FERC on Tuesday rejected PJM’s Tariff changes that would have exempted a capacity resource from nonperformance charges if it was following the RTO’s dispatch instructions and operating at an acceptable ramp rate during periods of high load.
The changes, approved in April by the Members Committee after months of stakeholder debate, were designed as an interim solution to guard against generators self-scheduling prior to a performance assessment hour in order to avoid nonperformance charges. Such behavior, PJM said, would pose operational challenges and create reliability issues. (See “MRC, MC Endorse Interim Ramp Rate for Performance Assessment Hours,” PJM Markets and Reliability and Members Committee Briefs.)
“Given the importance of the penalty structure to the Capacity Performance design, we … must carefully weigh whether the operational concerns documented in the record justify the negative impact that PJM’s proposed penalty exemption would have on these performance incentives,” FERC ruled. “We conclude that PJM has not met that burden here” (ER16-1336).
Under PJM’s proposal, resources’ energy offers would include a historical three-month average ramp rate.
The Independent Market Monitor and LS Power said that PJM had not proven its assertion that self-scheduling before an emergency period would cause operational issues.
“According to the Market Monitor, if resource owners self-schedule their resources in anticipation of tight conditions in the energy market, it is less likely that emergency procedures would be triggered and would instead indicate that nonperformance charges are working as intended to incent generation to operate during high-demand conditions,” FERC said.
“The Market Monitor argues that PJM’s proposal is discriminatory and disincents flexibility by holding more flexible resources (i.e., those with faster ramp rates) to a higher standard for expected incremental megawatts during a performance assessment hour than less flexible reserves.”
Calpine and Rockland Capital argued that generators should not be excused from penalties because of their choice of the type of capacity they offer into the market.
The PJM Power Providers Group, the Delaware Public Service Commission and Dayton Power and Light supported PJM’s proposal.
In rejecting the Tariff changes, FERC quoted from PJM’s own initial filing proposing Capacity Performance, which said, “Parameter limits should not be viewed as a permanent entitlement to underperform. Instead, those limits should be exposed to financial and market consequences: If sellers of resources with fewer operating limits earn more from the capacity market … than sellers of resources with more restrictive operating limits, then all sellers will be incented to find ways to minimize those operating limits, which should over time increase overall fleet performance and benefit loads in the region.”
Great Plains Energy, the parent of Kansas City Power and Light, announced Tuesday it would buy Westar Energy for $12.2 billion in a deal that will give Great Plains a customer base of 1.5 million in Kansas and Missouri, nearly 13,000 MW of generation and 10,000 miles of transmission lines.
Great Plains will pay $8.6 billion in cash and stock while also assuming $3.6 billion in Westar debt.
Under the terms of the agreement, Westar shareholders will receive $60/share, consisting of $51 in cash and $9 in Great Plains common stock. Westar closed at $52.92/share on Friday.
Talk of a Westar acquisition has been percolating through the industry for weeks, with Ameren named as one of the potential buyers. Bloomberg reported earlier in the month that an investment group from Canada was also eyeing Westar.
But it was Great Plains that clinched the deal. Great Plains and Westar currently co-own and operate the 1,200-MW Wolf Creek Nuclear Generating Station, as well as the 1,418-MW La Cygne and 2,155-MW Jeffrey coal plants.
“Westar and KCP&L are trusted neighbors and have worked together for generations in Kansas. The combination of our two companies is the best fit for meeting our region’s energy needs,” said Terry Bassham, CEO of Great Plains Energy and KCP&L.
“This is an important transaction for Kansas and our entire region. By combining our two companies, we are keeping ownership local and management responsive to regulators, customers and regional needs, while enhancing our ability to build long-term value for shareholders.”
Bassham said the merger would create efficiencies that would help reduce future rate increases resulting from increasing environmental standards, cybersecurity threats and slow demand growth.
Great Plains, which operates as KCP&L and KCP&L Great Missouri Operations, has been growing. In 2008, it acquired Aquila, an electric utility that operated adjacent to its territory in Missouri. Headquartered in Kansas City, Mo., it has more than 838,000 customers in Missouri and Kansas and owns about 6,446 MW of generation.
Westar, based in Topeka, Kan., has about 700,000 customers in east and east-central Kansas and about 6,267 MW of generation, mostly coal fired.
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 still exists.
First in a Series
By Tom Kleckner and Rich Heidorn Jr.
LITTLE ROCK, Ark. — SPP has interfered with the autonomy of its internal Market Monitoring Unit and FERC should order changes to ensure its independence, according to two former monitors who say they were fired for voicing their concerns.
Catherine Tyler Mooney and John Hyatt, who were fired in December, say they were forced out for resisting pressure to conform to policy positions of SPP management and members.
FERC assigned market monitors a key function in the nation’s wholesale electricity markets, making them responsible for ensuring markets are competitive, efficient and provide residential and business ratepayers with just and reasonable rates. Unchecked by independent, effective monitors, RTO stakeholder processes could shift market risk from generators, increasing their profits at the expense of ratepayers.
Mooney and Hyatt say SPP’s system is fatally compromised and that it should give at least some functions to an external monitor.
External market monitors are the norm, with Virginia-based Potomac Economics keeping tabs on the markets in ERCOT, ISO-NE, MISO and NYISO, and Monitoring Analytics performing the same duties for PJM. Only CAISO and SPP have internal MMUs.
Hyatt, a Ph.D. mathematician, and Mooney, who holds a doctorate in economics, were two of three staffers who reported directly to MMU Director Alan McQueen. They said McQueen told them he faced pressure to follow the policy positions of SPP members and RTO management, and that he proposed concessions to mollify generation owners as a result.
Despite FERC rules prohibiting RTO management from supervising their market monitoring units, SPP management, including CEO Nick Brown and COO Carl Monroe, took part until recently in performance reviews of MMU Director Alan McQueen and helped determine annual performance bonuses for MMU employees. Under SPP’s Tariff, the MMU was to report to the SPP Oversight Committee. But OC Chairman Joshua Martin III refused to meet with former monitors Catherine Mooney and John Hyatt when they raised concerns about the independence of the MMU, referring them to McQueen, the target of their complaints, and General Counsel Paul Suskie.
“Some in SPP’s leadership and membership dreaded the idea of the MMU publicly disagreeing with the RTO before FERC,” Mooney said.
“There were examples where [we were told] to change our stance on an issue because if we didn’t change our stance, the MMU could get shut down. We were told we have to think about people and politics and relationships, to think about preserving the internal MMU.”
Under SPP’s Tariff, the MMU is supposed to report to the Board of Directors’ Oversight Committee, which is composed of three outside directors. But the chairman of the committee refused to meet with the monitors after they wrote him a letter outlining their concerns in September.
In addition, despite FERC rules prohibiting RTO management from supervising their MMUs, SPP management took part until recently in performance reviews of McQueen and in reviewing the bonuses of other MMU employees. Management also attended Oversight Committee meetings with the MMU.
Meanwhile, FERC’s Office of Enforcement, which was aware of the monitors’ allegations, effectively ended an audit of SPP and the MMU in April without interviewing the committee. FERC declined to comment.
The independence concerns raised by Hyatt and Mooney resulted from FERC’s compromises in Order 719, its 2008 rule spelling out MMUs’ duties and their relationships with their RTOs (RM07-19, AD07-7). The commission rejected protections urged by some stakeholders, allowing RTOs to choose their structures and declining to provide job security protections for MMU employees. (See related story, Order 719: FERC Balanced MMU Independence Against RTO Autonomy.)
McQueen declined to say why Hyatt and Mooney were terminated, adding it is the “MMU’s policy not to publicly discuss human resource matters.” He said “they were not fired because the market monitor is not independent.”
Joshua W. Martin III, chairman of the Oversight Committee, said he refused to meet with the monitors because their letter, which outlined the problems with the internal monitoring function, proposed an external monitoring function that they offered to join.
“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,” said Martin, who says he supported the monitors’ firing.
Mooney and Hyatt said they proposed an external monitor to solve the problems they experienced, not out of any desire to increase their incomes. They said it was SPP officials who initiated the discussion of a contract; the letter does not mention the word.
“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 were not acting in our own self-interest.”
The two monitors agreed to tell their stories after resettling in suburban Philadelphia, where they have joined the staff of PJM’s Independent Market Monitor, Monitoring Analytics. They told RTO Insider that they hope going public with their concerns will lead to improvements at SPP.
“I really like this work,” Mooney said. “I think it’s really important, and I would like to see something good come of what happened to us.”
“I think what we’re showing is that the internal market monitor framework has some really big problems with it,” Hyatt said.
Echoes of PJM Monitoring Flap
Mooney and Hyatt’s departure from SPP recalls Monitoring Analytics’ own formation in 2007, when founder Joe Bowring — then a PJM employee — complained to FERC that his reports were being censored by then-CEO Phil Harris.
“You cannot do your job as a market monitor if you’re not independent, if you’re not free to criticize the RTO and its members, if you’re told to pull your punches,” Bowring said in a recent interview. “I am amazed [SPP] had the chutzpah to do this — fire the two best monitors they have. We’re very fortunate to have hired them.”
“I don’t know how we would do this job effectively if we weren’t independent,” agreed Potomac Economics President David Patton.
McQueen insisted in an interview that he has had no problems maintaining the MMU’s independence despite its place within SPP.
SPP Headquarters Source: WER Architects
“That’s demonstrated by our record,” he said in an interview at SPP headquarters, citing the MMU’s three filings opposing SPP positions last year. “We oppose the RTO. We oppose the Board of Directors. That’s our right and that’s our responsibility to do that when we determine it’s appropriate.”
Oversight Committee Chairman Martin also defended the MMU’s independence, saying it has taken positions contrary to RTO staff and stakeholders both in FERC filings and stakeholder meetings.
But Mooney said that, until recently, the MMU dropped any opposition once an issue left the stakeholder meetings, failing to inform FERC when it disagreed with an SPP Tariff filing, as required by FERC Order 719.
Days after the firing of Hyatt and Mooney, the Oversight Committee adopted a revised statement on the MMU’s independence, which included two substantive policy changes: It made the committee responsible for all salary and bonus decisions for McQueen and other MMU employees and ensured that the MMU director could meet with the committee in executive sessions without RTO officials present. The statement also reiterated its choice of the internal market monitoring structure.
Martin announced the statement at January’s board meeting, adding that McQueen will retire by the end of the year.
SPP acknowledged that until the revised policy statement in January, CEO Nick Brown, COO Carl Monroe and SPP’s other officers had reviewed performance compensation bonuses for all RTO employees, including the MMU.
Spokesman Dustin B. Smith said the review of bonuses is separate from the annual performance reviews, which he said McQueen performed for MMU employees.
“Performance compensation, or annual bonuses, are given in the first quarter of each year based upon the prior year’s successes,” Smith said. “Nick, Carl and the other officers would only have reviewed these employees’ payout amounts in the context of their impact on the overall performance compensation budget. During this process, Nick and Carl did not change substantive performance compensation payouts as recommended by the director of the MMU.”
“We believe that SPP has been in compliance with Order 719,” Smith said, adding that the revised policy statement was “not to bring SPP into compliance with Order 719 but to further insulate MMU employees.”
Martin acknowledged that Hyatt and Mooney’s complaints and the FERC audit contributed to the decision to revise the statement.
“We were very attuned to the fact that SPP is under a magnifying glass in terms of … the independence of its MMU structure,” he said in an interview at his law office in Wilmington, Del. “I don’t want my answer to lead you to believe that what Catherine and John said made us generate this statement that came out in January. I know that that would not be accurate. But by the same token, obviously the concerns that they were expressing were one of the factors that were playing out in this process.”
FERC spelled out its rules on the structure and independence of market monitors in Order 719 in 2008. It allowed internal market monitors, external monitors and hybrid structures using both.
“Order 719 was a vast improvement and important, but … this is evidence that the RTO can still put a lot of pressure on the market monitor,” Hyatt said. “I would hope [that FERC takes] another look at whether this purely internal market monitor system really does work.”
Members of SPP’s MMU, which typically carries a staff of about 12, work alongside members of SPP’s market design, transmission congestion rights, internal audit and communications departments at the RTO’s headquarters in Little Rock. In the open seating, conversations two or three rows away can easily be heard. [SPP has also used outside consultants, including Monitoring Analytics, Potomac Economics and D.C.-based Boston Pacific.]
Joining SPP
Hyatt, who has a doctorate in applied mathematics and a master’s in economics, came to SPP from Arkansas’ Public Service Commission in 2008.
In about September 2014, he was promoted from supervisor to principal market monitor. He led the work on the RTO’s first annual State of the Market report and a study on frequently constrained areas. He also designed the mitigation plan for SPP’s energy and ancillary services markets.
Mooney joined SPP in 2011 from the University of Oklahoma, where she was an assistant professor of economics. She has a doctorate and master’s degree in economics and worked before graduate school as an economic consultant for Hagler Bailly and PA Consulting Group, where she focused on utility merger and anti-trust filings.
The SPP job was a homecoming for Mooney, who grew up in Little Rock. “I thought SPP was a great place for someone like me to analyze the industry and market power issues from an independent perspective,” she said. “And I could go home. It was a dream come true to me.”
But Mooney said she began to have concerns with the structure of the MMU immediately after joining the RTO.
At first, things appeared to be going well. Mooney received SPP’s President’s Award in December 2013 for helping launch the Integrated Marketplace, which gave the RTO a day-ahead market, a real-time balancing market, transmission congestion rights and a centralized balancing authority. About a year later, she was promoted to a position as a manager and lead market monitor, responsible for investigations, special studies and market-design issues.
With her promotion, Mooney became one of three who directly reported to McQueen, along with Hyatt and Barbara Stroope, a Ph.D. sociologist who is manager of market monitoring. Stroope, who joined the MMU seven years ago, remains with the MMU and sat in on RTO Insider’s interview with McQueen.
McQueen, who has a bachelor’s degree in environmental science and a master’s in economics, joined SPP in 2003 as a market analyst after 20 years at American Electric Power and Central and South West Corp.
SPP organizational chart, dated March 1, 2011 shows MMU Director Alan McQueen reporting to SPP’s vice president and chief compliance officer, in apparent violation of FERC Order 719.
He was hired by Richard Dillon, SPP’s director of market design, and worked under him when Dillon oversaw both the market monitoring and market design functions. In about March 2011, following FERC Order 719, the market monitoring function was moved from Dillon’s operation, with McQueen reporting to Stacy Duckett, then vice president and chief compliance officer.
SPP’s MMU staff is required to abide not only by Order 719 but also the RTO’s bylaws, which state among their “values and principles” that SPP is “a relationship-based organization” employing “member-driven processes.”
“It’s a member-friendly organization, and I felt SPP wants the MMU to be a part of that,” Mooney said.
The message starts at the top of the organization, the former monitors say, with CEO Nick Brown’s quarterly staff meetings, at which he stresses the need for SPP staff and stakeholders to reach “consensus” on contentious issues. Brown declined to comment, referring questions to Oversight Committee Chairman Martin.
‘You don’t understand the pressure I’m under.’
Hyatt and Mooney said McQueen, in turn, pressured them to compromise their positions in order to minimize conflicts with SPP management and stakeholders.
In 2013, for example, they said SPP management blocked them from asking FERC to reconsider changes to rules regarding physical withholding and uneconomic production because of fears they might delay SPP from the promised March 2014 start of the Integrated Marketplace. SPP boasted in a press release that it was the first RTO “to design, build and deliver a Day 2 market on time.”
After the market opened in 2014, Hyatt said, McQueen proposed a change that would have essentially increased generators’ make-whole payments by 25% — an effort, he said, to pacify generators upset by how the MMU was calculating cost-based offers.
“There was really no economic justification for this,” said Hyatt, who said he and Mooney were able to block the change. “It seemed to me that the MMU was expected to make some sort of significant concession … to appease the market participants.
“I never held the position that the policy was perfect,” he said. “But I do hold firmly to the belief that the general construct of the mitigation policy is sound, and I repeatedly disagreed with the concessions that the MMU director was pushing.
“Alan would say on many occasions, ‘You don’t understand the pressure I’m under,’” Hyatt said.
McQueen declined to say whether he had made such a comment.
“We all live under pressure,” he said. “The Market Monitor … we disagree with all different levels of the stakeholder process. If you don’t disagree with different groups at various times, then you’re probably not doing your job.”
McQueen added that he takes input from all sides before taking a position. “I listen to all sides, but I listen most to what [the MMU] staff has to say, and that’s absolutely where the primary position comes from in everything that the Market Monitor does.”
Mooney, however, said that until late 2014, the MMU was not fulfilling its responsibility to notify FERC when it disagreed with RTO filings. It began to change only when MMU management believed FERC wanted the MMU to become more vocal, Mooney said.
FERC Audit
It’s unclear how much of this FERC auditors knew when they arrived in Little Rock in March 2015. The commission has regularly looked over the MMU’s shoulder, however.
Following an audit in 2008, FERC ordered SPP to appoint an independent director for its NERC-deputized Regional Entity. The commission said an SPP officer was improperly wearing two hats — serving as an RTO official and overseeing the RE, which is supposed to police SPP’s compliance with NERC reliability standards (PA08-2, AD09-3).
In late 2013, members of FERC’s Division of Analytics and Surveillance traveled to Little Rock for a briefing on metrics, screens and dashboards the MMU was developing in preparation for the day-ahead market start-up.
In its audit initiation letter in late February 2015, FERC Enforcement said that, in addition to evaluating SPP’s compliance with the MMU rules in Order 719, it would be evaluating SPP’s obligations under its Open Access Transmission Tariff, the implementation of its Integrated Marketplace and compliance with commission accounting regulations and reporting requirements (PA15-6).
Over the next several months, according to Oversight Committee minutes, FERC auditors conducted weekly or biweekly conference calls with the MMU. FERC sought briefings on stakeholder activities regarding proposed changes to the SPP mitigation rules, the MMU told the committee. By September, FERC had issued three sets of data requests and broadened its questions to “all aspects of the Integrated Marketplace,” including “special studies, market efficiency, market anomalies, market participant [involvement] in new markets, Market Working Group issues and market screen results,” the MMU said.
The Beginning of the End
Mooney and Hyatt said they felt that the FERC audit presented an opportunity to address the MMU’s lack of independence. They also believed speaking up could jeopardize their careers at SPP.
For more than a year before the auditors arrived, Mooney said she had been told that some in SPP management disliked her independence.
In early 2014, Mooney said she was told by Hyatt — then her supervisor — that in the performance evaluation for her bonus, COO Carl Monroe had expressed concern that she was taking policy advice from the PJM Market Monitor. Monitoring Analytics has provided SPP technical assistance, including data collection and development of rules for cost-based offers, since 2012.
“SPP’s displeasure was apparent among staff, and [John and I] were not alone in the fear that it could lead to one or both of our eventual terminations,” Mooney said.
In September 2014, Mooney says, she succumbed to the pressure. At McQueen’s direction, she said, she advocated market design changes regarding mitigated offers “with the goal of appeasing SPP members’ complaints taking precedence over supporting an efficient market” (ER15-2268).
“This was a turning point for me,” she said. “I did not like being put in that position.”
Mooney said she began to fear being fired in about December 2014.
A later SPP organizational chart, dated Jan. 1, 2015 adds the Oversight Committee and describes the relationship with SPP management “for administrative purposes,” the limitation FERC imposed in the order.
“RTO and MMU staff would come to me, behind closed doors, to tell me that SPP was unhappy with the fact that I would not back down from MMU positions when under pressure from the RTO and members,” Mooney said. “Sometimes they would tell me how much they respected what I was doing, but that they would understand if I backed down out of fear that I might lose my job.”
As the FERC auditors asked more questions during 2015, that fear grew. “We received our first negative performance evaluations in August 2015” — just after FERC’s auditors announced they wanted private meetings with the two, they said.
Hyatt said McQueen told him in his review that he needed improvement in “teamwork” and that he was “not interested in developing a consensus.”
His review occurred two days before he met with FERC auditors, Hyatt said. Although McQueen was not present for that interview, an attorney for the MMU was and confirmed he would be reporting to McQueen on what was said.
As a result, Hyatt said, he was reluctant to discuss his concerns with the auditors. He said he was more forthcoming after FERC requested yet another conversation — this time without the MMU lawyer.
Letter to Oversight Committee
In September 2015, Mooney and Hyatt wrote a letter to the Oversight Committee outlining their concerns and proposing a hybrid structure, with an independent monitor.
Martin declined to meet with Mooney and Hyatt, instead telling them to discuss their concerns with McQueen and his superior, Executive Vice President and General Counsel Paul Suskie. The monitors had what Hyatt called a “fairly cordial” meeting with McQueen and Suskie. But the monitors said the account of the meeting that Suskie and McQueen later wrote was inaccurate and incomplete.
At a second meeting with the two, Hyatt said, Suskie stated that, as SPP general counsel, he was acting as counsel for the Oversight Committee. Hyatt said he found Suskie’s role “confusing.”
“I had been encouraged to take issues to the Oversight Committee, and the one time I did go to the Oversight Committee with a concern, they dispatched the RTO general counsel and executive vice president to represent them in discussions on the issue.”
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.
Suskie said a no-bid contract would violate SPP’s purchasing policies. “When asked whether this contract should be competitively solicited, Mooney and Hyatt said that SPP’s failure to award them a contract could constitute retaliation for their statements to FERC staff,” Suskie said in a comment. “SPP estimates that such a contract would have amounted to a multi-million-dollar, no-bid contract for Mooney and Hyatt, which SPP’s board refused to consider.”
Mooney said it was Suskie and McQueen who initiated the discussion of contracts. “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 more than a couple of responses. Market monitoring requires an analytical infrastructure that few firms possess, and many of those that do would be prevented from bidding because they consult for market participants. When Texas issued a solicitation last year for monitoring of ERCOT, only incumbent Potomac Economics submitted a bid.
Firing
At its Dec. 7 meeting, the Oversight Committee went into an executive session that included discussion of “MMU matters.” Executive sessions are typically called to discuss legal or personnel issues. In this case, Hyatt and Mooney were on the agenda.
McQueen confirmed that he informed the committee of his intention to fire Hyatt and Mooney but would not say if the committee formally voted to endorse the terminations.
Martin said the decision to fire Hyatt and Mooney was made by McQueen and SPP’s human resources department. “I thought that this was an appropriate decision for management to take,” he said. “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 and 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.”
A week later, the two monitors were called separately to human resources and fired within minutes of each other.
Both were told they had violated SPP’s Code of Conduct, but they say they were given no details of the allegations. McQueen told Mooney he had “lost faith” in her judgment, she said.
When Mooney filed an application for unemployment with Arkansas, she reported to the state Department of Workforce Services that she had been discharged “for alleged violation of company rules or policies.” The department approved her compensation, however, reporting, “Insufficient evidence has been presented by the employer to establish misconduct.”
SPP spokesman Smith said the RTO “does not comment on human resource matters.”
“In keeping with this policy, SPP did not report anything to the Arkansas Department of Workforce Services regarding the reasons for Mooney’s termination,” he continued. “Likewise, although SPP was given the opportunity to object to Mooney’s unemployment application, SPP chose not to do so.”
Revised Policy Statement
On Dec. 23, nine days after Hyatt and Mooney’s firing, the committee adopted a revised position statement on the MMU’s independence, which had last been updated in 2012.
The statement reiterated SPP’s choice of an internal monitor, saying “an internal MMU provides both an appropriate level of independence and the level and depth of expertise needed to perform its functions and does so at a more economical cost than an external contractor.”
“In addition,” the statement says, “the Oversight Committee believes that an internal MMU provides the tailored focus and overall consistency that would be more difficult to achieve with an external contractor.”
The statement did make two substantive changes.
In contrast with prior practice, the MMU will be able to meet with the Oversight Committee without RTO management present. The new statement says that “to maintain confidential communication between the MMU and the Oversight Committee, a member of the MMU staff will be designated as a staff secretary for MMU purposes.”
It adds, however, that “RTO staff may attend such executive sessions at the mutual consent of the Oversight Committee and the MMU director.”
The statement also makes the committee responsible for determining salary and bonus compensation for McQueen and his unit.
The committee shared its statement with the Board of Directors at the board’s Jan. 26 meeting. “It’s a step beyond where we’ve been in the past,” Martin said. “We wanted to be as clear as we can that the MMU is an independent entity.”
Mooney said the revised policy statement “reflects changes that are being put in place as a result of our concerns, concerns that the MMU leadership was unwilling to raise. … These changes notwithstanding, the MMU will not be independent as long it is subject to a member-driven RTO culture, instead of its own independent, market-driven principles.”
Hyatt says that the MMU should be the voice of the market. “If no one says what a true, efficient market is, then no one is going to get that market.”
Retirement Unrelated
Martin also announced at the January board meeting that McQueen would be retiring by the end of the year. McQueen said his decision to retire was driven by a desire to spend more time with his grandchildren in northern Michigan and had nothing to do with the conflicts in the MMU. No date has been set for his departure.
“I have never been limited in any of my positions or felt any pressure to do anything other than what my department has decided to do,” he said.
Are Mooney and Hyatt lying when they say otherwise?
“I’m not going to get into that,” he responded. “You know, that’s something for them to decide, not me.”
Mooney and Hyatt say they believe McQueen was conflicted.
McQueen “could have quieted us more than he did,” Mooney added. “He seemed uncomfortable, but I believe he felt that we were generally right.”
Mooney and Hyatt are happy to have landed new positions at Monitoring Analytics. The job change, however, meant Mooney’s and Hyatt’s children won’t often get to see their extended families in Arkansas. The firing was “heartbreaking for my family,” she said.
[Editor’s Note: SPP/ERCOT Correspondent Tom Kleckner worked as an SPP spokesman from 2011 to 2015; Editor-in-chief Rich Heidorn Jr. participated in the 2008 audit of SPP as a member of FERC’s Office of Enforcement.]
PJM members approved a charter for the Seasonal Capacity Resource Senior Task Force last week, but not before a long discussion in which some voiced concern over its potential to undermine the new Capacity Performance product.
The Markets and Reliability Committee passed the motion with 68% of a sector-weighted vote.
The charter stemmed from a problem statement and issue charge that also passed with 68% approval in February to study how seasonal resources could be incorporated into Capacity Performance. (See “Seasonal Resources in the Capacity Market to be Studied,” PJM Markets and Reliability Briefs.)
Katie Guerry of EnerNOC introduced the issue after no aggregated seasonal resources offered into the first Base Residual Auction involving Capacity Performance last August. One aggregated resource offered into this month’s BRA, but Stu Bresler, PJM senior vice president of markets, said he did not know whether it cleared.
In the last two auctions, PJM required 80% of the capacity procured to meet Capacity Performance standards. The market goes to 100% Capacity Performance resources in the next BRA, for the 2020/21 delivery year.
Since the endorsement of the problem statement and issue charge, the task force has added a work activity: to analyze alternatives to requiring 100% Capacity Performance resources, including the development of stand-alone sub-annual products.
Contrary to FERC Order?
Those opposed to the charter worried that the task force’s deliverables might run afoul of FERC’s ruling allowing Capacity Performance.
David “Scarp” Scarpignato of Calpine said his company did not want to move forward with the effort.
“We understand that PJM wants to give people the ability to truly offer aggregated resources,” Scarp said. “We do appreciate that anyone who can meet the CP requirements should be able to bid in. But this goes contrary to a very recent FERC order.”
Jason Barker of Exelon said the desired timeline to study the issue and recommend changes “seems strained at best.” Any modifications to planning parameters would have to approved by the first week of February for next year’s BRA.
Bresler echoed Barker’s concern. “I recommend restricting the talk to things that might be attainable,” he said. “You’re really going to have to focus your discussion on something that’s manageable.”
Aggregation not an Option
Dan Griffiths, executive director of the Consumer Advocates of the PJM States, said that when FERC ruled, it didn’t know that aggregated products would not be offering into the BRA or subsequent transitional auctions.
“The longer we go, the clearer we will see that’s not an option that works for seasonal capacity resources,” he said. “The notion that we shouldn’t do something because we’re changing the model I think is inconsistent in that we’ve been changing the model since it was created.”
Gregory Carmean, executive director of the Organization of PJM States, said that the challenges to seasonal resources participating in the market is an unintended consequence from the “rushed” Capacity Performance model.
Capacity Performance, he said, “was designed only to meet one objective: reliability. There are other aspects of competitive markets that can be affected. … It behooves PJM to at least study these options. If we move forward, and these things fall by the wayside, I don’t think PJM will be doing its part to foster competitive markets that meet the needs of the public.”
The MRC also approved a problem statement and issue charge to study the challenges associated with capacity resources subject to pseudo-tie requirements. (See “Study of Pseudo-Tie Standards for External CP Deferred,” PJM Markets and Reliability Committee Briefs.)
The issue had been postponed a month after members asked staff to narrow the scope of the proposal.
The work will be assigned to the Underperformance Risk Management Senior Task Force, which will be asked to devise recommendations addressing “equal opportunity based on deliverability” and “existing or new challenges to currently approved pseudo-tie resources.”
The task force will be expected to present their findings to the MRC in August or September for implementation in the 2017 BRA.
The motion passed with one “no” vote and zero abstentions.
Joining others in raising the alarm, NERC released a short-term special assessment last week that highlighted the reliability risks created by increased dependence on natural gas for electricity generation.
Aliso Canyon Relief Well Source: Southern California Gas
The report focused on the four regions with gas-fired generation penetration of more than 40%: New England, New York, ERCOT and California. It found that most regions, while potentially at risk if a major supply interruption occurs during a period with exceptionally high load, are prepared to address it with contingency plans and alternative pipeline routes.
The lone exception was the Southern California region, where the shutdown of the Aliso Canyon storage facility earlier this year is straining the system. NERC reiterated warnings that the Los Angeles area could be at risk for outages for the next year. (See Aliso Canyon Gas Restrictions Cloud CAISO Summer Outlook.)
NERC recommended that it and the Western Electricity Coordinating Council convene a meeting with industry stakeholders to identify reliability impacts and develop mitigation strategies.
18-Month Forecast
NERC compared generation expected to be unavailable with forecasted loads over the next 18 months to identify potential times when demand might outstrip supply. The report then analyzed the region’s infrastructure and planning to determine the likelihood of service disruptions.
The assessment pointed out that supply disruptions are possible in both the winter, when gas is needed for heating, and the summer, when air conditioning increases electric demand. Greater coordination between the natural gas and electric industries would help mitigate those risks, the report said.
The report recommended continuing to account for reliability risks from extreme weather events and large-scale supply disruptions and enhancing coordination during supply shortages. It also recommended two strategies ISO-NE and PJM have encouraged through new capacity market rules: dual-fuel generators and firm gas-delivery contracts.
Iberdrola Renewables last week struck back at a FERC judge’s April ruling that could subject the company to more than $370 million in penalties over an electricity contract signed with California near the end of the Western Energy Crisis.
In a brief on exceptions filed with FERC on May 27, the Spanish energy giant contends that Administrative Law Judge Steven Glazer’s initial decision “contradicts” a landmark Supreme Court ruling, “undermines” commission precedent and “ignores” the commission’s directive when the case was sent to the judge (EL02-62-006, EL02-60-007).
“The [initial decision’s] misapplication of [the Supreme Court decision in] Morgan Stanley reflects a results-driven approach that permeates the entire opinion,” Iberdrola wrote.
Iberdrola’s filing attempts to poke holes in the complex legal reasoning underpinning Glazer’s ruling, which relied on the application of the Mobile-Sierra rule “as reinterpreted by Morgan Stanley.” In addition to finding that the contract imposed an excessive “down the line” burden on California residents based on an examination of comparable marginal production costs, Glazer also reinstated the company as a party to the proceeding following a previous dismissal. (See FERC ALJ: Shell, Iberdrola Owe California $1.1B over Energy Crisis.)
Iberdrola is contesting both findings, arguing first that FERC should once again dismiss any claims against the company and — barring that — asking the commission to uphold the company’s contract rates as “just and reasonable.”
Shell also Responds
Shell North America, which Glazer said imposed an “excess burden” of $779 million on California consumers, submitted a brief contesting the judge’s ruling that Mobile-Sierra protections were both “avoided” and “overcome” in the company’s contract with CDWR. Glazer based that determination on the finding that Shell traders manipulated the spot market through practices such as false exporting, false load scheduling and “anomalous” bidding strategies — all designed to drive up market clearing prices.
The company — like Iberdrola — contended that its contract did not impose an excessive burden on California consumers, saying that “even the most pessimistic economic assessment credited by the [initial decision]” showed the agreement added no more than 9 cents to the average $75 residential bill in the state.
Shell also attempted to root its appeal to the commission in FERC’s historical support for market-based rates and the Mobile-Sierra presumption of the “integrity of contracts.” The company argued that CDWR “carefully evaluated” the company’s proposal before signing, and that the weighted average price of the contract “sat well below the commission’s own just-and-reasonable benchmark.”
“Rejecting the [initial decision] is therefore essential to the continued viability of the commission’s market-based-rate program and, more generally, of the country’s energy markets,” Shell said.
[Editor’s Note: An earlier version of this story incorrectly reported that Shell had not filed a brief before the May 27 deadline.]
2006 Acquisition
Iberdrola’s connection to the energy crisis-era case is a complicated one. In 2006, the company acquired Scottish Power, previously the parent of Portland-based utility PacifiCorp. During the previous year, Scottish Power had sold PacifiCorp to Warren Buffet’s MidAmerican Energy Holdings but retained ownership of merchant affiliate PacifiCorp Power Marketing (PPM), which was absorbed by Iberdrola — renamed Avangrid in February 2016 — in the 2006 buyout.
As the energy crisis abated in summer 2001, PPM signed a long-term tolling agreement with the California Department of Water Resources (CDWR) to ensure power supplies to constrained areas in the northern part of the state. Capacity would be supplied by PPM’s gas-fired Klamath Falls plant in southern Oregon.
| Dr. Richard E. Goldberg via FERC
By that time, the department had assumed the role of electricity buyer of last resort after widespread manipulation drove Pacific Gas and Electric and the now-defunct California Power Exchange into bankruptcy. The state’s other two investor-owned utilities (IOUs) teetered on the brink of insolvency because of soaring wholesale power costs.
After the crisis passed, the California Public Utilities Commission initiated proceedings to recover the state’s costs for sustaining operation of the IOUs. Shell Energy North America and Iberdrola are the only suppliers involved that have not settled with the state or renegotiated the terms of their contracts, which expired in 2011 and 2012. The ALJ’s April decision also determined that Shell’s long-term agreement saddled California consumers with an “excess burden” of $779 million.
Novel Interpretation
Glazer’s decision to overturn the companies’ agreements with CDWR was rooted in a novel interpretation of Mobile-Sierra, the Supreme Court doctrine that holds that bilateral energy contracts can be voided only when shown to adversely affect the public interest.
In 2003, FERC ruled that it was not in the public interest to break the contracts, a decision that California appealed to the 9th Circuit Court of Appeals. A 2008 Supreme Court decision in Morgan Stanley Capital Group Inc. v. Public Utility District No. 1 of Snohomish County ultimately boosted the state’s prospects for cost recovery. That decision required the commission to apply an additional standard to Mobile-Sierra, testing whether the terms of a contract were the result of market manipulation.
Glazer’s decision against Shell rested on evidence that the company manipulated spot electricity prices during the crisis employing many of the same strategies as Enron, practices that directly influenced the forward prices forming the basis for the company’s CDWR contract. For that reason, Shell’s contract “avoided” Mobile-Sierra protections as reinterpreted through Morgan Stanley.
While Glazer determined that Iberdrola — then PPM — had engaged in its own manipulation during the crisis, he also found that CDWR had not relied on forward prices to negotiate the contract, as the department by that time no longer found forward price curves to provide a reliable benchmark for setting prices. Still, the ALJ decided the Mobile-Sierra doctrine was “overcome” because of the long-term costs of the contract carried by California, which was forced to issue bonds to fund the capacity purchases.
Iberdrola Reinstatement
Key to Glazer’s ruling was the decision to reinstate Iberdrola as a party to the proceeding. The company had been previously dismissed from the case largely because its contract was signed July 6, 2001, two weeks after FERC imposed price caps across the state, ending the crisis. Glazer reasoned that, regardless of the signing date, the contract was still negotiated during the height of the crisis, which resulted in rates far exceeding those even in September of that year.
Iberdrola’s rebuttal takes up the issue of the contract date as evidence of what it called the flawed reasoning behind the ALJ’s decision. The company contends that it is “undisputed” that the energy crisis ended with FERC’s June 19, 2001, order instituting price caps and that “spot market volatility had ended and forward prices had largely returned to pre-crisis levels” by early July.
“Yet, so as to sweep up the Iberdrola contract into the group of energy crisis contracts that should be abrogated for no reason other than the timing of their execution, the [initial decision] pronounces that the energy crisis ran through July 6, 2001,” Iberdrola wrote.
‘Peanut Buttering’ Analogy
The company also contests Glazer’s use of a “fundamentals-based” price standard that calculates the “excessive burden” on California consumers by comparing the contracts pricing with assumed marginal costs of production.
“In so doing, the [initial decision] contradicts Morgan Stanley, which holds that ‘a presumption of validity that disappears when the rate is above marginal cost is no presumption of validity at all, but a reinstitution of cost-based rates,’” Iberdrola said.
Iberdrola further contends that the ALJ — and the California complainants — failed to provide convincing evidence for how the contract constituted an “excessive burden” on California consumers through increased electricity rates, an explicit requirement of FERC’s order on remand. The company objected to Glazer’s adoption of Commissioner Mike Florio’s “peanut buttering” analogy, which says that a burden analysis that focuses on consumer rates spreads costs too thinly.
“But, of course, the question of whether a rate impact on individual consumers is excessively burdensome is the very inquiry that Morgan Stanley requires, and that the commission has evaluated in each of the cases on remand post-Morgan Stanley,” the company countered.
Having provided that context, Iberdrola noted that its contract produced an average rate impact of 5 cents/month for residential customers of PG&E. FERC had previously ruled that a 27-cent impact wasn’t excessive.
Still, Iberdrola’s strongest appeal to the commission might be an argument that moves from the specific to the general, contending that the ALJ’s reliance on a marginal cost test undermines FERC’s “historic market-based rate program.”
“[U]nless the commission intends to alter the nature of the energy industry, marginal cost simply cannot be where the commission draws the line in determining whether an excessive burden exists,” Iberdrola said.
CPUC Weighs In
The California PUC filed its own brief with FERC largely supporting the ALJ’s ruling and the conclusion that Shell and Iberdrola overcharged the state by more than $1 billion through the energy crisis contracts. The brief did contest a handful of other conclusions, however, including the finding that Mobile-Sierra protections were “overcome” rather than “avoided” in the case of the Iberdrola contract. The agency contended that PPM’s manipulation “altered the playing field for the Iberdrola contract negotiations such that the Mobile-Sierra presumption is avoided.”
“Still, the initial decision sent a powerful message that anti-competitive and manipulative behavior that imposes an undue burden on consumers will not be tolerated,” the PUC said.
Briefs opposing exceptions must be submitted to FERC by June 27.
Kinder Morgan formally withdrew its application for the Northeast Energy Direct natural gas pipeline in a filing with FERC (CP16-21).
Tennessee Gas Pipeline, a Kinder Morgan subsidiary, in April suspended development of the $3.3 billion project that would have brought 1.3 million dekatherms per day into the New York-New England power markets from Pennsylvania. (See Kinder Morgan Board Suspends Work on Northeast Energy Direct Pipeline.) It cited a lack of customers and low natural gas prices.
“Tennessee provides notice of its withdrawal of the application in this proceeding,” the company wrote to FERC, with no further explanation.
Talen Energy gave notice that it will pull out of its operator role at the Colstrip coal-fired power plant in Montana by May 2018. The Pennsylvania-based merchant generating company co-owns the plant near Billings, part of the fleet it inherited from its predecessor, PPL.
Talen notified the other owners of the plant that its role as operator of the giant complex is “not economically viable” and that they should start seeking a new operator. “This decision is part of Talen Energy’s overall strategy to conclude our business operations in the state,” said Todd Martin, the company spokesman. Talen is obligated to give two years’ notice.
The other owners are Avista, Puget Sound Energy, Portland General Electric, PacifiCorp and NorthWestern Energy. Unlike the plant’s other shareholders, Talen is an unregulated entity and unable to recover costs related to the plant.
The Tennessee Valley Authority’s Watts Bar Unit 2 went critical last week, the first new nuclear reactor to achieve a self-sustaining nuclear reaction in 20 years. When it comes online and is synchronized to the grid, it will bring 1,411 MW of generation to the region.
The plant’s $4.7 billion cost is far less than another new reactor in the wings, Southern Co.’s Plant Vogtle in Georgia, which has an estimated $14 billion price tag. Construction of Watts Bar began nearly 30 years ago.
Ameren Illinois Touts Savings Secured Through Auction
Ameren Illinois is touting the lower prices it secured in April during MISO’s annual capacity auction. The company said its 2016 $72/MW-day capacity prices — compared with $150/MW-day in last year’s auction — will translate into a $1.75/month savings for the average utility customer.
“This year’s capacity planning auction resulted in a much more equitable distribution of charges for customers in the MISO footprint,” said Richard J. Mark, president of Ameren Illinois.
However, watchdog group Citizens Utility Board said more can be done to lower costs, including purchasing electricity at off-peak times. “Nobody thinks their electric bills are low, so we’ve got a lot more to do to fix the Illinois electricity market,” said CUB spokesman Jim Chilsen.
Invenergy to Build 25-MW Solar Plant on Long Island
Invenergy announced that it will build a 25-MW solar facility on the grounds of Long Island’s former Tallgrass Golf Course in Brookhaven.
The Long Island Power Authority will buy the output, the company said. The plant, to be called the Shoreham Solar Commons project, still needs the approvals of the New York attorney general’s office and the state comptroller, according to a company spokeswoman. Construction is expected to begin in October.
Lincoln Electric Accelerates Local Transmission Project
Lincoln Electric System, the public utility serving Nebraska’s capital city, is accelerating the timeline for a $17.7 million transmission line and substation that will help meet increasing electric demands. The SPP member plans to complete its Southeast Reliability Project in in 2018, two years earlier than planned.
LES held three open houses for the project last year and is now expediting the project to stay ahead of continuing development in the area, LES representatives said during the monthly meeting of the utility’s board.
The project includes construction of three substations and a 7.5-mile-long 115-kV overhead transmission line, as well as the relocation of a 345-kV line that will follow the same route.
Chinese American Subsidiary Acquires Texas Wind Farm
China’s Xinjiang Goldwind Science & Technology says its American subsidiary, Goldwind Americas, has signed an agreement with Renewable Energy Systems Americas to acquire the 160-MW Rattlesnake Wind Project in West Texas.
Goldwind says the Rattlesnake project will be its largest U.S. wind project once it is operational.
Located approximately 125 miles northwest of Austin, the project will use 64 Goldwind 2.5-MW permanent magnet direct-drive wind turbines. According to Goldwind, the development represents the first phase of an expected 300-MW wind project, which will be constructed under a balance-of-plant agreement by RES.
North Dakota researchers and regional energy companies are asking the state’s Lignite Research Council for $3.5 million to continue research on what the industry considers a promising carbon-capture technology.
Energy & Environmental Research Center, Basin Electric Power Cooperative, 8 Rivers and ALLETE say the funds are needed for further lab testing and pre-planning for a synthetic gas-fired pilot plant using the Allam Cycle system for lignite coal. The Allam Cycle, invented by 8 Rivers, uses pressurized carbon dioxide rather than steam to generate power more efficiently, cheaply and cleanly.
A $140 million, 50-MW natural gas-fired Allam Cycle pilot power plant in Texas will start up in 2017. If the technology is proven to work with natural gas, the lignite coal industry is hopeful the system and processes can be adapted to handle gasified lignite.
The owner of the 33-MW Glen Park hydro facility near Watertown, N.Y., says it has a prospective buyer for the plant.
Calgary-based Veresen did not identify the prospective buyer, but it expects to close the $61 million transaction by the end of September, pending FERC approval.
Veresen, previously known as Fort Chicago Energy Partners, acquired the facility in 2010 for $80.1 million.
Caithness II Plant Proponents Urge PSEG, LIPA to Deal
Proponents of Caithness II, a proposed 750-MW natural gas-fired power plant, are calling for PSEG Long Island and the Long Island Power Authority to enter into power purchase agreements with the plant. Caithness Energy already operates a 350-MW plant in Yaphank on Long Island and sells the output to PSEG and LIPA.
PSEG hasn’t committed to Caithness II and questions the need for it. But local elected officials and others say the area is served by outdated, inefficient plants that should be replaced.
“Caithness II will help offset Long Island’s reliance on aging power plants that are inefficient and costly,” said Brookhaven Councilman Kevin LaValle. “Brookhaven and the entire region stands to prosper greatly from a modernized electric power supply, and this project brings us closer to the goal of providing Long Island ratepayers with more affordable and reliable energy.”
Fluor Says Brunswick County Generating Station Complete
Fluor, the primary contractor for Dominion Resources’ Brunswick County Power Station in Virginia, said that it has completed constructing the 1,358-MW natural gas-fired plant. Final testing will be needed before it goes into operation.
Fluor is now scheduled to begin construction of another Dominion project, the 1,600-MW gas-fired Greensville County generating station, which will be located 7 miles from Brunswick Station.
Duke Energy has signed a deal with pork producers in North Carolina to use captured methane to run two power stations.
Methane from the Smithfield Foods farms in the Kenansville area will be captured by Optima KV, converted to pipeline-quality fuel and transported to the H.F. Lee and Sutton power plants. Optima has a 15-year contract with Duke.
Duke in March joined in a similar project with Carbon Cycle Energy to capture manure gas to fuel four of its plants in the state.
Union, Talen Offer Conflicting Reports on Job Losses
Talen Energy plans to eliminate 125 union jobs at three Pennsylvania power plants, according to the International Brotherhood of Electrical Workers 1600.
A Talen spokesman, however, disputed the report and would confirm only job cuts at the Susquehanna nuclear plant. The other two plants slated for job losses, according to the union, are the Brunner Island and Montour coal-fired facilities.
The company and the union cited the depressed cost of electricity as a driver in the restructuring.
Public Service Electric and Gas this year has deployed $2.7 billion in infrastructure improvements that it said will help it meet summer demand.
“Equipment has been replaced, facilities upgraded and additional redundancies added systemwide in order to maintain reliability,” said John Latka, vice president of electric and gas operations.
The summer peak is expected to hit 10,090 MW, compared with last year’s peak of 9,579 MW, set July 20.
The Utah Supreme Court last week voted to uphold a $130.7 million jury award against PacifiCorp and its lawyers for violating trade secrets when the company constructed a power plant similar to a nearby facility being built by Dallas-based USA Power.
In bringing the suit in 2005, USA Power argued that PacifiCorp — parent of Utah’s Rocky Mountain Power — had copied the plans for the air-cooled, gas-fired Spring Canyon plant, which was designed to limit impact on the local environment. PacifiCorp had previously entered negotiations to buy the plant, but it later backed out and constructed a similar unit a mile away.
After a five-week trial in 2012, a jury awarded USA Power $18.2 million in damages for stealing trade secrets and $112.5 million in damages because PacifiCorp unjustly profited from the theft.
A long-awaited bill introduced in the Massachusetts House of Representatives last week that would ease the path for Canadian hydropower and offshore wind into the state and New England electricity markets was criticized by both clean energy advocates and power generators.
Daniel-Johnson Dam and Manic Generating Station Source: Hydro-Quebec
The bill calls for power distribution companies and the state Department of Energy Resources to procure 1,200 MW of offshore wind and 9,450 GWh of hydropower annually by June 30, 2017. The contracts would last between 15 and 20 years.
Gov. Charlie Baker called the proposal “a very strong bill that’s built around the idea of expanding our portfolio, diversifying our energy sources and incorporating big slugs of hydro and wind into our portfolio here in Massachusetts and across New England.” (See Baker: Hydropower Contracts Best Way to Lower Costs.)
The bill isn’t as comprehensive as many stakeholders had hoped for, lacking provisions for solar, nuclear power, energy efficiency or other technologies. An extension of the solar net metering cap earlier this year was the only significant issue addressed this session. (See Massachusetts Raises Net Metering Cap, Cuts Payments.)
The New England Power Generators Association said the bill interferes with market mechanisms that had delivered lower-cost power.
“The proposal would carve up one-third of the Massachusetts electricity marketplace into decades-long contracts that have the potential to dramatically increase electricity costs for consumers,” NEPGA president Dan Dolan said in a statement.
Some environmental advocates see the bill as weighted too heavily toward hydropower. “The Massachusetts House deserves full credit for recognizing the urgent need to address our state’s energy future. However, this bill is not strong enough,” said Caitlin Peale Sloan, a staff attorney for the Conservation Law Foundation. “We need to take bold action to counter climate change and that means choosing the cleanest energy that we can. Wind is one of the cleanest energy sources — cleaner than imported hydropower.”
A coalition of offshore wind developers said the bill begins a new era for the state.
“Offshore Wind Massachusetts looks forward to continuing to work with the House and Senate to fashion a final bill that will enable Massachusetts to make use of one of its greatest resources — abundant and reliable wind that will power a new industry and benefit our citizens for the rest of this century and beyond,” said Matthew A. Morrissey, its managing director.
The bill would exclude the Cape Wind project in Nantucket Sound by limiting eligible offshore wind projects to those in a “competitively solicited federal lease area” south of Massachusetts and Rhode Island. The project, once expected to be the country’s first offshore wind farm, has struggled to obtain financing.
MISO’s Advisory Committee last week settled on five priorities for 2016 after adding an obligation to “improve coordination across market and non-market seams” under the seams optimization priority.
In approving the priorities, the committee also called for:
Improving operational coordination when dealing with federal regulations such as the Clean Power Plan;
A focus on price formation under the grid technology advancement priority; and
Refinement of the competitive transmission development process under the infrastructure development enablement priority.
The changes were made in response to recommendations from MISO sectors. (See “AC to Finalize Priority-Setting for May Vote,” MISO Advisory Committee Briefs.)
Advisory Committee Chair Audrey Penner noted that the priorities would be revisited during the committee’s October strategic session. “I want to remind folks that … we will review this again,” she said. “It’s meant to be a reiterative, back-and-forth document.”
With priorities set for this year, work on 2017 begins immediately. Penner said the committee should focus on deciding if this year’s priorities have a shelf life that can continue into 2017 or if they should be reworked.
Committee Retires Stakeholder Governance Working Group
The committee retired the Stakeholder Governance Working Group after the group concluded modifications on the governance guide.
Vice Chair Tia Elliott said the Steering Committee will absorb the group’s responsibilities, and task teams could be formed to deal with more specific issues involving the governance guide. Outstanding governance issues could also be addressed at the annual stakeholder workshop.
Elliot said an “expertise safety net” already exists in the Steering Committee with MISO liaison Eric Stephens, who is able to assist with the governance guide and data requests from the recently retired Data Transparency Working Group.
Gary Mathis, representing the Transmission-Dependent Utilities sector, said more work is needed on stakeholder redesign implementation and that task teams are not the ideal venue.
“The Stakeholder Governance Working Group doesn’t meet very often, it’s efficient, has a chair and vice chair and, unlike a task team, follows the governance guide,” Mathis said.
He said the decision to retire the working group should rest with its parent entity, the Steering Committee.
Dynegy’s Mark Volpe said he has viewed the working group as a “transitional body” since February, when it first dodged retirement through an Advisory Committee motion. (See “Stakeholder Governance Working Group Sidesteps Retirement,” MISO Advisory Committee Briefs.) Elliott said the committee retained the right to retire the group.
AUSTIN, Texas — ERCOT members last week voted down the ISO’s attempt to salvage a revision request that would have replaced several ancillary services with four new products.
The nodal protocol revision request (NPRR), rejected earlier in the month by the Protocol Revision Subcommittee, was shot down again when the Technical Advisory Committee upheld the subcommittee vote by a 23-3 margin Thursday.
NPRR 667 would have improved regulation service and replaced non-spinning reserve and responsive reserve service with a combination of four new services: fast-frequency response, primary frequency response, contingency reserve and supplemental reserve.
However, staff was unable to convince stakeholders the revisions were ready for prime time. Speaking for the subcommittee, Luminant’s Amanda Frazier said ERCOT did not demonstrate a current or future reliability need for the services and did not adequately address their costs and funding.
“What I heard from PRS members is [ERCOT has] exceptional performance from a reliability perspective,” said Frazier, the subcommittee’s chair. “It has consistently improved over time, so even though we’ve seen growth of intermittent resources over the last decade — exponential growth — we also see performance that is improving.”
Frazier said stakeholders also had concerns over market liquidity for the new services and would prefer to see ERCOT focused on identifying reliability needs and alternatives to NPRR 667. “ERCOT has expressed a preference for a vote on 667 before examining alternatives,” Frazier said. (See “NOGGR Tabled, Other Revision Requests Approved,” ERCOT Technical Advisory Committee Briefs.)
“ERCOT doesn’t do this very often,” said Dan Woodfin, the ISO’s director of system planning, of the appeal by staff. “I can’t recall [something like] this in my 13 to 14 years here.”
Woodfin based his case to the TAC on ERCOT’s changing resource mix since the ancillary service framework was built. Whereas ERCOT was 75% reliant on coal- and gas-steam energy in the late 1990s, half the current resource mix comes from gas turbines, combined cycles and renewables.
He said the current bundled framework will keep more expensive generation online, extend negative price periods and curtail less expensive resources, resulting in increased ancillary service prices and higher overall costs — especially with an increase in high-wind, low-load periods.
Ancillary service “was designed around the characteristics of those steam boilers,” he said. “We have a whole lot of new resources … that has changed both the needs and the ability of different resources to provide those services. We’re expecting the resource mix to continue to change. We’re seeing some pretty tremendous changes on wind in the system … solar is growing exponentially.
“[ERCOT’s current] ancillary service requirements … provide a barrier to entry to new types of resources that don’t have inherent characteristics of the old steam boilers.”
“We don’t want to maintain barriers of entry for any technology,” said Frazier in questioning the benefit of ERCOT’s proposed changes. “It seems expensive to invest millions of dollars for new technology that would only bring in 200 MW.”
Frazier said several market participants (MPs) believed ERCOT’s estimated impact analysis of $12 million to $15 million was too low. She also acknowledged “the good work done in the last several years to think through the future resource mix.”
“We think there are also many MPs that believe there are incremental changes that can be made to the ancillary service suite that can deliver the value Dan mentioned,” Frazier said.
ERCOT was unfazed by losing its appeal of NPRR 667, which was first filed in November 2014 after a year of stakeholder discussions. Spokesperson Robbie Searcy said the ISO will continue its work with stakeholders to plan for future ancillary service needs.
“ERCOT continues to believe the concepts set forth in” the NPRR, she said. “As grid characteristics evolve, it is important that we are planning ahead to ensure we have appropriate market tools in place to maintain system frequency and overall reliability.”
“We don’t want to maintain barriers of entry for any technology,” said Frazier in questioning the benefit of ERCOT’s proposed changes. “It seems expensive to invest millions of dollars for new technology that would only bring in 200 MW.”