping costs as low as possible for customers.”

SaskPower Footprint (SaskPower) Content.jpgSaskPower’s footprint has three ties with the U.S. | SaskPower

SaskPower will build the necessary transmission facilities on its side of the border over the next five years, and SPP will be responsible for construction on its side.

SPP has been making international transactions with SaskPower since 2015, thanks to Canadian interconnections that came when the Integrated System joined the RTO. (See SPP, SaskPower Make First International Trade.)

Clements Dissents on Accreditation Order

After two deficiency notices, FERC has approved SPP’s request to add capacity accreditation methodology provisions for wind and solar resources to its business practices and planning criteria. The RTO now determines the accredited capacity of qualified run-of-river hydroelectric, wind and solar resources based on historical performance, effective Feb. 15, 2022 (ER22-379).

The commission in its Aug. 5 order directed SPP to make a compliance filing within 30 days. The RTO filed its request in November 2021.

Commissioner Allison Clements partially dissented from the order, tweeting last week that she did so on the condition that SPP submit revised tariff compliance records. She said the RTO “should have submitted tariff revisions that explain what its proposal actually is.”

“Granted, the majority agrees that SPP’s proposal falls short of the commission’s rule of reason,” Clements wrote. “But they take it on faith that SPP will submit satisfactory tariff revisions on compliance, without knowing what those revisions would actually say. I cannot conclude that a tariff change is just and reasonable based solely on its general description.”

M2M Settlements up to $341.9M

SPP staff briefed the Seams Advisory Group on Friday on three months of market-to-market (M2M) transactions that brought the settlement accruals in its favor with MISO to $341.9 million.

More than half of the three months of transactions came in April at $26.5 million, the third-highest month between the seams neighbors. Settlements in May and June pushed the three-month total to $50.6 million. Permanent and temporary flowgates were binding for 5,907 hours during the three months.

M2M settlements for the redispatch of market flows around congested flowgates have now been in SPP’s favor for 16 straight months and 31 of the last 33. The RTOs began the process in 2015.

“The weather wasn’t too crazy,” SPP’s Jack Williamson told SAG. “We’re constantly breaking new peak records all the time. We’re seeing more and more wind on the system.”

Staff also told the stakeholder group that it is developing its first emergency energy exchange agreement with another seams neighbor, Missouri-based Associated Electric Cooperative Inc. The joint operating agreement does not currently have provisions for energy exchanges during energy emergencies, but SPP has similar arrangements with SaskPower, MISO and Public Service Company of Colorado.

Posted on

PJM Planning Committee Briefs: Aug. 9, 2022

PJM to Make Designated Entity Agreement Filing ‘Shortly’

VALLEY FORGE, Pa. — PJM attorney Pauline Foley provided a brief update on the RTO’s plans to make a Federal Power Act Section 206 filing asserting that the Operating Agreement’s provisions on designated entity agreements (DEAs) are unjust and unreasonable.

Foley said the RTO will assert that the OA’s references to DEAs are “overly broad and imprecise.”

PJM “anticipates making the filing shortly,” she said. “I don’t have an exact date.”

News of PJM’s planned filing prompted the cancellation of scheduled votes on competing issue charges on the matter at the July 27 Markets and Reliability Committee and Members Committee meetings. (See “Application of Designated Entity Agreement,” PJM MRC/MC Briefs: July 27, 2022.)

On July 26, a group of load-side stakeholders beat PJM to FERC, filing a complaint asking the commission to force the RTO to require incumbent transmission owners to sign DEAs on “immediate need” projects. The complainants contended the RTO has violated the OA by refusing to do so. (See PJM Challenged on Oversight of ‘Immediate Need’ Tx Projects.)

Generator Deliverability Test Update

Most stakeholders urged PJM to delay a vote on changes to generation deliverability testing procedures until the rules for effective load-carrying capability (ELCC) capacity interconnection rights (CIRs) are considered.

The deliverability test ensures the transmission system can transmit its generating capacity at summer peak load as well as under light load and winter conditions. The proposed changes are in response to increasing system variability caused by growing renewable penetration. (See “Generator Deliverability Education,” PJM Planning Committee Briefs: July 12, 2022.)

CIRs set an upper bound on the amount of installed capacity attributed to a generation capacity resource. ELCC resources such as renewables cannot run at their maximum output for more than 24 hours.

“It could be independent and should be independent,” Exelon’s Pulin Shah said of the two processes.

But other stakeholders — including Apex Clean Energy Group, LS Power, the PJM Public Power Coalition, Old Dominion Electric Cooperative, and economists Paul Sotkiewicz and Roy Shanker — said the issues should be considered together.

“I don’t see how it can be done separately,” said Shanker. “You could have a whole lot of [generation] that’s approved but not deliverable because of changes that happen two months later.”

“They need to go hand in hand,” said Sotkiewicz, of E-Cubed Policy Associates.

Carl Johnson, representing the PJM Public Power Coalition, said coupling the issues “creates the least uncertainty.”

PJM’s Jonathan Kern said the RTO is proposing to merge summer, winter and light load deliverability testing methods.

In June, the PC’s special session on CIRs for ELCCs discussed competing proposals from PJM, LS Power, Global Infrastructure Partners’ Eolian subsidiary and Sotkiewicz. The group originally planned a final review in July, but the meeting was postponed until late August to allow for more offline discussions to forge compromises. (See “‘Time to Get Involved’ in Capacity Interconnection Rights for ELCC Resources,” PJM Planning Committee Briefs: July 12, 2022.) New rules would be implemented for the 2025/26 Base Residual Auction.

The generator deliverability test changes would be made in Manuals 14A and 14B. They would add a new block dispatch approach to dispatch cases. To ensure a realistic dispatch, the base case would not allow any locational deliverability area (LDA) to import more power than their capacity emergency transfer objective (CETO).

The light load period, currently 12 to 5 a.m., would be redefined to include daytime hours from 10 a.m. to 3 p.m. where the RTO’s coincident peak load is between 40 and 60% of the annual peak. The default light load temperature would be 59 degrees Fahrenheit.

The new rules also will include more wind and solar in base case dispatches, with fixed solar rising from 38% to 47 to 55% of nameplate capacity in summer. Onshore wind would increase from 13% to 16 to 20%, and offshore wind would jump from 30% to 33 to 38%.

PJM wants stakeholder approval of the deliverability changes by December so they can take effect for the 2028 Regional Transmission Expansion Plan.

Load Model Selection Endorsed

Members unanimously endorsed PJM’s proposal to use a 2002-2012 load model for the 2022 Reserve Requirement Study.

PJM’s Patricio Rocha Garrido said the RTO changed its recommendation from the 2000-2010 model after discovering that a Monte Carlo simulation of the model “distorts the total distribution.”

The model selected is based on an analytical method rather than Monte Carlo sampling, he said. “At the 97th percentile and above, the Monte Carlo is not doing a good job.”

Sotkiewicz asked PJM to provide written language describing its algorithms “to avoid … confusion.”

Posted on

PJM Market Implementation Committee Briefs: Aug. 10, 2022

Issue Charge Approved on Day-ahead Zonal Load Bus Distribution Factors

VALLEY FORGE, Pa. — The PJM Market Implementation Committee last week approved an issue charge to consider a new method of determining day-ahead zonal load bus distribution factors.

The RTO’s current rules state that the default distribution of load buses for a zone in the day-ahead energy market is the state-estimated distribution of load for that zone at 8 a.m. one week prior to the operating day. Thus, the share of the zonal load attributed to each node remains constant for all 24 hours, even though the node’s share of total load may vary throughout the day because of nonconforming loads, such as data centers and behind-the-meter solar. This can cause a mismatch between the day-ahead nodal loads and real-time state-estimated load, according to the problem/opportunity statement.

Amanda Martin, who presented the issue at the committee’s meeting Wednesday, said the mismatch is not currently a concern but that PJM expects it to become one with the growth in nonconforming loads.

Jason Barker 2022-08-10 (RTO Insider LLC) FI.jpgJason Barker, Constellation Energy | © RTO Insider LLC

The committee unanimously approved the issue charge under the “CBIR Lite” (Consensus Based Issue Resolution) process despite the concerns of some stakeholders that the issue is more complicated than portrayed: Martin said it affects a single line in the tariff.

Paul Sotkiewicz of E-Cubed Policy Associates said the issue is not appropriate for CBIR Lite.

“I can think of places in PJM where just a small change [in distribution factors] can change plant commitments. This is not a trivial issue,” he said. “It can change pricing. It can change commitments in real time. I don’t think we can come up with a solution without doing that hard work [to model the impacts of the change]. Otherwise we’re just guessing.”

Independent Market Monitor Joe Bowring said he supported PJM’s proposal but that it should also create an initiative to consider long-term implications.

“Using one hour at 8 a.m. for all 24 hours makes no sense. To me this is clearly and obviously an improvement,” he said.

“If it needs more analysis, fine,” Constellation Energy’s Jason Barker said. “I don’t think we need to make a science experiment out of it.”

To address stakeholders’ concerns, PJM added to the issue charge a requirement that the initiative include an historical analysis to evaluate the impact of proposed solutions relative to the current practice.

The work is expected to take four months, with changes to tariff section 31.7c(i) and updates to Manual 11 and Manual 28.

Variable Operations & Maintenance Cost Development

Members heard a first read on competing proposals by PJM and Constellation Energy on changes to variable operations and maintenance (VOM) cost development that differ over the treatment of nuclear refueling costs and associated major maintenance.

The PJM proposal includes default adders for minor maintenance and operating costs; a new review process and timeline; clarifications to definitions of major and minor maintenance; and clarifications to requirements on supporting documentation.

Barker said that Constellation, the largest nuclear operator in the U.S., treats the projects undertaken during planned refuelings as fixed costs because they are scheduled long in advance, irrespective of the number of starts. As a result, he said, they should be included in capacity offers rather than as VOM in energy offers.

Barker said Constellation generally agrees with PJM’s desire to move most variable costs into cost-based offers. But he said the RTO incorrectly classifies projects associated with planned nuclear outages as major maintenance costs, defined as costs that “vary directly with electric production.”

Nuclear units would not likely have an opportunity to recover costs through a cost-based offer because they are price takers that bid zero into the energy market and are highly unlikely to be dispatched on a cost-based energy offer.

“PJM’s definitions don’t apply well to the nuclear fleet,” he said.

“You’re suggesting a significant change to the definition of what can go into VOM versus what’s allowable in the capacity market,” Bowring said. “This is way beyond the scope of the proposal by PJM. This is about how the review process is conducted, not the definitions of what is VOM.”

Barker insisted he was not seeking a “major change.”

“What we’re trying to do is accurately reflect the nature of nuclear cost accounting,” he said.

MIC Chair Lisa Morelli said she was “not prepared to rule on [the procedural question] now.”

PJM’s Tom Hauske said the RTO considers any cost based on starts and run times as variable and does not distinguish between capital and operating expenses.

PJM’s Glen Boyle said the RTO “wanted the stakeholder process to play out and see where the stakeholders were” on the question.

Heather Svenson of Public Service Enterprise Group said her company “strongly supports” Constellation’s proposal. It is “not a carve out” for nuclear units, she insisted.

The committee will be asked to vote on the proposals at its next meeting.

Manual Revisions OK’d on Reserve Price Formation

Members endorsed revisions to Manual 15: Cost Development Guidelines to conform with FERC’s order approving revised energy price formation rules (EL19-58, ER19-1486).

It will be effective Oct. 1, contingent on FERC approval of PJM’s compliance filing in EL19-58-012.

The changes remove VOM from synchronized reserve offers and eliminate references to Tier 1 and Tier 2 offers to reflect the consolidation of the tiers.

Posted on

DC Circuit Faults FERC on Cost Allocation of New Jersey Transmission Projects

FERC failed to explain why the DFAX method should be used to allocate the costs of two North Jersey transmission projects but not for a similar project in Artificial Island, the D.C. Circuit Court of Appeals ruled last week, partially supporting appeals by Consolidated Edison (NYSE:ED), the New York Power Authority and two merchant transmission operators (15-1183).

The court also rejected PJM’s “de minimis” exemption for applying DFAX, short for “solution-based distribution-factor analysis.”

But the court’s Aug. 9 order rejected a related challenge by the New Jersey Board of Public Utilities, ruling that Public Service Electric and Gas (NYSE:PEG) customers would foot the bill for the North Jersey projects after Con Ed terminated its use of the “PSEG wheel,” an agreement that allowed the utility to deliver power to New York City through PSE&G transmission.

The 43-page order addressed 13 petitions for review challenging 20 FERC orders, “involve numerous parties, implicate a series of related legal issues and arise from a complex procedural history,” the court said.

Bergen-Linden, Sewaren Projects

Much of the case involves $1.3 billion in transmission upgrades authorized by PJM to address short-circuit problems between PSE&G’s Bergen and Linden switching stations and repairs to and around the utility’s Sewaren substation.

To address the short-circuit problem, PJM directed PSE&G to expand the Bergen-Linden corridor into a double-circuit line with higher voltages. The project incidentally also provided additional protection against thermal overloads.

Con Ed and NYPA — as well as Linden VFT and Hudson Transmission Partners, operators of two merchant transmission facilities — challenged FERC’s orders approving PJM’s five cost allocations from 2014 to 2017. Linden and Hudson reroute electricity from New Jersey into the New York market and resell it at a profit when PJM prices are lower than New York’s.

Before they were relieved of liability for the Bergen-Linden and Sewaren projects, the four complainants — which the court labeled the “New York entities” — had been assessed approximately $115 million, which was paid.

PJM allocated most of the costs of the Bergen project ($763 million of $1.2 billion), and all the costs of the Sewaren project ($125 million), via DFAX. In 2014, PJM assigned most of the DFAX costs for Bergen-Linden to Con Ed ($629 million), with the rest allocated to Hudson ($69 million), PSE&G ($52 million) and Linden ($13 million). Sewaren’s costs were split between Con Ed ($64 million) and Linden ($61 million).

The DFAX method models how electricity will flow across a new transmission facility at moments of peak grid use and assigns costs proportionally, based on the projected use of the facility in each transmission zone of the PJM grid. DFAX was designed to apply to “flow-based” projects to increase transmission capacity. But the Bergen-Linden and Sewaren reliability projects were non-flow-based.

The New York entities complained that PJM’s allocations violated the cost-causation principle because the projects were intended to improve PSE&G’s infrastructure, but other parties were assigned most of the costs.

After FERC denied its request for rehearing on the cost allocation, Con Ed notified PSE&G that it would not renew their wheeling agreement. As a result, PJM eliminated Con Ed’s cost liability, reassessing Bergen-Linden’s DFAX costs to Hudson ($634 million), Linden ($132 million) and PSE&G ($128 million). Hudson and Linden responded by converting their firm withdrawal rights to non-firm, absolving them of cost responsibility under DFAX and leaving their costs with PSE&G.

In 2018, FERC reconsidered its use of DFAX on the Artificial Island transmission project, which was designed to address stability problems for three nuclear plants in South Jersey. On rehearing, FERC concluded that the beneficiaries of at least some non-flow-based projects are “not necessarily captured” by the DFAX method and directed PJM to adopt a different cost allocation method for stability-related projects. FERC approved PJM’s revised “stability deviation” method — which identifies which loads would most benefit from projects that address stability issues — in February 2019. (See FERC: Stability Deviation Method Best for Artificial Island.)

But FERC continued to defend the DFAX method for short-circuit projects like Bergen-Linden and Sewaren.

The New York entities contended that because the Artificial Island, Bergen-Linden and Sewaren projects all addressed non-flow-based issues, their costs should all have been allocated similarly.

FERC’s Artificial Island ruling concluded that “stability is analytically unique compared to voltage or thermal overload problems,” which are both flow-based. But the commission did not address whether short-circuit projects should also be treated differently from flow-based, the court said. “Therefore, FERC could not rationally explain its decision to treat Bergen-Linden and Sewaren differently from Artificial Island by simply pointing to its earlier finding that ‘stability is analytically unique compared to voltage or thermal overload problems.’ Instead, FERC needed to explain why stability is ‘analytically unique’ compared to short-circuit issues,” the court said.

In rehearing on Linden’s protest, FERC insisted DFAX should still be used to assign Bergen-Linden’s costs because it was similar to a thermal overload project. But “FERC did not adequately explain why that similarity mattered,” the court said. “Short-circuit issues, not thermal overloads, were the primary impetus for [Bergen-Linden]. While [Bergen-Linden] expanded the grid’s overall capacity, the same is true of Artificial Island.

“Given the similarities between the projects, basic rule-of-law principles required FERC to justify its different treatment of the projects. It needed to explain why, in contrast to Artificial Island, the costs of [Bergen-Linden] and Sewaren should be assigned via DFAX to the utilities whose electricity flows across the upgraded facilities, rather than to the projects’ other beneficiaries,” the court continued. “We do not hold that the use of the DFAX method for short-circuit projects violates the cost-causation principle per se. On remand, FERC may be able to provide a more satisfactory explanation of the distinction between stability-related projects and those that address short-circuit issues and to articulate why DFAX cost allocations are appropriate for the latter but not the former. But the commission ‘must provide an adequate explanation to justify treating similarly situated parties differently.’”

De Minimis

The court rejected the New York entities’ challenges to the use of netting and peak-load assumptions as part of the DFAX model, but it agreed with their complaint over the de minimis threshold, which exempts transmission zones with a distribution factor below 1% of cost responsibility.

Because distribution factors measure a zone’s use of a facility relative to its total load, the de minimis exception depends on the size of the zone, not on the zone’s share of the facility’s total flow, the court said.

A zone with load of 1,000 MW that uses 9 MW of a 30-MW facility — almost one-third of the total flow — would be exempted because the distribution factor would be only 0.9%.

“The de minimis threshold exempts zones from bearing any costs based on their load size — a quality unrelated to the burdens they impose on or the benefits they receive from any individual facility. And in so doing, it unduly discriminates against small zones, which must absorb higher cost allocations after large zones are exempted,” the court said. “Peak load sizes vary greatly across the relevant zones, which makes the de minimis exception border on absurd.”

PSE&G’s peak load is about 11,000 MW versus Hudson’s 320 MW. “So if PSE&G used 100 MW of flow across a transmission facility (yielding a distribution factor slightly under 1%), and if Hudson had 4 MW of flow across the same facility (yielding a distribution factor slightly over 1%), then PSE&G but not Hudson would be exempt from paying any of the facility’s costs, even though PSE&G derived 25 times more of the benefits,” the court said. “And because the large PSE&G would not have to pay any costs of the facility, the small Hudson would have to bear a substantially greater share of those costs.”

NJ BPU Challenge Rejected

The New Jersey BPU challenged FERC’s orders reallocating costs for the Bergen-Linden project from Con Ed, Hudson and Linden to PSE&G.

The court said FERC correctly determined that Con Ed did not have to pay project costs after the termination of the service agreements, noting that the Bergen-Linden project was planned solely by PJM.

The court said the BPU presented a “powerful argument” that Linden’s relinquishment of its firm withdrawal rights and its election of firm point-to-point service allowed it to receive the same benefits from the Bergen-Linden project without any of the costs.

But it said it lacked jurisdiction to consider it because the BPU had not first raised the issue in its rehearing requests with FERC.

The BPU also contended FERC conducted a “siloed analysis” that did not consider the “total effect” of its orders, which it said left New Jersey ratepayers with an “exceedingly disproportionate share” of the costs.

“But FERC did perform the kind of back-end analysis that the New Jersey board claims was required,” the court said. “FERC recognized that the [Bergen-Linden] project was planned by PJM, and [it] relied on PJM’s statement that the project would still be needed in New Jersey ‘even if there were no flows on the transmission facilities interconnecting New York and New Jersey.’”

Orders Vacated

The court vacated FERC’s denial of two Linden complaints and remanded them for further proceedings. It also vacated the commission’s denial of Con Ed’s complaint and remanded it for further proceedings on the de minimis issue.

It also vacated FERC’s 2020 order (ER17-950) reallocating the cost of the North Jersey projects reflecting the end of the PSEG wheel and rejecting Linden’s challenge and remanded it on both the Artificial Island and de minimis issues. (See FERC Rebuffs Challenges to PJM Tx Cost Allocation.)

“FERC did not raise a procedural bar to the New York entities’ challenges there, instead rejecting them on the merits for reasons we have found defective,” the court said. “On remand, FERC may consider in the first instance whether the challenges to PJM’s 2017 cost reallocation are procedurally barred.”

Posted on

ACORE Panel Lauds MISO Tx Benefits Process

An American Council on Renewable Energy (ACORE) panel last week largely agreed that MISO’s current transmission benefits process could serve as a blueprint for the country.  

Industry experts analyzed the RTO’s business case behind its recently approved long-range transmission plan (LRTP) as FERC prepares to issue a rule on regional transmission planning and cost allocation (RM21-17). (See FERC Issues 1st Proposal out of Transmission Proceeding.)

“I usually say cost allocation is the biggest barrier to long-term transmission development, and, of course, the key to cost allocation is to find transmission plans where the benefits outweigh the costs,” Grid Strategies President Rob Gramlich, said. “This is really important, to measure these benefits and get it right.”

Gramlich said during the Aug. 9 webinar that the country could use a standardized method for quantifying transmission benefits.

“There isn’t really a standard of how to do this. Even the categories themselves differ,” he said, adding it would be helpful if FERC created consensus on benefits categories and their metrics.

Gramlich said MISO has been a leader in proactive, multi-benefit planning beginning with its 2011 Multi-Value Project (MVP) portfolio — lines now delivering wind power from the Upper Midwest — and its recently approved LRTP. (See MISO Board Approves $10B in Long-range Tx Projects.)

He said beyond MISO’s recent success, there’s a widespread absence of effective transmission planning. Regions aren’t planning using scenarios or a portfolio approach, he said.

Gramlich said transmission planning has been in decline since 2013, when about 4,000 miles of 345-kV and higher lines were added.  

“We did a whole lot of successful transmission planning a decade ago,” he said. “But since then, unfortunately, it’s been sort of going down to a trickle because of the lack of effective transmission planning. Hopefully, we’re in the process of reversing that.”

Gramlich called on grid operators to do “at least an initial screening” of the 12 transmission benefits FERC identified in its notice of proposed rulemaking and pursue the ones that show significant benefits.

He said MISO arrived at a set of benefits that seemed to make sense for its LRTP planning. Other regions can take a similar approach to come up with different menus of benefit categories, he said.

While the LRTP benefit-cost analysis included congestion savings, resource adequacy savings and avoided risk of load shed and transmission and generation investment, it didn’t include seven other benefits FERC suggested in the NOPR. MISO did include decarbonization as a benefit, something the commission hasn’t called for.

The NOPR asks regions to consider the transmission benefits of avoided reliability and aging infrastructure projects, production cost savings, lower transmission energy losses, reduced chances of load shed or lowered reserve margins, diminished congestion, mitigation of extreme events and system contingencies, tempering of weather and load uncertainty, capacity cost benefits from reduced peak energy losses, deferred generation investments, access to lower cost generation, increased competition and increased market liquidity.

MISO’s first LRTP portfolio is expected to deliver $37.3 billion from its defined benefits to ratepayers from 2030 to 2050. The grid operator also estimates that the plan will help facilitate the 56 GW of new renewables it anticipates adding over the next 20 years in its most conservative planning scenario.

Jeremiah Doner (ACORE) FI.jpgMISO’s Jeremiah Doner | ACORE

Jeremiah Doner, MISO’s director of cost allocation and competitive transmission, said it’s “not an easy endeavor” to build a business case for a long-term transmission portfolio.

“There really isn’t a playbook to take from,” he said.

Doner said the LRTP business case has a lot of commonalities with FERC’s categories. He said planners considered how much time it would take to incorporate benefit categories versus how much value they would demonstrate. For example, Doner said the LRTP’s savings from transmission energy losses weren’t promising enough to quantify.

He said it’s important to allow grid planners flexibility in what benefits they choose to quantify. He noted that MISO used different benefit metrics between its multi-value projects and its LRTP portfolio.

ITC Holdings’ manager of federal affairs, Devin McMackin, said his company believes MISO’s business case can be held up as a model for the nation.

“The important thing is that we can now repeat this and double down on these types of regional planning efforts, especially now that we have a climate bill that has passed Congress,” he said.

McMackin said it seemed that FERC’s NOPR was “taking cues” from regional planning MISO performed under its MVP and the LRTP portfolios.

“What we don’t want to see are these 10-year lulls in between regional planning efforts because these needs are only accelerating and it’ll start to get away from us if we don’t keep at it,” he said.  

It makes sense for FERC to prescribe a minimum set of benefit metrics and leave some flexibility between regions, McMackin said. MISO’s benefit metrics represent a good starting point for the commission to consider, he said, adding that having planners on the same page is crucial for interregional projects.

“If we want interregional planning to work, there has to be some level of common benefits basis,” he said, “so not only would FERC be aiding the regional planning process, but it would also set the stage for the ability to then move forward and do some interregional planning.”

Michigan Public Service Commission Chairman Dan Scripps said he considers the first set of LRTP projects as above other benefits and key to the future system’s reliability. He characterized long-range planning as a shift from “reactive, near-term” reliability planning to a “forward-looking, proactive” approach to addressing reliability.

“The challenge with the value of lost load is you sort of know the value when you don’t have it,” Scripps said. “Winter Storm Uri was very clear evidence of that, not just in the loss of life, but also in the bills that folks saw after the fact.”

Scripps said there’s a risk with undervaluing transmission reliability benefits. He said the public needs a prepared system with extreme weather becoming more common and severe.

Jennifer Easler, an attorney with the Iowa Department of Justice’s Office of the Consumer Advocate, said regional transmission planners should allow stakeholders access to modeling and planning assumptions early in the process so there’s a broad understanding of benefit analyses.

She said MISO’s set of benefits are appropriate for its backbone transmission buildout.

Gramlich said in a perfect world, all transmission benefits should be compared against all costs.  

“It’s almost an obvious point … You have to consider all the benefits and all of the costs,” he said. “It’s a little weird that we’re even arguing about whether one should consider all the benefits and that we have a FERC NOPR that says, ‘Yeah, here are 12 benefits but feel free to ignore a bunch of them.’ That’s obviously inconsistent with good public policy.”

Gramlich also said it’s clear that FERC’s list is limited to its jurisdiction under the Federal Power Act and cannot include a full array of benefits like economic development or local emissions reduction.

“At this point, I like the FERC list of 12,” he said later during the discussion.