SPP’s efforts to extend reliability coordination services to about 12% of the Western Interconnection’s load remains on a glide path, staff said this week during a pair of meetings with Western entities at Black Hills Energy’s offices in Rapid City, S.D.
The RTO is preparing for the start of shadow operations and a second certification visit by regulatory representatives in October. It plans to go live with RC services in the West on Dec. 3.
C.J. Brown, SPP’s director of system operations, told the Western Reliability Executive Committee on Wednesday that the grid operator is focused on closing issues identified by a Western Electricity Coordinating Council-led certification team’s August site visit. (See Certification Team Checks SPP’s Western RC Function.)
“Everything is on track,” he said.
The team did not find any “showstoppers,” Brown said, but left behind several issues it felt SPP needs to resolve before going live. Staff expect to close those issues by October and are on track to close about 40% of “recommended” issues before the certification team’s return visit on Oct. 9.
By then, SPP will have begun two months of shadow operations with Peak Reliability, WECC’s incumbent RC. Peak said in August 2018 it would wind down operations by the end of this year. SPP, CAISO RC Wins Most of the West.)
Shadow ops begin on Oct. 7, but SPP operators will begin staffing the RC desk on Sept. 25. A shadow ops model is expected to be in production on Oct. 1.
Brown said SPP staff have received a separate request from WECC, FERC and NERC staff to visit the RTO’s Arkansas headquarters in early November. The agencies conducted a similar visit to CAISO’s RC West.
“If it’s a good idea for California, it’s a good idea for SPP too,” Brown said.
| SPP
Tri-State Generation and Transmission’s Keith Carman, chair of the WREC, offered words of praise for Peak employees, who have been working closely with staff from the incoming RCs.
“These employees have been nothing but professional, responsive, kind and receptive,” Carman said. “It’s way unexpected too, considering the predicament they’re in.”
RCs have been compared to top cops for transmission reliability across wide geographic areas. They are responsible for ensuring each member focuses on reliability, particularly across the seams from one area of responsibility to the next.
Brown also briefed the NERC Operating Committee on the RC transition last week, telling members said SPP “will be more proactive” in November before going live at noon MT on Dec. 3.
SPP’s Yasser Bahbaz told the Western Reliability Working Group it has received more than 10,000 inter-control center communications protocol (ICCP) data points from CAISO as it works to stand up its western RC model. Staff is currently validating about 4,000 of those points, which changed from Peak’s model to CAISO’s.
“Someone made a change from an old name to a new name,” Bahbaz said. “We’re having to go one-by-one to reconcile.”
Brown said the CAISO model will become SPP’s primary model, with an earlier Peak model becoming secondary.
SPP has also downloaded Peak’s outage data into its systems and was to spend this week validating software applications with Peak’s balancing authorities. The RTO has already completed ICCP connectivity with its 13 RC customers.
SPP has ‘Good Handle’ on Reserve Sharing Groups
SPP is not concerned with “special circumstances” surrounding reserve sharing groups (RSGs) in the West, Brown told the WRWG. RSGs consist of two or more BAs that collectively maintain, allocate and supply operating reserves for use in recovering from contingencies within the group.
The Northwest Power Pool’s RSG has reserve requirements for the Western Area Power Administration’s Colorado and Missouri (WACM) region’s BA, while other WACM entities are part of the Southwest Reserve Sharing Group.
“I believe we have a good handle on the RSGs,” Brown said. “It’s pretty basic. We run one.”
SPP is working to receive contingency reserve data from the NWPP and Bonneville Power Authority RSGs. It plans to soon request the contingency reserve data for each BA within its RC footprint.
“We want to ensure every resource is covered by an RSG or a reserves requirement,” Brown said. “We just want to know how it’s done in the West. We want to understand the situation, so we have [it] accurately modeled.”
Brown said SPP would only issue energy emergency alerts in the West for reliability concerns. BAs will be responsible for meeting NERC’s BAL-002 requirements.
“We don’t expect anyone to shed load for a compliance violation,” he said.
WREC Approves Doc Modification Process
The WREC unanimously approved a modification oversight process (MOP) to manage document modifications related to the RTO’s Western RC services. The WRWG had been working to finalize the document since May.
The MOP applies to documentation established by SPP or SPP working groups that might affect operations or have a compliance or financial impact on its Western RC services customers. (See “SPP’s MOP ‘Cleans Up Stuff,’” SPP Western Reliability Briefs: Week of May 13, 2019.)
The NERC Standards Committee on Wednesday delayed the posting of a standard authorization request (SAR) by SPP on generator weatherization because of a competing proposal from the Edison Electric Institute.
SPP proposed the SAR in response to the joint FERC and NERC staff report on the Jan. 17, 2018, cold weather event in the South Central U.S., which caused MISO and SPP to seek voluntary load reductions and nearly forced load shedding in MISO South.
The committee balked at posting SPP’s SAR for comment after Soo Jin Kim, manager of standards development, announced that NERC had received a competing SAR from EEI the previous day — too late for it to be considered on the agenda.
SPP’s SAR proposed development of a standard “to include such activities as winterization activities on generating units, winter-specific and plant-specific operator awareness training, and processes to ensure [balancing authority] and [reliability coordinator] awareness and accounting of unit limitations in performing operational planning analysis, and determining contingency reserves.”
Charles Yeung, SPP executive director of interregional affairs, amended the SAR to eliminate a reference to “fuel assurance” among its deliverables. “I’m trying to anticipate the alternate SAR because there was a concern about fuel assurance,” he said.
Several committee members said that the competing SARs should be posted simultaneously. “I think if they’re not posted concurrently … it will be extremely confusing,” said Jennifer Flandermeyer, director of federal regulatory policy for Kansas City Power & Light.
Howard Gugel, NERC director of engineering and standards, suggested the committee delay posting SPP’s SAR until the SC’s Executive Committee reviews the EEI proposal and then post them together.
After a lengthy debate, the committee voted 10-7 not to post the SPP proposal. It then approved on a voice vote a motion to remand the initial SAR back to SPP and direct the RTO to work with EEI to reconcile the differences between the two proposals. The EEI proposal was not publicly available as of Thursday, and an EEI spokesman did not respond to a request for comment.
The FERC/NERC report, released in July, said the need for a new reliability standard to improve generators’ winter performance was demonstrated by the 2018 incident as well as the large-scale unplanned outages during the 2014 polar vortex and the 2011 Southwest cold weather event.
The report found 183 generating units in the RC footprints of SPP, MISO, Tennessee Valley Authority and Southern Co. suffered an outage, derate or failure to start between Monday, Jan. 15, and Thursday, Jan. 19.
It said generator owners and operators should be required to winterize their units and provide their RCs and BAs with information about their preparations.
At the NERC Operating Committee meeting in Minneapolis last week, however, some stakeholders questioned regulators’ authority to issue such requirements, citing arguments that helped sink such an initiative in 2013. (See Déjà vu for Winterization Standard?)
Several said it would be improper to penalize generators if they suffered forced outages during severe weather.
“If you have power plants that haven’t run in weeks and you wait until the coldest day of the year to start them, you should anticipate a couple may have problems starting up,” said Allen Schriver, general manager of compliance for NextEra Energy Resources and COO of the North America Generator Forum.
“Whatever this SAR ends up being can’t mess up incentives already out there in the markets,” said Dan Woodfin, ERCOT’s senior director of system operations.
James Merlo, NERC director of reliability risk management, promised that a standard would not be punitive or require specific weatherization requirements.
“Some people have an expectation that we would say, ‘Winterize your generator. Use heat tracers.’ We don’t have standards like that,” he said.
“The expectations would be that you at least have a [winter operating] plan, and you’re going to operate to that plan. If you say you have firm fuel, then the expectation is that is what you purchased. … There were generators that said, ‘This is what I can operate at.’ Some of them were as low as -10 degrees Fahrenheit. We didn’t get … anywhere near that,” yet the units suffered outages, he said.
“Sometimes a standard is [about] getting everybody up to the same level of expectation,” he continued. “And when you have units telling us. … ‘We don’t have a cold weather preparedness plan. We don’t know what our temperature operating characteristics are; that’s troubling. It’s really beyond troubling. … Everybody sitting here is [saying] well, ‘That’s not my company.’ Well, it was someone’s company. It was several companies that gave these replies.”
John Stephens, director of power system control for City Utilities of Springfield, Mo., said he was troubled by recommendation 11 in the report, which said that when MISO relies on 3,000 MW of regional directional transfer (RDT) flows in determining reserve levels for MISO South, “it should remain mindful that … ‘any amount above 1,000 MW of the 3,000 MW north-to-south limit … [is] only available on a non-firm, as-available basis.’”
“If either party is depending on non-firm service to maintain reliability, you’ve already failed,” Stephens said.
“Non-firm is exactly what it says. If you and I go out on a boat and I [say] you can borrow my life preservers as long as I don’t need it, that’s non-firm,” he said, prompting laughter.
In response to a question from Stephens, David Zwergel, MISO’s senior director of regional operations, initially said the RTO did rely on the non-firm portion of the RDT for deliverability of its reserves.
After a break in the meeting, however, Zwergel said he needed to make a correction. “I checked back with our experts, and with the changes we’ve made, we do not rely on that non-firm capability for deliverability of reserves,” he said.
WASHINGTON — FERC has shifted several employees out of its Office of Enforcement, eliminating the office’s Division of Energy Market Oversight (DEMO), Chairman Neil Chatterjee announced Thursday during the commission’s open meeting.
DEMO staff responsible for reports examining broad market trends, such as the commission’s annual State of the Markets, were transferred to the Office of Energy Policy and Innovation (OEPI), according to FERC. Those responsible for data management support functions in Enforcement’s Division of Analytics and Surveillance (DAS) were transferred to the newly created Data Governance Division within the Office of the Executive Director (OED).
The remaining DEMO staff were shifted to other divisions within Enforcement. Employees monitoring and conducting analysis of market power using electric quarterly report (EQR) data and other market data moved to DAS. Staff administering and performing compliance functions related to EQR and financial forms moved to the Division of Audits and Accounting.
“This reorganization will allow the Office of Enforcement to be more focused on its core mission: continuing oversight of market activities, investigations and audits,” Enforcement Director Larry Parkinson said in a statement. “Assessing broader market trends fits squarely in OEPI’s mission.”
Of Enforcement staff, 9% moved to OEPI and 2% moved to OED, according to FERC. Compliance and market surveillance functions will remain in Enforcement. The office employs 163 full-time equivalents post-reorganization, according to spokeswoman Mary O’Driscoll.
Organizational chart for FERC’s Office of Enforcement as of Sept. 13, before the elimination of the Division of Energy Market Oversight | FERC
“The reorganization in no way impacts resources needed to address market oversight and compliance activities executed by the Office of Enforcement,” FERC said in a statement. Enforcement “maintains sufficient resources to execute comprehensive oversight and compliance activities on behalf of the commission.”
“This reorganization makes a lot of sense, and it will create efficiencies and more effectively align staff resources and functions,” Chatterjee said at the meeting. Enforcement “will maintain all of the resources it needs to comprehensively address market oversight and compliance.”
Noting that he has been critical of the commission for not being aggressive in its enforcement duties, Commissioner Richard Glick rebutted suggestions that the shuffle would “defang” Enforcement. “It seems to me like a simple matter of administrative efficiency, trying to move things around a little bit and make them function a little bit better,” Glick said. “If I thought there was something nefarious going on, I think the chairman knows and Commissioner [Bernard] McNamee knows that I wouldn’t be shy to talk about it.”
The San Diego City Council approved a plan Tuesday to create California’s second largest community-choice aggregator and the first providing electricity to all the customers of a major city.
“Today represents a monumental opportunity,” San Diego Mayor Kevin Faulconer told the councilmembers as he introduced a plan that’s been working its way through city government for the past year.
“Community choice is really the culmination of our climate efforts,” he said. “We will have full control about where we purchase power from. It will be clean energy.”
The joint powers agreement and ordinance, approved by a 7-2 vote, require the CCA to obtain all its energy from carbon-free sources by 2035, ahead of the state’s 2045 clean-energy timeline established in last year’s Senate Bill 100.
San Diego Gas & Electric, a subsidiary of Sempra Energy, has been the city’s monopoly electricity provider for decades, but Sempra has expressed interested in getting out of the retail electricity business and becoming a wires-only company.
“SDG&E is here to support the city of San Diego,” Vanessa Mapula Garcia, public affairs manager at SDG&E, told councilmembers. “We support our customers’ right to choose an energy service provider.”
The company will continue providing transmission and distribution services to the city, as it has done for more than a century.
The new entity, tentatively called the San Diego Regional Community Choice Authority, will likely include a dozen other communities in the San Diego region. The cities of Encinitas and Chula Vista, with a combined population of more than 300,000, have already voted to join, and others are expected to follow suit. San Diego, the state’s second largest city, has a population of 1.4 million; San Diego County totals 3.3 million.
California currently has 19 CCAs, and other areas around the state are considering forming CCAs to purchase and provide power, displacing investor-owned utilities in that role. The state’s largest CCA, the Clean Power Alliance in the Los Angeles area, has about 1 million customer accounts and 3 million customers.
The state’s first CCA was Marin Clean Energy, formed in 2010, following the passage of a state law in 2002 allowing CCAs.
State officials have expressed concern about the rapid spread of CCAs and their potential effects on reliability and resource adequacy in the areas they serve. On Aug. 30, however, a group of California stakeholders filed a plan with the California Public Utilities Commission that would replace the state’s current resource adequacy framework with a “central buyer” responsible for procuring resources for multiple years.
The central buyer proposal is the product of a settlement agreement that includes SDG&E, Calpine, the Independent Energy Producers Association, Middle River Power, NRG Energy, Shell Energy North America, Western Power Trading Forum and CalCCA, which advocates on behalf of the state’s growing number of community choice aggregators. (See Calif. Participants Float ‘Central Buyer’ RA Plan.)
PROVIDENCE, R.I. — New England renewable energy advocates are skeptical of federal officials’ claims to be acting in the public interest by delaying the final permits for the Vineyard Wind project in Massachusetts, raising the question of whether the Trump administration is slow-walking offshore wind approvals.
Early this summer, the project’s biggest obstacle appeared to be local, after the Edgartown Conservation Commission denied a permit for the project’s cables to come ashore on Martha’s Vineyard. (See “Land Ho is Wind Woe,” New England Officials Speak on Grid Transformation.)
But challenges rose to the federal level last month when the Bureau of Ocean Management announced it would postpone a final environmental impact statement and extend the project’s permitting timeline to conduct an expanded analysis of “cumulative impacts” from the multiple offshore projects proposed for New England.
Participants at a Sept. 10 Environmental Business Council of New England (EBCNE) meeting on Vineyard Wind questioned the federal government’s rationale for the delay.
“For years, we asked for cumulative impacts in things like port development, LNG facility development, energy development in general; and FERC said, ‘No, we never do that; we never ask how many ports do we really need. … One port rises and falls on its own merits,’” said the Institute at Brown for Environment and Society’s Curt Spalding, a former EPA regional administrator for New England during the Obama administration.
Spalding said the federal review under the National Environmental Policy Act “is not simply a written, hard and fast scientific process. The key decisions are made along the way by regulators that obviously look at all the data that NEPA generates. But let’s be honest: It’s a very politicized process in a lot of cases.”
As evidence of an overall strategy to delay development of renewable energy, and in particular offshore wind, Spalding pointed to apparent short-staffing at the National Oceanic and Atmospheric Administration, which he said “has not been given any resources to do all the reviews that we’re talking about. It’s a joke; it’s absurd. They’re being asked to review I don’t know how many projects, but they’re given no resources.”
Every Hour Matters
A joint venture between Avangrid Renewables and Copenhagen Infrastructure Partners, Vineyard Wind in May 2018 won a contract to supply Massachusetts with 800 MW of offshore wind energy. Later that year it won another lease area off Martha’s Vineyard in an auction conducted by BOEM. The company last month bid for the state’s second solicitation by offering several options on up to 800 MW in additional offshore wind energy.
Rachel Pachter, vice president of permitting affairs at Vineyard Wind, described the path to construction of the large project, which could ultimately generate as much as 3,200 MW. Asked about the BOEM delay, Pachter said, “The issue as we understand it is not specifically at all about Vineyard Wind. … This is about the other projects and their development, and them wanting to do a more comprehensive cumulative impacts analysis of all of those in order to better understand where the industry’s headed.”
“So they are not coming back to you asking for more information?” EBCNE President Daniel Moon asked.
“They’re coming back and asking for money, since we pay for a third-party contractor, but it’s really about future projects,” Pachter said. “They actually have all the information they need on Vineyard Wind.
“An important way to think about offshore wind farms, the way we think about them, is they’re really, really big logistics projects,” she said. “What matters most to us is how we can build this most efficiently, spend the least amount of time offshore and get everything done before the [winter] weather.
“Our windows to work are extremely critical. You can lose an entire year, and when we have vessels with half-a-million to million-dollar [per] day rates, these are all extremely critical to construction of the project. Every hour matters to us. And on the opposite side, making space for the right whale, to make sure that’s protected.”
Andrew Gottlieb, executive director of the Association to Preserve Cape Cod, said that “moving the goalposts of the regulatory process is nothing more than a cynical attempt by the administration to delay offshore wind development in general.”
“The senior levels of the federal government are really being captured by oil-and-gas-industry interests who see the potential for large-scale wind being a threat to wringing out the last nickel of what would otherwise be known as stranded assets,” Gottlieb said.
Responding to the claims of critics, BOEM spokesperson Tracey Moriarty told RTO Insider: “Because BOEM has determined that a greater build out of offshore wind capacity is reasonably foreseeable — more than what was analyzed in the initial draft [environmental impact statement] — BOEM has decided to supplement the draft EIS and solicit comments on its revised cumulative impacts analysis.”
NOAA backed BOEM’s view, asserting that the agency “is committed to ensuring fishing activities and offshore renewable energy interests can operate in harmony,” according to agency spokesperson John Ewald. “We appreciate BOEM’s desire to strengthen their analysis and more fully address the cumulative impacts of offshore wind activities through development of a supplemental environmental impact statement.”
NOAA did not address the contention that it has inadequate resources to expedite project reviews.
The EBCNE meeting also featured a panel that provided a flavor of the logistical complexity of building a wind farm.
“Throughout this multiyear review period, there has been a considerable amount of attention focused on Vineyard Wind because they are the first project, the project that’s farthest through permitting,” said panel moderator Maria Hartnett, of consulting firm Epsilon Associates, which has been working on Vineyard Wind for two years.
Priscilla Brooks, vice president and director of ocean conservation at Conservation Law Foundation, said, “Our approach to offshore wind has been one of wanting to see this industry advance, with a focus on siting projects … how to site them in an environmentally sensitive way and also ensure that they get a fair environmental review.”
Jill Rowe, director of ocean science at consultancy RPS Group, which has been working with the project since 2017, said the company has done “many of their [construction and operations plan] sections, have provided permitting support … but there’s a lot of science.” She said RPS has brought its experience from the oil and gas industries to the offshore world.
PJM says it won’t take sides in a debate between transmission owners and load interests over the TOs’ proposal for removing substations and other “critical” assets from NERC’s CIP-014-2 list.
NERC’s critical infrastructure protection standard CIP-014-2 requires TOs to identify and protect transmission stations and substations whose loss or sabotage could result in widespread instability, uncontrolled separation or cascading outages. The TOs last month proposed Tariff Attachment M-4, which outlines a process for vetting transmission projects to remove the assets from the list.
Some stakeholders contend PJM rules require that addressing the CIP-014-2 assets must involve an open and transparent discussion with stakeholders. But doing so, the TOs contend, could reveal the highly secretive location of these facilities.
The RTO said it will stay on the sidelines of the transparency debate and encouraged stakeholders to work out the Tariff language among themselves.
“PJM is prepared to assume the role of an independent, third party to assess whether a transmission project will effectively address the critical infrastructure and associated operations and reliability risks giving rise to the CIP-014 designation in the first place,” PJM spokesperson Susan Buehler said in an email to RTO Insider. “By so doing, PJM can ensure that projects meet the shared objective to reduce critical facilities outright. Because this is a PJM transmission owner proposal, we encourage dialogue between the transmission owners and other stakeholders.”
Consumer Advocates of the PJM States questioned why the draft attachment wasn’t scheduled for discussion at the August meeting of the Markets and Reliability Committee or the Planning Committee. (See PJM TO Tariff Filing Stirs up Transparency Concerns.)
Last week, the D.C. Office of the People’s Council presented a problem statement and issue charge that would require all sectors come together to manage future CIP-014 projects. (See “Consumer Advocates: CIP-014 Projects Need More Transparency,” PJM PC/TEAC Briefs: Sept. 12, 2019.)
American Municipal Power took the debate a step further on Tuesday when the company publicized its “profound” concerns about the TOs’ proposal in a letter to PJM’s planning department and Board of Managers. Of particular concern, AMP said, was the TOs’ attempt to classify CIP-014-2 projects as supplemental, which it said could hide large-scale upgrades with regional and interregional impacts behind a veil of secrecy.
“Given the importance of these substations to regional and possibly interregional operations, there can be little question that the planning of those substations would be conducted through the PJM-administered Regional Transmission Planning Process,” AMP CEO Marc Gerken wrote.
PJM said NERC assigned TOs the role of managing physical security for CIP-014-2 facilities. Ken Seiler, vice president of planning, told the Planning Committee last week that staff support the idea of reducing or eliminating the number of CIP-014-2 assets in the RTO’s territory, but he would not comment on the transparency concerns raised by the consumer advocates. There are less than 20 “critical” assets within the footprint.
“The elephant is in the room, so it’s not like we are ignoring it,” he said. “PJM conceptually supports the idea of electrically making critical facilities noncritical. We think that’s the best thing for this system.”
Pulin Shah, director of transmission strategy and contracts for Exelon, said TOs “will follow the process laid out in the Consolidated Transmission Owners Agreement and the Tariff” when collecting and responding to stakeholders’ comments on Attachment M-4. Exelon has led the PC and MRC discussions on the attachment thus far, though it was just one of several members of the Transmission Owners Agreement-Administrative Committee that helped develop the proposal, Shah said.
“We have extended the comment period to ensure we allow ample time for stakeholders to provide their comments and questions, as the transmission owners determine next steps,” he said. “We will review and respond accordingly to relevant comments and questions through this process, as opposed to having one-off discussions that could lead to confusing the issue.”
SACRAMENTO, Calif. — One of the biggest energy-related bills of the year in California shot through the State Legislature earlier this summer, well ahead of lawmakers’ Sept. 13 deadline to pass legislation, but other noteworthy electricity bills landed on the desk of Gov. Gavin Newsom in recent days.
Among them was SB 520, which reworks the notion of the provider of last resort (POLR) in the face of the state’s fast-changing electricity landscape. Traditionally, California’s three big investor-owned utilities have filled that role. But with the emergence of community-choice aggregators (CCAs), lawmakers decided the old rules needed updating. (See Calif. Lawmakers Reveal Growing Divisions over CCAs.)
The bill would let CCAs be the POLRs in their service territory, contingent on approval by the California Public Utilities Commission. State Sen. Bob Hertzberg (D) authored the bill.
One bill sent to California Gov. Gavin Newsom could affect the potential purchase by San Francisco of PG&E’s electric grid there.
Another measure, SB 550, conceivably could help shepherd the sale of PG&E Corp.’s assets in bankruptcy to the city of San Francisco or other public entities hoping to buy. San Francisco on Sept. 6 offered the bankrupt utility $2.5 billion to sell its wires and poles. (See PG&E Ends Bond Bid as SF Makes Wires Offer.)
PG&E has made public statements appearing to reject the offer but leaving the door ajar. It said selling its San Francisco wires wasn’t in the best interests of the company and its shareholders but that it remained open to discussing the matter with the city.
Under current law, the CPUC must evaluate the sale or merger of utility assets based on the net benefit to ratepayers. SB 550 would require the commission to also review the acquisition of an IOU’s assets based on safety criteria. It also specifies that the commission’s review would apply even if the sale is to a public entity, such as a city.
But the bill would also let the CPUC delay its implementation until July 2021, meaning SB 550 may not apply to PG&E if it becomes law — and the utility decides to accept the city’s offer. PG&E must conclude its bankruptcy reorganization by June 30, 2020, to access a $21 billion wildfire recovery fund.
Two measures authored by Sen. Steven Bradford (D) — a former public affairs manager for Southern California Edison and member of the Energy, Utilities and Communication Committee — bear on the state’s long-term clean-energy goals.
SB 676 seeks to ensure that adding millions of electric vehicles in coming years won’t overtax the grid and lead to greater need for fossil-fuel generation. It would instruct the CPUC to establish strategies and metrics to integrate EVs, including time-of-use rates that encourage charging during the “belly” of the state’s so-called duck curve, when there’s a glut of cheap solar power in the middle of the day.
Bradford’s SB 155 would require the CPUC to monitor the renewable portfolio standards of load-serving entities to make sure they’re meeting their goals. The larger goal is for the state to rely on zero-carbon energy sources by 2045, as required by last year’s SB 100.
Newsom has yet to sign the four bills, as of press time. The governor has until Oct. 13 to approve or veto measures sent to him this legislative session. Of the 2,600 bills introduced this year, more than 100 dealt with electricity, but only about a quarter of those measures passed.
State regulators and other PJM stakeholders last week expressed dismay over the announcement last week that PJM Vice President Denise Foster, head of the RTO’s State and Member Services Division, was resigning and that her unit would be “realign[ed].”
The decision was announced Sept. 9 in a letter to members from interim PJM CEO Susan Riley, who said Foster will resign effective Oct. 31 and that her unit will be reorganized under Associate General Counsel Jen Tribulski.
“With Denise’s decision to step down, we have decided to realign the State and Member Services Division to further demonstrate the organization’s willingness to listen to key stakeholders and provide a more direct line of communication between the executive team, the states and members,” Riley said.
The news was greeted with surprise and sadness.
“I love Denise. Everyone loves Denise,” said Greg Poulos, executive director of Consumer Advocates of the PJM States (CAPS), calling Foster’s departure “very much a surprise.”
“I thought everyone thought highly of Denise. I would say it’s definitely a loss for advocate relations,” Poulos said.
“No, I didn’t see it coming,” said Glen Thomas, a former Pennsylvania regulator and president of the PJM Power Providers Group (P3 Group). “I generally had very good experiences” with Foster’s division, he said. “There are a lot of things we were complaining about and focused on — and this was not one of them.”
“If Denise leaving is the answer, I’d like to know what the question is,” West Virginia Consumer Advocate Jackie Roberts said. “She created PJM’s outreach to members, especially advocates and the states. … There are very few lawyers with a combination of creative interpersonal skills and an understanding of the technical nature of PJM’s business. It’s a really hard thing to do for lawyers. Most of them are not wired that way.”
“I think she’s incredibly intelligent. I think she’s an effective communicator,” said Maryland Public Service Commissioner Michael T. Richard, president of the Organization of PJM States Inc. (OPSI). “PJM and the states were very well served by Denise Foster’s work. … I don’t think we’ve ever felt we’ve not been heard.”
Diminished Voice for Stakeholders?
PJM declined to say who initiated the discussion about Foster’s departure and whether it was voluntary. Foster also declined to comment.
Nor would PJM explain the need to “further demonstrate the organization’s willingness to listen to key stakeholders” or why Riley is making the changes now, while the board is conducting a search for a new CEO.
Under the changes announced Sept. 9, Tribulski will become senior director of member services, with oversight of stakeholder affairs, member relations, and state and member training. Former Ohio regulator Asim Haque, who joined PJM in February, will continue as executive director of strategic policy and external affairs.
Haque and Tribulski will report to Vince Duane, general counsel and senior vice president of law, compliance and external relations. Under the old structure, Haque reported to Foster.
PJM also declined to explain how the changes would result in a “more direct line of communication between the executive team, the states and members.”
Poulos and Roberts said it does exactly the opposite.
“Why was Denise’s role diminished in this reorganization?” Roberts asked. “An important voice is now absent on the executive team. Everything now has to come through Vince. Before, she’d be sitting at the same table. That voice is gone because neither Asim nor Jen are on the executive team. So, I find the role being diminished as really upsetting.”
Poulos said that although CAPS has a “really good relationship” with Haque, Foster’s departure is a loss. “Denise was an executive. From a consumer perspective, we lost a voice on the executive team.”
Did She Jump or Was She Pushed?
PJM’s refusal to provide more details and the fact that Riley announced the organizational changes at the same time as Foster’s resignation led to speculation among stakeholders over whether Foster was being forced out.
“She had to be asked to leave,” one stakeholder said. “She’s committed to the organization, and she’s too young to retire.”
Among stakeholders and PJM staff there was discussion over whether she was leaving to care for her partner, who has a serious illness. There was also a rumor that former CEO Andy Ott is starting his own venture and wants to bring Foster on board.
Poulos said he would like PJM to offer more information on the reason for the changes. “When you don’t give us the information, people are trying to fill in the blanks,” he said.
Roberts acknowledged that it is not common for corporate boards to discuss the reasons behind their personnel decisions.
“However, in this specific case, where PJM has admitted that it needs changes to its culture and how it operates, it would be best to explain how this change is consistent with that,” she said. “Given how well-liked [Denise] is, it would behoove them to give us some explanation.”
Second Stint at PJM
A graduate of Dickinson Law School, Foster worked for three years as an assistant consumer advocate for Pennsylvania before joining PJM as senior counsel in 2000. After five years in that post, she moved to Exelon, where she spent another five years, rising to become director of policy development. She returned to PJM, taking her current post, in 2009.
Foster had been reporting to Andy Ott, then executive vice president of markets, in June 2015 when Ott was named CEO-elect to replace Terry Boston. Foster then began reporting to COO Mike Kormos. (See Boston Retirement Prompts Additional Promotions at PJM.)
When Kormos left PJM in March 2016, his position was not filled, and three months later, Ott announced Duane would head a newly formed Law, Compliance and External Relations Division, with Foster as a direct report.
OPSI President Richard said he was informed of the restructuring shortly before it was announced Sept. 9 but not given an explanation of why PJM was making the changes or how it would affect OPSI and state regulators.
Richard said he was contacted by Stu Widom, manager of regulatory and legislative affairs under Haque, who joined PJM from Calpine in July.
“They told me that Denise was resigning and that they’re making these changes. It seems like they’re moving people around.”
Richard said “there’s been a desire [by OPSI] to have better communication with the [PJM] board” and said he was “very encouraged” by Riley’s comments on the subject.
The OPSI board meets twice yearly with the PJM Board of Managers, Richard said, and will have an “extended meeting” at their next face-to-face in October.
The Real Source of the Friction
Asked whether he had any problems in his dealings with Foster, Richard said, “None whatsoever.”
Richard also said he had not suggested any changes to PJM’s structure. “Generally, they have a good shop in keeping states apprised of what’s happening. … How the organization works I don’t think is key to having a good relationship.”
New Jersey Board of Public Utilities President Joseph L. Fiordaliso, who has been highly critical of PJM for failing to communicate with his state, said he didn’t hold Foster responsible. And he said he knew of no other regulators who had difficulties with her. “Denise and I have always had a cordial relationship,” he said.
At the Mid-Atlantic Conference of Regulatory Utilities Commissioners annual meeting in July 2018, Fiordaliso threatened to pull the state from the RTO, saying “it’s not rocket science to make people feel a part of the process, … Pick up the phone. … That’s all we want.” (See NJ Regulator Threatens to Exit PJM Amid States’ Complaints.)
Regulators’ criticism was frequently directed at Ott.
“I think you would find a number of states that certainly would have the same concerns that [Fiordaliso] has,” Illinois Commerce Commissioner John Rosales, then president of OPSI, said at the same conference. “I’ve made this clear to Andy that the communication could be better.”
Former FERC Commissioner and Pennsylvania regulator Robert Powelson had similar criticism at a PJM issues workshop in D.C. last year. “You talk to certain state commissioners; you talk to consumer advocates; there’s a concern that voices are not being heard,” he said. “I think PJM — Andy has heard me say this — has to do a better job with their state outreach. … A lot of states right now are not happy.”
Ott declined to comment Monday.
Rosales and Pennsylvania Public Utility Commission Vice Chairman Andrew Place, who also spoke at the workshop, agreed with Powelson’s characterization.
“It becomes very frustrating for us because they’ll say they listen, they’ll tell us about the stakeholder process, they’ll tell us everything that they’ve done … and then they’ll just throw it out the door and say, ‘We’re going to go with this anyway,’” Rosales said.
Place was referring to PJM’s April 2018 “jump ball” filing that asked FERC to choose between RTO staff’s capacity repricing proposal or the Independent Market Monitor’s plan to extend the minimum offer price rule to existing resources in addition to new entries (ER18-1314). (See Glick Recusal May Mean No MOPR Ruling Before December.)
PJM further angered states with its energy price formation proposal, which the RTO filed unilaterally in March after a yearlong discussion with stakeholders produced no consensus. In a letter to stakeholders in December, PJM Chairman Ake Almgren had pledged that a “comprehensive” energy price formation proposal would include six elements, including a transitional offset in the capacity market to prevent ratepayers from being overcharged because of increased energy and ancillary services revenue.
But the proposal PJM ultimately filed lacked the transition, OPSI complained, meaning consumers would be overcharged for seven years, from implementation in June 2020 to completion of energy and operating reserve revenue increases being fully reflected in capacity prices in 2027.
OPSI also has repeatedly clashed with PJM’s management and board over the independence of the Monitor. The Monitor’s independence has been a recurring source of contention since IMM Joe Bowring accused then CEO Phil Harris at a FERC technical conference in 2007 of attempting to muzzle it, an allegation that ultimately led to Harris’ resignation.
Improvements Seen
In an interview on Friday, Fiordaliso said PJM’s communication with the state has improved with the addition of Haque in February and the July 1 appointment of Riley — a member of the board since 2005 — as interim CEO.
“I think they’re making a concerted effort to keep a line of communication open with the states,” he said. Riley is “a very outgoing person and a person who is more than willing to communicate and keep the member states up to date on things. My encounters with her thus far have been beyond pleasant.”
Haque was the chair of the Public Utilities Commission of Ohio when he took a newly created position as PJM’s executive director of strategic policy and external affairs. PJM said Haque would report to Foster, who in turn reported to Duane.
“It’s always encouraging when you have someone you know well being brought into the inner circle,” Maryland’s Richard said of Haque. “He’s a known entity and has a great deal of credibility [with the states]. He understands the issues of importance to the state. He’s very easy to reach.”
“I think everyone’s really happy with him. He’s a breath of fresh air,” West Virginia’s Roberts said. “He’s objective, and he’s openminded, and he’s willing to hear different views and try to understand those views. He seems open to new and novel solutions to the problems that PJM has had.
“I don’t see Asim coming in as any kind of force-out” of Foster, she added.
Culture Problem?
One stakeholder who declined to be identified said that Riley is attempting to address a “cultural problem” identified in the report on the GreenHat Energy default: “the idea that we’ve got it [under control], we don’t have to tell the stakeholders anything.”
A report by independent consultants on the fiasco concluded that “an unwarranted air of confidence facilitated GreenHat’s ability to grow” and recommended PJM “create a culture and environment that encourages staff to challenge internal assertions and test their own assumptions.”
The stakeholder said the culture stems from PJM’s early years as an RTO under Harris, who “controlled the board” and saw stakeholders as “an irritant and a hindrance.”
But under Ott, who was mentored by Harris, “it switched back to what it was under Phil,” the stakeholder said.
“These are the type of crux issues that lead to mistakes like GreenHat. Sue Riley is really committed to improving the culture.”
Riley has said little publicly since becoming interim CEO. Earlier this month, however, she took steps to defuse the latest clash between PJM and the Monitor. In January, PJM made a FERC filing arguing that the Monitor should not be permitted to file complaints under Federal Power Act Section 206 without a change in the RTO’s governance structure (EL19-27). On Sept. 5, PJM indicated it was abandoning that request, with Riley and Bowring issuing a statement that reaffirmed their “relationship of mutual respect.” (See PJM Content with IMM Role after Fuel-cost Policy Ruling.)
Threading the Needle
Some observers worry that PJM’s board is not attuned to the real reasons for the RTO’s often fractious relations with its stakeholders and wonder what that means for the search for a new CEO.
In July, state consumer advocates and regulators said the new CEO should support state environmental goals to address climate change and a stronger partnership with the Monitor. (See States, Regulators: Look Outside PJM for Next CEO.)
But East Kentucky Power Cooperative COO Don Mosier said the search committee should not overlook internal candidates and the “successes of the PJM leadership team.”
“The new CEO must have a vision for threading the needle between state and federal authority on market issues, while maintaining a strong rapport with both authorities, the Market Monitor and PJM members, taking into account what is best for the majority of market participants,” Mosier said.
PJM spokeswoman Susan Buehler said Monday that the RTO’s search committee is scheduling interviews with both internal and external candidates. “To my knowledge, [Riley] is not” a candidate, Buehler said.
One stakeholder who thinks Riley could end up the permanent CEO said she will “either be the best CEO or the worst CEO.”
“Frankly, I think the board in its ignorance thought the commissioners’ and advocates’ and other stakeholders’ objections to what PJM’s doing [was because of] a lack of a relationship with them. The real problem was Andy wouldn’t do it any other way than his way, and Vince was driving the car for him,” the stakeholder said. “The board’s culpable in all this GreenHat stuff they’re trying to fix now. They believed senior management and didn’t ask questions.
“I’m really concerned that the PJM board has mistaken a problem with their relationship with certain stakeholders with Denise’s oversight of that. Because they’re two different things. … As engaging as she is, that’s not going to stop people from being disappointed in what PJM is doing.”
PJM generators seeking must-offer exceptions will lose their capacity interconnection rights (CIRs) unless they meet Capacity Performance requirements within five years under Tariff changes approved by FERC on Monday (ER19-2417).
Rejecting arguments from some of PJM’s largest utilities, the commission said the joint PJM-Independent Market Monitor proposal was needed to mitigate market power and hoarding of CIRs.
Exelon, Duke Energy and Public Service Enterprise Group had contended the revocation of CIRs was overly punitive and that CIRs are a contractual right resulting from investments and not granted on a “use it or lose it” basis.
The commission disagreed. “The interconnection service agreement or wholesale market participation agreement, which is signed by the seller, explicitly provides that CIRs are subject to the terms of the Tariff, which may change over time. … We agree with PJM that sellers that are neither meeting nor attempting to meet the Capacity Performance resource requirements should not be able to retain capacity resource status and CIRs indefinitely through must-offer exceptions.
FERC approved a joint PJM-IMM proposal to revoke CIRs from generators seeking must-offer exceptions without a plan to meet their CP commitments within five years. | PJM
“We do not agree with the protesters’ arguments regarding the types of hardships sellers could face if they lose their CIRs,” FERC continued. “The proposed procedures for removal of CIRs because of a resource status change are the same Tariff procedures used for removal of CIRs after a resource deactivates. After a resource loses its capacity resource status, the seller is able for one year to transfer the CIRs or submit a new generation interconnection request that contemplates the use of the same CIRs. Sellers also may choose to continue to participate in the PJM markets as an energy resource.”
Sellers will have up to five years to develop and complete necessary upgrades to achieve CP status, which FERC noted “is consistent with the time frames for new resources to complete upgrades and reach commercial operation.”
The changes, endorsed at the Markets and Reliability Committee in April, will require existing capacity resources not offered in three consecutive auctions to change to energy-only status. A resource receiving a must-offer exception must also file a plan showing how it will become able to satisfy CP requirements or forfeit its CIRs. Resources would be granted exceptions for no more than two auctions. (See Load Interests Endorse PJM-IMM Must-offer Proposal.)
The commission approved the proposal, effective Sept. 23, with the new provisions first affecting the 2023/24 delivery year.
“The main motion would permit hoarding of CIRs inappropriately,” Monitor Joe Bowring said at the time. “We continue to believe the compromise we worked out with PJM makes the most sense.”
FERC shot down arguments from Exelon, Duke, PSEG and FirstEnergy that PJM has exaggerated the potential for capacity sellers to exercise market power and that the change would encourage unit retirements.
“The underlying purpose of the must-offer requirement is to ensure that sellers do not withhold capacity resources from [Reliability Pricing Model] auctions and potentially exert market power,” the commission wrote. “We concur with the IMM that the historical frequency of exception requests is irrelevant and that a small number of units in constrained locations in the market could have significant impact on prices. We find that the proposed revisions to the must-offer exception procedures and limitations on the number of exceptions are consistent with the purpose of preventing sellers from physically withholding capacity. We also agree that these provisions will prevent hoarding of CIRs by resources that are not performing as a capacity resource.”
FERC was also unmoved by arguments the proposal could result in generators making hasty investment decisions. “PJM has concluded a multiyear transitional period to the Capacity Performance resource requirements, and through that process, sellers have had opportunities to determine if upgrades were necessary for existing resources to meet those requirements,” it said.
The commission directed PJM to submit a compliance filing to add some clarifying language and correct a ministerial error in one of its Tariff citations.
ISO-NE Load Forecasting Manager Jonathan Black provided the New England Power Pool Reliability Committee last week with more details on the forecasting changes that contributed to a reduction in the installed capacity requirement (ICR) in the 2019 capacity, energy, loads and transmission (CELT) summer demand forecast.
Participants at last month’s Power Supply Planning Committee and the RC meetings requested more information on the load forecast changes, which produced a 1,250-MW reduction in net ICR for delivery year 2023/24.
The forecast cycle change (using macroeconomic assumptions from 2019 data vs. 2018) produced a reduction of 300 MW, while the use of a second weather variable (adding cooling degree days, in addition to the weighted temperature-humidity index previously used) caused an additional 855-MW drop.
The use of separate July and August peak load models rather than a combined July/August case was the only change to increase the ICR, responsible for a 45-MW boost.
Shortening the weather history period to 25 years from 40 years subtracted 140 MW. ISO-NE said it made the change primarily because wind speed data needed for the new winter demand model used for CELT 2019 was unavailable for all the years of the former 40-year period. The shorter history allows the RTO to keep a consistent historical weather period for both summer and winter monthly forecasts.
It is also more consistent with the practices of other grid operators such as NYISO (20 years) and PJM (25 years).
Black also discussed the reduction in the region’s energy intensity over the last two decades, largely caused by increased end-use efficiency driven by federal standards. Since 2005, he noted 45 mandatory Department of Energy efficiency standards have gone into effect.
The electric energy intensity of the New England regional economy has been declining for the past few decades. | ISO-NE
The relationship between annual electric gigawatt-hours and regional gross state product has dropped by almost 25% since 1991 on a gross energy basis and 35% on a net energy basis, including the impact of behind-the-meter solar.
Evolving ICAP Requirements
Peter Wong, ISO-NE manager of resource studies and assessments, presented a review of the schedule for developing the “ICR-related values” for Forward Capacity Auction 14 (capacity commitment period 2023/24).
These values include the ICR; local resource adequacy requirement; transmission security analysis; and local sourcing requirement for import-constrained Southeast New England. Also included are the maximum capacity limit for the export-constrained capacity zones of Maine and Northern New England and the marginal reliability impact demand curves.
Proposed ICR-related values for capacity commitment period 2023-2024, FCA 14, *including Mystic Units 8 and 9 | ISO-NE
Including Mystic Units 8 and 9, the RTO has proposed an ICR of 33,431 MW and a net ICR of 32,490 MW after a 941-MW reduction for Hydro-Québec interconnection capability credits. That is a 1,260-MW reduction from the net ICR for FCA 13. (See “ICAP Requirements and Tie Benefits,” NEPOOL Reliability Committee Briefs: Aug. 20, 2019.)
If the RC approves the values Sept. 25 and the Participants Committee does on Oct. 4, the RTO plans to file the ICR-related values with FERC by Nov. 5 both including and excluding Mystic Units 8 and 9.
