Search
December 17, 2025

Posted on

Capacity Market Sellers Anxious over Uncertain PJM Auction Rules

By Christen Smith

VALLEY FORGE, Pa. — Capacity market sellers expressed anxiety Wednesday over PJM’s “parallel path” for its upcoming Base Residual Auction, urging staff to consider delaying the auction until FERC clarifies the minimum offer price rule (MOPR).

Stu Bresler, PJM senior vice president of operations and markets, said the RTO is asking capacity sellers to adhere to BRA timelines under current rules as a preventative step in case the commission provides no additional guidance before the auction, which has already been delayed to Aug. 14.

FERC last summer granted PJM’s request to delay the auction in response to the commission’s June ruling requiring the RTO to revamp its MOPR to address price suppression from rising state subsidies for renewable and nuclear power (ER18-2222). (See FERC OKs Delay of PJM Capacity Auction.)

PJM filed its proposed MOPR changes Oct. 2 and said a FERC ruling by March 15 would keep the August schedule on track (EL18-178, ER18-1314, EL16-49).

But at Wednesday’s Market Implementation Committee, PJM’s Jeff Bastian said the RTO had no indication when a ruling would be made.

Bastian then walked stakeholders through the upcoming deadlines in what he called its “parallel path” to the August auction, for delivery year 2022/23. The document called for sellers to confirm whether they will be offering resources with “actional subsidies” by March 17 — a deadline stakeholders said was unreasonable.

Jason Barker, Exelon | © RTO Insider

Staff said they believe only the MOPR will be subject to change in the pending ruling. But they acknowledged the auction might need to be pushed back again if the ruling is not issued soon.

“I would concede that at some point we would get to where it would be impossible to proceed and we would have to look at delaying the auction,” Bresler said. “I don’t have a specific date I can give you at this point.

“I think any delay has some kind of a consequence, so that’s why we are trying to avoid it,” he continued. “We wouldn’t want to go past next May’s auction, obviously. Anything in between has a certain level of negative consequences with it, but I think it gets worse as we go through time.”

Stakeholders balked at the plan, insisting it contradicted the arguments made in PJM’s original delay waiver that its market suffers without certainty.

“It’s hard, as sellers, to know what to provide for MOPR,” said Jason Barker of Exelon. “This new path no longer allows us as sellers to evaluate FERC’s new conditions. This is going to be problematic for market sellers. You guys realize that and wrote it in your Tariff waiver request. Now we seem to be slavishly following a schedule and not the needs balanced in the FERC order.”

Adrien Ford of Old Dominion Electric Cooperative echoed Exelon’s sentiments and complained about the persisting uncertainty across PJM’s markets.

“I don’t feel like there is a single market I can give an update [to colleagues] on with any certainty,” she said. “Then to add this on top of it? I just think it’s going to be really problematic for capacity market sellers.”

John Horstmann, Dayton Power & Light | © RTO Insider

John Horstmann of Dayton Power & Light pressed PJM for more time.

“This could be life and death for your unit,” he said. “You’ve heard from a number of stakeholders how there’s going to be huge impacts. And yet you want us, without any real Tariff, to comply with all these data submissions because they might be enforced. Of course, they might not. ‘Oh yeah, and we want it in a week and a half.’ Where’s the reasonableness in that?”

“What we appear to be doing is asking people to make irreversible decisions based on rules that may change,” said Joe Bowring, PJM’s Independent Market Monitor. “It sounds like PJM’s theory is move forward with existing rules and just be prepared for changes.”

Posted on

SPP Briefs: Week of March 4, 2019

SPP celebrated the fifth anniversary of its wholesale market by noting it had produced the nation’s lowest electricity costs, saving market participants $2.7 billion, and exceeded initial projections for annual net savings.

In making its case, SPP cited a 2018 FERC market report that listed its average year-to-date monthly day-ahead prices in October at $29/MWh. The Southeast region came in second at $31/MWh.

SPP had projected the Integrated Marketplace would yield $100 million in annual net savings to market participants when it was brought online in March 2014. Instead, it said, the markets have “dramatically outperformed expectations” by producing an average of $570 million in annual savings from lowered production costs, reductions to excess capacity requirements and other efficiencies.

“Our market has continually proven itself to be one of the wisest investments our members have made,” SPP CEO Nick Brown said in a statement referring to the market’s economic and reliability benefits. “It has also set us up for continued success well into the future.”

2018 RTO/ISO Spot Power Prices | FERC

The Integrated Marketplace added day-ahead generation dispatch, congestion management and real-time balancing solutions to SPP’s market offerings. At the same time, the RTO consolidated the 16 balancing authorities (BAs) in its 14-state footprint to coordinate next-day generation, increasing access to lower-priced renewable energy and energy reserves.

SPP said wind energy made up 3% of its annual energy production (6 of 176 GWh) in 2008. Last year, the RTO produced 276 GWh of energy, with wind accounting for 23% of that figure. It has seen a peak wind penetration level of 64%.

“A decade ago, serving even a quarter of our load with variable, renewable generation wouldn’t have been possible, but today it is almost a daily occurrence,” Vice President of Operations Bruce Rew said.

Conservative Operations Alert Ends

SPP ended two-and-a-half days of conservative operations on Tuesday after successfully meeting high demand, despite subzero temperatures in the northern portion of its footprint. The RTO issued the conservative operations alert about midnight March 3, lifting it shortly after noon Tuesday.

Spokesman Derek Wingfield said SPP was able to mitigate the loss of 2.5 GW of generation from derates and failures to start in the cold weather, primarily in the southern part of the footprint.

SPP saw peak loads, all in the 7 a.m. hour, of 41.1 GW on March 4; 40.6 GW on March 5; and 39.3 GW on March 6. The RTO hasn’t met demand that high since September 2018.

Temperatures in Bismarck, N.D., dipped to -15 degrees Fahrenheit on March 3, before rising to 22 F on Wednesday.

SPP, Members Prep for Summer in Arctic Temps

Temperatures were 18 F on Tuesday as SPP staff and market participants gathered in Omaha, Neb., for — ironically enough — a workshop on summer preparedness.

Staff said a new summer peak is unlikely. SPP expects average heat during the early summer months across its footprint, with a 33 to 40% chance of above-average temperatures in later months. It also gave a 33 to 40% chance of above-average precipitation in early summer months, with average precipitation later in the season.

SPP’s all-time peak demand of 50.6 GW came in July 2016. Demand in 2017 was 50.5 GW, dropping to 49.7 GW last summer.

Staff reviewed with members last summer’s performance, when the only critical moments came during the shoulder months. SPP issued a hot-weather alert in May and a level 2 emergency energy alert in September, both during periods of above-average heat and low wind.

“We have tight capacity issues because we try to run a tight ship,” SPP’s Jon Langford said.

Staff is working on its 2019 summer assessment, using power flow and voltage stability analyses.

— Tom Kleckner

Posted on

PJM Operating Committee Briefs: March 5, 2019

VALLEY FORGE, Pa. — PJM’s Operating Committee breezed through a light agenda during its March meeting on Tuesday.

Frequency Response Performance Underwhelms

The number of generators providing primary frequency response (PFR) in 2018 fell short of PJM’s expectations, according to the RTO’s most-recently analyzed data.

Danielle Croop, PJM senior engineer of operations and analysis, told the Operating Committee PFR-capable generators didn’t respond as anticipated during five low-frequency events selected for evaluation throughout the year, at times providing less than half the megawatts PJM expected.

“These five events are the only ones that met the [PJM] criteria for 2018,” Croop said. “There’s usually about 25 or 30 events that meet [NERC’s] BAL-003, so you can see how narrow the evaluation selection is.”

At last October’s OC meeting, PJM shared frequency response data from 13 BAL-003 events between December 2017 and April 2018 that showed similar results. (See “The Right Metric on Frequency Response” in PJM Operating Committee Briefs: Jan. 8, 2019.)

PJM assesses generator performance during events in which the system frequency goes outside a +/-40-mHz deadband for 60 continuous seconds and the minimum or maximum frequency reaches +/-53 MHz. (See “Utilities Question Primary Frequency Response Calculation” in PJM Operating Committee Briefs: Feb. 5, 2019.) The five events fitting into the narrower criteria occurred on Jan. 27, April 7, June 30, Sept. 13 and Sept. 20.

Count of units that provided PFR by % of response compared to expected response. Only units expected to respond are in evaluation. | PJM

While generators provided 130 MW of the anticipated 165 MW during the January event, available energy dipped to 50% or less of what PJM expected during the April 7, June 30 and Sept. 13 events.

Brock Ondayko, of AEP Energy, refuted PJM’s expectation for more output, calling it “incorrect.” He said PJM’s existing dispatch software often oversimplifies a resource’s anticipated PFR capability because it doesn’t account for physical operational hold points.

“Until PJM modifies [its] dispatch software to take into account how resources actually operate and then subsequently begins to preposition capable units to respond, ‘expected’ numbers really need to be taken with a grain of salt,” he said in an email Tuesday. “While I sympathize with PJM’s dispatch issues and understand the limitations of [its] current estimates, my continuing to bring up the topic/issues for what has seemed like years has never stopped PJM from continually sharing what must be considered suspect data, without disclaimers.”

Croop defended the numbers during the meeting Tuesday, noting more accurate data will come from analysis of individual generators — to which Ondayko agreed.

“This is not absolute … but it’s a good line in the sand to see if we are getting the PFR we are expecting or not,” Croop said. “I think more intricate details will work through at the generator evaluation level.”

Ondayko requested PJM consider accounting for future PFR sources and those scheduled for retirement, referencing FERC Order 842 requirements.

“It would give us a better sense of how successful the FERC order is going to be or not going to be,” he said.

2018 Primary Frequency Event Response by Megawatts. | PJM

Stakeholders Ponder Meeting Changes

As the schedule for upcoming Operating Committee meetings fills up with obligations from new and continuing task forces, stakeholders pondered getting an earlier start.

OC Chair Dave Souder suggested starting April’s meeting at 8:30 a.m. to account for agenda items related to non-retail behind-the-meter generation business rules. Stakeholders approved a problem statement and issue charge revising the existing manual language during Tuesday’s meeting. (See “PJM Continues Review of Non-retail BTM Generation Business Rules” in PJM Operating Committee Briefs: Feb. 5, 2019.)

“I think the 8:30 start time is a little early,” said Sharon Midgley, of Exelon. “And the beginning of the meeting is sometimes important, particularly if there are any controversial endorsement items.”

Jim Benchek, of FirstEnergy, agreed an earlier start time would prove difficult for stakeholders commuting and instead suggested staying an hour later.

Souder proposed implementing a working lunch for future OC meetings, to which no stakeholders voiced any objections. He said PJM’s Dave Anders also suggested moving meetings to Thursday mornings beginning in 2020 so staff could have more time to provide accurate and updated reference materials. Planning Committee meetings would occur Tuesday mornings, instead.

— Christen Smith

Posted on

NextEra Gains Incentive for Hartburg-Sabine Project

By Robert Mullin

FERC on Tuesday authorized NextEra Energy Transmission (NEET) Midwest to recover all “prudently incurred” costs related to the company’s investment in the Hartburg-Sabine Junction 500-kV project in East Texas, MISO’s second-ever competitively bid transmission project (ER19-775).

The commission’s granting of the abandoned plant incentive ensures NextEra will be covered for 100% of its investment if the project is canceled for reasons outside the company’s control.

Hartburg Sabine map | MISO

The Hartburg-Sabine project will consist of a new 23-mile 500-kV transmission line, four short 230-kV lines and a new Stonewood substation that will connect the longer line with the existing Hartburg substation. The project is designed to relieve congestion issues and import limitations along the Texas-Louisiana border.

MISO awarded the project to NextEra last November following a competitive bidding process in which the company’s proposal scored 97 out of a possible 100 points, beating out 11 other competitors. (See NextEra Wins Bid to Build MISO’s 2nd Competitive Project.) NextEra’s proposal capped total project costs at $114.8 million, less than MISO’s $122 million estimate, and demonstrated a 2.2-1 benefit-to-cost ratio.

Under its FERC-approved formula rate, NextEra is already entitled to a 50-basis-point adder for RTO participation and a mechanism for later recovery of pre-commercial and formation costs along with a carrying charge. In its request for the abandoned plant incentive, NextEra noted the Hartburg-Sabine project is still subject to multiple layers of review, including those by the U.S. Fish and Wildlife Service, Federal Aviation Administration and EPA, as well as those by several Texas state and county agencies.

NextEra pointed to other nonregulatory risks confronting the project.

“In this regard, NEET Midwest states the project was included in the 2017 [MISO Transmission Expansion Plan] primarily because of the economic benefits to be derived from the project,” the commission wrote. “However, NEET Midwest points out that under the MISO Tariff, significant changes in those anticipated benefits could result in MISO reconsidering and potentially canceling the project.”

The company said it has no rate base or other revenue stream that could potentially offset any costs sunk into the project.

In approving the incentive, the commission noted it has previously found reliability and congestion-relieving projects selected through a regional transmission planning process are entitled to the rebuttable presumption established under Order 679, which requires an applicant to show “there is a nexus between the incentive sought and the investment being made.”

“We find the total package of incentives, including the previously granted incentives, as modified as part of the selected proposal, is reasonable because it addresses the risks and challenges associated with the development of the project,” the commission said.

Posted on

ERCOT Summer Forecast: Record Demand, Alerts

By Tom Kleckner

ERCOT is forecasting record peak demand with increased potential emergency alerts this summer, given its historically low planning reserve margin of 7.4%.

The grid operator said Tuesday it expects a summer peak of 74.9 GW, which would break the mark of 73.3 GW set just last summer. ERCOT has 78.2 GW of capacity on hand to meet that demand, according to its preliminary summer seasonal assessment of resource adequacy (SARA).

March Seasonal Assessment of Resource Adequacy | ERCOT

David Bellman, head of power for Houston-based Skylar Capital Management, told RTO Insider the “surprising thing to note” is this year’s projected peak is almost 3% higher than last year’s predicted high of 72.8 GW, as well as being 1.6 GW higher than 2018’s actual peak.

Bellman said the forward markets lost about $2/MWh Tuesday and were trading at $138/MWh.

“The increase in peak demand and drop in resource adequacy means we expect emergency alerts to be issued this summer,” Resource Adequacy Manager Pete Warnken said during a media call.

Declaring an energy alert during scarcity situations would free up the ISO to tap into a variety of additional resources to meet demand. Those resources include demand response products, resources normally set aside to provide operating reserves, additional generation or imports from neighboring RTOs, and calls for voluntary conservation measures.

David Bellman | RTO Insider

Dan Woodfin, ERCOT’s director of system operations, said the grid operator has 900 MW of emergency response service available and another 1,300-1,800 MW of capacity from load-management programs.

The grid operator’s reserve margin dropped from 8.1% to 7.4% with the December retirement of the Gibbons Creek coal plant. Warnken said 500 MW of summer capacity, much of it from wind and solar projects, has been delayed until late spring and early summer.

The final summer SARA report will be released in May and will reflect the expected summer weather conditions.

ERCOT also released its final SARA for the spring months (March-May), saying it has sufficient capacity (81.3 GW) to meet a forecasted spring peak of 61.6 GW. The system has added 577 MW of planned gas, wind and solar resources for the spring, with another 50 MW of wind and solar capacity expected to be available for the season’s start.

Posted on

Senate ENR Committee Discusses Climate Change

By Michael Brooks

The hearing the Senate Energy and Natural Resources Committee held Tuesday was perhaps less noteworthy for what was said than the fact it even happened.

Chaired by Sen. Lisa Murkowski (R-Alaska), committee members and panelists discussed the electricity industry’s role in mitigating climate change. According to ranking member Joe Manchin (D-W.Va.), it was the first hearing the committee had held on climate change since 2012.

Compared to the House of Representatives, now in Democratic hands and holding almost weekly hearings on climate change, the GOP-controlled Senate has been nearly silent on the phenomenon. (See House Democrats Put Climate Change Front and Center.) That will change as Senate Democrats up their rhetoric and make it a central platform of their 2020 re-election campaigns, as The New York Times reported Monday.

Sen. Lisa Murkowski (R-Alaska) opened the hearing displaying this graphic, which shows the rapid decrease in Bering Sea ice, as a demonstration of the impacts of climate change. | Rick Thoman, Alaska Center for Climate Assessment and Policy

Tuesday’s hearing, however, lacked partisan rancor. Instead, the few senators who attended and the panelists focused on increased investment in research and development of new technologies to make generating resources cleaner and more efficient.

This was in part because of the committee’s jurisdiction: It does not oversee EPA nor does it have direct oversight of U.S. greenhouse gas emissions. Those are under the charge of the Environment and Public Works Committee.

“I think it’s important to point out, we know here on the committee we have jurisdiction in certain areas,” Murkowski said. “We do not have complete jurisdiction over climate change — we recognize that — but we do have a role to play in developing reasonable policies that can draw bipartisan support that I think will be a pragmatic contribution to the overall discussion.”

But the homes of the committee’s leaders also played a large role in what was discussed. Murkowski, who opened the hearing with a list of adverse effects being felt by Alaska — including rapidly decreasing Bering Sea ice and a more challenging Iditarod Trail Sled Dog Race — has broken away from her party in even discussing the issue. Manchin, who frequently sides with Republicans on the committee, criticized regulations as a solution, saying they disproportionately hurt rural residents and coal miners, like those in West Virginia.

“Therefore, the path to a climate solution must offer West Virginians opportunity — not additional economic burdens,” Manchin said. “Chairman Murkowski and I share a deep concern for our rural communities and seek to use this committee as a means of identifying and legislating pathways to ensure our constituents have a role in the clean energy future.”

Manchin said the use of fossil fuels to generate electricity is “not going away anytime soon” and noted China and India are increasing the use of coal. Kenneth Medlock, senior director at Rice University’s Center for Energy Studies, put an exclamation mark on Manchin’s point by noting China has 254 GW of coal-fired capacity under construction — more than the entire U.S. coal fleet.

“So … when we think about CO2 being a problem of the global commons, it really means we need to lead by example,” Medlock said.

Manchin jumped in, asserting that the U.S. has led by example, mandating technologies such as scrubbers and low-NOx boilers. “They’re not implementing any of those,” he said.

Medlock replied his point was that the U.S. needs to lead in innovation, such as developing scalable carbon capture and sequestration (CCS), a technology seen as key to reducing emissions and even potentially reversing climate change. He noted federal R&D spending has been declining for the last 30 years “and that doesn’t make any sense.”

Susan Tierney, senior adviser at Analysis Group, said, “China is actually an unsung story on a lot of innovations,” building advanced reactors and wind turbines.

“The U.S. needs to continue to advance technology leadership … so we don’t lose to them on these competitive technologies,” she said.

Notably absent from the hearing was EPW Committee Chair John Barrasso (R-Wyo.), who last month reintroduced the Utilizing Significant Emissions with Innovative Technologies (USE IT) Act. The bill, which enjoys bipartisan support, would fund CCS R&D and create a board of experts to oversee projects under development.

Posted on

NEPOOL Debates Winter Energy Security Moves

By Michael Kuser

New England Power Pool stakeholders are this week discussing potential changes to ISO–NE wholesale energy markets that would include interim generator compensation to improve winter fuel security and the introduction of a multi-day-ahead market (M-DAM).

ISO-NE Principal Analyst Andrew Gillespie will on Wednesday present the NEPOOL Markets Committee conceptual details as well as a timeline for a fuel security FERC filing by Nov. 15, in line with the RTO’s January request for a four-month extension to file a plan, currently pending before the commission (EL18-182).

In the motion for an extension, ISO-NE said, “New England’s winter energy issues are fundamentally an energy supply problem, not a generation capacity shortfall problem,” but the presentation to the MC acknowledges the RTO has “heard a number of questions and concerns about the length of the market horizon, primarily how this may not align with participants’ hedging strategies … “

ISO-NE filed the rule revisions after the commission last July denied a Tariff waiver to allow the RTO to enter a cost-of-service agreement to keep Exelon’s 2,274-MW Mystic plant running after its capacity obligations expire in May 2022.

Interim Compensation

Several NEPOOL stakeholders have proposed alternatives to the RTO’s market mechanisms regarding interim compensation treatment to improve fuel security.

David Cavanaugh, vice president of regulatory and market affairs for energy services firm Energy New England (ENE), was slated Tuesday to present an amendment to the RTO’s proposed Tariff language. The outcome of the planned discussion and vote, the first of a two-day MC, will not be revealed until NEPOOL posts the meeting minutes.

ENE argues the RTO’s proposal “far exceeds” its stated goal of retaining resources for fuel security reliability and preventing uneconomic retirement bids and its “resource eligibility is too broad and extends beyond target resources.”

The company instead recommends modifying ISO-NE’s proposal to limit compensation to oil, natural gas, demand response and electric storage resources.

“Compensation should be limited to resources capable of improving winter energy security by providing incremental reliability benefits,” ENE said. The RTO estimates costs for the interim program will exceed those of the last winter reliability program by $100 million, a figure ENE says drops to around $51 million under its amendment.

Winter reliability program costs were capped in advance and ranged from $30 million to $70 million annually. The RTO replaced that program last June with the Pay-for-Performance program, which is designed to fund performance bonuses mostly through penalties on nonperforming resources and not directly by customers. (See NEPOOL Debates Fuel Security, Cost Allocation.)

ISO-NE CEO Gordon van Welie last month said energy security risks “could become a year-round concern” as the grid transitions to distributed and renewable generation and “eventually nearly all resources in the fleet will have some energy limitations.” (See ISO-NE Chief Sees ‘Year-round’ Energy Risks Coming.)

The Pilgrim Nuclear Power Station on Cape Cod is scheduled to close down permanently later this spring, increasing New England’s fuel security risks. | Entergy

Abigail Krich, president of Boreas Renewables, was to present on behalf of the Union of Concerned Scientists a proposal guaranteeing that energy actually provided would receive the same compensation as inventoried energy.

Forward Capacity Auction 13 last month awarded payments to new renewable energy resources and also made ISO-NE the first grid operator to implement a market-based mechanism to accommodate state-sponsored resources. State-sponsored Vineyard Wind won a 54-MW capacity obligation from a retiring resource in the substitution auction. (See ISO-NE Completes FCA 13 Despite Controversy.)

Count the Days

The Massachusetts attorney general’s office commissioned London Economics International (LEI) to prepare an alternative to the RTO’s M-DAM proposal, which LEI found “conceptually and operationally complex” and would “require substantial administrative costs.”

Complete revamping of the day-ahead market (DAM) into M-DAM is an unproven mechanism and may not meet all of the RTO’s goals, LEI concluded, proposing instead a Forward Stored Energy Reserve ancillary service with updated technical methods to provide parameter values for the forward capacity market.

The advisory firm contends that while the RTO’s proposal might increase revenues for some power plants and prevent inefficient retirement, the resulting higher energy prices may lower net cost of new entry, which would suppress capacity market prices and potentially accelerate retirement.

FSER Timeframe: Forward stored energy reserve timeframe should balance ISO-NE’s ability to forecast its need for reserves versus the time it takes to arrange fuel or other necessary inputs to stored energy. | London Economics

LEI said its proposal meets the ISO-NE’s needs and Massachusetts’ goals of incorporating market signals, supporting operational visibility and helping prevent inefficient retirement, while its blend of old and new components creates a “solid foundation for winter energy reliability.”

Calpine is scheduled to present again its case for a Forward Enhanced Reserves Market (FERM), with Senior Analyst for Government and Regulatory Affairs Rebecca Hunter arguing all problems that fall within a planning horizon time frame are left unsolved without a forward price signal. (See “Market Reaction,” New England Talks Energy Security, Public Policy.)

FERM would have no offer cap, but awards to resources with capacity supply obligations would be incremental to the clearing price. In addition, FERM resources would have daily day-ahead must-offer obligations in winter months only, and the construct would allow participation from resources without a supply obligation, such as energy-only resources that only plan to be available for peak days in the winter.

Posted on

FERC OKs CAISO Tariff Changes on Generator Outages

By Hudson Sangree

FERC last week approved CAISO Tariff changes designed to incorporate generator contingencies and remedial action schemes into its market optimization and congestion pricing methodology (ER19-354).

“The commission accepts CAISO’s filing because we agree with CAISO that its proposal will more closely align market dispatch and prices with actual operations,” FERC wrote. “This will allow prices received by generators to more accurately reflect their contribution to congestion under a dispatch that is secure against generator contingencies. We also agree with CAISO that its proposal will be beneficial by reducing reliance on exceptional dispatch.”

FERC approved CAISO tariff revisions related to generator contingencies and remedial action schemes.

The ISO filed the Tariff revisions in November. It proposed language to clarify its rules on modifying and operating the grid to expressly include generator contingencies and remedial action schemes to deal with the loss of generators. It also proposed adding new components to its marginal cost of congestion formula.

“CAISO states that making several clarifications to existing terminology will improve transparency,” FERC wrote. “In particular, CAISO proposes to add a sentence to the definition of a ‘contingency’ to expressly include ‘potential outages due to remedial action schemes.’”

The ISO proposed similar clarifications to section 27 of its Tariff, which addresses its market and processes.

“CAISO states that these clarifications consist of parentheticals to clarify that remedial action schemes are included in CAISO’s modeling of transmission contingencies,” FERC said.

The ISO also proposed adding a new component to its formula for calculating congestion prices that accounts for generator outages. Currently, the grid operator calculates the marginal cost of congestion based on the “economic effect of additional power at a specific point flowing across a given transmission constraint,” the commission said.

To do so, CAISO multiplies the transmission constraint coefficient by the power transfer distribution factor and its shadow price, FERC noted.

“The power transfer distribution factor is the percentage of a power transfer that flows on a transmission facility as a result of the injection of power at the relevant bus and the withdrawal of power at the reference bus,” the commission said. “CAISO notes that the shadow price is the marginal value of relieving the constraint.”

Under the revised formula, CAISO will calculate the cost of congestion, then subtract the product of the power transfer distribution factor for the relevant generator contingencies and its shadow price, FERC said.

“CAISO contends that its proposal will ensure that its preventative modeling and market prices reflect grid realities. CAISO argues that the proposed revisions will also decrease out-of-market actions and the need for operators to manually monitor remedial action schemes and generator contingencies,” the commission said. “In addition, CAISO asserts that its proposal will appropriately price each generator’s contribution to congestion in the markets.”

Posted on

SMUD Cancels 500-kV Tx Line Project

By Hudson Sangree

The Sacramento Municipal Utility District (SMUD) said Friday it is canceling a 500-kV transmission line project it was developing in conjunction with the Western Area Power Administration because the project had proven too expensive and was no longer needed.

The Colusa-Sutter Transmission Line Project (CoSu) was intended to increase SMUD’s ability to import hydroelectric power from the Pacific Northwest and export from the Sacramento area. (See WAPA, SMUD Extend Scoping Period for Colusa-Sutter Project.) It would have created a new link between the California-Oregon Transmission Project (COTP) and SMUD and WAPA facilities on the east side of the Sacramento Valley.

“A recent California Energy Commission study makes the case for projects like this that enhance transmission capability to import valuable out-of-state renewable resources for California to meet its 50% renewable energy goals by 2030,” WAPA and SMUD said in a statement in 2017. That study pointed out that a shortage of available transfer capacity on the California-Oregon Intertie would inhibit California’s ability to import additional carbon-free energy from the Northwest.

The proposed Colusa-Sutter transmission project was intended to improve SMUD’s access to Pacific Northwest renewable resources via the California-Oregon Transmission Project. | WAPA

In a news release Friday, however, SMUD said “it was determined that the project is too costly.”

As planning for the project commenced, federal power marketing agency WAPA said its existing transmission facilities did not have enough capacity to meet SMUD’s increasing need for energy.

SMUD said that the project’s initial phase, meant to evaluate environmental impacts and conduct preliminary engineering, had shown the estimated $245 million price tag had increased by more than $100 million and could end up costing much more.

The utility said its decision to join CAISO’s Western Energy Imbalance Market starting in April “will provide lower-cost access to a broader regional market,” reducing the need for transfers to and from the Pacific Northwest.

SMUD and WAPA have been working on the CoSu project since the utility’s board of directors approved a development agreement in December 2014. The new line would have connected the COTP system in Colusa County with the Central Valley Project system in Sutter County, improving access to renewable energy generated in the Northwest.

SMUD, headquartered in Sacramento, canceled a 500-kV transmission line project it was planning in conjunction with WAPA.

Since the project’s inception, the need for it has diminished, SMUD said.

“Since SMUD started planning the project, the development of SMUD’s long-term integrated resource plan has greatly reduced the value and need of the proposed line,” it said. “The IRP analysis indicates SMUD would better focus its resources on the suite of local, regional and in-state renewable and reliability projects, as well as incremental transmission infrastructure.

“Canceling CoSu also reduces pressure on SMUD rates during the early critical phase of IRP implementation,” SMUD added.

Posted on

FERC Reverses Waiver on SPP’s Z2 Obligations

By Tom Kleckner

FERC last week reversed a waiver it had previously issued to SPP on Attachment Z2 of its Tariff and directed the RTO to provide refunds of credit payment obligations, with interest (ER16-1341).

The commission ordered SPP to refund credit payment obligation amounts dating back to 2008, except for the one-year billing adjustment limit allowed in the Tariff.

SPP was seeking a retroactive waiver of its Tariff so that it could invoice transmission service customers for Attachment Z2 credit payment obligations for the 2008-2016 time period prior to its April 2016 request. In its reversal Thursday, FERC found “the relief sought by SPP … is prohibited by the filed rate doctrine and the rule against retroactive ratemaking.”

SPP’s headquarters in Little Rock, Ark. | WER Architects

The commission approved the waiver request in a July 2016 order that set aside the one-year time limit. In November 2017, FERC denied a rehearing request by several stakeholders. (See “Z2 Waiver Upheld,” FERC Rejects SPP Change on Network Resource Upgrades.)

But FERC issued a voluntary remand of the waiver orders after Xcel Energy appealed to the D.C. Circuit Court of Appeals in January 2018. The commission’s reversal was prompted by the court’s June decision to uphold FERC’s order rejecting Old Dominion Electric Cooperative’s request for a waiver of Duke, ODEC Rebuffed on Polar Vortex Gas Refunds.)

FERC noted the D.C. Circuit has recognized the commission’s “‘broad remedial’ authority to remedy unjust outcomes.” But it said that exercising its authority under the Federal Power Act in this instance “would be inappropriate,” noting that the court in ODEC “highlighted that the commission cannot disregard for good cause or any other equitable grounds either the filed rate doctrine or the rule against retroactive ratemaking.”

Attachment Z2 details how sponsors that fund network upgrades can receive reimbursements through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrade. SPP said that delays in implementing computer software kept it from listing certain creditable upgrades in aggregate facilities study reports, calculating and assessing costs, and distributing credits to transmission customers before August 2016.

An SPP spokesman said the company is reviewing the order and its options. It estimates the credit payment obligations for the historical period to be approximately $200 million.

Last week’s order requires SPP to file a report within 120 days detailing how it plans to make the required refunds and allows third parties to comment on the RTO’s proposal. “SPP shall not provide any refunds prior to the issuance of a further commission order directing refunds,” FERC said.

Xcel Energy upgrade project | em>Burns & McDonnell

Commissioners Cheryl LaFleur and Richard Glick, who reluctantly concurred with the decision, issued separate statements attached to the order.

“The financial impacts of today’s order will rightly be frustrating to those parties that would otherwise receive credits for the historic period, and the order provides an unfair windfall to those who benefited from those upgrades during the historic period but are not required to pay for them,” LaFleur wrote.

“This is a result that could have been avoided, and we should, where possible, take steps to prevent similar issues in the future. As today’s order notes, the New York Independent System Operator Inc. Tariff authorizes the commission to order changes to otherwise ‘finalized’ data and invoices. I join Commissioner Glick in encouraging SPP and other RTOs/ISOs to consider comparable revisions to their tariffs to avoid similarly inequitable outcomes in the future.”