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. — Representatives of MISO sectors gathered Wednesday to discuss how a greater number of distributed energy resources could interact with the grid. Topics ranged from the gig economy to state jurisdiction to the socioeconomic barriers preventing some from obtaining those resources.
Vice President of System Operations Todd Ramey said DER “such as rooftop solar systems and microturbines” are not as widely used in MISO as in other RTOs.
“However, the MISO region could see a substantially higher penetration of distributed energy going forward as the costs of the resources continue to decline and if cities, states and the federal government continue to adopt policies that encourage their use,” Ramey said.
By 2030, installed photovoltaic resources could top 17 GW, while demand response and energy efficiency deployments could exceed 6 GW and 8 GW, respectively.
Discussion facilitator Julia Johnson, president of regulatory advising firm Net Communications, kicked off the discussion by engaging stakeholders, MISO staff and board members in a sing-along of Fleetwood Mac’s “Don’t Stop.”
“‘Don’t stop thinking about tomorrow.’ That’s the trend. There hasn’t been much DER activity so far, but we plan for it,” Johnson said.
Defining DER
MISO presented a draft definition describing DER as power generation, storage or load-modifying resources connected either through a utility’s distribution system or behind the meter. DER can include photovoltaics, combined heat and power, cogeneration systems, reciprocating engines, combustion turbines, microturbines, wind turbines, back-up generators, energy storage and even DR and energy efficiency, according to the definition.
Most sectors, including the Organization of MISO States, agreed with MISO’s take. OMS organized an early August workshop in which state regulators and industry officials similarly explored DER topics, and has since formed a temporary work group to consider how to incorporate the resources into the grid. (See Stakeholders Hash out Future of DER at OMS Workshop.)
“Consumers [are] moving to being customers of the grid,” said John Moore, attorney for the Natural Resources Defense Council, who likened the energy customer transition to that of licensed drivers and the rise of Uber’s ride-share program.
Director Baljit Dail seized on the Uber analogy. “There may be a whole new player that comes into the mix and provides a platform for people with DER to sell,” Dail said.
Entergy’s Matt Brown said there will probably be a future need to designate a minimum megawatt participation limit on DER to include them in whatever market definition the RTO eventually settles on. “MISO might not be the appropriated entity to draw those lines,” Brown added.
“The advantage that we have here is that we really have some time to make some really elegant solutions,” Northern Indiana Public Service Co.’s Paul Kelley said.
“Let’s not lose sight of [the fact] that getting paid within MISO is not a trivial matter,” Dynegy’s Mark Volpe said. He said suppliers must go through the process of creating commercial pricing notes, signing agreements with MISO and posting collateral to get set up on the wholesale distribution level — none of which is an easy task.
State Jurisdiction
Minnesota Public Utilities Commissioner Matt Schuerger said that while DER rules will fall under state jurisdiction for resource adequacy, MISO, industry leaders and generation and transmission operators will play a vital role in coordinating and planning. “I think state regulators will need information from MISO to help make decisions,” he said.
Arkansas Public Service Commission Chairman Ted Thomas reiterated a warning issued by former FERC Commissioner Tony Clark at the OMS DER workshop, saying states will get rules mandated to them by FERC if they fail to write their own.
“States can [wait to] act and wait for FERC to act, and what we’ll get is a velvet glove around an iron fist — one size fits all,” he said.
Wind on the Wires’ Beth Soholt pointed out that many Midwest manufacturing plants are already beginning to alter their energy supply mix to meet renewable goals. “You’re going to continue to see this trend ripple through large energy customers,” she said. Soholt said MISO planning might need to look past demand, including at customer preference. She said as long as demand growth remains the single most important factor in transmission planning, MISO will not have a complete picture of the future.
“I think people think, ‘demand is going down, so we don’t need to plan as much transmission or generation. Customers want a particular kind of mix. … I worry about that if we just look at demand in and of itself, that’s not capturing all the value that these resources have to offer,” she said.
At a Sept. 21 Board of Directors meeting, Executive Vice President of Operations Clair Moeller told board members that MISO is overall moving to a “less peak, more load served” model with the contributing factor of electric vehicles.
Missouri Public Service Commission economist Adam McKinnie agreed that the “haircut of load growth” has been an obstacle in recent transmission planning studies by consulting firm Applied Energy Group.
McKinnie said some states, including his own, collect rooftop solar data, and those numbers could be passed on to MISO planners.
“This could be an example of how the states could gather and provide MISO with information, so MISO doesn’t have to guess,” he said.
Dail urged stakeholders to give MISO guidance on DER market rules. “You didn’t want a MISO that picked winners and loser in regards to technology,” he reminded them.
Moore said MISO must avoid “siloing,” referring to the tendency for DER information to remain in just one database.
“Is there siloing occurring at the distribution level that prevents a complete picture of how much distributed energy is bubbling up?” he asked.
Socioeconomic Differences
Brown said MISO and industry leaders must also pay attention to distributed energy trends in wealthy communities versus poverty-stricken areas, contrasting the incomes in the toney Twin Cities suburb of Maple Grove with those of Flint, Mich., both in the MISO footprint.
“It’s easy to lose sight of how large our footprint is. It’s easy to make sweeping statements like ‘customers want this’ or ‘customers want that,’ but we have to remember the range of customers we have,” Brown said.
Director Thomas Rainwater thanked Brown for bringing up the socioeconomic disparity across the footprint.
“I happen to live within 40 minutes from Flint,” Rainwater said. “One of the great inventions of the last 100 years is the electrification of households and the health and economic benefits that it brings … but there are those that have been left behind. I think that we can all agree that while solar is great and wind is great, the early [residential] adopters are in the upper strata. We need to not lose sight of that.”
Director Todd Raba said regulators and industry officials have an “ethical” obligation to pay attention to keeping costs low for their poorest customers.
CAISO this week will gather feedback on its proposal for reliability payments to keep Calpine’s Metcalf gas-fired plant from going offline, a decision drawing scrutiny amid a larger conversation about local resource adequacy (RA) planning.
The ISO relies on reliability-must-run (RMR) contracts to keep resources online that are slated for retirement but are still needed for reliability. It has a stakeholder call scheduled for Sept. 26 to gather feedback on its recent proposal to designate Metcalf as an RMR resource.
CAISO is Considering an RMR Contract for Calpine’s Metcalf Energy Center | Calpine
The contract is slated for a vote by the CAISO Board of Governors in early November, leading some to complain about a quick decision timeline. The board also faced some scrutiny in March when it designated Calpine’s Yuba City and Feather River gas-fired plants as RMR contractual facilities. (See CAISO RMRs Win Board OK, Stakeholders Critical.)
Calpine in June told CAISO that it intends to take the Metcalf plant offline at the end of this year. The company’s request that the ISO study the reliability impact came back in the plant’s favor. “Analysis has indicated that Metcalf Energy Center is in fact required in order to meet the relevant criteria for reliable system operation,” the ISO said in a notice for the call.
At its most recent meeting Sept. 19, the board voted unanimously to extend the current reliability RMR contract for three 55-MW oil-fired units at Dynegy’s Oakland facility. CAISO says it will not renew a contract with AES for the synchronous condensers at its Huntington Beach plant, and those units are expected to shut down.
At the board meeting, Pacific Gas and Electric Director of ISO Relations Eric Eisenman said “these continuing RMR designations show that the market is changing,” pointing to new solar and other resources. He added that “the RA process, especially the local process, needs improvement.”
The RMR contract for Metcalf will put tens of millions of dollars of costs onto ratepayers, he said, asking the board to work with regulators “to improve the local RA paradigm sooner, not later.” He expects more RMR designations for 2019, which will almost certainly raise customer costs.
Noting that CAISO informed stakeholders of the possible RMR designation for Metcalf in early September ahead of the Nov. 1 vote, he said: “We are feeling kind of jammed when it’s tens of millions of dollars.”
Local RA Adjustments Planned
Part of the problem is the way the RA for load-serving entities is measured, CAISO Vice President of Market and Infrastructure Development Keith Casey said at the meeting. RA is currently measured across a broad area, but individual capacity areas within that territory might have inadequate resources.
“We cannot operate being short in a specific area, and I think Metcalf is probably indicative of that deficiency in design,” Casey said. The ISO is working with the California Public Utilities Commission on the problem, and “I am optimistic we will have a proceeding soon to take on some of the deficiencies around the local RA design.” In a Sept. 12 memorandum to the board, Casey said “reliability-must-run contracts remain an important backstop instrument to ensure reliability when other alternatives are not viable.”
RMR contracts are pursued when an LSE does not purchase sufficient capacity to meet local reliability criteria, or when CAISO needs reliability service such as voltage support, black start or dual-fuel capability. RMR can also be used to address local market power or protect availability of a given resource that could retire in the absence of a contract. LSEs are required to provide the RA showing by Sept. 15 of each year and have until Oct. 31 to submit their final year-ahead RA showings. CAISO must notify a potential RMR unit by Oct. 1 of each year whether it will extend an RMR contract.
The number of facilities under RMR contracts has dropped significantly since the implementation of the RA program and the addition of other types of resources. In 2006, CAISO had 9,963 MW under RMR, which dropped steeply to 3,995 MW in 2007. Today, in addition to the Oakland units under RMR, CAISO has about 1,500 MW under black start contracts and about 160 MW under dual-fuel extension status.
CAISO Says Puente Plant Needed
Reliability needs have also led CAISO to conclude that a new gas-fired plant on the California coast cannot affordably be replaced with other alternatives. CAISO on Aug. 16 released its study on the 260-MW Puente Power Project, but NRG Energy has run into heavy opposition to its proposal to build the plant on an existing site in Oxnard to replace its retiring Mandalay and Ormond Beach plants.
Puente Power Project viewed from beach | California Energy Commission
The California Public Utilities Commission authorized Southern California Edison to enter into a long-term RA contract with NRG for the plant’s capacity, and the California Energy Commission is reviewing the construction and operating permit for the facility. The project was approved because 2,000 MW of generation in the area is due to retire by 2020 because of once-through-cooling regulations.
As part of its review process, the CEC accepted CAISO’s offer to study whether demand response, energy efficiency, renewable generation and combined heat and power could offset the need for the Puente project. CAISO last month issued its findings in the Moorpark Sub-Area Local Capacity Alternative Study, after gathering comments from market participants.
After examining three scenarios, the ISO concluded that Puente would be the cheapest alternative at a cost of $299 million. The most expensive scenario was “incremental distributed resources plus grid-connected battery storage (if the Ellwood Generating Station is retired)” at $1.1 billion, more than triple the cost of Puente.
CAISO Determined the Puente natural gas plant was the cheapest option to meet local reliability needs. | CAISO
RMR revenue helps keep natural gas a player in the CAISO market as environmental opposition toward fossil fuels is on the uptick. Gas remains the largest component of CAISO’s fuel mix, making up about 54% of its installed capacity of 71,400 MW, followed by renewables at 29%, large hydro at 12% and nuclear at 3%. Oil, coal and “other” comprise about 2%.
However, conventional generation such as natural gas makes up only 9% of CAISO’s interconnection queue of 325 projects totaling 58,000 MW, while 68% are renewable projects and 20% are energy storage devices.
Aside from RMR, CAISO also has a risk-of-retirement program called the Capacity Procurement Mechanism Risk-of-Retirement Enhancements (CPM ROR) initiative, which is generally regarded as a better alternative to RMR. (See CAISO Finalizes Risk-of-Retirement Program Changes.) That package of market rules is also due for a vote from the board at its November meeting.
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.
