Entergy on Thursday said it will continue to operate the Palisades nuclear plant until early 2022 under the terms of its original agreement with Consumers Energy, representing an about-face for the companies after they announced last winter they planned to terminate the arrangement.
The two companies now say they will honor the terms of their 15-year power purchase agreement, which will keep the Michigan nuclear unit running until April 2022. The companies signed the deal in 2007 after Entergy paid Consumers parent CMS Energy $380 million for the plant.
Palisades plant | Entergy
Charlie Arnone, Entergy’s top official at Palisades, said last week’s ruling from the Michigan Public Service Commission factored heavily into the decision to terminate the buyout of the PPA. The Sept. 22 order (U-18250) permitted Consumers to issue securitization bonds for just $142 million of the $184.6 million in qualified costs needed to buy out the PPA. Consumers planned to make a one-time, $172 million payment to Entergy.
The PSC said Consumers’ substitute capacity plan was not solid enough to grant the requested funds, and customer savings as a result of exiting the PPA wouldn’t be as significant as the company had estimated.
“Having certainty around the replacement portfolio is integral to the commission’s determination on whether a regulatory asset should be granted because it will ultimately affect electric reliability and whether savings will be achieved,” the PSC wrote in its decision. “Accordingly, the replacement portfolio is the underpinning of the commission’s evaluation and approach to the regulatory asset determination.”
The PSC pointed out that major components of Consumers’ plan — which included the purchase of a gas-fired plant and the expansion of the 60-MW Filer City coal plant in Michigan — “are either not near the conclusion of the regulatory process or, in the case of the gas plant purchase, have not yet been filed,” even at the “tail-end” of a seven-month proceeding.
Consumers spokeswoman Katelyn Carey said the decision not to pursue a 2018 Palisades shutdown was made after careful review by both parties.
“Moving ahead under the terms of our current Palisades’ power purchase agreement through 2022 is the best path forward. We appreciate the thoughtful, deliberate approach by all parties during the process and remain committed to delivering affordable, reliable, safe and clean energy to our customers across Michigan,” Carey said in a statement.
Entergy last December announced it would close Palisades on Oct. 1, 2018, citing unfavorable market conditions for nuclear generation and more economic alternatives. (See Entergy, Consumers Announce Closure of Palisades Nuke.)
In a press release Thursday, the company said that it “remains committed to its strategy of exiting the merchant nuclear power business.”
“We greatly appreciate the continued patience of our employees and the local community in Southwest Michigan throughout this regulatory process, and we will continue to focus on the plant’s safe and reliable operations,” Arnone said. “Entergy will continue to make all necessary investments and maintain appropriate staffing, in accordance with strict licensing standards.”
Local media outlet MLive reported that some of Palisades’ 600 employees celebrated the news.
Entergy said it expects to free up $100 million to $150 million in cash flow through keeping the PPA in place. Revoking the termination also enables the company to amortize and depreciate refueling outage costs and capital expenditures, with those cost to be included in operational results, rather than incurred as expenses.
As recently as late July, officials from the Nuclear Regulatory Commission were attending citizen meetings on Palisades’ decommissioning process, with some nearby residents concerned about on-site storage of radioactive materials. NRC said that a reserve account for Palisades contained $425 million to cover the potentially 60-year decommissioning process.
During a February earnings call, Consumers CEO Patti Poppe said CMS would improve its financial position by terminating the Palisades nuclear plant PPA in favor of employing more energy efficiency, demand response, renewable power and coal-to-gas switching. She added that Consumers’ substitute capacity plan for the “above-market” PPA would have replaced a single, big-bet capital project with many smaller options carrying less risk, and that CMS could replace other PPAs by building its own plants.
MISO’s proposed multiyear evaluation on the future impact of integrating renewable energy will consist of 10 separate studies, with each focused on projected grid conditions at steadily increasing levels of renewable penetration.
But the RTO’s sweeping approach is drawing mixed reactions from stakeholders.
MISO policy studies engineer Jordan Bakke said the evaluation will first model current renewable penetration — about 8% of the resource mix. It will then examine growing system complexity in increments of 10% renewable resource penetration, concluding with an RTO system powered 100% by renewable sources.
Existing renewables in MISO footprint | MISO
At each 10% checkpoint, MISO will assess systemwide ramping capability, operating reserves, transmission congestion, voltage and frequency stability, and loss-of-load expectation, among other data.
“Between some milestones, the system complexity might not increase much, but at other points, it could increase a lot — and those are our inflection points,” Bakke said during a Sept. 27 Planning Advisory Committee meeting. “We currently don’t know where these inflection points lie.”
The evaluation will attempt to identify when the growth of renewables and the retirement of baseload units require changes in the structure or operation of the system, something MISO has not attempted to answer until now, Bakke said. (See MISO to Conduct Long-Term Renewable Integration Study.) It also aims to predict:
How and when system reliability will be impacted by heavy renewable output;
Whether there are limits to the amount of wind and solar generation MISO can support;
How long until energy storage becomes a requirement;
What parts of the grid will be stressed first; and
How much renewable energy can be deployed before substantial system changes are needed.
The study will also explore what solutions will best mitigate system stressors, Bakke said, whether they be new transmission lines or buses, energy storage, better dispatch availability, demand response measures or better coordination efforts.
Bakke said he would return to later PAC meetings to discuss what MISO has discovered at each study milestone. The study doesn’t have a definitive end date, but Bakke said MISO would likely examine the effectiveness of continuing the study after a year.
Wind on the Wires’ Natalie McIntire said the study may not be “helpful or accurate” given that MISO has not yet reached a 10% renewable penetration and will take several years to achieve a 50%. Transmission could look very different by then, she noted.
“We’ve seen a lot come on in a relatively short amount of time,” countered Bakke, adding that MISO is especially interested in studying the system at a 30-60% renewable penetration, which may become a reality.
Other stakeholders pointed to the high number of renewable projects lined up in MISO’s interconnection queue, which could quadruple wind capacity in some parts of the footprint.
“We started out calling this a breakpoint study,” said MISO Director of Planning Jeff Webb. “If the systems breaks here, what do you do to fix it? And if it breaks here, what do you do to fix it?”
Some stakeholders said the study seems like a high-risk, low-reward endeavor, considering that advances in renewable technologies could solve their own shortcomings by then. Others suggested that generation and transmission owners might question the relevance of study results going out to 2050.
“We’re asking what things do we need to care about in 10 years, and what things do we have to care about in 30 years,” Bakke explained.
Xcel Energy’s Drew Siebenaler said that the study could yield a “holistic look” at renewables and system capability. “We fully support this effort as long as it takes,” he added.
NEW YORK — New York’s Reforming the Energy Vision initiative aims to fulfill a twofold objective, according to the state’s top energy official: attract the capital needed to integrate renewable energy into the grid while simultaneously motivating utilities to work with clean energy startups instead of treating them like enemies.
“Everything has to change,” New York State Chairman of Energy and Finance Richard L. Kauffman said Tuesday at Greentech Media’s New York REV Future 2017 conference in Brooklyn.
Government is changing too, the state’s first “energy czar” said. While state agencies “used to just do one-time grants,” they are now working to develop sustainable business models for the electricity sector.
REV Changing the Role of the Utility
Kauffman said he sees “green shoots of change” as evidence of New York’s evolving energy framework, such as Consolidated Edison’s Brooklyn-Queens Demand Management program (BQDM), a $200 million effort designed to defer infrastructure spending through energy efficiency, distributed energy resources and demand response. (See NYPSC Extends Con Ed Demand Program.)
“Its non-wires requirement — that was a big deal and that has spread to Central Hudson … and we’re close to National Grid — thousands of rate cases,” he said.
And while the solar industry has shown a profound change in its willingness to engage with state agencies, utilities have “a real struggle to figure out how to be partners [with DER providers] instead of competitors.”
But integration of DER will be key to the evolution of the grid, he said.
“There’s no question that storage has to be a critical part of the system, which is getting peakier and peakier. Yet the value of storage is not adequately captured yet,” Kauffman said. “Utilities procure power, but up to now have not had any financial incentive to reduce peak power purchases.”
Moderating a panel on REV policy, Greentech’s Katherine Tweed asked where to draw the line to mark the right mix of energy resources: “BQDM is the greatest experiment in the world … but people say Con Edison’s going to build that substation when they need it.”
Con Ed Vice President for Distributed Resource Integration Matt Ketschke said, “Most DER doesn’t line up with Con Edison because most of it is not in the business of power generation. … Our real goal is ultimately to eliminate the need for those substations.”
Theatrical Disruption
Three protesters from the New York Energy Democracy Alliance disrupted Kauffman’s talk with a bit of guerrilla theater to highlight the difficulty they say some 800,000 low-income people in the state have paying their energy bills under REV.
The skit began when a man several rows from the stage stood up and identified himself as a renter having trouble paying his utility bills.
After he had asked Kauffman how REV would address the concerns of “low-income communities of color,” two women on either side of the man stood up, pretending to be Kauffman’s security guards.
“Silence!” shouted the women, who wore capes reading “REV = Not Your Business” and “REV = Not a Democracy.”
“This is not the place for the complaints of the working class.”
They went on to bow at Kauffman, a former Goldman Sachs banker, mocking him as the “all-powerful energy czar.”
They finished their skit within a couple minutes — escorting the man out of the conference room before the real security could arrive — and exited to scattered audience applause.
Kauffman took the disruption with humor, saying he was “well aware that accountability is key and that well more than 800,000 New Yorkers have trouble paying their electric bills.”
The electric power system “is financially inefficient as well as energy-inefficient,” Kauffman said.
“So, guilty as charged — I do have a financial background,” he said. But Kauffman said that background only motivates people inside the industry to make the system more efficient.
‘Where Policy Meets Reality’
Nilda Mesa, director of urban sustainability and equity planning at Columbia University’s Urban Design Lab, opened the conference by saying that energy efficiency should be treated like a renewable resource “because the greenest electron is the one that’s not used.” Eventually, “financing people can start to understand the engineering language,” she said.
Scott Weiner, deputy for markets and innovation at the New York Department of Public Service, pointed to the challenge of shifting “from a paradigm of net metering to more market-based uncertainty that exists through the value of DER methodology,” particularly for the solar sector.
“But the industry has stepped up,” he said.
Financing is key to the transformation of the grid, Weiner said: “If I could take out my magic REV wand, I’d like to see the investment community, the people who provide project financing, more directly engaged.”
Todd Glass, energy lawyer with Wilson Sonsini Goodrich & Rosati, asked how project financiers could judge utilities, considering the wide spread between various utilities’ cost of service estimates. Weiner said, “Figuring out the marginal cost of service can be hard to do; that’s where policy meets reality.”
Energy Secretary Rick Perry on Friday ordered FERC to rescue at-risk nuclear and coal generation in deregulated states by ensuring they receive “full recovery” of their costs.
Perry’s extraordinary Notice of Proposed Rulemaking, invoked under Section 403 of the Department of Energy Organization Act, requires FERC to complete a final rule within 60 days after publication of the NOPR in the Federal Register.
Separately, DOE announced it had conditionally approved a $3.7 billion increase in the federal loan guarantees for the over-budget and behind-schedule Vogtle nuclear project. Georgia Power and its partners, Oglethorpe Power and the Municipal Electric Authority of Georgia, had previously received guarantees of $8.3 billion to support construction of Vogtle Units 3 and 4.
Spent nuclear fuel pool | Simone Ramella via Wikimedia Commons
In a letter to FERC, Perry cited coal and nuclear retirement statistics and DOE staff’s recommendations in the grid study it released in August. The study said FERC “should expedite its efforts with states, RTO/ISOs and other stakeholders to improve energy price formation in centrally organized wholesale electricity markets” to ensure “baseload” coal and nuclear generators receive compensation for their “resilience” to fuel supply disruptions. (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
Coal generators typically keep 60 to 90 days of fuel at plant sites; operators of nuclear plants refuel every 18 to 24 months.
60 Days to Act
“Now that a quorum has been restored at the commission, I am confident that the commission will act in an expeditious manner to address this urgent issue,” Perry said his letter. “To that end, in the enclosed NOPR, I direct the commission to consider and complete final action on the rule proposed therein within 60 days from the date of the publication of the NOPR in the Federal Register. As an alternative, I urge the commission to issue the proposed rule as an interim final rule, effective immediately, with provision for later modifications after consideration of public comments.”
Perry said the final rule should take effect within 30 days of publication in the Federal Register and that each RTO and ISO submit a compliance filing within 15 days of the effective date of the rule.
Perry began his letter by invoking President Trump’s campaign slogan, saying “America’s greatness depends on a reliable, resilient electric grid powered by an ‘all of the above’ mix of generation resources.”
The secretary went on to cite the 2014 polar vortex, Superstorm Sandy and Hurricanes Harvey, Irma and Maria as evidence that “much more work needs to be done to preserve these fuel-secure generation resources” to ensure sufficient power, “voltage support, frequency services, operating reserves and reactive power.”
“Distorted price signals in the commission-approved organized markets have resulted in under-valuation of grid reliability and resiliency benefits provided by traditional baseload resources, such as coal and nuclear,” he said. “The rule will ensure that each eligible reliability and resiliency resource will recover its fully allocated costs and thereby continue to provide the energy security on which our nation relies.”
Polar Vortex
When PJM lost as much as 22% of its generating capacity to forced outages during the polar vortex, Perry noted, the RTO needed generation from coal plants scheduled for retirement to prevent rolling blackouts, with American Electric Power reporting that it deployed 89% of its coal units scheduled for retirement. Nuclear plants, he noted, had an average capacity factor of 95% during the crisis. He did not mention that some coal plants also were unable to operate because of frozen coal piles and other problems.
Lignite coal conveyor at plant | FEECO International
Perry cited DOE’s January 2017 Quadrennial Energy Review, which reported that 37 GW of coal capacity retired between 2010 and 2015, more than half of all generation retirements during the period. The report predicted coal would also represent half of the 34.4 GW of retirements projected between 2016 and 2020, with natural gas plants (30%) and nuclear (15%) making up most of the remainder.
The secretary quoted NERC’s warning that “premature retirements of fuel-secure baseload generating stations reduces resilience to fuel supply disruptions.” Unmentioned was that NERC’s most recent State of Reliability report concluded “bulk power system reliability remained … adequate” in 2016, repeating the group’s findings from 2013–2015.
At a 2013 technical conference, FERC stopped short of NERC’s warning, saying that the shift in generation from coal toward gas and renewables “may result in future reliability and operational needs that are different than those of the past.” (See Capacity Market Attracts Praise, Criticism at FERC.)
“The fundamental challenge of maintaining a resilient electric grid has not been sufficiently addressed by the commission or the commission-approved ISOs and RTOs, and the lack of a quorum at the commission has undoubtedly thwarted the issuance of rules,” Perry continued in his letter. “But the continued loss of baseload generation with on-site fuel supplies, such as coal and nuclear, must be stopped. These generation resources are necessary to maintain the resiliency of the electric grid. Failure to act expeditiously would be unjust, unreasonable and contrary to the public interest.”
Asked for comment, FERC spokeswoman Mary O’Driscoll said only, “We have received the proposal and are reviewing it.”
DOE’s proposed rule would require RTOs and ISOs to implement market rules that allow the generators with a minimum 90-day fuel supply on site “full recovery of costs.”
“These resources must be compliant with all applicable environmental regulations and are not subject to cost-of-service rate regulation by any state or local authority,” Perry said. “The rule requires the organized markets to establish just and reasonable rate tariffs for the full recovery of costs and a fair rate of return.”
Analysts at ClearView Energy Partners said Perry’s action makes it likely that some method of compensating “essential reliability services” (ERS) could be in place in RTO markets by next spring, “although we caution that it may differ from the NOPR and reflect substantive variations across regions.” NERC has described ERS as including frequency and voltage support, and ramping capability.
“In our view, DOE has placed the essential reliability services issue at the top of FERC’s near-term electric agenda (even though we thought FERC might be leaning that way anyway). We also believe this rulemaking pushes consideration of the non-peak pricing proposal sketched out by PJM and other general price formation rulemakings aside between now and December, at least, should FERC hit DOE’s aggressive timeline.”
Industry Reaction
Predictably, Perry’s order sparked widely divergent reactions.
Maria Korsnick, CEO of the Nuclear Energy Institute, praised what she called Perry’s “decisive … remarkable action,” which she said addresses two “fundamental problems” in the electric sector.
“One is markets that fail to value everything that is important to our electricity system. … Our pricing system is badly broken and … is based almost entirely on short-term price. As a result, nuclear reactors, which provide benefits that everyone agrees we need, find themselves struggling to survive when the nation needs them most,” she said.
“The other problem is that electricity is essential to modern life but only gets noticed if the electricity fails to flow, as has happened most recently in Texas, Florida and Puerto Rico. It is taken for granted, and it does not command the attention it needs from policymakers all across the nation. This course needs to change.”
“We commend Secretary Perry for initiating a rulemaking by FERC that will finally value the on-site fuel security provided by the coal fleet,” said Paul Bailey, CEO of the American Coalition for Clean Coal Electricity. “The coal fleet has large stockpiles of coal that help to ensure grid resilience and reliability. We look forward to working with FERC and grid operators to quickly adopt long overdue market reforms that value the coal fleet.”
The American Wind Energy Association said Perry’s proposal “would upend competitive markets that save consumers billions of dollars a year.”
“The best way to guarantee a resilient and reliable electric grid is through market-based compensation for performance, not guaranteed payments for some, based on a government-prescribed definition,” said Amy Farrell, AWEA’s senior vice president for government and public affairs.
“This looks like federal cost-of-service regulation, and a major retreat from competition in electricity,” said Rob Gramlich, a consultant who worked for AWEA for several years after serving as an aide for former FERC Chairman Pat Wood III.
Mary Anne Hitt, director of the Sierra Club’s Beyond Coal campaign, said the NOPR ignores FERC’s role as an independent agency.
“The Federal Power Act clearly states that FERC cannot favor one energy source over others in its rulemakings, and Perry’s ask — without evidence or common sense — seeks to prop up dangerous coal and nuclear plants that can no longer compete in the wholesale market,” she said. “We are prepared to take to court any illegal rule that props up dirty fossil fuel plants or weakens clean energy’s market access.”
Graham Richard, CEO of Advanced Energy Economy, said FERC should reject what he called a “Perry Energy Tax” on consumers.
“Simply put, this proposed rule has something for everyone to dislike. If you’re a believer in competition and free markets, this rule would insert the federal government squarely into the middle of market decisions. If you are driven by keeping energy costs low, this rule would impose higher energy costs on consumers for no tangible benefit by forcing electricity customers to pay to keep uneconomic power plants in operation,” Richard said. “Finally, if you are driven by innovation and technology, this rule purposefully puts a thumb on the scale for existing, century-old technology at the expense of modern advanced energy that is currently winning based on price and performance.”
RTO Response
ISO-NE spokesman Matthew Kakley said the RTO was reviewing the NOPR while it completes work on a fuel security study. “New England’s wholesale markets have been competitive and brought forward the resources necessary for reliable operations. With the region’s resource mix evolving, ISO New England is conducting an operational analysis of fuel security risks under a range of potential resource scenarios, and we plan to release the study results next month.”
SPP spokesman Derek Wingfield said the RTO was awaiting FERC’s response to the NOPR. “As always, we remain committed to partnering with DOE, FERC and others in our industry to ensure our markets and other services are designed to protect our nation’s electricity infrastructure,” he said.
CAISO is aware of the NOPR and will continue working “with state and federal energy regulators and stakeholders to maintain and strengthen grid resiliency and reliability,” said spokesman Steven Greenlee.
PJM, NYISO and MISO all said they were reviewing the directive.
“As you can imagine, with this just out, we’ll need time to review, analyze and understand,” said PJM spokesman Ray Dotter.
Vogtle Guarantees
While Perry’s NOPR is intended to preserve the current nuclear fleet, his approval of additional loan guarantees is intended to ensure that hopes for a new generation of units are not crushed under the weight of Vogtle’s delays and cost overruns. Vogtle Units 3 and 4 are the first nuclear plants to be licensed and begin construction in the U.S. in more than three decades.
“I believe the future of nuclear energy in the United States is bright and look forward to expanding American leadership in innovative nuclear technologies,” Perry said. “Advanced nuclear energy projects like Vogtle are the kind of important energy infrastructure projects that support a reliable and resilient grid, promote economic growth, and strengthen our energy and national security.”
Rory D. Sweeney, Jason Fordney, Peter Key, Amanda Durish Cook, Tom Kleckner and Michael Kuser contributed to this story.
AUSTIN, Texas — DeAnn Walker will chair her first open meeting of the Public Utility Commission of Texas on Thursday after her recent appointment, which couldn’t come at a busier time for the commission.
Walker | Courtesy DeAnn Walker
The Sept. 28 agenda includes an update on Hurricane Harvey restoration efforts, consolidated dockets related to a proposed swap of transmission assets between Oncor and Sharyland Utilities, and Lubbock Power & Light’s request to move its load from SPP to ERCOT.
The PUC is also in the midst of rulemaking projects to improve price formation in ERCOT’s energy-only market, reliability-must-run service and determining rate case procedures for transmission and distribution providers.
And then there’s Sempra Energy’s $9.45 billion bid to acquire Oncor, the state’s largest utility. A federal bankruptcy court has already approved Sempra Energy’s purchase of Oncor and its bankrupt parent, Energy Future Holdings, but the California company must still gain the PUC’s approval. (See Bankruptcy Court Advances Sempra Bid for Oncor.)
The commission has rejected two previous acquisition attempts by Hunt Consolidated and NextEra Energy.
Texas Gov. Greg Abbott last week announced Walker’s appointment as PUC chair to replace Donna Nelson, who stepped down in May. Walker, who served as a senior policy adviser to Abbott on regulated industries, will fill out the remainder of Nelson’s term, which expires in September 2021. (See Texas PUC Chair Nelson Stepping Down.)
Commissioners Ken Anderson and Brandy Marty Marquez have kept the three-seat PUC running while waiting on a new chair. Anderson has served on the commission since September 2008 — a record tenure — though his term expired Aug. 31. Marquez’ six-year term expires in September 2019.
Walker returned to the PUC on Sept. 21, after previously working at the commission from 1988 to 1997 as an assistant general counsel and then as an administrative law judge. She spent 15 years at CenterPoint Energy as director of regulatory affairs and as an associate general counsel, before joining Abbott’s staff.
Walker is a member of the State Bar of Texas. She received her bachelor’s degree from Southern Methodist University and her law degree from the South Texas College of Law.
CAISO and Pacific Gas and Electric have asked FERC to reconsider its decision last month to approve only some of the utility’s requested transmission rate incentives related to more than $1 billion in planned grid improvements.
The ISO and the utility on Sept. 25 filed separate requests for FERC to rehear a determination that PG&E had not justified all of its proposed “abandoned cost” recovery, which allows it to recover from its customers the costs of abandoning construction for reasons beyond its control. (See FERC Approves PG&E Transmission Cost Recovery.)
Timeline and cost of PG&E’s proposed projects | PG&E
PG&E in its rehearing request called the incentive request “narrowly tailored” and said it faces significant challenges in developing the greenfield projects that are not in an existing right of way (EL16-47). The utility had requested 100% recovery of costs for any of the eight projects if they are abandoned, but FERC approved incentives for only three of them. The utility said it has already invested $68 million in construction and that the projects face risks, including environmental permitting, siting authority and potential impacts of from California’s renewable energy goals.
“Consequently, under a rigid application of the effective-date limitation imposed in the orders under review, PG&E now faces an unexpected risk of loss equal to 50% of that initial $68 million investment,” the company said, adding that “if allowed to stand, this outcome will create a disincentive for PG&E to make similar investments in the future.”
PG&E said that while the requested incentives would allocate to ratepayers 100% of the risk of abandonment for reasons beyond a utility’s control, “FERC’s orders here shift 50% of that risk for a defined period (before the issuance of a project specific declaratory order) to the utility and its shareholders. This reallocation makes investment in new transmission projects riskier and less attractive.”
CAISO’s filing contended that each project meets FERC’s standard because it was approved by the ISO as part of a regional planning process and that “CAISO approved these specific projects to meet identified reliability needs on the CAISO system.” Project sponsors such as PG&E have an obligation to obtain approvals and rights if the projects are approved as part of the ISO’s annual transmission planning process.
CAISO said it has canceled other projects approved in annual plans and that it is currently assessing whether to cancel other previously approved projects, so “the risk of abandonment is not hypothetical.” When developing its 2015-2016 plan, the ISO canceled 13 PG&E low-voltage transmission projects it had previously approved.
Southern California Edison on April 7 filed a similar request for abandoned cost recovery upon which the commission has yet to rule (EL17-63). The petition requested approval of incentives for a package of transmission improvements totaling about $1.3 billion, approximately $903 million of which are recoverable in transmission rates.
While the California Public Utilities Commission had objected to PG&E’s incentive rate request, FERC rejected the state regulators’ arguments about PG&E’s transparency and cost control.
Earlier this month, FERC in a different proceeding also rejected a protest from the PUC over incentive rate adders the commission had approved for PG&E in 2016. (See FERC Upholds PG&E ISO Incentive Adder, Rebuffs CPUC.)
ST. PAUL, Minn. — MISO revealed three new candidates for its Board of Directors and reported on an expected budget overrun during the quarterly board meeting on Thursday.
Board Chairman Michael Curran opened the meeting with a moment of silence for the victims of Hurricane Maria in the Caribbean and Puerto Rico. “It underscores the importance of what we do,” Curran said.
Curran announced incumbents Baljit Dail and Thomas Rainwater and newcomer Theresa Wise, former chief information officer for Delta Air Lines, are the candidates for three new terms beginning in January.
If any of the three fails to receive a majority vote, stakeholders will consider alternates John “Jeb” Bachman, former partner at PricewaterhouseCoopers, and Wolfgang Richter, former chief information officer at PricewaterhouseCoopers. In MISO board voting, alternates would only rotate into the election for a second membership vote if any of the candidates in the first vote did not receive a majority of the vote.
The slate was prepared with help from search firm Russell Reynolds. In June, Dail — who by the end of the year will reach MISO’s three, three-year term limit — was granted a one-time waiver to stand for this year’s election. (See “Committee Permits Consideration of Extra Term for Dail,” MISO BoD Briefs: June 22, 2017.)
Senior Vice President of Compliance Services Stephen Kozey said electronic voting will be open for 39 days — “not a short amount of time” — and 25% of MISO’s 138 voting members will need to cast ballots to reach an election quorum.
“We’ve been lucky in the past to have voting participation over 60%,” Kozey said.
Noticeably absent from the roster was current Director Paul Bonavia, who had been seeking re-election as of the last board meeting.
Bonavia said that when he announced in summer that he would stand for re-election, he fully intended to do so, but since that time, unforeseen “personal and family matters totally unrelated” to MISO have arisen.
“It’s been a pleasure to be part of the MISO board, and we still have a lot of work to do this year, and I promise to stay fully engaged. I also would like to congratulate MISO on a wonderful roster of candidates,” Bonavia said.
Small Budget Overrun
To date, MISO is $1.8 million under its annual budget, but Chief Financial Officer Melissa Brown said the RTO will likely spend $240.4 million by year-end, exceeding its $239.1 million budget by $1.3 million (0.5%).
Forecast expenses of $240.4M results in being over budget by $1.3M or 0.5% | MISO
As of the end of July, MISO was under budget by 1.3%, having spent $138.7 million of the $140.5 million allotted for the first six months.
In June, Brown prepared the board for a possible 1.2% budget overrun, due in part to MISO’s lower-than-expected employee vacancy rate. (See “MISO Reports Likely Year-End Overage; Board Urges Staff Stick to Budget,” MISO BoD Briefs: June 22, 2017.) The low rate persists, Brown said, but MISO has since shifted some project spending around.
Brown said that while employee retention and spending on employee medical benefits is the biggest cause of the overrun, it’s a sign that MISO’s recent programs aimed at retaining talent are working.
MISO’s capital spending in 2017 is similarly expected to go over budget. Brown said MISO will probably spend $30.2 million instead of its assigned $29.9 million on capital projects (1%).
So far this year, capital spending is $20.1 million, under budget by $600,000 (2.9%).
Dail said stakeholders can expect MISO’s other capital spending to shrink over the next few years to make room for MISO’s multiyear, $130 million project to replace its market system computer platform.
The replacement took more of a share of this year’s overall budget than originally anticipated. The program began with a $1.7 million spend in 2017, but MISO won board approval to increase it to $5.2 million so that staff could start early on vendor evaluation and gathering bids. (See MISO Makes Case for $130M Market Platform Upgrade.)
“It was never easier for me to vote for a budget increase,” Director Barbara Krumsiek said. “It means you’re moving at such a pace” that early spending is needed. “I’d like to thank you for asking for the increase.”
Brown said MISO offset some of the extra platform spending by not having to spend money developing a separate, three-year forward capacity auction for competitive retail areas — a proposal that FERC rejected.
ST. PAUL, Minn. — While MISO “generally” agrees with all nine market improvement recommendations raised by its Independent Market Monitor in its 2016 State of the Market report, the RTO says it must first consult with stakeholders on any proposed market changes.
“There are a number of them where we agree, both on the notion behind them and the recommended approach,” MISO Executive Director of Market Design Jeff Bladen said during a Sept. 19 meeting of the Markets Committee of the Board of Directors.
The RTO said it agrees with the Monitor’s idea of representing the value of lost load with a more sloped contingency reserve demand curve. Patton recommended a curve capped at almost $12,000/MWh, rather than MISO’s proposed $3,500/MWh cap, which the RTO filed in May to comply with FERC Order 831 (ER17-1571).
MISO’s flatter proposed curve generally hovers at $2,100/MWh, unless the market clears less than 8% or more than 96% of its requirement. The current curve is largely priced at $1,100/MWh.
“It seems like a fairly simple question: Why don’t we do this?” Director Paul Bonavia asked regarding the Monitor’s proposed curve.
Executive Vice President of Operations Richard Doying said that while MISO agrees with the more steeply sloped curve, the process for changing “isn’t as simple as filing” a new curve. The RTO must first put the change before its stakeholder community and gather consensus before turning to FERC with a proposal.
“We’ll get to a change. We’re not sure what the shape of the curve will look like, but [a change] is beneficial,” Doying said.
MISO officials are in the midst of developing a plan to transfer control of market-to-market (M2M) flowgates to neighboring RTOs. Bladen said MISO and SPP plan to begin swapping flowgate control soon — a goal first outlined in a June memorandum of understanding between the two RTOs — while MISO will look improve its control transfer process with PJM. (See MISO Interregional Plans with SPP Echo PJM Efforts.) The Monitor wants the three RTOs to become more active in transferring monitoring of constraints when the non-monitoring RTO has all of the transmission loading relief on a flowgate.
Generation Outages
MISO is also aware that it needs a greater say in the scheduling of planned generation outages, Bladen said. In his report, Patton asked the RTO to file changes with FERC to give itself increased authority to approve generation and transmission outages and the ability to coordinate outage schedules in order to lower costs.
“We think that generation outages will somehow be changed. That, I think, is not a question,” Bladen said. “How it’s going to be implemented, that’s an area where stakeholders, the Market Monitor and MISO will have to work together.”
About 16,000 MW of generation was offline for planned outages despite unseasonably warm forecasted temperatures during emergency conditions in MISO on April 4, and the Monitor maintains that the planned outages exacerbated the situation.
During a Sept. 20 Advisory Committee meeting, Citigroup Energy’s Barry Trayers said generators planning the outages should possibly bear some of the related congestion costs.
“By nature of our names, we are transmission-dependent utilities,” Wisconsin Public Service’s Chris Plante said. “What we found out real quickly when working with our transmission providers is that we have to coordinate heavily to align outages.”
“The consumers are bearing the burden of these costs. I still carry the concern of the ratepayer,” NRG Energy’s Tia Elliott said. “We have to consider the economics of these outages — and not the economics of filling our own pockets, but the economics of who bears these costs — because we can’t get the planning and the coordination down right. And maybe we can’t get it perfect, but there needs to be some coordination here.”
Entergy’s Matt Brown said he personally opposes scheduling wintertime outages for the sake of staggering planned outages in the interest of community safety.
“It’s one thing not to have air conditioning in April when it’s 70 degrees. It’s another thing not to have heat in December,” Brown explained.
Reliability Subcommittee Chair Tony Jankowski pointed out that MISO is not charged with evaluating outages based on cost. “If you want MISO to put a price on that outage, that’s a whole different thing. That’s not in MISO Tariff,” he said.
Two Separate Reserves?
Like the generation outage issue, Bladen said MISO faces a similar stakeholder process to create separate regional reserve requirements and cost allocation for its North and South regions, another Monitor recommendation. He pointed out that MISO is currently conducting a multiyear regional transmission overlay study that could identify a transmission solution for the RTO’s constrained interface between the two regions. Neither the Market Congestion Planning Study nor footprint diversity study, both conducted this year, have been successful in identifying a project that could meet cost-benefit requirements.
Other Recommendations Get a Look
The Monitor’s remaining recommendations also must undergo more review, according to Bladen.
State of the Market recommendations take an average of 2.2 years to resolve | MISO
A recommendation to improve the accuracy of MISO’s look-ahead commitment tool by modeling system conditions for a three-hour time frame could be folded into the RTO’s market platform replacement if the Monitor has provided compelling enough evidence for doing so, he said.
Officials also agree with the Monitor that the RTO could tighten qualification guidelines for day-ahead margin assurance and real-time offer revenue sufficiency guarantee payments in order to improve performance incentives and reduce gaming opportunities. Bladen said MISO plans to begin stakeholder discussions about the issue next month.
MISO may be willing to improve forecasting incentives for its wind operators by changing dispatch deviation thresholds and settlement rules, but it must first evaluate how other RTOs have handled wind forecasting, Bladen said.
“There’s a quote by Pablo Picasso: ‘Good artists copy and great artists steal.’ The concept of stealing as he was describing is building on what others have done. That’s what we want to do here; we want to build on and improve,” he said. (Whether Picasso actually said this is disputed.)
Bladen also said MISO still faces a full technical review in front if it undertakes a recommendation to disqualify from the Planning Resource Auction any resources expected to be unavailable during peak conditions. “We’ll be working through with our stakeholders to figure out how to do this,” he said.
Now What?
The Monitor’s recommendations are included for consideration in the current and upcoming Market Roadmap project lists. Patton’s recommendation to create regional reserve requirements was the only one to earn a “top 10” stakeholder ranking among 34 market modification proposals in the RTO’s annual Market Roadmap process. MISO has yet to provide its own staff weightings alongside the stakeholder scoring results to determine what market projects the RTO will eventually undertake. (See “Stakeholders Give Energy Storage Top Spot in Roadmap,” MISO Market Subcommittee Briefs: Aug. 10, 2017.) MISO will unveil a final project prioritization by December.
MISO said it plans to spend about $53 million in Market Roadmap market revisions over the next five years.
Director Michael Curran said that roadmap efforts are a sizeable endeavor when combined with the RTO’s day-to-day operations and multiyear effort to entirely replace its market platform.
“This is a big lift,” agreed Director Baljit Dail.
ST. PAUL, Minn. — MISO’s Steering Committee will reopen nominations for vice chair of its newly formed Energy Storage Task Force after initiating what stakeholders are calling a confusing elections process.
The move has opened discussions that could have implications for how the RTO nominates and elects individuals to fill stakeholder group leadership positions in the future.
In selecting leaders for the task force, MISO’s Steering Committee deviated from standard practice by administering separate elections for the positions of chair and vice chair. While votes for the chair are already in (with results still unannounced), the election of the vice chair is still pending.
Steering Committee Chair Tia Elliott said that both candidates for chair expressed an interest in running for vice chair if they weren’t picked for the top position. As a result, a nomination for vice chair was submitted after the deadline, leaving the Steering Committee to decide whether to include the late submission for voting.
During a Sept. 20 Steering Committee meeting, Vice Chair Audrey Penner suggested reopening the nomination process but including all previous nominations, a motion committee members backed by consent.
“That’s the only way I see getting around this confusion,” Penner said.
In explaining the reason for the split elections, Elliott said the Steering Committee is under pressure to produce stakeholder leadership for the task force so the group can begin work on pressing energy storage issues. MISO has already assigned Chief Compliance Officer Joseph Gardner to serve as liaison to the group, and stakeholder input is needed as the RTO begins to craft market rules and definitions to manage storage participation in the market. (See Progress Builds for MISO Energy Storage Effort.)
“There’s a push to get this off the ground,” Elliott said.
Some Steering Committee members asked who had the authority to separate the voting in the first place. Others said moving deadlines for late nominations could result in increased confusion during elections for other stakeholder committees.
Elliott said MISO staff and Steering Committee leaders decided to split the election, as the RTO’s Stakeholder Governance Guide is silent on the issue of moving election dates.
“That’s stepping way outside the governance guide. I’m concerned a decision like that has been made,” said Northern Indiana Public Service Co.’s Bill SeDoris.
“I made the decision. I will not apologize for that,” Elliott said, pointing to the scarcity of volunteers within the MISO stakeholder community to take on leadership positions.
“If we have a deadline, in fairness to the process, we need to stick by that date,” Penner said of the possibility of allowing a late nomination.
In response to a question by Ameren’s Ray McCausland about why the Steering Committee didn’t simultaneously solicit nominations for chair and vice chair, Elliott said nominations were held in conjunction, but elections were held separately.
“The way this ended up is a bit cumbersome,” McCausland said.
Elections for chair and vice chair for all MISO stakeholder committees and groups are held via electronic ballot among MISO members with voting rights.
The Steering Committee will next month explore possibly amending elections provisions in the Stakeholder Governance Guide, Elliott said. She asked stakeholders to email MISO’s stakeholder relations team with opinions on the subject. The committee will consider revising elections rules after reviewing responses and holding a discussion on the topic.
As I walk the halls of National Association of Utility Regulatory Commissioners meetings, I hear a lot about the “grid of the future” or “grid modernization.”
Thomas
According to the North Carolina Clean Energy Technology Center’s “The 50 States of Grid Modernization” report, more than 30 states are exploring “grid modernization” to various degrees. New York is knee-deep in Reforming the Energy Vision, Ohio is doing “Power Forward” and Illinois is pursuing “NextGrid.” These are all terrific initiatives, and these state’s utility commissions should be applauded for their efforts to proactively realize that the traditional electric utility service business model is changing and unless utilities and regulators get in front of certain issues, consumers will ultimately pay the price later.
These grid modernization efforts are driven by several factors that stem from technological innovations changing consumer needs for electricity in the face of aging infrastructure. While different states have different dynamics and different solutions, they are fundamentally addressing the same challenge. Fortunately, these challenging circumstances are leading to creative thinking and solutions that are more than just throwing money at the problem.
Changing Dynamics
Similar to these state-led efforts that focus on the retail electric delivery system, a parallel re-examination of our wholesale energy markets is long overdue. For a variety of reasons, the dynamics in our wholesale markets are changing. Flat peak consumer demand year over year, low-cost natural gas-fired generation, the proliferation of subsidized intermittent resources (with no fuel costs) and an increasingly flat supply stack, combined with market rules that have not kept pace, have all contributed to a wholesale power market in which units that produce relatively inexpensive power and are needed for reliability are in significant financial stress and at risk for closure.
Just last month, Energy Secretary Rick Perry recognized that the power industry “has experienced massive change in recent years, and government has failed to keep pace.” The much anticipated Department of Energy “Staff Report to the Secretary on Electricity Markets and Reliability” called for FERC and RTOs to reform market rules in order to promote grid resilience and proper energy price formation. In many respects, the DOE report recognizes that if certain low-cost plants do not receive proper price support in the current market, those plants will likely retire, leading to higher costs to consumers over the long term.
Energy price formation is not a new issue, and FERC has taken positive steps to improve it over the last several years. FERC, through Order 825, has made significant changes to the settlement of energy transactions and the triggers for scarcity pricing. PJM and the other RTOs are in the middle of implementing these reforms. While their impacts have yet to be realized, they nonetheless offer great promise.
Energy Price Formation 2.0
While the reforms to date have been important, it is time for the next step — Energy Price Formation 2.0, if you will. As a result of technological advances and current market conditions, PJM has a glut of units that participate in the market at roughly the same low price. LMP was developed based on a supply stack and a sloped supply curve, but today’s supply “stack” looks more like a flat piece of glass. In today’s market, new natural gas combined cycle plants, baseload coal plants and most nuclear plants can produce power at prices that by historical standards would be considered a bargain.
The fact that there is a bounty of low-cost resources available to meet demand means that prices will be less volatile and costs to consumers of electricity will be lower over time. The last two summers in PJM bear witness to the fact that high temperatures and higher-than-normal demand did not lead to significant upward pressure on electricity prices in PJM (see chart below).
| PJM
As a result of these current market conditions, it takes longer for those higher-cost peaking plants to be dispatched and set the energy price. While good for consumers at the present moment, if market rules are not altered, consumers will lose the benefits associated with the plethora of low-cost resources, as those resources will be forced out of the market because of insufficient revenues. In such a scenario, higher-cost resources will move closer to the front of the supply stack, run more often, set the clearing price at a higher level and cost consumers more over time.
Clock is Ticking
PJM has suggested a series of energy market reforms to allow consumers to continue to benefit from this abundance of low-cost resources. PJM has proposed that energy prices should be set by the units that are running to serve consumer needs and unit flexibility should be rewarded, not punished. The current rules do not do this and instead rely on out-of- market payments to specific operationally constrained, low-cost units that must run for reliability purposes. Ultimately, such a regulatory paradigm does not send the appropriate price signal to either the flexible or inflexible unit. While such a market design may have worked against an actual supply stack with material differences in price among resources, it falls short in the current “flat” market.
The wholesale power market of today is not that same as the wholesale power market of 10 years ago. To date, wholesale markets have delivered enormous value to consumers. In order for the value to continue for the next 10 years, regulators, consumers and other stakeholders need to recognize and respond to the changes that are already here. The clock is ticking. We all need to get to work.
Glen Thomas is president of PJM Power Providers Group (P3), which represents independent power producers.
