FERC halted PJM’s plan to run its capacity auction next month in a surprise order issued Thursday, just hours after the Markets and Reliability Committee reaffirmed the RTO’s decision to move forward as planned.
The commission refused to “rule prematurely” on PJM’s request for clarification that if it ran the 2022/23 Base Residual Auction using the existing minimum offer price rule (MOPR) — while the revised version awaits approval — that FERC would enforce any new rates prospectively, saving the August auction from being rerun (EL16-49).
PJM argued that if the commission granted its request, filed in April, the “critical” confidence in auction results necessary for market participants would be preserved. (See PJM to Hold Capacity Auction in August.) The RTO’s Board of Managers also maintained that the rejected MOPR only impacts a small number of resources, meaning an updated commission ruling on the matter wouldn’t change prices too much within the current environment.
“PJM asserts that, here, refunds would not be warranted because the basis of the underlying complaint is that the relevant rates are too low, not too high, which is a required finding for refunds under Section 206 of the Federal Power Act,” FERC summarized in its ruling.
FERC advised PJM to cancel its August capacity auction. | PJM
PJM delayed the BRA once already after FERC ruled in June 2018 that the RTO’s MOPR was unjust and unreasonable because it didn’t address price suppression arising from state subsidies for renewable and nuclear power. The RTO proposed a new rate in October and had hoped for a ruling from the commission by March 15 to no avail.
PJM entities including American Municipal Power, Dominion Energy, Exelon, EDP Renewables, FirstEnergy and its subsidiaries, Talen Energy and its subsidiaries, the Electric Power Supply Association, Direct Energy, the American Wind Energy Association, the Solar Council and the Illinois attorney general’s office all filed in support of the RTO’s decision to run the auction in August, agreeing that further delays have proved detrimental to the market and interfered with the necessary forward pricing signals that sellers need.
The entities also agreed that should FERC reject the clarification, PJM should delay the auction because running it without the guarantee from the commission would “undermine the very certainty the BRAs are designed to provide.”
The Illinois AG’s office further argued that if FERC granted the request, it should also “address flaws in the existing capacity market rules that facilitate market power abuse by requiring PJM to release generator bidding data and to replace the algorithm that PJM uses to increase clearing prices above the highest bid.”
In the end, FERC advised PJM to cancel the auction until it provides a suitable replacement rate, though it’s unclear when that decision may come. ClearView Energy Partners speculates that if the commission doesn’t provide a ruling on the MOPR before November, PJM won’t have enough time to implement Tariff changes in time to hold the 2022/23 auction in April.
“We recognize the importance of sending price signals sufficiently in advance of delivery to allow for resource investment decisions,” FERC said. “However, we believe that in the circumstances presented here, on balance, delaying the auction until the commission establishes a replacement rate will provide greater certainty to the market than conducting the auction under the existing rules.”
PJM spokesperson Jeff Shields said on Thursday that the RTO will follow the commission’s guidance.
“In its ruling today directing PJM Interconnection to postpone its capacity auction, the Federal Energy Regulatory Commission recognized that confidence in the auction and its results is vitally important to all of our stakeholders and the integrity of the market,” Shields said in an emailed statement. “We look forward to additional guidance from FERC on the design of PJM’s capacity market.”
Commissioners Debate
While concurring with the order, Commissioner Richard Glick issued a scathing indictment of FERC’s inaction on PJM’s proposed changes, saying the RTO and its 65 million customers deserve better.
“One year later, Commissioner [Cheryl] LaFleur’s description of the June 2018 order as ‘regulatory hubris’ seems more apt than ever after the commission has shown an absence of leadership that has caused us to drift rudderless into the position in which we find ourselves today,” he said.
As the lone dissenter on the June 2018 order, Glick said he agrees with his colleagues that running the auction next month provides only a “short-term palliative effect … that would be outweighed by the long-term uncertainty” of allowing capacity commitments under Tariff previsions found unjust and unreasonable, leaving PJM vulnerable to years of litigation.
But he blamed FERC for putting PJM in the situation in the first place.
“If ever the Pottery Barn Rule applied to a regulatory proceeding, it is this one,” he said, referencing what Secretary of State Colin Powell told President George W. Bush in the lead-up to the War in Iraq: “You break it, you own it.”
LaFleur took her previous criticisms a step further in her own statement.
“Given the passage of time, the uncertainty created by the commission might better be labeled an act of regulatory malpractice,” she said. “The commission, whatever concerns it has with the PJM capacity market, should not have put PJM, the states and customers served by its markets, and its stakeholders in this position.”
Commissioner Bernard McNamee — who joined FERC after the June 2018 order — called Glick’s usage of the Pottery Barn Rule “misleading.”
“To suggest the commission is the source of the problems presently facing PJM is to ignore nearly a decade of proceedings attempting to address the interaction between competitive markets and out-of-market subsidies,” he said. “More importantly, such a statement only makes sense if one ignores the impetus behind PJM’s original filing in Docket No. ER18-1314, which was PJM’s desire to address issues arising from state out-of-market support for generation resources in its footprint.”
Glick argued that McNamee “misses the point.”
“It was the commission — not PJM — that made the finding that has prevented PJM from running its capacity auction,” he said. “And it has been the commission — not any party to this proceeding — that has failed to act, even though we are now more than six months past the date promised in the June 2018 order. Meanwhile, neither the facts nor the law have changed, and the time for deliberation has long passed. The commission is now fully responsible for the damage done to date and whatever comes next.”
Chairman Neil Chatterjee did not weigh in on the controversy.
The federal judge overseeing PG&E Corp.’s Chapter 11 bankruptcy granted a motion by the California Public Utilities Commission on Wednesday to hold off on deciding whether to terminate the utility’s exclusivity period while it attempts to create a process for choosing among the several competing plans.
A group of unsecured bondholders on Tuesday had requested that Judge Dennis Montali, of the U.S. Bankruptcy Court for the Northern District of California, terminate PG&E’s exclusivity — the time it has to offer a reorganization plan without the judge having to weigh competing proposals — in light of the enactment of Assembly Bill 1054 earlier this month.
“The debtors’ legislative requirement was addressed on July 12,” the ad hoc committee of senior unsecured noteholders told Montali in court papers. PG&E would have to emerge from bankruptcy by June 30, 2020, to take advantage of the measure’s provisions. The unsecured bondholders — a group of 25 banks, mutual funds and others — say that makes getting PG&E out of bankruptcy more urgent. They encouraged the judge to accept their proposal, which would pay off or refinance their notes.
“With the recent inception of the 2019 wildfire season and the impending June 30, 2020, deadline, it is now time to move these cases as quickly as possible towards emergence,” the bondholders’ lawyers wrote. “Unfortunately, to date the debtors have almost entirely failed to do so” and instead have sought legislative help to securitize equity in the company to protect shareholders and raise capital.
But on Wednesday, Alan Kornberg, an attorney representing the California PUC, told Montali that the commission is “keenly interested” in the bondholders’ plan, as well as a competing plan by insurers with more than $20 billion in unsecured claims against PG&E for payments made to wildfire victims.
Any exit plan would need to be approved by the commission, and it is “vital” that be done by the June 2020 deadline, Kornberg said. Both the commission and Newsom want a competitive process, and he acknowledged the request was an unusual one, “but we cannot permit competition to turn into chaos.” He asked Montali to give the commission and PG&E two weeks to work out a process and timeline for evaluating the different plans.
The bondholders’ lawyer, Michael Stamer, objected to the proposed delay, calling it “an unprecedented, undocumented road to nowhere.”
“Everyone is in violent agreement that every day counts, and two weeks is a long time,” Stamer said.
This did not persuade Montali, however. He noted that he had only received the bondholders’ 33-page plan Tuesday morning and finished going through it at midnight, indicating he was not prepared to rule on the exclusivity motion that day anyway.
Montali also noted that the bondholders were not the only ones seeking to terminate exclusivity. “The one thing we don’t need, more than anything, is a lot of lawyers writing a lot of briefings that don’t need to be written, and one judge reading all the briefs that don’t need to be read,” he said.
He set Aug. 9 to hear the results of the PUC and PG&E’s discussions, and Aug. 13 to rehear the bondholders’ exclusivity motion. A hearing to consider the insurers’ exclusivity motion was already set for that day.
Montali has wide latitude to consider the competing plans. He ended exclusivity early during PG&E’s prior bankruptcy case in the early 2000s, allowing the PUC to offer its own reorganization plan.
The judge warned PG&E’s lawyers in May he could revoke exclusivity if he saw fit. “This judge has never been a fan of exclusivity but is a fan of practical consequences,” Montali said. He explained at the time he did not want to deal with competing reorganization plans that might be unworkable.
“The proposal would hold PG&E accountable for wildfire liability, maintain price stability for PG&E’s ratepayers [and] contribute billions of dollars to California’s wildfire recovery fund,” the insurers said in a news release.
Their plan provides for payment of victims’ wildfire claims through a settlement trust, with a $5 billion contribution to the state’s recovery fund for future wildfire claims that was part of AB 1054.
Subrogation claimants would be paid 90% of their claims with shares in the company, “thereby reducing the amount of new money necessary for PG&E to exit Chapter 11,” they said.
Like the unsecured bondholders, the unsecured insurers stand to lose in the PG&E bankruptcy because they would have to get in line behind secured creditors whose claims will be paid first.
PG&E cited billions of dollars in wildfire liability when it filed for bankruptcy in January. The company has been blamed for starting major fires in 2015, 2017 and 2018, including last November’s Camp Fire, the deadliest in state history.
INDIANAPOLIS — Regulators should preserve the multiple incentives currently offered to transmission developers — and possibly consider creating new ones, two former FERC commissioners said Monday.
Speaking on a panel at the National Association of Regulatory Utility Commissioners’ 2019 Summer Policy Summit, former Commissioners Suedeen Kelly and Philip Moeller expressed support for incentives granted on a case-by-case basis, but they said the time may be ripe to create new categories of adders to encourage development.
Entitled “(Trans)Mission Critical? Reconsidering FERC’s Electric Transmission Incentives,” the panel focused on the commission’s recent Notice of Inquiry into transmission rate incentives and the ensuing comments from transmission owners, load, utilities, regulators and trade groups. (See Tx Incentives NOI Brings Calls for Broader Reforms.)
Virginia State Corporation Commissioner Judith Jagdmann, the panel moderator, asked if regulators view the incentives as a “fist on the scale or a thumb on the scale.”
Kelly, now a partner with the law firm Jenner & Block, said the incentives were designed to be a thumb. “It was clear from the beginning that you couldn’t incent something where rates were no longer just and reasonable,” she said of FERC’s philosophy behind creating incentives.
She said there wasn’t much common ground on specific, standardized incentives as she and her fellow commissioners were developing Order 697, issued in 2006.
“We agreed that incentives were necessary. We didn’t agree on what certain projects should be incented and not others. We couldn’t agree on the particulars. If you look at the rule, it reflects that. … We put the burden on the developer when they came to us” with an application, Kelly said.
Moeller, now executive vice president at Edison Electric Institute, said the incentive applications that started to come in after the 2006 rulemaking were generally on par with the commission’s expectations.
“I actually dissented from many incentive requests, and through my dissent, I was trying to create my own incentive policy, Kelly recounted. “Some of my dissents were an inchoate wanting to know more about the challenges and the benefits.”
Save the RTO Adder
RTO adders are still an important piece of encouraging transmission investment, Kelly said, especially in the West and Southeast, where participation in organized markets is less common.
“RTO membership was clearly something that the commission was trying to encourage. I think it’s taken for granted now, but 15, 20 years ago, it was really something different,” Moeller said.
However, the lone panelist without a regulator background argued for eventual phaseout of the RTO adder.
“We were concerned that the RTO incentive packages were too easily granted. It was becoming routine,” American Public Power Association General Counsel Delia Patterson said.
She said FERC has struck more of a balance between consumers and investors since its 2012 policy statement on transmission incentives, which was crafted to create a more rigorous standard for requesting incentives. Still, she said RTO membership is too commonplace to warrant the incentive.
But Moeller said it remains fair, also adding that between 2006 and 2012, transmission buildout was appropriately robust.
“I thought we went too far in terms of cutting things back in 2012. But I agree that transmission investment is necessary. … It’s so doggone hard to build for the most part,” Moeller said.
Risky Business
Kelly agreed that transmission construction is a risky venture: “It’s a very difficult decision in a public company to put up capital and make a transmission investment.”
During her time on the New Mexico Public Regulation Commission, Kelly said, she agonized the most over transmission siting decisions. “Nobody wants to put a transmission line in their neighbor’s farm or yard or along the edge of a national forest. It’s not a pleasant job.”
Asked whether they would prefer a case-by-case review or standardized incentive approval, the former commissioners still prefer the former — although Kelly thinks “slam dunk” incentives should be made into a standard.
Patterson concurred on the need for case-by-case review. “I trust my daughter, Emily, to make sure to pack a balanced lunch, but it’s up to me to verify that,” she said to audience laughter.
Moeller said FERC might consider additional incentives for transmission systems that are reinforced against intensifying climate change.
“What’s the value of electricity when you don’t have it? Many, many, many times more.”
“Not just consolidation, but also how to improve the effectiveness and efficiency of the groups,” the MOPC staff secretary said during the July 16-17 meeting. “Do they have the right structures? The right representatives? Do they coordinate when they coordinate? Should they coordinate? Are there opportunities to consolidate?”
Members pushed back against recommendations that would disband the Seams Steering Committee (SSC) and parcel out its responsibilities to other working groups.
American Electric Power’s Jim Jacoby, who chairs the SSC, said he supports handing off planning functions and operational issues to other groups to retain a focus on the interregional transmission process. He also said much of the SSC’s recent work has been related to markets and improving their coordination with MISO.
“To me, it comes down to policy issues,” Jacoby said. “I want to keep the focus on the seams. If you push that into other groups, I think you will lose that focus.”
Jacoby is supported by the Holistic Integrated Tariff Team (HITT), which recommends that SPP continue to make seams a high priority and address them as a part of the strategic plan. The HITT says the SSC “should continue to provide direction to SPP staff on seams issues.”
“We need to collapse the groups for the sake of efficiency, but we need to maintain and increase the focus on seams questions,” the Advanced Power Alliance‘s Steve Gaw said, adding that his main concern is that interregional planning with MISO is shifting into the regional planning process. “If it morphs into something different than today, we will really need closer coordination, particularly with the Economic Studies Work Group (ESWG), to make sure those two groups are linked.”
Gaw credited Jacoby, who also participates on the ESWG, with ensuring coordination between the two groups. The ESWG develops and evaluates the planning processes’ economic studies.
Reacting to the possibility of combining the Operating Reliability and Transmission working groups, Southwestern Public Service’s Bill Grant drew laughs when he said, “I want to be in the room when you do that.”
“I come from the operations side, and I’ve had my share of arguments with the planners,” Grant said. “It’s just different issues. I think we lose some expertise when you do this.”
Stakeholders Get Last Chance at HITT Report
The HITT celebrated the release of its executive summary with a tag-team education session for the MOPC and the Strategic Planning Committee. HITT Chair Tom Kent, of Nebraska Public Power District, and Rob Janssen, of Dogwood Energy, took turns reviewing the group’s 21 recommendations and offering stakeholders one last chance to provide comments before the Board of Directors sees the final report July 30.
“When I walked out of that last meeting, I thought, ‘I wish I had another three months of this process, because we have X, Y and Z issues that we can now pursue,’” Janssen said. “I’m glad we didn’t extend the timeline. We’re done, but this packet of recommendations moves SPP’s operations to a different level. As a result, everyone involved will see new things to resolve and new opportunities to pursue that we haven’t seen before.”
The HITT separated its recommendations into four categories: reliability, marketplace, planning and cost allocation, and strategy. Thirteen of the recommendations, some of which are already in progress, are planned for implementation; the other eight require further study. (See HITT Shares Draft Report with SPP Stakeholders.)
Kent said the team spent much of its time improving SPP’s congestion-hedging practices, before determining the RTO should continue with a market mechanism to hedge load against congestion charges. It suggested the existing market design include modifications to implement counter-flow optimization that is limited to excess auction revenues.
A suggestion to decouple the Schedule 9 and Schedule 11 transmission pricing zones and create larger Schedule 11 pricing zones and/or Schedule 9 sub-zones was also the subject of much conversation before the HITT. The team said that when creating the new pricing zones, “consideration should be given to new deliverability sub-regions, distribution factor calculations, and market and power flows.”
“The debate … could be part of a broader policy debate. There are a lot of things to sort out, such as how transmission planning, cost allocation and resource adequacy issues interact within new zones or sub-regions in SPP,” Janssen said.
The recommendation is being handed to the Regional State Committee and its Cost Allocation Working Group for further evaluation.
“Finding common thought and commonality to deliver holistic recommendations is pretty exceptional,” Kent said, thanking staff and stakeholders for their input. “There was a lot of response in bringing their issues and putting them on the table. We’re ready to drop our mics.”
Fortunately, no microphones were harmed during the presentation.
Western EIS Market Drawing Interest
While SPP works to complete NERC certification as a Western Interconnection reliability coordinator by September, it is holding “a lot of interesting” discussions with parties interested in its Western Energy Imbalance Service (WEIS) market.
Vice President of Operations Bruce Rew said there has been “significant interest” in SPP’s proposal to stand up an EIS market in the West. An original Friday deadline for commitments has been pushed back to Sept. 3, extending the go-live date to February 2021. (See SPP’s Western EIS Market Poised to Challenge EIM.)
Rew said market participants are expected to make a four-year commitment to the WEIS, with new entrants added every six months after go-live and allocated a portion of the start-up costs. Participants will be charged for implementation and ongoing costs based on a proportional share of annual net energy for load.
The WEIS is modeled on SPP’s Energy Imbalance Market, which was replaced by the Integrated Marketplace in 2015.
WEIS implementation schedule | SPP
MOPC Approves Early Market Close
The MOPC approved the Market Working Group’s recommendation to shorten the window between submitting day-ahead offers and their posting by moving the award time from 2 p.m. to 1 p.m. CT. The MWG said the revision request (RR365) would result in a shorter day-ahead market time frame and move SPP closer to meeting FERC Order 809’s requirement that the timely nomination cycle for scheduling gas transportation be from 9 a.m. to 1 p.m.
AEP’s Jacoby offered an alternative motion that would have shifted the bid/offer submission deadline from 9:30 a.m. to 9 a.m. and the awards to 12:30 p.m. The motion was soundly defeated, receiving only 10 votes. (RR365 passed with five votes opposing and four abstaining.) Members in the northern states said they don’t have price certainty on natural gas until 9:30 a.m.
“Even with price certainty, if you don’t get to the timely nomination cycle, does it help you?” Jacoby said. “You can pick up a bid and hope the market solves for what you want, but that is not always the case.”
“The extra 30 minutes goes a long way for us to have gas-price certainty,” SPS’ Grant said.
The vote was emblematic of the discussion held within the MWG, said Vice Chair Jim Flucke, of Evergy.
“Each had a different gas situation. Some members wanted an earlier time, others advocated for a later start time,” he said, noting the one-hour shift was largely a consensus agreement.
Flucke said the MWG would withdraw RR339, which would set the submission deadline at 10 a.m., in favor of RR365.
The MOPC easily endorsed the MWG’s RR352, which moves up the start of the day-ahead reliability unit commitment process to 1:45 p.m. from 2 p.m. The day-ahead market’s posted results would then follow. ITC Holdings abstained from the vote.
Staff said the change will keep SPP in compliance with FERC’s directive to eliminate “inflexible” operating limits and other rules that the commission said are preventing prices from reflecting the marginal cost of serving load. (See FERC Orders Fast-start Rules for SPP.)
“FERC’s order was not without merit,” Flucke said. “We remove the screening run, because that allows the correct resources to set the price.”
LREs Meet Resource Adequacy Requirements
All of SPP’s load-responsible entities (LREs) are in compliance with the resource adequacy (RA) requirement for the 2019 summer season, according to the Supply Adequacy Working Group’s (SAWG) first RA report.
As a result of the Tariff’s Attachment AA, which went into effect last July, LREs are required to maintain adequate capacity to cover their summer load and planning reserves. SPP’s LREs met the 12% planning reserve margin (PRM) threshold with the exception of the Western Area Power Administration, which met its 9.89% PRM, carved out for LREs with at least 75% hydro-based generation.
SAWG Vice Chair Natasha Henderson, of Golden Spread Electric Cooperative, said generation retirements will drop SPP’s reserve margin to 18.2% through 2024. The footprint will lose at least 1.8 GW in confirmed retirements this year, with confirmed and unconfirmed retirements totaling 3.5 GW in 2024, she said. With peak demand expected to grow at an annual rate of 0.6%, the 12% PRM is expected to be sufficient through 2024.
The MOPC approved an unbudgeted $80,400 for a battery storage study as part of a larger effective load carrying capability (ELCC) assessment. The ELCC study will determine the amount of incremental load a resource can dependably and reliably serve during peak hours by calculating the system’s loss-of-load expectation with and without the resource.
CAISO, MISO and PJM already use the ELCC methodology. The SAWG wants to use ELCC as the guiding principle to accredit wind, solar and battery storage resources. An ELCC wind study will be posted annually in October.
“Companies retiring coal resources need to know what kind of accredited renewable resources they’ll get,” said SAWG Chair Brad Hans, of the Municipal Energy Agency of Nebraska.
2021 ITP Begins, Joining 2019, 2020 Studies
This was supposed to be the year SPP’s transmission planning process was easy. Instead of separate 10-year, 20-year and near-term assessments, the RTO implemented an annual planning cycle with a standardized study scope and common reliability models.
Instead, SPP finds itself with three studies being conducted simultaneously.
The ESWG will present its final package of recommendations for the 2019 Integrated Transmission Planning study in October. Meanwhile, the 2020 assessment is establishing its economic model, while the 2021 study kicked off Thursday with a first discussion of its scope.
SPP Planning Director Antoine Lucas said the studies are hitting their deadlines but admitted the work “is very resource-intensive.”
Questioned as to whether this was the intent of the revised planning process, Lucas said the studies are at very different stages.
“They require different sets of people. There’s some overlap, but we’re able to focus on different specific areas,” he said. “We’ve learned a lot. We’ve been trying to do some refinements as we go along, but it’s still too early in the process to determine whether or not we need to look at any significant changes to the process.”
ESWG Chair Alan Myers, of ITC, said the group will work on “optimizing” the 2019 ITP’s best portfolio for the October meetings, balancing reliability and market efficiency.
SPP Borrowing MISO’s Generation Replacement Process
The MOPC directed staff to work with the Regional Tariff Working Group in developing language addressing the transfer of interconnection rights for existing generators that have been retired, demolished or replaced.
Steve Purdy, SPP’s manager of generation interconnections, said the RTO could benefit from a similar process modeled on a recently approved MISO Tariff change. (See “Other Interconnection Filings,” MISO Promises Refile on Stricter Queue Requirements.)
MISO can now accommodate the replacement of a generator with the same or lesser capacity at the same interconnection point. It will charge generation owners a flat study deposit of $60,000 — regardless of size — and conduct replacement impact studies and reliability assessments. The replacement must undergo the full interconnection study process if the new generator causes a material adverse impact.
Should the new capacity be greater than the existing capacity, only the incremental capacity must undergo the full study process. In any case, the new generator must be in service within three months of the existing facility.
Purdy said if SPP adopts a similar process, it will remove unnecessary barriers to beneficial replacements, facilitate reliable resource planning, and remove incentives for uneconomic retirement and interconnection queue behavior. The proposal would also be consistent with FERC guidance, he said.
“Yes, we should do this,” SPS’ Grant said. “Most of our generation is getting old. If everyone sticks to their plans, there are a lot of retirements coming our way.”
Grant also recommended that SPP proceed with the Market Monitoring Unit’s proposal to measure avoidable costs if a generator is retired or mothballed. (See “Best Practices,” Stakeholders Push Back Against SPP Retirement Changes.)
“It’s not directly related, but you need a process for generation retirement for this to be effective,” he said.
Another BTM Load Survey in the Offing
Staff will once again survey its members and network customers as it attempts to validate billing efforts for behind-the-meter generation reporting network load for transmission service billing.
SPP staff and stakeholders have been wrestling with the issue since 2015. The MOPC rejected a revision request in 2017 that would have established a 1-MW threshold for reporting BTM load. (See “Stakeholders Unable to Reach Consensus on Network Load,” SPP Markets and Operations Policy Committee Briefs.)
COO Carl Monroe said the survey, which will differentiate between wholesale and retail BTM loads, will be distributed to MOPC members, who would be responsible for providing their companies’ positions. Staff would propose ways to address the issue in order to solicit responses, he said.
SPP will use the responses to bring a proposal clarifying network load calculations and reporting to the MOPC’s October meeting.
Staff last surveyed members in 2018 when they assessed transmission customers’ understanding of their responsibility to report network integration transmission service data.
Consent Agenda Lowers Project Estimate
The committee unanimously passed the consent agenda, which included seven revision requests and a Project Cost Working Group recommendation that a cost estimate for a previously approved project be reduced from $40.4 million to $31.6 million. Evergy’s Kansas City Power & Light, KCP&L-Greater Missouri Operations and Westar Energy companies are responsible for the 345-kV voltage conversion project in Missouri.
The RRs were:
ESWG RR362: Requires SPP and the ESWG to monitor changes to production tax credit values and federal corporate tax rates before each ITP study to help estimate the curtailment price applied to both internal and external projected wind units on a per-site basis.
MWG RR356: Cleans up missing language, incorrect capitalized and lowercased terms, typos and other discrepancies between the Integrated Marketplace’s production protocols and the forward-looking protocols.
MWG RR357: Clarifies language to accurately describe the trading hub modifications process by removing the need for administrative changes.
MWG RR359: Clarifies that non-dispatchable variable energy resources (NDVERs) registering and converting to dispatchable variable energy resources must do so even if they don’t have generation-interconnection agreements. The change also includes a missed reference to run-of-river hydro in complying with FERC’s conditional order (ER19-356) on RR272.
MWG RR360: Ensures that settling credits through revenue neutrality uplift is accurately documented in the Tariff and Integrated Marketplace protocols and improves market settlements for emergency energy.
RTWG RR354: Waives the requirement that a transmission project sponsor provide a letter of credit when funding an upgrade should the sponsor and the transmission owner building the project be the same entity.
RTWG RR358: Revises the cost-recovery mechanism from market participants who use and benefit from SPP’s services by subdividing Schedule 1-A into four rate schedules, including a mix of demand and energy charges. Current 1-A charges for transmission service will become Schedule 1-A1 charges and three market-related charges would be recovered through three energy charges. (See “Board Approves Modernized Cost-recovery Structure,” SPP Board of Directors/Members Committee Briefs: Jan. 29, 2019.)
Despite a rebuke from a federal appeals court, FERC last week reaffirmed its earlier decision that Pacific Gas and Electric participates voluntarily in CAISO and qualifies for hefty financial incentives to remain in the ISO (ER14-2529-005).
The decision came after the 9th U.S. Circuit Court of Appeals instructed FERC in January 2018 to reassess its longstanding practice of granting an annual 50-basis-point return on equity adder to encourage PG&E to be part of CAISO. The incentive earns the currently bankrupt utility about $30 million a year.
In response to the court’s ruling, FERC instructed PG&E, the California Public Utilities Commission and other interested parties to brief it on the issue of whether PG&E could leave CAISO if it chose. (See Can PG&E Quit CAISO? FERC Wants to Know.)
FERC had concluded in late 2017 that participation in the ISO was voluntary. The commission decided Thursday it had been right all along.
We “find that California law does not mandate PG&E’s participation in CAISO, and that the RTO participation incentive induces PG&E to continue its membership,” FERC wrote. “We therefore reaffirm the commission’s prior grant of PG&E’s request for the RTO participation incentive.”
Mandatory or Voluntary?
The controversy over whether PG&E and other utilities are entitled to the incentive payments has been going on for years.
In the Energy Policy Act of 2005, Congress amended the Federal Power Act to require FERC to provide financial incentives to induce utilities to join RTOs.
FERC responded in 2006 with Order 679, which provided ROE adders for utilities that participate in transmission organizations. The bonuses were meant to give utilities an extra reason to join or remain members of RTOs, which are generally voluntary.
For staying in CAISO, PG&E has requested and received adders under Order 679 since 2007.
The CPUC, however, argued that membership in CAISO is mandatory for the state’s three big investor-owned utilities: PG&E, Southern California Edison and San Diego Gas & Electric. It protested in years past and again in November 2017, saying the adder for PG&E was an “unjustified windfall” at the expense of California ratepayers. The Sacramento Municipal Utility District joined the protest.
FERC dismissed the objections, but on appeal, a three-judge panel of the 9th Circuit ruled FERC commissioners had abused their authority. The commission, the court said, did not reasonably interpret Order 679 as justifying adders for remaining in a transmission organization. Instead, the commission created a generic adder in violation of the order, the judges ruled.
“Order 679 says FERC ‘will approve, when justified, requests for ROE-based incentives for public utilities that join and/or continue to be a member of’ transmission organizations,” the court noted.
“If all utilities that continued to be members of transmission organizations automatically qualified for incentive adders, the ‘when justified’ language would be surplusage,” it said.
FERC Erred, CPUC Argues
On remand from the appeals court, FERC asked the parties to brief it on four issues, including whether California law requires PG&E to participate in CAISO and whether FERC must defer to the CPUC’s interpretation of state law.
PG&E, SCE and SDG&E responded in September and October 2018, supporting PG&E’s contention that participation in CAISO is voluntary and that the incentive adder is justified to encourage them to remain CAISO members.
In addition, PG&E’s participation in CAISO is governed by the Transmission Control Agreement (TCA) between the ISO and transmission owners, whose assets the ISO controls, SCE and SDG&E said in their joint brief. Only FERC has authority over the TCA, they argued.
“The TCA is a filed rate subject to the exclusive jurisdiction of [FERC] and explicitly allows PG&E to withdraw from the CAISO. California lacks jurisdiction to alter the terms of the TCA,” the utilities argued.
The CPUC, the Sacramento Municipal Utility District and the Transmission Agency of Northern California (the “California parties”) filed joint briefs. They argued FERC had misinterpreted the 9th Circuit’s decision, which they said directed FERC to correct its own errors, not to undertake further inquiries.
Moreover, state law governs the dispute, and FERC is obligated to show deference to the CPUC, they contended.
“The California parties respectfully request that the commission conclude that PG&E does not qualify for the transmission organization membership incentive … because the CPUC has demonstrated that PG&E’s continued CAISO membership is not voluntary because it is required by state law,” they wrote.
FERC Decides it was Right
FERC disagreed that the 9th Circuit had only wanted the commission to correct itself.
The “California parties erroneously assume that the 9th Circuit found that California law mandates PG&E’s ongoing participation in CAISO,” it said.
The commission also rejected contentions that state law alone governed the matter.
“As a creature of federal statute created by Congress, this commission’s subject matter jurisdiction over proceedings before it arises solely under the acts that the commission is required to administer,” it said. “Specifically, the issue here involves the transmission and sale at wholesale of electric energy in interstate commerce, over which the FPA provides exclusive jurisdiction to this commission.”
Finally, FERC said PG&E and was free to leave CAISO. No California law prevented it from doing so, FERC concluded, and PG&E could reclaim control of its transmission grid from the ISO without CPUC approval.
“As the commission explained in Order No. 679, the basis for the RTO participation incentive is a recognition of the benefits that flow from RTO/ISO membership and the fact continuing membership is generally voluntary,” FERC wrote.
“In light of the voluntary nature of RTO/ISO membership from the commission’s perspective and the lack of any relevant mandate under California law, we find that PG&E could unilaterally leave CAISO without obtaining CPUC authorization,” FERC said. “Consequently, we find that the RTO participation incentive induces PG&E to remain a participating member of CAISO … [and] we reaffirm the continuation of PG&E’s 50-basis-point ROE adder.”
The transmission trade group WIRES praised the ruling, saying it “clearly complies with the congressional mandate for FERC to provide incentives for public utilities for their participation in RTOs and ISOs.”
Texas regulators last week postponed action on improvements to ERCOT’s day-ahead market (DAM), citing potential delays to implementing the real-time co-optimization (RTC) of energy and ancillary services (48540).
PUC adviser Stephen Journeay
During the Texas Public Utility Commission’s open meeting Thursday, PUC Chair DeAnn Walker said she had met with ERCOT staff earlier in the week. Walker said she was told that incorporating DAM improvements along with RTC would cause a two-year delay in the latter’s implementation.
“ERCOT told me there would be a delay in opening the hood,” Walker said. “Fixing [the DAM] at the same time doesn’t fit in there. I’d rather have them focusing on real-time co-optimization than coming up with a solution on this.”
Walker said delaying day-ahead improvements would give ERCOT’s market participants and the Independent Market Monitor time to determine how they want to move forward.
“This is not anywhere close to being thought through,” she said. “I think they can do this in the regular stakeholder process.”
Rate Case Recovery Remanded Back
The commission remanded back to docket management Southwestern Electric Power Co.’s request to recover $3.9 million in rate case expenses, asking the parties involved to seek a settlement (47141).
Walker told fellow Commissioners Arthur D’Andrea and Shelly Botkin she has long been concerned with the methods used by utilities to recover rate case expenses.
“We would be approving ratepayer expenses that have nothing to do [with the case]. To me, they seem to be the cost of doing business,” Walker said. “The goal by utilities is to recover every single penny over a period of time. If that’s the goal, then we have to start seriously looking at the risks involved when setting their [returns on equity].”
From left to right: PUC Commissioners Shelly Botkin, Chairman DeAnn Walker and Arthur D’Andrea
Commission staff, SWEPCO, the municipal group Cities Advocating Reasonable Deregulation (CARD), the Office of Public Utility Counsel and Texas Industrial Energy Consumers had reached a settlement over rate case expenses incurred through June 30, 2018, in dockets 46449 and 48233.
The commission’s remand asked the parties to reach an agreement that will “fully and finally resolve all issues concerning SWEPCO and CARD’s rate case expenses.” If they are unable to do so, they will request that the case be sent to the State Office of Administrative Hearings for a hearing.
SWEPCO, Entergy Get TCRF Approvals
The PUC approved transmission-cost recovery factor (TCRF) modifications for SWEPCO (49042) and Entergy Texas (49057). The changes will result in TCRF annual revenue requirements of $11.5 million for SWEPCO and $2.7 million for Entergy.
PHILADELPHIA — PJM’s anticipated increase in renewables over the next decade won’t succeed without the support of more reliable fossil fuels and nuclear reactors, industry analysts said last week.
The predictions came during presentations at the Mid-Atlantic Renewable Energy Summit hosted at The Bellevue Hotel on Thursday, where experts from all corners of the energy sector gathered to discuss the future of PJM’s resource mix and the anticipated shift from policy-based investment to more economic drivers.
“The increase we’ve seen so far is nothing compared to the increase that looks like it’s coming at us in the future,” said Stu Bresler, PJM’s senior vice president of markets and planning. “We ain’t seen nothing yet.”
Data from the National Renewable Energy Laboratory and U.S. Energy Information Administration show PJM’s installed wind and solar capacity currently exceeds 11,000 MW — the majority of which joined the grid during the last 10 years. ICF Resources said 70% of the renewables scheduled for connection through 2030 will come online in New Jersey, Maryland and D.C., where elected officials have set aggressive clean energy targets and other policies to reduce the effects of climate change.
The Garden State alone will install 3,500 MW of offshore wind power over the next decade. It announced last month that Denmark-based Ørsted will construct the first 1,100 MW 15 miles off the coast of Atlantic City beginning in the early 2020s. (See Ørsted Wins Record Offshore Wind Bid in NJ.)
“We are living amidst a revolution right now, a revolution in terms of technology change, a revolution of climate change … and finally a revolution of electricity decarbonization,” said Stuart Caplan, partner at Troutman Sanders. “Beware of what you ask for … treat fossil fuels not as an enemy of renewables. The pendulums can swing quickly.”
Caplan said that the intermittency of current renewable technologies means fossil fuels will continue to have a place in PJM in order to “preserve balance.” In March, the Independent Market Monitor said natural gas-fired energy output exceeded coal in PJM’s market last year for the first time ever. (See Monitor Says PJM’s Capacity Market not Competitive.) Economists on Thursday said coal retirements in favor of more efficient combined cycle units will continue — but the cheap price will not, providing a valuable opening for nuclear energy in the market.
D.C. Public Service Commissioner Greer Gillis said reaching the district’s goal of 100% renewable energy and 50% carbon emissions reduction by 2032 will be challenging, but possible. D.C. set the targets in December 2018, making it the most ambitious clean energy policy enacted nationwide, she said.
“We are very optimistic,” she said. “But I think one thing we are all concerned about is the pricing.”
Judah Rose, executive director of energy markets for ICF, said zero-emission credits and renewable energy credits will likely increase between 2022 and 2025, temporarily spiking energy costs. Post 2025, he said, the combination of carbon pricing and states meeting their renewable portfolio standard mandates will cause renewable energy prices to fall.
ICF’s market forecast assumes the implementation of a national CO2 program with a price of $4/ton, though Rose said the “real action” could happen through the Regional Greenhouse Gas Initiative, where policy in the participating states could create “big upward pressure” on the price of carbon. It wouldn’t wipe out gas development entirely, however.
“We still see huge economics for combined cycle units … mostly located in western PJM,” he said. “For coal and nuclear, we see unfavorable economics for both areas. In the long run, however, as gas prices increase and we have some kind of carbon price, we see nuclear becoming economic.”
New Jersey and Illinois have already enacted ZEC programs for their own nuclear plants, despite criticism that the subsidies distort prices in the wholesale electricity market. Ohio legislators also appear close to consensus on a bill to rescue FirstEnergy Solutions’ reactors at Davis-Besse and Perry nuclear plants near Lake Erie. (See Ohio Senate Clears Nuke Rescue.) Supporters of the programs argue PJM’s existing market structure doesn’t value the carbon-free reliability of nuclear energy and that allowing the units to retire would not only be irreversible, but foolish.
“Nuclear has to be part of the equation,” said Jason Barker, director of wholesale market development for Exelon. “If you take just the carbon output in one year of those three [retiring nuclear] units, it’s equal to all of the wind that’s ever been installed in PJM. It’s undeniable in the short run if we want to reach our societal targets.”
Exelon manages the largest nuclear fleet in the country, including the remaining operating reactor at Three Mile Island near Harrisburg, Pa. The company said in June it will deactivate the unit in September after state legislators stalled on a plan to keep it running via ratepayer subsidies and changes to Pennsylvania’s RPS. (See Nuclear Subsidies Still on the Table in Pennsylvania.)
“Because of the intermittency of current dominating renewables, we need something to pick up when the wind stops blowing and the sun stops shining,” Barker said. “We need to value the flexibility attributes of those units, and that will be what drives LMP.”
“So, if there were border adjustments … it would increase the energy value and therefore decrease the cost of the ZEC, therefore making the MOPR less destructive,” Barker said. “Depending on what this MOPR ruling looks like … the carbon pricing could be a substitute or a type of substitute in the absence of more global policy.”
LOS ANGELES — To open his presentation at Infocast’s California Energy Summit last week, Marty Niles, a veteran lineman and founder of Cantega Technologies, played a clip from the quiz show “Jeopardy!”
The deputy director of the National Security Agency said the No. 1 threat to the U.S. electrical grid came from these climbing rodents, host Alex Trebek said.
“What are squirrels?” a contestant answered correctly.
Niles, whose company makes Greenjacket covers for electrical equipment, then showed a series photos and videos in which birds and animals had become trapped in substations, transformers and conductors, sparking fires and explosions. Greenjacket’s covers could help prevent fires caused by animal damage, Niles said.
“We’re just another tool in the toolbox with regard to the fire suppression effort,” he said.
Niles’ presentation was one of several talks at this year’s summit that focused on the utility-sparked wildfires that have ravaged California in recent years. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)
In a panel on wildfire prevention, panelists discussed the need for microgrids to maintain essential services — such as emergency shelters at schools — during incidents in which the main power supply was switched off or damaged.
Craig Lewis, executive director of the nonprofit Clean Coalition, said smaller-scale grids powered by renewable energy are essential, with California facing greater threats from massive fires fueled by climate change.
In the fire-prone Santa Barbara area, he said, electric infrastructure is crucial for pumping water uphill from coastal areas to battle mountain blazes.
“That water is absolutely critical for fighting fires,” he said.
Tim Hade, co-founder and COO of Scale Microgrid Solutions, said California is “on the path to having the most expensive and least reliable electricity in the United States” because of the wildfire threat.
Utilities have been using public safety power shutoffs to prevent their equipment from sparking fires during periods of low humidity and high winds.
With power shut off to entire communities, having microgrids as backup is crucial, Hade and others said. Those who depend on medical devices, for instance, can’t go without electricity.
“We need to reinvent electricity,” Hade said. “That’s the challenge.”
On the same panel, Sumeet Singh, vice president of Pacific Gas and Electric’s community wildfire safety program, said the bankrupt company has been making strides to head off wildfires before they start.
The company is widely blamed for causing the Camp Fire, which burned much of the town of Paradise in November, killing 85 people. PG&E equipment also sparked devastating wildfires in Northern California’s wine country in 2017 and in the Sierra Nevada foothills in 2015, the California Department of Forestry and Fire Protection has said.
The company recently issued a press release outlining the accomplishments of the program Singh heads. They included visual inspections of 96% of about 50,000 transmission structures in high fire-risk areas, the utility said. The company also said it had inspected 222 substations and nearly all its 700,000 distribution poles in high-risk fire areas.
PG&E has installed 430 weather stations since 2018, including 231 so far this year, it said.
In Paradise, PG&E is undergrounding new power lines where it makes most sense, Singh said. It’s also replacing wooden poles with composite structures. During the fast-moving Camp Fire, wooden poles toppled, blocking escape routes for some who died.
“I wish we could say undergrounding is a panacea,” Singh said. But it’s costly and time consuming, and while 1 mile of conductor is being undergrounded, many other miles of line remain at risk.
Another panelist, Diane Moss, founder and director of the Renewables 100 Policy Institute, said her friends from Germany were amazed to see overhead power lines in California that “reminded them of Africa.” Germany undergrounded most of its lines after World War II, she said.
“Are we going to have to wait to do that?” Moss asked.
Abe Powell, chairman of the Montecito Fire Protection District Board, said he understood undergrounding 200 miles of line in Paradise would cost about $1 billion. Montecito, near Santa Barbara, was ravaged by the Thomas Fire in late 2017 and ensuing mudslides in early 2018. The death toll was 23. Southern California Edison has admitted at least partial responsibility. (See Edison Takes Partial Blame for Wildfire in Earnings Call.)
Powell, however, questioned whether undergrounding lines for one community is the best use of $1 billion.
“We haven’t thought this through all the way,” he said.
WASHINGTON — FERC on Thursday adopted two new rules intended to reduce paperwork for electricity sellers with market-based rate authority (MBRA), acting on a proposal issued more than three years ago (Order 860, RM16-17).
Currently, sellers are required to describe the activities of all their upstream owners, often requiring them to submit multiple amendments to their filings. Once the new rule goes into effect on Oct. 1, 2020, sellers will only need to identify their “ultimate” upstream affiliate — the furthest upstream owner.
Sellers will also no longer be required to report assets — such as generators and long-term power purchase agreements — owned by its affiliates with MBRA. They will also no longer have to submit corporate organizational charts. They will, however, be required to report assets owned by affiliates without MBRA, as these are relevant to the seller’s market power analysis, the commission said.
FERC will collect all seller information through a relational database to be created by the order.
“The relational database construct modernizes the commission’s data collection processes, eliminates duplications and renders information collected through its market-based rate program usable and accessible for the commission,” FERC said.
Types of market-based rate authority filings | FERC
Connected Entity Info Tossed
Under the proposal, sellers would have had to identify all affiliate owners with franchised service areas or MBRA, or that directly own or control generation; transmission; intrastate natural gas transportation, storage or distribution facilities; coal supply sources; or access to transportation of coal supplies.
Collectively known as connected entity information (CEI), this new class of information was panned by market participants in late 2015 and again in response to FERC’s proposed 2016 revision. (See FERC Issues Revised Connected Entity, Data Collection Proposal.)
Speakers at a 2015 technical conference and commenters on the proposal said it would create significant reporting burdens.
On Thursday, FERC declined to adopt the CEI provision, instead opening a new docket (AD19-17) “should the commission wish to consider this again in the future,” staff said.
This move was strongly criticized by Commissioner Richard Glick, who issued a partial dissent. “I’m really having a hard time figuring out how that’s any different from killing the proposal altogether, and that’s what I’m very much troubled by,” he said at the commission’s open meeting Thursday.
“In my opinion, through its actions today, the commission is dropping the ball to the detriment of consumers across the country,” he continued. He called CEI “critical” to preventing market manipulation and the exercise of market power. “What I want to know is, why was this information no longer considered to be necessary, or [do] we simply no longer care about how we’re addressing market manipulation?”
FERC also dropped the proposed requirement that traders of financial transmission rights and virtual products also submit affiliate information, which Glick also criticized.
“Virtual/FTR participants are very active in RTO/ISO markets, and surveilling their activity for potentially manipulative acts consumes a significant share of the Office of Enforcement’s time and resources,” Glick said in his dissent. “It may, therefore, be surprising that the commission collects only limited information about virtual/FTR participants and often cannot paint a complete picture of their relationships with other market participants.”
“Without the connected entity reporting requirements contemplated in the [proposal], the commission lacks any effective means of tracking individuals who perpetrate a manipulative scheme at one entity and then move locations and engage in similar conduct elsewhere, as Corteggiano is alleged to have done,” Glick said. “That makes no sense. We should not be leaving the Office of Enforcement to play ‘whack-a-mole,’ addressing recidivist fraudsters only when evidence of their latest fraud comes to light.”
“I know that there are some who will construe our decision not to move forward with the connected entities proposal as a lack of commitment to our Enforcement program,” Chairman Neil Chatterjee said before Glick spoke at the meeting. “To anyone with that misconception, let me be clear: Robust enforcement of our orders and regulations is and will remain one of the commission’s most critical objectives.”
Speaking to reporters after the meeting, Chatterjee said, “I respect Commissioner Glick, but I disagree with the point that he made. I think it’s a matter of good governance. We were ready to move forward with a piece of it; we weren’t ready on the connected entities part, so rather than hold up the MBR piece, which has been out there for three years, we moved forward with it.” He also said he didn’t think “it was a fair characterization” to say that opening the new docket ends the process.
The order is “a critical step in our ongoing efforts to modernize and, where possible, streamline the MBR program to ensure that we have the information we need to evaluate market power while not unduly burdening market participants,” Commissioner Cheryl LaFleur said. “I recognize that these reforms do not address all the issues the connected entities proposal would have covered, particularly with respect to financial market participants and traders. I made the pragmatic decision that it was important to move forward on the MBR improvements that have been held up for three years due to being placed in the same [proposal] as the connected entities.”
Commissioner Bernard McNamee did not participate in the ruling.
Screens Eliminated for 4 RTOs
FERC also approved eliminating the requirement for power sellers with MBRA to submit pivotal supplier and wholesale market share screens in PJM, ISO-NE, MISO and NYISO (Order 861, RM19-2). FERC will now presume that the grid operators’ commission-approved monitoring and mitigation rules provide adequate protection against market power abuse.
MBR sellers of capacity in SPP and CAISO, which do not have capacity markets, will still need to submit the screens. The order’s relief also does not apply to any participants in CAISO’s Energy Imbalance Market.
Effective 60 days after its publication in the Federal Register, the order’s relief would begin with MBR sellers scheduled to file their triennial updates for the Northeast region in December 2019 and June 2020, commission staff said.
Sellers filed almost 600 indicative screens over the last three years, according to staff. Once the rule goes into effect, sellers would be relieved of submitting more than half of those screens, they said.
FERC clarified certain details about its initial proposal, issued last December, but it did not decline to adopt or alter any of its provisions. (See FERC Proposes Market Screen Exemptions.) Though paired with RM16-17 for discussion at Thursday’s open meeting, it received little mention in comparison.
Rehearing Denied on Interlocking Directors
In a third ruling, the commission denied rehearing but made one clarification on its February order updating its regulations on commission authorization of interlocking positions between public utilities and financial companies. (Order 856-A, RM18-15-001). The revised rule provides an exemption for some applicants for interlocking positions between utilities and companies that underwrite public utility securities. (See “Other Rules,” ‘Boring Good’ Rulemaking Seeks to Clean up Order 845.)
The commission denied El Paso Electric’s rehearing request that FERC grant equal treatment to all interlocks authorized under section 45 of its regulations.
“The commission has recognized a difference between holding interlocks among two or more commonly owned or controlled public utilities, and holding an interlock between, for example, a public utility and an electrical equipment supplier,” FERC said. “Interlocks that fall under section 45.2 and are not between two or more commonly owned or controlled public utilities (and therefore are outside the scope of section 45.9a) are reviewed by the commission so that the commission can be sure that the ‘evils to be eliminated by the enactment of [Federal Power Act] Section 305b’ are not present. By contrast, for interlocks that fall under section 45.9a’s automatic authorization, the commission has found that the evils to be eliminated by the enactment of Federal Power Act Section 305b are not present because the potential for abuse would be unlikely to result from such interlocks.”
The commission did grant a clarification on another question raised by EPE, saying that “if, as a result of the change in FPA Section 305b(2) in 1999 and the corresponding changes to section 45.2 of the commission’s regulations made by Order No. 856, an individual no longer holds an interlock that requires commission authorization, that individual no longer needs to adhere to the requirements of [sections] 45 and 46 of the commission’s regulations governing commission approval of such interlocks.”
STOWE, Vt. — Mary Bimonte of Eversource Energy on July 16 presented a joint meeting of the New England Power Pool Reliability and Transmission committees with an overview of the regional network service (RNS) rates that became effective June 1.
Bimonte, a member of the Participating Transmission Owners Administrative Committee, showed the RNS rate increased $1.51/kW-year from last year to $111.94/kW-year, with the region’s aggregate annual transmission revenue requirement (ATRR) rising $41.3 million to nearly $2.19 billion.
Eversource subsidiaries Public Service Company of New Hampshire, NSTAR West and NSTAR East accounted for much of the ATRR increase, along with Vermont Transco and Maine Electric Power.
During a presentation of the five-year RNS rate forecast, Bimonte noted this year’s increase was 67 cents/kW-year short of projections made last year for 2019.
A summary of the RNS five-year forecast from 2020 to 2023 | ISO-NE
Modifying Interconnection Procedures
ISO-NE Director of Transmission Strategy and Services Al McBride led a discussion of proposed modifications to interconnection procedures — specifically, Planning Procedure No. 10 sections 7.7 and 7.8 — to clarify adjustments to interconnection capability following partial market exits.
According to the RTO’s market procedures, “permanent and retirement delist bids can be submitted for all or just a portion of a resource’s capacity. A partial delist bid allows a resource to remove the portion of its megawatts it cannot deliver from all ISO-NE markets or only the capacity market, depending on the type of delist bid submitted.”
“When a partial retirement delist bid clears in the Forward Capacity Auction, the resource remains active and its interconnection rights are reduced to the appropriate megawatt level,” according to the RTO. “When a partial permanent delist bid clears in the FCA, the qualified capacity value for the resource is reduced.”
In February, the NEPOOL Participants Committee approved the general changes, which include methodologies to update the levels of interconnection service available for generators (and external elective transmission upgrades) after the clearing of a retirement delist bid, permanent delist bid or substitution auction demand bid in the Forward Capacity Market.
The RC and TC will alternately discuss the specific proposed revisions ahead of a planned vote by the PC in November, with a tentative effective date of January 2020.
During the previous discussions, stakeholders identified circumstances where the winter capability of their generating facilities after a partial market exit may not be correctly calculated by the formulas currently contained in PP10, McBride said.
The RTO will propose a new section of the Tariff to capture the rules associated with the establishment and relinquishment of interconnection service amounts and plans to present the proposed revisions at the Aug. 21 TC meeting.
Operating Procedure Revisions
The RC voted to recommend that the PC support revisions to a handful of ISO-NE operating procedures slated to become effective Aug. 2, including:
Altering OP-24 to describe the confidential Appendix C as a list of transmission facilities for which transmission owners are required to report protection settings, characteristics, failures or degradation. RTO staffer Jerry Elliott presented proposed revisions reflecting that Appendix C previously included a diagram, but now includes a list. The proposed changes to OP-24 are conforming changes.
Revising OP–12 (Voltage and Reactive Control) and OP-12D (Voltage Schedule Annual Transmittal Form) to clarify local control center actions for providing voltage schedules to generators.
Revising OP-5 (Resource Maintenance and Outage Scheduling) to indicate that outage requests for import capacity resources are for notification purposes only. The motion passed with six opposed (two from the Generation Sector, two from the Supplier Sector and two from the Alternative Resource Sector) and three abstentions (one Generation Sector, one Supplier Sector and one Alternative Resource Sector).
Future Vote on OP-14E Revision
Elliott presented proposed revisions to OP-14E to incorporate energy storage as a type of asset-related demand that can be selected on ISO-NE’s form NX-12E.
The RC is scheduled to vote on the revisions at its Aug. 20 meeting, and the RTO is seeking a vote by the PC at its Sept. 13 meeting.
The changes include correcting terms defined in section I.2.2 of the Tariff or ISO-NE manuals, in addition to replacing the term “nominated consumption level” with the defined term “nominated consumption limit.”
The RTO also notified the RC of revisions to OP-10 Appendix A to update the contact information for the U.S. Department of Energy in cases of reporting major system disturbance, outage or incident. The revisions took effect immediately upon the notification.
Reactive Capability Auditing Tariff Changes
The RC voted to recommend PC support for proposed revisions to section I.2.2 of the Tariff to incorporate definitions for interconnection reliability operating limit (IROL) and system operating limit (SOL).
ISO-NE lead operations analyst Kory Haag said the revisions incorporate four new defined terms in the Tariff: reactive capability audit, reactive resource, IROL and SOL.
The meeting focused on IROL and SOL, which will now be defined as the meaning specified in the glossary of terms used in NERC reliability standards.
NERC defines IROL as “a system operating limit that, if violated, could lead to instability, uncontrolled separation or cascading outages that adversely impact the reliability of the bulk electric system.”
It defines SOL as “the value … that satisfies the most limiting of the prescribed operating criteria for a specified system configuration to ensure operation within acceptable reliability criteria.”
The RC requested an Oct. 1 effective date for the definitions, following a vote by the PC in August.
Eversource Substation Upgrades
The RC voted to recommend that ISO-NE determine that three proposed substation upgrades by Eversource would not adversely affect the stability, reliability or operating characteristics of nearby transmission facilities.
Eversource crews work to restore power following a Jan. 20 ice storm in Connecticut. | Eversource Energy
Upgrades to the Andrew Square and Dewar Street substations in South Boston would entail the installation of two independent current differential high-speed protection groups on the K Street-to-Andrew Square 115-kV cables and the Dewar 115-kV cables to provide the selectivity to differentiate between a line fault and a transformer fault. The work will provide protection system fault clearing selectivity and design in compliance with Northeast Power Coordinating Council protection system design criteria (NPCC Directory 4 BPS). The proposed in-service date for both projects is in November 2019.
An upgrade to the Portsmouth substation in New Hampshire would entail the replacement of an existing 115/34-kV, 44.8-MVA transformer with a 62.5-MVA rated unit, the addition of a second 115/34-kV, 62.5-MVA transformer, installation of one new 115-kV bus tie circuit breaker, and installation of two new 115-kV circuit breaker disconnect switches. Eversource will also install one new 11-kV circuit switcher for high-side transformer protection and add two 7.2-MVAR capacitor banks, one on each 34-kV bus. The upgrade also will add a 34.5-kV bus tie circuit breaker, which will normally be open, with an automatic close function upon loss of a transformer. The proposed in-service date is June 1, 2020.
4 20-MW Solar Projects by FPS Approved
The RC voted to recommend that ISO-NE determine that implementation of four separate 20-MW solar projects proposed by Freepoint Commodities (FPS) would not adversely affect the grid.
None of the projects include energy storage, and each comprises 10 2-MW arrays.
Solar panels in Vermont like the 20-MW projects approved by the NEPOOL RC on July 16 | Green Mountain Power
SGC Engineering’s Jeff Fenn presented the separate project overviews, showing the solar farm in Plainfield, Conn., interconnecting to the 23-kV bus at the Fry Brook substation and with a proposed in-service date of December 2022.
The firm’s project in Fair Haven, Vt., will interconnect to the 46-kV line between the Green Mountain Power Fair Haven and Carver Falls substations, while the project in Shaftsbury, Vt., will interconnect to the 46-kV line between the GMP South Shaftsbury tap and East Arlington substation, both with a proposed in-service date of July 1, 2022. The project in Claremont, N.H., has the same in-service date.
Enhancing Competitive Tx RFP
ISO-NE Transmission Planning Director Brent Oberlin led a discussion of competitive transmission solicitation enhancements that included proposed clarifications to Attachment K of section II of the Tariff, the draft selected qualified transmission project sponsor (SQTPS) agreement, and to sections I.2.2 and I.3.9 of the Tariff associated with preparing for competitive transmission solicitations under FERC Order 1000.
Based on the results of the 2028 Boston Needs Assessment, which were presented to the ISO-NE Planning Advisory Committee in April, the RTO plans to issue its first request for proposals for a competitively developed transmission solution in December 2019. (See ISO-NE Planning Advisory Committee Briefs: April 25, 2019.)
Tx Cost Allocation Revisions
The RC voted to recommend that ISO-NE approve pool-supported costs for two projects by Avangrid’s United Illuminating subsidiary in Connecticut, including $11.24 million for work associated with the East Shore 345-kV circuit switcher replacement and $8.17 million to replace line optical ground wire and related fiber optic equipment on the 115-kV 1130 Line between the Pequonnock and Sasco Creek substations.
UIL determined that none of the costs associated with either upgrade can be considered localized.
Capacity Cost Compensation
The RC voted to recommend that ISO-NE designate PSEG Power’s Bridgeport Harbor gas-fired plant and the Wheelabrator North Andover waste-to-energy plant as dynamic reactive resources meeting the RTO’s capacity cost compensation program eligibility requirements.
The committee recommended the facilities be eligible for compensation associated with a qualified reactive resource designation effective Aug. 1.
RC Consent Agenda
The RC approved a consent agenda that included seven proposed plan application (PPA) notifications for Massachusetts solar generation totaling nearly 27.5 MW.
The list includes five projects being interconnected through Eversource:
Borrego Solar’s 3.75-MW project in Plymouth, interconnecting to the Valley substation, with a proposed in-service date of Dec. 31.
Borrego’s 4.999-MW project in Freetown, interconnecting to the Bell Rock substation, with a proposed in-service date of May 1, 2020.
CVE North America’s 2.5-MW/1.262-MW Wing Lane solar and battery project in Acushnet, interconnecting to the Wing Lane substation with a proposed in-service date of Oct. 31.
SunRaise Development’s 2.5-MW Cranberry Highway project in Wareham, interconnecting to the Tremont substation with a proposed in-service date of Dec. 1.
Syncarpha’s 4.99-MW Chester Road solar and battery project in Blandford, interconnecting to the Blandford substation with a proposed in-service date of Nov. 18.
Two projects will interconnect through New England Power:
Ameresco’s 2.5-MW Otter River Road project in Gardner, interconnecting to the Crystal Lake Substation with a proposed in-service date of Sept. 1, 2020.
NSTAR Electric’s 4.99-MW Denslow Road project in East Longmeadow, interconnecting to the East Longmeadow substation with a proposed in-service date of Nov. 15, 2020.
The consent agenda also included one PPA non-solar notification, the 1.5-MW Madison Business Park battery energy storage facility in Madison, Maine, which New England Battery Storage will interconnect to the Jones Street substation with a proposed in-service date of Jan. 1, 2020.
The agenda also included three Level I (for information only) transmission PPA notifications:
New England Power is updating the summer normal and revised winter line ratings to reflect current cable design on a new 345-kV underground line from the Wakefield Junction substation to the company’s border with Eversource at the Wakefield/Stoneham, Mass., town line; two new circuit breakers at the Wakefield Junction substation; and a new 345-kV variable shunt reactor. The proposed in-service date is in May 2021.
Eversource is updating the summer normal and revised winter line ratings to reflect current cable design on the installation of a new 8-mile, 345-kV underground cable circuit from the Woburn substation in Massachusetts to National Grid’s Wakefield Junction substation, in Wakefield, including 160-MVAR variable shunt reactors at each terminal. The work will expand the 345-kV switchyard at Woburn to be a breaker-and-a-half substation with four bays. The proposed in-service date is in May 2021.
Eversource is also rebuilding the existing 69-kV 667 Line from the Salisbury substation in Salisbury, Conn., to the Falls Village substation because of asset conditions. The proposed in-service date is Dec. 31.
