Exelon told New York regulators on Tuesday that it will close its Nine Mile Point Unit 1 nuclear plant next spring if the state has not guaranteed it a financial lifeline by September (16-E-0270).
The company announced its plans in a filing with the New York Public Service Commission in response to requests from commercial and industrial customers for more time to comment on an Exelon proposal for cost-based compensation for its nuclear plants. That proceeding is running concurrent with one on New York’s proposed Clean Energy Standard that includes a mechanism to compensate nuclear plants through zero emissions credits. (See New York Would Require Nuclear Power Mandate, Subsidy.)
Nine Mile Point Source: Constellation Energy Group
Exelon supported the request to extend the comment deadline until July 15, after a June 24 PSC technical conference at which the company’s proposal will be considered. Exelon also wants a pricing formula determined by the PSC by Aug. 1.
The company has previously said that it would need financial support to keep its single-unit, 581-MW R.E. Ginna plant operating after a reliability support services agreement with Avangrid’s Rochester Gas & Electric expires next March.
In a filing in May, in which it proposed the compensation plan, Exelon also said it must “make immediate decisions” regarding the nuclear plants’ continued operation. But the Tuesday filing is the first time the company said it would not refuel Nine Mile Point in March.
Exelon told the PSC its Constellation Energy Nuclear Group could not count on a CES that is “merely speculative.”
“In order for CENG to make the investment and commitment necessary to keep Nine Mile Unit 1 and Ginna in operation, it needs the certainty provided by a commission order approving the CES and a signed contract procuring zero emission credits from the nuclear generators,” Exelon wrote. “CENG cannot simply roll the dice and make substantial investments on the hope that the program ultimately adopted by the commission is sufficient to justify the substantial investments and commitments required to enable continued operation of CENG’s upstate nuclear plants. Thus, CENG will need a contract in hand by September 2016. Time is of the essence.”
Exelon said refueling the unit would cost approximately $55 million, and while the process normally takes nine months to a year, it believes it can be compressed into six months.
The company just finished refueling Unit 2 at the plant. The two units, located on the shores of Lake Ontario, north of Syracuse, generate a combined 1,900 MW.
Nine Mile Point, Ginna and Entergy’s James A. FitzPatrick plant represent the entire upstate nuclear fleet that Gov. Andrew Cuomo wants to save to help the state meet its low-carbon emissions goals. Cuomo wants to exclude Entergy’s Indian Point plant, which he wants closed because of its proximity to New York City.
Under the CES, the zero emissions credits would provide extra compensation, similar to the way in which renewable energy projects receive additional payments for their clean energy attributes.
SPP’s “year of focus” on the eight-year-old Z2 crediting project may now stretch into 2017 after the Board of Directors on Monday sided with stakeholders and delayed a vote on waiver requests that would allow the work to stay on schedule.
SPP staff last week asked the Markets and Operations Policy Committee, the Regional State Committee and the Cost Allocation Working Group to reject requests by six transmission customers for waivers that would reduce their bills under the project. All three committees tabled or took no action on the requests, despite staff warnings that the failure to act could push the project into next year.
On Monday, the board followed suit, deferring action during a special one-hour conference call with the Members Committee. The MOPC will try to resolve stakeholder concerns over staff’s reading of the RTO’s Tariff, waiver eligibility and invoice amounts during its July 12-13 quarterly meeting.
‘Full and Proper Vetting’ Needed
“I fully understand SPP’s desire to move forward and get the baseline established to do that,” said Les Evans, COO for Kansas Electric Power Cooperative, whose company is facing a $6 million bill. “We believe we need to have a face-to-face so everyone can have a full and proper vetting of the issues.”
“I listened to the MOPC call … a number of points were raised that I wholeheartedly agree with,” SPP Director Phyllis Bernard said. “I think [the vote] was premature. I think [the discussion] needs to be face-to-face. My concern is if the board [was] to take a vote today, we [would be] affirming something that isn’t particularly clear and that’s hotly disputed.”
Attachment Z2 of the Tariff details how entities that fund network upgrades can receive reimbursements through transmission service requests that could not have been honored “but for” the upgrade. But a series of problems have prevented SPP from doing a proper accounting to determine which companies owe money and which are due to receive it.
In January, the Z2 project team set a Nov. 4 date for the project’s completion. CEO Nick Brown told members that same month the project would be his organization’s focus this year. (See “Brown: Finishing Z2 Crediting Project RTO’s Top Priority,” SPP Board of Directors/Members Committee Briefs.)
$99 Million in Waiver Requests
Staff asked the three committees last week to recommend approving a different set of waivers allowing four point-to-point transmission customers to reduce their Z2 obligations. All three committees endorsed the recommendation — as did the board Monday — meaning that $56.4 million in payments due from American Electric Power, Arkansas Electric Cooperative Corp., the Northeast Texas Electric Cooperative and the Oklahoma Municipal Power Authority (OMPA) will now be allocated to the base plan and included in regional and zonal charges under SPP’s Tariff rather than being directly assigned to the companies, who were designated as “Group A.”
Staff also asked stakeholders to reject an additional $42.8 million in “Group B” waiver requests from AEP, OMPA and four additional transmission customers that SPP said don’t qualify for waivers. But Steve Purdy, SPP’s manager of generation interconnections, told the RSC an error had incorrectly included OMPA’s waiver request in Group B and said that further requests in the group may also be “waivable.”
Because the MOPC had tabled the Group B recommendation earlier in the week, the RSC voted unanimously to delay its decision until it meets July 18. The CAWG also agreed not to vote on the Group B recommendation and will discuss those waivers at its next meeting July 6.
Why Go Ahead with a Vote?
Murphy
“If we know there are issues out there, why are we going ahead with a vote?” asked Oklahoma Corporation Commission Vice Chairman Dana Murphy on June 10. “This process has been going on for eight years, and the first presentation made to us was a few months ago. If we’ve waited eight years, I don’t think a few months will cost us.”
SPP COO Carl Monroe said approving both staff recommendations would allow the RTO to continue the historical calculation of transmission credits owed and due. He said two months of work has already gone into determining who owes what and how much, work that might have to be redone if further waivers are granted.
Staff said Monday it still plans to publish the final numbers, the source of much stakeholder consternation, in September. The first invoices will be due in November.
“Part of the calculations depend on knowing the … base-plan funding rates going forward,” Monroe said. “With no action taken on this, the best we can assume is Group A is the only one waived. If that changes in the next few months, that backs us up.”
“I don’t know that July 18 affects us that much, given the eight years it’s taken to get here,” Murphy said.
Nelson
Donna Nelson, chair of the Public Utility Commission of Texas, joined Murphy in resisting the Group B recommendation. She said the situation facing the RSC was “systemic” of the larger problem facing the committee.
“Eleven years is a long time,” said Nelson, counting from 2005, when SPP created the aggregate transmission service study process that resulted in Attachment Z. “We need to have the option of doing what we think is right and not be blamed for delaying something that’s been delayed forever.”
Not Assigning Blame
Monroe said staff is not attempting to assign blame. “The intent is to continue the process,” he said.
During an open meeting of the Texas PUC on Thursday, Nelson updated her fellow commissioners on the Z2 billings. Commissioner Brandy Marty Marquez said she found the amount of money involved “shocking.”
“I can understand the concerns being raised,” Marquez said. “We are going to be concerned about the impact to ratepayers.”
Monroe
SPP staff divided the waiver applicants into two groups after spending several months calculating credit payments due from long-term reservations for transmission service and determining whether the credits should be base-plan funded or directly assigned to individual transmission customers. Staff sent reports on April 28 to all customers with directly assigned upgrade costs, giving them an opportunity to ask for waivers.
The board in April approved a level payment plan in which each entity with a net payable will be given the option to pay the entire amount at once or in equal installments every three months. Payments were to begin in November, with the final installment due in August 2017. (See “Board Approves Z2 Level Payment Plan,” SPP Board of Directors Briefs.)
SPP has scheduled a two-day review session for the Z2 credit-settlement system June 28-29 at its Little Rock headquarters. The session will run 9 a.m. to 4:30 p.m. each day.
MISO is unlikely to meet a July 15 target for filing its proposed competitive retail solution (CRS) with FERC, raising doubts that changes can be implemented in time for the 2017/18 planning year.
Jeff Bladen, MISO executive director of market services, said the timeline has been placed on hold while the RTO and its Independent Market Monitor attempt to strike a compromise.
Bladen announced the delay during a Monday conference call of the Resource Adequacy Subcommittee (RASC), where the RTO had intended to review draft Tariff language. “Given the ongoing work with the Market Monitor on alternative approaches … we did not post draft Tariff language,” Bladen said.
He said MISO will continue to work with the Monitor until a “hybrid” version of the competitive retail solution emerges. MISO’s Board of Directors ordered staff and Potomac Economics into negotiations late last month. (See Board Orders Negotiation in Auction Disagreement.)
Pressed by stakeholders, Bladen said a July filing is becoming “less likely.”
Audrey Penner, market access and regulatory affairs officer at Manitoba Hydro, asked when MISO would have to file in order to implement changes in time for next year’s capacity auction.
MISO RASC liaison Renuka Chatterjee said a filing targeting 2017/18 implementation could be submitted as late as September. But she added, “We feel the further we get away from July, the less likely a 2017/18 implementation is.”
Dynegy’s Mark Volpe said “a 2017/18 implementation is paramount to Dynegy” and asked that August be used to vet the hybrid resolution.
MISO’s auction design timeline, released earlier this month, will be reworked to include later draft Tariff language release and filing dates. The March launch of the competitive retail solution is also in question.
Seeking Common Ground
While both MISO and the Monitor want unique auction treatment and use of a sloped demand curve for competitive retail areas such as Southern and Central Illinois, the two differ on other key elements:
The Monitor maintains the entire footprint can be kept on a prompt auction schedule and says MISO’s proposed three-year forward auction will create doubt in generators wanting to suspend or retire.
The Monitor wants all planning needs represented with a sloped demand curve; MISO wants to use the sloped curve only in competitive retail areas.
“What we’ve been talking about is a prompt hybrid and a forward hybrid, and at some point we’re going to have to choose which one to present to FERC,” Potomac’s Michael Chiasson said.
“While I can speak to what has been proposed, I can’t talk about what a final proposal would look like,” Bladen said. “We simply don’t have one today.”
Whatever hybrid resolution results, Bladen said there is “no chance” MISO will support a forward auction for the entire footprint.
Bladen said he hoped to have an outline of a hybrid proposal by the RASC’s next meeting, June 29-30.
Ameren, Dynegy, Industrials Weigh In
Both Ameren Illinois and Dynegy say they prefer the Monitor’s proposal over MISO’s. In comments submitted to the RTO last week, Ameren repeated its call for a single Planning Resource Auction with the addition of a sloped demand curve for deregulated areas.
“Our position at this time continues to be opposition to the MISO proposal in favor of the concepts put forth by the IMM. … Our support of the IMM proposal is conditioned on reviewing more detailed information in the future, including any proposed tariff language and/or changing dynamics in Illinois,” the company said.
Dynegy says MISO’s proposal does not address minimum offer price rules or other means for mitigating buyer market power. “Dynegy would prefer MISO embrace the co-optimized prompt year-only CRS market design proposed by the IMM because we believe Dr. [David] Patton’s proposal lays out a viable foundation for efficient price formation,” the company said.
Illinois Industrial Energy Consumers repeated its earlier stance that the entire proposal is unwarranted: “IIEC continues to believe the MISO [proposal] is unnecessary for either Southern Illinois or the broader MISO footprint and would act to unduly subsidize generation resources at the expense of consumers even when the capacity market is not tight.”
Bladen called the feedback “helpful” but declined to address any specific points raised by the three entities. “Having that kind of well-thought-out commentary is very valuable as MISO has these alternatives on the table,” he said.
Avoidable Costs Filing Remains on Track
MISO’s announcement of the delay comes little more than a week after it again pushed back its schedule for proposed seasonal and locational auction constructs. Meanwhile, RTO officials said the FERC-required filing on avoidable costs is expected to take place as planned on June 28.
The commissioners agreed at their open meeting Thursday with a recommendation by PUC staff that it open a rulemaking proceeding to reconcile data discrepancies but also limit operating-cost increases.
According to the staff, transferring authority to ERCOT would ensure that the interval data on SMT matched better with the data the ISO uses for market settlement. However, that move would also increase operating costs while simultaneously reducing the timeliness of delivering consumption data to the market.
The staff recommended that ownership of SMT remain with the transmission companies, but that the rulemaking consider the entity’s governance, performance and funding. Additionally, the data that goes to SMT would come directly from ERCOT so they match.
While all three commissioners agreed with the staff’s plan, Commissioner Kenneth W. Anderson Jr. stressed the importance of carefully delineating third-party access to customers’ data on the site. He told staff “not to languish but to move expeditiously.”
Fixing these issues are “important to the continued development of responsive demand in the ERCOT market,” he continued, adding that new technologies exist to help overcome the problems. Chief among his concerns was maintaining privacy and ensuring that consumers provide “knowing consent” when allowing third parties to access their data.
Chairman Donna L. Nelson cautioned that they not “overregulate and stop this market from evolving” and charged the PUC to “go forth and do good.”
Northern Pass Transmission and New Hampshire Public Utilities Commission staff have reached a settlement that would allow the company to conduct business in the state as a public utility.
The settlement, filed with the New Hampshire PUC last week, must still be approved by the commission. It is contingent on the Northern Pass transmission line receiving all state and federal permits.
“NPT asks that the commission find … that it would be for the public good for NPT to engage in business in those towns in which it seeks to construct an electric transmission line and associated facilities,” the settlement says.
“We are pleased to have achieved this settlement that establishes the framework for the safe operation and maintenance of Northern Pass under New Hampshire regulations,” said Bill Quinlan of Eversource Energy, NPT’s parent company.
The settlement says the developer has the technical, managerial and financial expertise needed to conduct business in the state.
Also included in the agreement is a commitment from Northern Pass to provide $20 million, allocated from the developer’s Forward NH Fund, for clean energy programs or economic development initiatives approved by the commission.
Despite higher-than-normal temperatures and severe storms, MISO’s grid remained stable over the months of April and May, Senior Manager of Dispatch Steve Swan told the Reliability Subcommittee last week.
Unit commitment was nearly perfect and there were no minimum or maximum generation events, Swan said in presenting the RTO’s monthly operations updates. April’s full report has already been posted, while May’s will be online by June 21.
April’s peak load was 79.5 GW, set on the 26th, while May’s was 95.4 GW, set on the last day of the month.
A 14% jump in natural gas prices at the Henry Hub drove April’s day-ahead energy prices up 16% to $22.49/MWh, but prices remained low because of MISO’s “very strong wind production and low spring-time load levels.”
Despite the uptick, MISO said natural gas costs were still 26% lower in a year-over-year comparison. Henry Hub prices averaged $1.91/MMBtu for April, up from March’s average of $1.67/MMBtu but still lower than the $2.58/MMBtu average a year ago.
Wind turbines produced 4,934 GWh of energy in April, the highest ever for MISO. Wind’s share of MISO electricity production was 10.9%, up from 8.8% in both March 2016 and April 2015.
MISO’s frequency response under a shifting resource mix (pictured in chart) will be the subject of a coordinated issues statement.
Use of coal-fired resources continues to trend downward. Coal supplied 38.9% of April’s total energy, down from 40.5% in March and 48.3% in April 2015.
Gas-fired generation was down slightly to 25.3% in April from 26.5% in March. The number still surpasses April 2015’s 18.4% share.
MISO Wants More Response in Frequency Response
The RSC is concerned about the reliability of MISO’s frequency response under a changing resource mix.
The RTO said changes to the fleet, including the retirement of baseload generation, development of utility-scale wind and solar units and increased demand-side resources, could impact its performance.
MISO adviser Ed Skiba said a coordinated issues statement would be submitted to the Steering Committee for consideration in its issues review process.
“Frequency response is one of our key issues. The main thing is we’re trying to stay ahead of how the world evolves,” RSC Chair Tony Jankowski said.
Skiba said staff has seen “overall improved governor response from the fleet” although there were missing answers in most of the 18 governor surveys returned by balancing authorities.
Results showed the average frequency response of the generation fleet was a -0.35% of capacity/0.1-Hz frequency change. MISO said a figure closer to -1%/0.1 Hz is ideal.
In the near term, Skiba said MISO plans to send an abbreviated survey, requiring a limited amount of data.
Monitor: Changes Needed for Reliability
While the Independent Market Monitor’s State of the Market report for 2015 has not been released yet, Potomac Economics Vice President Michael Wander said the report will show that MISO needs market modifications to support reliability.
“Our State of the Market does reach a conclusion that changes are needed both for reliability and efficiency,” Wander told the RSC. “Our results show a significant amount of generator commitment that is missing is actually being scheduled in the look-ahead process.”
Wander said the appendix’s aggregate data sets will be presented to MISO staff for analysis.
WASHINGTON — The Supreme Court’s recent rulings in three state-federal jurisdictional cases provide only limited guidance for how it might decide future turf disputes, a panel of attorneys agreed in a discussion at the Energy Bar Association’s Annual Meeting last week.
They disagreed, however, over whether the court should be praised for its diffidence.
The panel focused on the court’s April ruling in Hughes v. Talen and its January order in Electric Power Supply Association v. FERC, with mentions of the 2015 ruling in ONEOK v. Learjet.
The court backed FERC’s authority in both of the most recent cases — upholding its jurisdiction over demand response in EPSA and rejecting Maryland’s subsidy of a generator that could have undermined PJM’s FERC-regulated capacity auction.
But FERC General Counsel Max Minzner isn’t letting the victories go to his head. The court’s ruling in Hughes v. Talen was “a very narrow decision,” Minzner said. (See Supreme Court Rejects MD Subsidy for CPV Plant.)
The court unanimously rejected Maryland’s contract-for-differences with a natural gas plant, saying it violated the Constitution’s Supremacy Clause, which establishes that federal law preempts contrary state law (14-614, 14-623).
Minzner said the ruling preserved “a wide range of tools for states to incentivize or affect generation” but found the Maryland program improper because it interfered with FERC’s jurisdiction over wholesale electric markets and could distort price signals in PJM’s annual capacity auctions.
“The court, I think, was clear that a significant number of traditional state activities that could in theory have an impact on the wholesale rate are likely to be preserved after Hughes,” Minzner said. “There was a long discussion at the end [of the opinion] about the range of things the states can do without running afoul of this specific problem.”
Connecticut Assistant Attorney General Clare E. Kindall, who co-authored an amicusbrief in Hughes, said she was “relieved to hear that FERC’s general counsel thinks it’s a narrow ruling.”
“I believe that the Supreme Court did narrow the 4th Circuit’s original holding [against Maryland]. But I also think the Hughes case and this trio of cases is a full employment act for this group [lawyers] for the next 10 years, because I think there will be a lot of litigation over what exactly a state can and cannot do,” she said. “There is a role for FERC and there’s a role for the states. And this room will spend most of the next 10 years drawing those lines.”
Dentons partner Stuart A. Caplan, who moderated the discussion, echoed Kindall’s comments, complaining of “an unsatisfying lack of clarity in the decisions as to the basis of jurisdiction.”
Bancroft partner Erin E. Murphy, a member of Talen’s legal team, agreed that the rulings are “hardly going to put an end to litigation.”
“The court was trying to avoid drawing particularly bright lines or giving a whole lot of guidance. It really had to approach each of the cases as: ‘We’re going to decide precisely what’s before us and not say a whole lot more than that — which isn’t all that unusual for how the court operates, particularly when it’s dealing with an area like this that the court knows it’s not the body with the great expertise.”
Kindall lamented that the rulings did nothing to answer a policy question: “whether markets answer all questions.”
“The markets have done a tremendous good,” she said. “Connecticut is deregulated and [I] was a little offended by the idea that the only way to ensure reliable energy was to reregulate, which was one of the suggestions in Hughes. That struck us as a really wrong tack to take. … The question becomes, if you have a market failure, how do you address it? That will have to be a [discussion] between the federal agencies and state agencies.”
Not Identical
Minzner distinguished between the EPSA ruling, which he said was about the scope of the Federal Power Act, and the other two cases, which deal with “core Constitutional” questions about the meaning of the Supremacy and Commerce clauses.
“Those are related questions but I don’t think they’re identical,” he said.
“I think that was really what was guiding [the court] — and the fact that the states weighed in. They weren’t there saying protect their jurisdiction. … [They] said FERC absolutely should be able to do this as well [as the states]. You can sort of slice and dice all the legal analyses, but I think at the bottom that was what was really going on.”
“We did have a few states on our side too,” Murphy interjected, prompting laughter. But she said she agreed with Kindall’s analysis.
“When you look at the way the court was thinking about it … this is happening in FERC’s market, and how else can we make sure that this happens in FERC’s market if FERC can’t control it? Which is a little bit divorced from a starting principle of: ‘Is it wholesale or retail?’”
Caplan said he believed the Hughes ruling was based on broad “field preemption” grounds — that it was an intrusion into exclusive federal jurisdiction — rather than the narrower “conflict preemption” — that it undermined FERC policy.
“It seemed that the court explicitly declined to consider what the effects on the wholesale market were, which would have been necessary if the courts were applying the conflict preemption,” he said.
Murphy and Minzner agreed that the ruling seemed to be based on field preemption.
Murphy also offered a defense of the court’s refusal to draw bright jurisdictional lines. “While I think it’s frustrating to people who practice to not have this clear guidance from them … I do think that [the court’s] reluctance to provide it is animated by their decision that it’s better to not give totally clear guidance than to mess it all up in an area that they don’t understand as well as all the people in this room do.”
“A refreshing breath of humility,” Caplan quipped.
After allegations of management interference led PJM to replace its internal market monitoring unit with an independent monitor in 2008, FERC had an opportunity to prohibit other RTOs from using the internal structure. Because it chose not to do so, the temptation for RTO officials to muzzle their MMUs remains.
Oversight Committee Chairman Says He Can’t Remember Many Details in Controversy
Third in a Series
By Rich Heidorn Jr.
FERC auditors, who have been examining allegations that SPP officials interfered with the independence of its internal Market Monitoring Unit, effectively ended their audit at the end of April without interviewing a key witness.
That person is Joshua W. Martin III, the chairman of the SPP Board of Directors’ Oversight Committee, which is charged with supervising the unit and protecting its independence.
Former SPP monitors Catherine Tyler Mooney and John Hyatt, who were fired in December, had asked to meet with Martin last September to discuss their frustration with the internal MMU structure and recommend a role for an external monitor. The monitors told Martin that pressure to please RTO management and conform to the positions of membership made it impossible to exercise the independence required by FERC.
SPP Board of Directors’ Oversight Committee Chairman Joshua W. Martin III refused to meet with former monitors Catherine Mooney and John Hyatt when they raised concerns about the independence of the internal Market Monitoring Unit, referring them to Alan McQueen, a target of their complaints, and General Counsel Paul Suskie.
Martin, however, refused to meet with them, telling them to talk instead to General Counsel Paul Suskie and their direct supervisor, MMU Director Alan McQueen, who was the target of some of their complaints.
Hyatt and Mooney say they were terminated for their efforts to exert independence. SPP officials have declined to give a reason for the firings, citing RTO policy not to publicly discuss personnel matters.
FERC announced in February 2015 it was conducting an audit of SPP that included an examination of the MMU’s independence under Order 719 (PA15-6).
Yet the auditors effectively ended their 13-month inquiry without interviewing Martin, the single most important person to the protection of the MMU.
SPP said that FERC auditors conducted an exit interview April 29 with RTO officials, including Suskie and McQueen, at which they outlined their conclusions.
“FERC auditors did not indicate any findings that SPP’s MMU is not independent nor did the auditors indicate that SPP’s MMU should be an external market monitor,” SPP said in a statement. “We do expect FERC to issue recommendations for enhancements to SPP’s MMU similar to those approved [in a revised policy statement on the MMU] by SPP’s Board of Directors in January.”
FERC declined to comment.
Martin said in an interview May 2 that although he met FERC auditors at an Oversight Committee meeting in D.C. last March, “this was not an in-depth session where we were looking at specifics. They were just giving us an indication of the scope of the audit, how it was going to proceed,” he said.
Had it interviewed Martin, FERC would have found a board member seemingly detached from — or forgetful about — many of the details of the controversy surrounding the MMU.
Oversight Committee Role
Mooney
Attachment AG of SPP’s Tariff specifies that “the Market Monitor shall be an organization within SPP reporting to the Board of Directors, excluding any SPP management representatives serving on the Board of Directors.” (Emphasis added.)
The MMU reports in particular to the board’s Oversight Committee, which is composed of three outside directors led by Martin.
Despite the Tariff’s prohibition against “SPP management” having an oversight role, RTO executives were regularly present when McQueen reported to the committee, according to committee minutes reviewed by RTO Insider.
In 2013 and 2014, for example, McQueen’s direct supervisor, Stacy Duckett, vice president and chief compliance officer, usually recorded the minutes as the committee’s secretary.
Duckett died in March 2015 following a long illness. Suskie, who succeeded Duckett as McQueen’s supervisor, also attended meetings as secretary, as did Michael Desselle, vice president and chief compliance and administrative officer.
An SPP organizational chart shows McQueen reported to Duckett and, later, Suskie for “administrative purposes.” Until recently, that included requests to hire new staffers, budget and organizational reviews, and McQueen’s salary and bonus reviews.
Hyatt and Mooney say that when they pushed to oppose a position held by the RTO or members, McQueen often resisted, complaining, “You don’t understand the pressure I’m under.” McQueen declined to say whether he had made the remark. (See Part 1: SPP Squelching MMU Independence, Former Monitors Say.)
How could McQueen tell the Oversight Committee of such pressure when SPP management was present during the meetings? “We’ve been very, very open,” Martin said. “Alan’s communicated with me without management being there — through emails, through voice mail.”
Larry Altenbaumer and Phyllis E. Bernard, the other two members of the committee, declined requests for comment, referring questions to Martin.
Judge, Regulator, CEO
By any measure, Martin is an accomplished figure. A one-time civil rights activist in Camden County, N.J., he studied physics as an undergraduate before becoming a patent attorney for Hercules, a chemical manufacturer. He later served on the Delaware Public Service Commission (1978-1982), including three years as chairman, and became the first African American member of the Delaware Superior Court (1982-1989).
He retired from the bench to become general counsel of Bell Atlantic Delaware, rising to CEO of the company, which was renamed Verizon Delaware (1996-2005).
He has now come full circle. In 2005, he become a partner at Potter Anderson & Corroon, a venerable Wilmington, Del., law firm founded in 1826, whose office is in Hercules Plaza, an office tower that once housed 1,800 Hercules employees. He retired as a partner at the end of 2013 and remains with the firm as counsel.
It was in his seventh-floor office, with a commanding view that reaches New Jersey, that Martin sat down for an hour-long interview with RTO Insider.
Martin, who has been an SPP board member since 2003, forcefully defended his decision not to meet with Hyatt or Mooney and said he agreed with the decision to fire them.
He also insisted he had seen no evidence that the MMU was being pressured by executives to conform with RTO and stakeholder desires on market rules, as the two monitors contend.
But Martin said he was unable to answer numerous questions about the controversy, repeatedly answering with variations of “I don’t know” or “I don’t recall.”
He acknowledged that Potomac Economics — in addition to performing the functions formerly done by Mooney and Hyatt — is also doing an audit of the MMU, but said, “I don’t know the scope.” He also said he did not know when McQueen, whose retirement was announced in January, would be leaving. And he hasn’t seen a job description for McQueen’s replacement.
Below are excerpts from RTO Insider’s interview with Martin.
Martin was asked about the reasoning behind the Oversight Committee’s revised policy statement on the MMU’s independence.
The new statement makes the committee responsible for all salary and bonus decisions for McQueen and other MMU employees and ensured that the MMU director could meet the committee in executive sessions without RTO officials present.
Who was responsible for Alan McQueen’s salary and bonus evaluations [before the revised statement]?
“It would have gone to the board — and then through the administrative process of SPP — and to the board. That’s my assumption.”
You say you assume it went through the board. You’re a member of the board; why wouldn’t you be aware of it?
“I just don’t remember specifically. It wouldn’t have been significant enough for me to have that in my brain. But considering the fact that it had to go somewhere, and it didn’t come through the Oversight Committee specifically like it did this year, my assumption is it would have been in that package of compensation increases for the entire organization.”
And where did that package come from? That would have come from RTO management, right?
“Oh sure, human resources, RTO management, Human Resources Committee — all of that.”
So then is it fair to say that up until this most recent year and this change where the Oversight Committee was involved, that Alan McQueen’s compensation was being determined or recommended, at least, by RTO staff, RTO management?
“As best as I can recall, that would be accurate.”
Was there a realization that that was not compliant with Order 719? Is that why you changed it?
“Not to my knowledge. I don’t know that the issue was ever raised. It wasn’t raised with me.”
Martin went on to suggest that SPP might not have been in violation of Order 719 because the order allows the MMU to report to RTO management for “administrative purposes, such as pension management, payroll and the like.”
Payroll seems to me to be a more ministerial function — like how many deductions do you want taken out [of your paycheck] as opposed to supervision, which is: Are you doing a good job? Should you get a bonus? Should you get a raise this year?
“To be fair about this, assuming that there was some need for clarification on that, that was probably the genesis of the change that was made” regarding compensation.
You say it was probably the genesis, but you were there. You are the chairman of the committee. Wouldn’t you know what the genesis was?
“Well, here’s what I’m trying to distinguish. It wasn’t that we had FERC standing over us saying, ‘You must do this.’ But we looked at the situation concerning the independence of the MMU and we accepted certain changes that would make it clear that they were independent and that was one of them.”
When did those discussions start as to changing the statement?
“Good question. I can’t answer that. I just don’t know specifically when they started.”
What’s your first recollection? Who suggested it?
“I don’t remember that either. I can tell you that those discussions were ongoing in 2015. But I can’t tell you what the initial impetus for that was. It may well have been Alan McQueen who said, ‘I think we need to take a look at how the MMU operates versus the board and the Oversight Committee.’ But I can’t be specific on that. I just don’t remember.”
Martin was asked about the letter Hyatt and Mooney sent him in September.
What do you recall about that?
“What stood out for me more than anything else in that letter was the fact that there was this issue of a contract that they wished. And obviously directors do not negotiate contracts with employees. For that reason, I referred them to staff, specifically to the SPP general counsel, Paul Suskie.” [Editor’s Note: The letter recommends some MMU functions be transferred to an external monitor, which Hyatt and Mooney offered to join. It does not mention the word “contract.”]
The mention of the contract was why you chose not to meet with them? Even to talk about more generic issues?
“That stood out to me more than anything else because I’m very careful about my role as a director. Even though Southwest Power Pool is structured differently from a lot of organizations I’ve been associated with, the last thing you want is directors poking their noses in places where they shouldn’t be poking their nose in — namely operational issues.
“We’re supposed to set policy for the organization. And I felt that what I was being asked to get involved in there was beyond the scope of my role as chairman of the Oversight Committee. So I referred them to Paul Suskie, who … was general counsel and would be able to address whatever issue they wanted to advance.”
They have told me that Alan McQueen, their boss, was … preventing them from acting as independently as they thought the MMU should act. And they say that you telling them to go back and meet with McQueen and Suskie … was not in the spirit of you providing oversight for the independence of the MMU.
“Let me be very clear with you. If the issue were that simple — i.e., if they were coming to me purely to address the question of independence — we would have had a different situation. My analysis of what I was being asked to get involved in went beyond that and therefore I took the position that as a director and as chairman of the Oversight Committee, I should not get involved in that discussion and that’s why I referred them to the general counsel.”
Couldn’t you have bifurcated the discussion? Say I’m not going to talk about contracts or what the solution is but I will talk to you about the problem?
“I never got that far because a quick assessment of what I did would suggest that those issues were so interwoven that a bifurcation wouldn’t be possible.”
Martin was asked about the decision to fire Hyatt and Mooney, which McQueen discussed with the Oversight Committee at its Dec. 7 meeting.
Did the Oversight Committee explicitly approve the firing, or did it just say [to McQueen], ‘We won’t stop you from doing so?’
“My recollection is we acknowledged that what was happening from a human resources perspective was going forward. I don’t believe we approved that. …That’s my best recollection. As I think back on it, I don’t know why we would have to have approved it, because it was a human resource matter, a personnel matter…
“I can’t discuss with you publicly the personnel issues … but we did get a briefing on what Alan intended to do.”
Do you have any misgivings about the decision to terminate them?
“I thought that this was an appropriate decision for management to take. Recognize that as a board member I’m not involved in making that decision. This is not a policy decision. This is a personnel decision and this had worked its way through the various personnel levels. I felt that what was being requested was not unreasonable and I saw no basis for the Oversight Committee to refute what was getting ready to happen. It wasn’t our position to second guess the human resources structure.”
This was McQueen’s decision to fire them, not human resources, right?
“I’m assuming that it worked its way through human resources to make sure that all the T’s were crossed and I’s were dotted. That happens in any organization.”
SPP Headquarters Source: SPP
What is the process at SPP to terminate somebody?
“You’re asking for more detail than I can give you. The best I can do is to tell you this is a human resources function.”
Martin was also asked about the timing of the revised policy statement — which the committee approved Dec. 23, nine days after Hyatt and Mooney were fired — and the announcement of McQueen’s retirement. Martin announced the statement and the retirement at the January board meeting. McQueen, who has been with SPP since 2003, told RTO Insider he was leaving to spend more time with his grandchildren in northern Michigan.
A cynic would say SPP … got rid of the two malcontents but that looked kind of bad — they’re going to say they were fired for trying to assert their independence. ‘We [SPP] disagree with that and to show that that’s not true we’re going to put out this statement.’ But just in case FERC isn’t satisfied with that, Alan McQueen is going to be gone by the end of the year anyway so it’s going to be a moot point when the audit comes out.
[Martin smiles.] “Well, I can understand how somebody could look at all of the facts and extract that conclusion. But without getting into the details of why Alan McQueen elected to retire — and this was his election, let me be very, very clear with you. As a director I certainly am not aware of any desire to push Alan McQueen out. The Oversight Committee of the board has been very, very supportive of Alan and his role with the MMU. That’s a separate issue — his decision to retire.”
Why announce McQueen’s retirement in January when no date certain was given for his departure?
“It was announced at that time because a process had to be initiated for his replacement. That’s obviously going to be a public process.”
OK, but we’re now into May and I’m not aware that you’ve begun that process.
“The process of pursuing a replacement for Alan is not one that I’m directly involved in. That, too, is a staff function. But I wouldn’t assume because you haven’t seen a name emerge that the process isn’t underway.”
You’re saying that RTO management will choose McQueen’s replacement, not the board?
“Well, they’re going to do the mechanics of dealing with advertising the position and all of that. That’s where the process is going to be initiated. Ultimately, and obviously, the board is going to make the decision.”
When will the transition occur?
“Sometime this year. … What I can be clear about is the fact that it is his intention to be there until a replacement is in place. That much I can share with you. I just can’t be more specific.
“This is a very important role. You’ve obviously got to put the right person in that position, and I’m confident knowing that there isn’t going to be a vacuum there.”
What will you be looking for in a replacement for Alan McQueen?
“Really, a continuation of what we have right now. A very competent, talented MMU that’s able to satisfy its almost daily requirements from the FERC for information [and] also satisfy what Southwest Power Pool needs. An MMU that’s comfortable working through the Oversight Committee, which knows that we are available if there are some concerns and what have you.
“I’m looking for the kind of competence and expertise that would parallel the other RTOs and ISOs from around the country.”
Are there certain minimum academic or professional qualifications that you’re looking for?
“I can’t answer that question — simply because I haven’t seen the job description. If you were to ask me specifically do we want someone with a Ph.D. in economics, I don’t know that answer. Obviously Alan [who has a master’s in economics] doesn’t have one. A number of RTO/ISOs across the country do. I just don’t have an answer for that question.”
[Editor’s Note: Editor-in-Chief Rich Heidorn Jr. is a former member of FERC’s Office of Enforcement and participated in a 2008 audit of SPP.]
Former Monitors Dispute SPP Claims over ‘Contract’
Hyatt
Joshua W. Martin III, chairman of the SPP Board of Directors’ Oversight Committee, said he refused to meet with Market Monitors Catherine Tyler Mooney and John Hyatt last year because their letter requesting a meeting included a proposal that the RTO sign a contract with them to set up an external monitor.
SPP General Counsel Paul Suskie said in a statement that Hyatt and Mooney proposed that they would form their own company and that SPP would fund their startup costs and award them a no-bid contract — essentially the arrangement that PJM agreed to with Joe Bowring when he left the RTO’s payroll and founded Monitoring Analytics in 2008. (See Independent Market Monitors Wouldn’t Have It Any Other Way.)
Mooney said it was Suskie and MMU Director Alan McQueen who initiated the discussion of contracts. Although the letter recommends some MMU functions be transferred to an external monitor, which Hyatt and Mooney offered to join, the word contract is not mentioned.
“John and I felt that this was premature. The OC needed to make a policy decision about whether to pursue an external unit first,” she said. “We discussed whether an open request for proposals for an external MMU contract could be conducted in a way that would protect our careers given the retaliation we were experiencing. John and I never ruled out any options. We did not ask for a contract.”
If SPP had chosen an open solicitation, it’s unlikely it would have received many responses. When Texas issued a solicitation last year for monitoring of ERCOT, only incumbent Potomac Economics submitted a bid.
“We had very good jobs [at SPP],” Mooney said. “All we had to do to keep them was to keep our mouths shut. But we felt that was a compromise of our principles. … We felt that would compromise the SPP MMU’s integrity.”
Staff members are recommending that the Maine Public Utilities Commission not approve natural gas pipeline capacity contracts paid for by electric and gas customers.
Opponents of the Northeast Energy Direct pipeline marching in protest. (Source: PopularResistance.org)
An Examiners’ Report released last week said market changes since the price spikes of 2014’s polar vortex make it unlikely electric generators will make commitments for pipeline capacity in an effort to stabilize prices.
“The commission does not find that the market and rule changes to date are likely to alter the fact that the region’s generators do not make long-term commitments for pipeline capacity,” the report said, which is written as a draft order (2014-00071).
Maine’s Energy Cost Reduction Act, passed in 2013, authorized the PUC to execute “energy cost reduction contracts” for 200 million cubic feet of natural gas costing up to $75 million a year, if it found that the contracts would save ratepayers money. The law allows the PUC to administer and resell the pipeline capacity.
The report said that much has changed since the law was passed and that historic low prices for natural gas have removed the urgency felt two years ago.
The report comes two weeks after Kinder Morgan withdrew its application with FERC for the Northeast Energy Direct pipeline through New England, citing a lack of commitments from potential customers and an uncertain regulatory outcome for ratepayer financing.
“Hot on the heels of the recent downfall of Kinder Morgan’s massive pet pipeline project, this is an important victory on the path to stopping the patchwork effort across New England to build a polluting pipeline on the backs of consumers,” pipeline opponent Conservation Law Foundation said in a statement.
“We believe there is a strong case that electricity prices will be lower if the region has more gas pipeline capacity,” Tim Schneider, the state’s public advocate, told the Portland Press Herald. “This is why we supported Maine buying capacity as part of a regional effort. If Maine doesn’t buy capacity, it puts the regional effort at risk.”
Wholesale power costs in CAISO fell sharply last year as lower natural gas prices, increased solar generation and reduced loads more than offset the impact of a steep decline in hydroelectric output, according to a report from the ISO’s Department of Market Monitoring.
Solar output last year surpassed all other forms of renewable generation for the first time since CAISO began operation.
The ISO’s total cost of serving load decreased 31% to $8.3 billion in 2015, compared with $12.1 billion the previous year, the department said. Average wholesale costs dropped to $37/MWh from $52/MWh in 2014.
“Declining gas prices clearly had a role in the decrease,” Keith Collins, CAISO manager of monitoring and reporting, said during a June 7 call to discuss the report.
Collins noted that the 40% decline in California gas costs followed a national trend, with SoCal Citygate and PG&E Citygate prices falling along with the benchmark Henry Hub price. He also pointed out that, controlling for gas prices, CAISO power costs were down only 6% year-over-year, a decrease likely attributable to a sharp rise in output from low-cost solar. Lower congestion and increased virtual supply — which improved convergence between day-ahead and real-time prices — added downward pressure, the department said.
Last year also saw a seemingly contradictory movement between total loads and peak loads, with the former down and the latter up. Collins noted that a September heat wave produced CAISO’s highest annual peak load in five years, up nearly 5% from the 2014 peak.
Total and average load fell slightly for the year, continuing a trend of modest declines since 2012. The department attributed the drop-off to the growth of rooftop solar capacity, which the ISO estimates may have reached 4,000 MW last year.
Grid-connected solar reached a milestone in 2015, surpassing wind to become the largest source of renewable generation in the CAISO system. Solar output increased 38% during the year and accounted for nearly 7% of system energy. Wind output fell slightly, accounting for 5% of total supply. In 2014, solar provided less than 5% of system energy, below wind’s 5.6%.
Geothermal generation also accounted for about 5% of supply, gaining 24% over the previous year. The department attributed the increase to a group of geothermal units formerly outside CAISO’s footprint coming under its control.
In total, non-hydro renewables accounted for 18% of supply — not counting renewable imports — compared with 40% from natural gas and 8% from nuclear. Hydro (5%) and imports (28%) made up the balance.
While NV Energy did not join the CAISO-run Western Energy Imbalance Market (EIM) until the final month of 2015, Collins reiterated the ISO’s observation that the utility’s membership quickly unified what was previously a fractured market. (See NV Energy Has Smooth EIM Integration, CAISO Says.)
“The inclusion of Nevada really changed the dynamic of the market,” Collins said. The increased transfer capacity from NV Energy’s transmission network has significantly improved the link between CAISO and the PacifiCorp East (PACE) balancing area, creating more uniform pricing for imbalance energy, he said.
“We see the optimization creating a one-EIM price for those regions,” Collins said.
Other highlights of the report:
Hydroelectric output dropped for the fourth straight year in the face of extreme drought, falling to one-third the 2011 level. Snowpack in the Sierra Nevada mountains — a natural store for run-of-river hydro operations — was at 3% of normal on May 1, 2015.
Net imports fell 2% from 2014, mostly because of decreased imports from the Southwest. The department said the drop-off likely stemmed from lower price differentials between Southern California and the Palo Verde trading hub in Arizona.
Intervals of negative pricing in Southern California during the second quarter were attributed to combined surpluses of wind and solar generation during a period when outages on the Path 15 transmission line limited flows to the northern part of the state. Negative prices in the 15-minute market occurred in about 4.7% of intervals during that quarter, compared with an average of 2% for the year.
The settlement, filed with the New Hampshire PUC last week, must still be approved by the commission. It is contingent on the Northern Pass transmission line receiving all state and federal permits.
