FERC said last week that a proposed revision to the Federal Power Act that would increase the right to appeal rate changes may have only limited effectiveness.
Danly
General Counsel James Danly told the Senate Energy and Natural Resources Committee’s Energy Subcommittee on Tuesday that S. 186, which would allow parties to seek judicial review of rate changes in the case of commission inaction, “only partially advances the interests of an exceedingly narrow category of aggrieved parties in very rare occasions of commission inaction.”
The bill, sponsored by Sen. Ed Markey (D-Mass.), was prompted by the commission’s 2-2 deadlock in September 2014 over whether it should reject the results of ISO-NE’s eighth Forward Capacity Auction because of unchecked market power. The 2017-18 auction results became “effective by operation of law” (ER14-1409). Under the FPA, rates take effect 60 days after they are filed with FERC, absent a commission order to the contrary. (See FERC Commissioners at Odds over ISO-NE Capacity Auction.)
Catch-22
Under Section 313 of the FPA, parties must seek rehearing of FERC orders before filing an appeal in federal court. But in the case of FCA 8, because the commission never issued an order, challengers were blocked from seeking rehearing or challenging the auction results in court — a catch-22 that the legislation intends to address.
Last October, the D.C. Circuit Court of Appeals rejected an effort by Public Citizen and Connecticut officials to force FERC to rule on the legality of the auction. It agreed with the commission that there can be no rehearing or appellate review when there is no order in a Section 205 proceeding. (See Court Asked to Force FERC Action on Disputed ISO-NE Capacity Auction.)
Danly told the subcommittee he knew of only five other instances in which a utility’s filing has taken effect by operation of law under the FPA or the Natural Gas Act without a commission order.
Under S. 186, the absence of commission action that results in a filing taking effect would be considered an order, allowing rehearings and appeals.
“The proposed legislation offers the possibility for aggrieved parties to pursue further administrative and judicial process when a disputed rate goes into effect even though half of the seated commission would not have accepted the rate in an order,” Danly observed. “Oddly, under the current statutory framework, a party who manages to persuade only one of four commissioners, and loses on a 3-1 vote, may request rehearing at the commission and seek redress at a court of appeals. However, a party that is perhaps more persuasive and manages to convince two of four commissioners, resulting in a 2-2 split — and thus no commission order — is currently barred from seeking rehearing and appellate review.”
Danly noted that any party can file a Section 206 challenge alleging rates are unjust and unreasonable — albeit at increased cost and a higher burden of proof than Section 205 filings.
But he said the legislation may not provide the relief its sponsors intend.
“Should the commission’s inaction be the result, as in the ISO-NE case, of a 2-2 split, a similar result could obtain for a later order on rehearing,” Danly said. “In that case, there would be another 2-2 split and no order on rehearing would issue. In such a case, it would be exceedingly unlikely that a court of appeals would entertain a petition for review.
“Moreover, even if a court of appeals accepted the petition, the court would almost certainly remand the case back to the commission for further adjudication. When sitting in review of agency action, courts of appeals review the evidentiary record compiled below and the reasoning the agency employed — as reflected in its orders — to support its decision based on that record. In the case of a serial 2-2 split, no orders would issue and such a review would be impossible. Remand would appear to be the court’s only option.”
FERC Supports $10M Threshold on Merger Approvals
Danly told the committee FERC supports two other bills that would modify FPA Section 203 to set a minimum value threshold of $10 million for mergers of jurisdictional facilities subject to commission approval (H.R. 1109 and S. 1860).
The change would align this provision of the FPA, which currently has a $50,000 threshold, with other sections of the act that already set $10 million as the trigger, he said.
It would also “ease the regulatory burden on industry without impeding the commission’s regulatory responsibilities,” Danly said. “Transactions below the proposed threshold are unlikely to impose a significant negative impact on competition or the rates of utility customers.”
He said the commission has other tools to address market power concerns that could arise from mergers. “For example, if an entity with market-based rates obtained the opportunity to exercise market power as a result of such transactions, the commission could limit or eliminate its ability to engage in transactions at market-based rates. Additionally, the commission has a range of market power mitigation measures that limit market power within the organized wholesale electric markets. Finally, if the exercise of market power involves market manipulation or violation of a commission rule, regulation, order or tariff provision, the commission can bring an enforcement action.”
While MISO is no closer to establishing its version of what constitutes grid “resilience,” the RTO last week said it stands ready to study certain ancillary services to help the U.S. Department of Energy develop its understanding of a concept that is getting increasing industry play through Secretary Rick Perry’s efforts.
“It’s a term I hadn’t heard before,” MISO Director of Market Engineering Kim Sperry said at an Oct. 5 Reliability Subcommittee meeting.
Sperry said that when baseload generators were built, industry officials could not have predicted that natural gas prices would drop so low and that wind and other renewables would receive such heavy investment. From MISO’s perspective, the recent DOE grid study focuses particularly on “premature retirements,” she said. (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
In response to the report, MISO is willing to embark on new studies focusing on frequency control, ramping, voltage support, inertia and inertial response — all to better identify the features of a “resilient” generator, Sperry said.
“There is going to be opportunities for more research, and MISO is willing to assist in that research,” she said.
RSC Chair Tony Jankowski said the subcommittee and MISO should spend more time defining resiliency before attempting to study its aspects.
“We need to make sure when they say ‘resiliency’ that we understand what is meant,” Jankowski said, referring to the Energy Department. “If not, we’ll have to pay for a coal pile or a fuel rod, and that isn’t the end-all of resiliency.”
Gabel Associates attorney Travis Stewart echoed Jankowski’s thoughts. “As we’re walking down the pathway of defining this concept, could we also spend time differentiating between resilience and reliability? While it appears that they’re intrinsically linked items, they’re also distinct,” he said.
“Lights are on today — that’s reliable, but it doesn’t mean it’s resilient,” Jankowski added.
Sperry took down all points to include in future discussions on MISO’s exploration of the topic.
Patrick Clarey, FERC‘s liaison to MISO, said stakeholders have until Oct. 23 to comment on Perry’s Notice of Proposed Rulemaking, which asks FERC to ensure that generators with 90 days of on-site fuel supply receive “full recovery” of their costs (RM18-1). (See FERC’s Independence to be Tested by DOE NOPR.)
Some MISO stakeholders said the proposed rulemaking sounded like a measure to guarantee returns for some independent power producers.
Clarey declined to further explain the NOPR, instead saying he would let it “speak for itself.”
“I’m not going to speculate on what’s behind it. I will say it is unusual. It’s only happened a handful of times,” he said.
AUSTIN, Texas — The Gulf Coast Power Association’s 32nd Annual Fall Conference last week attracted several hundred attendees to the Texas state capital. A panel of CEOs discussed their reactions to the U.S. Department of Energy’s recent Notice of Proposed Rulemaking to FERC, while other panels covered ERCOT market reforms, federal policy issues, industry changes affecting transmission and distribution companies, and the future of the state’s energy markets
Likening himself to the annoying brother “in possibly the industry’s most dysfunctional family,” NRG Energy Director of Regulatory Affairs Bill Barnes explained his company’s push for ERCOT market reforms and the inclusion of marginal losses in LMPs.
Barnes participated in a lively panel discussion on marginal loss pricing, regional reserves and real-time co-optimization, where some attendees likened him to the “outnumbered” man on Fox News’ show by the same name.
But Barnes was happy to discuss recommendations made in a report commissioned by NRG and Calpine entitled “Priorities for the Evolution of an Energy-Only Electricity Market Design in ERCOT.” The report, written by Harvard University’s William Hogan and FTI Consulting’s Susan Pope, was the centerpiece of an August workshop at the Public Utility Commission of Texas. A second workshop is scheduled for Oct. 13. (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
“Everything that [the report recommends] is in the spirit of maintaining a sustainable energy-only market,” Barnes said. “You structure the market based on competitive principles, and let the market decide who the winners and losers are. We’re not scrapping what we currently have, or throwing the whole thing out and starting over. But if we’re going to be committed to an energy-only market design, you can’t ignore some clear design deficiencies.”
Barnes said the study’s proposed changes are “all about pricing integrity” and must be “price-scarcity appropriate.”
“We have to have the right price signals to reflect proper supply-and-demand decisions, [and] consumption and production decisions systemwide,” he said. “Pricing integrity is what I would consider the first pillar of key energy-only market design.”
The second pillar is marginal pricing, Barnes said.
“Certainty [in ERCOT] is based on marginal-cost pricing principles,” he said. That … just doesn’t work for congestion. There are too many physical properties that affect the value of electricity from one location to another. A megawatt of electricity that is injected 100 miles away from a load has a different value than a megawatt that is injected closer to load. That is an undebatable, economic principle. Why would we not have the locational marginal prices reflect that?”
“That’s a lot to respond to,” said Thompson & Knight’s Katie Coleman, speaking for Texas Industrial Electric Consumers (TIEC), which represents the state’s 50 largest electricity consumers. “Probably the most offensive aspect of the priorities for the energy-only market paper is the locational aspect. You want to send scarcity pricing signals to encourage new investment in ERCOT. Industrials have been very supportive of sending appropriate scarcity-pricing signals. … What we don’t think is appropriate is creating sustained high prices in one area of the state [such as that created by Houston congestion], irrespective of what’s going on statewide.
“That’s concerning to us because from a resource-adequacy standpoint … the minute you get a new transmission line, you’ve just exacerbated your oversupply capacity for the rest of the state, and you’re also suppressing price signals in that area,” Coleman said.
She said TIEC’s other concern is that locational prices won’t result in “very significant” construction of new generation. “Generators understand how to build just to the point where the pricing is maintained. They’re never going to build to the point where pricing collapses, right? That’s sort of self-defeating.”
Amanda Frazier, Vistra Energy’s vice president of regulatory policy, doubled down on the Hogan-Pope paper’s focus on locational losses. She noted that losses only account for about 2.5% of the total LMP cost that loads pay on a load-ratio share.
“Ask yourself, why is NRG clamoring for marginal losses to reduce prices to consumers, create more efficiencies in the market and help the poor consumers who are overpaying for transmission losses? Consumers aren’t clamoring for that,” she said.
Any savings would come “at an incredible expense to generators who don’t have the ability to change their siting decision,” Frazier said, referring to wind farms.
“It’s not just a renewable issue,” she added. “All you’re going to do is penalize those generators for taking advantage of the resources in the state and providing low-cost power to Texans. It just doesn’t make sense to us. We think the fact it’s more economic and efficient is not enough.”
GCPA attendees disagreed, voting 77% in favor of implementing marginal losses in an online poll at the conference.
The Wind Coalition’s Jean Ryall focused on subsidies and their effect on free markets. “One person’s subsidy is another person’s tax incentive, so where does that stop?” she asked, suggesting attendees visit stopthesubsidies.com and sign a pledge to stop the incentives.
“Nearly every type of generation on the ground today in ERCOT has been built with tax incentives or subsidies of some kind,” Ryall said. “It was sited and built, based on the current rules of the market. It’s not like we can change the rules and everybody rush out, pack up your iron and move it to the center of the load in Houston.”
CEO Pans Proposal
Vistra CEO Curt Morgan cautioned against the market reforms being considered, saying the nodal market is working, but that it is “fundamentally overbuilt.” He noted 21 GW of new generation has been built since 2011, the first full year of nodal operations.
“The proposals designed to raise prices inside a load pocket, when the market has sufficient generation, seem wrong-headed,” he said, referring to congestion issues near Houston. “That is a temporary position that will be resolved with transmission buildout.”
Indeed, ERCOT’s $590 million Houston Import Project is designed to address the congestion in and around Houston. Morgan said Vistra thinks the NRG-Calpine proposal is a one-sided solution.
“The proposal helps a few generators in Houston and increases expenses to others in the market,” he said. “It would threaten indispensable generation outside the Houston zone and perpetuates high prices in the Houston zone. It does nothing for renewables and sends the wrong message to those already invested in the current market structure.”
Morgan agreed that subsidized renewable energy is creating price pressure in ERCOT. He suggested an adder be used for real-time pricing when thermal units are needed to serve load but do not set the price.
“Low prices are great when the result of market fundamentals, but distorted when they’re not,” he said. “They’re happening even when traditional generation is needed to serve load. That ignores the real cost those units incur to stay online and serve load. Those resources are not receiving revenues needed to cover the short-term marginal cost.”
Legal Experts: Environmental Rollback no Sure Thing
A panel of legal and regulatory experts agreed that the Trump administration will work to roll back environmental regulations, but it remains to be seen how far those efforts will go.
“It is too soon to predict what the Obama legacy on environmental issues will look like,” said Kathleen Magruder, vice president of U.S. regulatory affairs for BP Energy. “On the one hand, several courts — including the Supreme Court — are reviewing Obama-era regulations, such as the Clean Power Plan. On the other hand, we have a number of states and cities saying they plan to adhere to the goals of the Paris Agreement, even if the United States does withdraw. It will take some time to see how this all lands.”
“Whatever the legal challenge, however they turn out, I think the Obama legacy will have a lasting impact,” said Chris Jones, a partner with Troutman Sanders. “The changes to the fleet nationwide are irreversible. If you have a new federal dictate that coal plants are reliable and resilient … how far does that go? Will investors feel comfortable putting capacity in these coal plants, based on that rule?”
Asked by panel moderator Jimmy Glotfelty, with Clean Line Energy Partners, whether a coal pile is the only way to have a resilient grid, Jones referred to problems caused by last winter’s so-called “polar vortex,” saying: “You need a diverse fleet to manage different challenges. I don’t care how much coal you have on site, when it’s frozen, it ain’t no good.”
Marquez: PUC Relies on Transmission Policies
Texas PUC Commissioner Brandy Marty Marquez sat down with the commission’s director of wholesale market policy, Julia Harvey, for an informal discussion of issues facing the state’s regulators.
Marquez told Harvey the commission may be over-reliant on transmission policy “because it’s the one aspect of the market we can control.”
“We have a really interesting market here in Texas,” Marquez said. “We want it to be free, but boy, the lights better stay on. That’s a tricky balance.”
Asked by an audience member what generation owners should do with their older, out-of-the-market plants, Marquez said that’s a decision market participants need to make.
“It can be argued one of the challenges we have in Texas is that we have too much power,” she said. “Everyone’s waiting for that shoe to drop. If it were me, I’d probably want to hang on for as long as possible. We hear from [market participants] we’re not seeing scarcity pricing, but when there’s not a lot of scarcity, there’s not a lot of scarcity problems. That’s not a bad problem to have, because power is cheap.”
Advanced Technologies: A Boon or a Challenge?
Wires company representatives discussed their learning experiences with advanced technologies such as smart meters, distributed energy resources and microgrids, and the challenges they pose.
“It’s forced us to be more thoughtful about how we’re stepping into the future,” said CPS Energy’s Rudy Garza, vice president of distribution services and operations. “We’re still trying to figure out how we want to position ourselves.”
With its New Energy Economy program, CPS is partnering with renewable developers and businesses that “share [its] vision for clean energy, innovation and energy efficiency.” Garza said the utility has deployed 85% of its smart meters to residential customers.
“I don’t think there’s any utility out there that has figured it out. Those that are out there playing and trying to understand these technologies will get there a little quicker,” Garza said. “Now we have all this information we didn’t have before. We have to match [the data] to know where outages are happening or know where they might happen. That’s the future. That helps save dollars, before the trucks start to roll or the trouble calls start to come.”
Bob Bradish, American Electric Power vice president of grid development, said his company has installed one battery storage system in Texas, with the understanding from the PUC “that this was a one-and-done type of deal.”
“When you look at those technologies as an alternative to transmission solutions, there is a difference to what they bring to table,” Bradish said. “Transmission will bring additional capacity, it will bring permanence. It can be there for 90 to 100 years. How long is a battery, or a DER, going to be there? What is its reliability going to look like? You’re going to have to get comfortable with that.”
“Batteries are coming faster than maybe mankind can appreciate,” CenterPoint Energy’s Kenny Mercado said. “As that demand grows, we’re going to be learning about its behavior. With our regulated responsibility, we have to think about [batteries] differently. We have to be more insightful about their functionality, their capability. Like the advanced meter, it’s owned by the utility, but its [data] is used by the market. The market wins.”
Mercado noted the advanced technologies do have their drawbacks, a point that was driven home when Hurricane Harvey submerged much of CenterPoint’s system.
“When they’re submerged in water, they don’t work. They won’t tell you if they’re drowning,” he said.
ARLINGTON, Va. — Newly appointed FERC Commissioner Robert Powelson, a former Pennsylvania Public Utility Commissioner, seemed at ease last week as he addressed the annual meeting of the Organization of PJM States Inc. He cracked jokes and shared memories with fellow regulators, RTO officials and stakeholders.
But when the subject turned to the Department of Energy’s recent proposal that FERC promulgate rules to support generators that can stockpile 90 days of fuel in deregulated states, he became emphatic.
“I will not support anything that undoes the value of the market,” he said Wednesday. “I remind everybody in this room, we are an independent agency. … FERC does not do politics.
“I give Energy Secretary [Rick] Perry credit. He’s trying to be thoughtful in the approach, but there’s many different approaches to how we can tackle this issue. I did not sign up for blowing up the markets,” he said to a round of applause. “We will not destroy the marketplace.”
The comments were in response to concerns that DOE’s Notice of Proposed Rulemaking would drive large subsidies to nuclear and coal units that would make competition untenable. (See Consumer Advocates Slam Perry NOPR, RTOs, FERC.)
Commissioner Cheryl LaFleur seconded Powelson’s vow “not to destroy” the markets, tweeting, “Great message!”
Perry Defends NOPR
On Friday, Perry defended the NOPR, saying it was not an order to the independent commission, but an effort to begin a “conversation” on the loss of baseload generation.
“I think it’s really important for people to understand, in general terms, there is no free market in the energy industry,” he told a meeting of the group Veterans for Energy, according to an account in The Hill. “And anybody that gets up and says that is lying — is not, with all due respect, educated as to what the reality of the market is.”
Perry said he was attempting to reverse the policies of the Obama administration, which he said, “had their thumb on the scale” to help out renewables to the “detriment … of reliable, baseload industries that are really important for the future security of this country.”
The commission last week issued a notice inviting comments on the NOPR (RM18-1). Comments are due by Oct. 23, with reply comments due Nov. 7.
Other Controversies
In his speech to OPSI, Powelson also referenced several other controversial issues before the commission, without explicitly identifying them.
“Dallas Winslow, do you have a question for me?” he asked the chairman of the Delaware Public Service Commission.
Delaware has been fighting use of the solution-based distribution factor (DFAX) cost-allocation method for Artificial Island upgrades, PJM’s first competitively bid project under FERC Order 1000. The original allocation left the Delmarva Peninsula on the hook for much of the project’s $280 million cost, but PJM has proposed alternative allocations that would shift much of the bill to New Jersey and Pennsylvania. (See PJM: AI Costs Would Shift to NJ, PA Under New Allocations.)
Winslow laughed but did not ask a question.
Powelson also hinted at action on natural gas pipelines, saying, “We love infrastructure, so we’re going to work on infrastructure — New Jersey included.”
The proposed 120-mile PennEast Pipeline — which would transport Marcellus Shale gas from northeast Pennsylvania to central New Jersey — is facing opposition from landowners in both states. In April, FERC staff filed their environmental impact statement on the project, concluding that it would have “less than significant” environmental effects (CP15-558).
MISO last week said it expects to have plenty of reserve capacity to cover upcoming winter operations, even as it announced a review of an emergency declaration made on the first day of fall when a heat wave pushed reserves to their acceptable limits.
The RTO’s preliminary forecast predicts a 28.3 to 37.3% reserve margin this winter, with about 142 GW of capacity on hand to meet an anticipated peak load of 103.4 GW, according to Rob Benbow, MISO senior director of systemwide operations.
“I would say this is a little colder-than-normal winter, but not by much. This is pretty typical of the last few years,” Benbow said during an Oct. 5 Reliability Subcommittee meeting.
MISO’s all-time winter peak of 109.3 GW occurred Jan. 6, 2014, during the so-called “polar vortex.”
Final values for forecasted winter capacity will be presented Nov. 6 at a MISO Winter Readiness Workshop.
| MISO
Benbow reminded stakeholders that MISO’s gas usage profile-sharing program will begin in December. Under the pilot program aimed at improving gas-electric coordination, the RTO will share hourly day-ahead gas usage profiles with a trio of selected gas system operators. (See FERC Approves MISO Plan to Share Generator Gas Data.)
Mark Thomas, electric-gas operations coordinator, said MISO is collecting data for its fourth annual gas-fired generation winter fuel survey, which focuses on generators’ winter preparedness efforts. Thomas said 87% of MISO’s gas-fired capacity participated in last year’s survey.
September Emergency
But even as MISO transitions to colder weather, it plans to review emergency operations spurred by an unexpected late summer/early fall heat wave.
MISO staff will offer a more detailed report on a late September maximum generation event during its Oct. 12 Market Subcommittee meeting, Benbow said.
| MISO
The event began to unfold 11 a.m. on Sept. 21 when the RTO initiated conservative operations measures in response to average temperatures reaching nearly 90 F, which produced a peak load approaching 109 GW. Peak load hit 114.7 GW the following day when temperatures climbed to 92 F, prompting MISO to declare a maximum generation event between 2 p.m. and 6:15 p.m. ET. The RTO declared another emergency warning Sept. 23 and finally lifted conservative operations at 8 p.m. on Sept. 26.
Benbow said a mixture of record temperatures, high load, and seasonal and forced generation outages contributed to the “challenging conditions.”
“Typical load this time of year might be 80 GW and even lower on the weekend,” Benbow said. “This heat dome was really caused by hurricanes stalling the [weather] system in our footprint.”
Benbow said the planning model did not forecast such extreme temperatures, and MISO staff are reviewing the RTO’s actions ― along with the outages ― leading up to the event. MISO has considered a possible expanded role in outage coordination since its Independent Market Monitor earlier this year recommended the RTO have a greater say in approving outages to reduced costs and instances of emergency situations. (See MISO in Harmony with IMM State of the Market Report.)
Some stakeholders last month also voiced support for more sophisticated outage planning between generators and transmission owners.
“I don’t believe that anyone had to shed load at any time. … Congratulations for keeping it together,” Indianapolis Power and Light’s Lin Franks said of MISO’s latest emergency declaration.
Benbow confirmed that no load shedding occurred during the five-day event.
AUSTIN, Texas — Appearing before the Gulf Coast Power Association’s Fall Conference last week, Texas Public Utility Commissioner Brandy Marty Marquez was asked about the retirement decisions facing owners of out-of-market coal plants.
“Everyone’s waiting for that shoe to drop,” she responded.
On Friday, the first pair hit the floor when Vistra Energy announced plans to retire three aging coal-fired units in East Texas. The Monticello units date back to the 1970s and have a capacity of 1,880 MW, rendered obsolete by ERCOT’s record low prices.
Vistra CEO Curt Morgan blamed the market’s “unprecedented low power price environment” as having “profoundly impacted” the plant’s operating revenues. He said the market, flooded with cheap renewable energy and low-cost gas generation, “no longer supports continued investment.”
Morgan alluded to the coming retirement announcement when he told the GCPA his company was “assessing the viability of our generation fleet.”
“We are willing to lead in this area, although we believe we are not the only ones who need to undertake some hard decisions,” he said.
Vistra’s decision was not unexpected. Executives told financial analysts in August it was considering retiring some of its coal plants and would make a decision in the fourth quarter. (See Analysts Debate Potential Vistra Coal Retirements.)
Luminant, Vistra’s generation arm, has two other 1970s-era coal-fired plants in Big Brown and Martin Lake. The plants, with 3.7 GW of capacity, have combined capacity factors of 59% and 52%, respectively. Luminant’s 18 GW of capacity includes 8 GW of coal-fired generation and 7.5 GW of gas.
Luminant’s Monticello Power Plant | Luminant
The Monticello units began life as a lignite mine mouth operation, but they switched to Powder River Basin coal in 2016.
Luminant filed a suspension-of-operations notice with ERCOT that triggered a reliability review. If the ISO determines the units are not needed for reliability reasons, Luminant expects to stop plant operations on Jan. 4, 2018.
Vistra estimates it will record one-time charges of approximately $20 million to $25 million in the third quarter of 2017 related to the retirement, including employee-related severance costs. Luminant has estimated the closure will affect about 200 employees.
ERCOT has also received suspension notifications for three smaller gas-fired units.
The City of Garland told ERCOT on Oct. 2 it plans to indefinitely suspend operations of two of its Spencer plant’s units, totaling 118 MW of capacity, in January. The units went into service in 1966 and 1973.
On Sept. 27, Talen Energy said it plans to retire a 330-MW gas unit at its Barney Davis plant near Corpus Christi in December. The unit went into service in 1974.
ARLINGTON, Va. — The panels at the Organization of PJM States Inc.’s annual meeting last week took on a wide variety of topics, but two themes rose to the top: cheap natural gas from local shale deposits has undoubtedly upended the electricity industry; and no matter how pure a market is, nothing will prevent the taint of politics.
“Politics sort of have everything to do right now in the energy market space,” said Susan Bruce, who represents the PJM Industrial Customers Coalition. “Low natural gas prices may have an adverse effect on certain PJM market participants, but as a general matter, the shale gas revolution should be viewed as a real positive for our region. Businesses make decisions to site here because of that. If we mute that in some fashion to give competitive advantage to others, I think we, looking at the issues as a whole, have done ourselves a disservice from an economic perspective.”
State regulators agreed. In the meeting’s opening panel, regulators of several PJM states tracked the current debate over providing subsidies to nuclear units — most notably through Illinois’ zero-emissions credit program — back to the low gas prices suppressing auction results so that “generation owners are not making enough money in the marketplace,” said Asim Haque, chair of the Public Utilities Commission of Ohio.
“If the power markets are just going to now be about state and federal politics, I think we’ve got a problem,” Haque said. “I worry where our collective heads are at. I worry that we’re all going to continue to be entrenched in our state policy and political objectives. … I do have fears of a full-on accommodation of all state subsidies.”
Pennsylvania Public Utility Commission Chair Gladys Brown noted her commission traditionally protests efforts to introduce unit-specific subsidies. The Pennsylvania legislature has developed a large pro-nuclear caucus and held two hearings on developing financial support for the state’s nine nuclear units, she said, but “we as a commission still have not been called over to provide any type of testimony.”
“It’s a catch-22 because we want access to that cheap natural gas, but they also know we’re a diverse state and we have so many other things that we could offer in terms of generation,” she said.
Illinois Commerce Commissioner John Rosales said he was “proud” of his state’s ability to coalesce around the issue and decide to support nuclear generators. “It was the right decision,” he said. “I realize there’s always going to be some political attributes that come into play.”
Kentucky Public Service Commissioner Talina Mathews noted that her state “loves to say how different it is” as one of the few in PJM that is fully regulated, has no renewable energy portfolio, energy efficiency standards or carbon emission goals, and remains a staunch advocate for coal use.
Still, she joined other regulators in defending states’ abilities to make decisions for their residents.
Differing Priorities
When asked what changes to the capacity market they endorse, only New Jersey Board of Public Utilities President Richard Mroz would say he favors a redesign that supports nuclear, saying “there are other attributes that are not being valued that should be valued.”
“I do not know who to trust anymore,” he said. “On the state side, you’ve just got different priorities developing. You’ve got different priorities developing in different states,” he said. “This is the sort of implicit cooperation that’s supposed to exist between the states when we’re all in this marketplace together, and Ohio unequivocally — when we made our [power purchase agreement] decisions [to subsidize some in-state generation units] — was a violator of that implicit cooperation.”
He said that Ohio is taking a different position now.
“The decision that I made when I was sworn in as the chair in 2016 was that the PUCO was out of the generation business,” he said. “Our advocacy now going forward will very much be tailored around trying to be constructive with that cooperation the best we can until we get to a breaking point where I think I’ve got to protect Ohioans. … We will start to become very active if I think that my residents and my businesses are going to be asked to stand on the Titanic.”
In a lunchtime address, PJM CEO Andy Ott explained that gas-fired units used to be on the margins of receiving enough revenue to cover their costs. However, they were small and flexible enough to turn on and off quickly as prices dictated. Cheap gas has allowed those units to offer into the market so low that they can always run and don’t have to respond to price signals. That has pushed large, inflexible units to the margin, where they can’t respond to price changes quickly, or at all. So that attribute of flexibility, which was previously inherent to the system, now needs to be valued in the market, he said.
“Hopefully, we’re not trying to solve a political problem,” he said.
Kathleen Barron, Exelon’s senior vice president for government and regulatory affairs, said markets are adjusting to state preferences. Her comments seemed to echo those made by James Wilson of Wilson Energy Economics, who consults for several state commissions and has argued at PJM stakeholder meetings that markets can absorb state actions given enough time and information. Tonja Wicks, who oversees FERC and RTO affairs for Duquesne Light, said her company has concluded the existing capacity design is the right one for now.
It wasn’t a surprise that Barron supported her own company’s proposed revisions, but she acknowledged, “I think we have a ways to go to make sure that what we actually adopt is fair to customers.”
Part of that may be because “we’re talking about different kinds of subsidies” that forestall exit from the market rather than incentivize entry as other state policies have done, said Marji Philips, Direct Energy’s director of RTO and federal services. They’re also targeted at a few very large units rather than many smaller ones.
“It’s about politics, and it’s really hard to price politics,” Philips said.
“What it really gets down to is investor confidence,” said Steve Schleimer, Calpine’s senior vice president for government and regulatory affairs.
There are trusted ways to secure a return on investments in competitive and regulated environments, but “where it’s part-competitive and part-regulated … that’s not stable.”
Split Over Cost Containment
In a separate session, stakeholders split on whether to factor cost-containment guarantees into proposals for transmission development.
PJM’s Craig Glazer said the RTO could consider caps on construction costs but isn’t prepared to determine whether other guarantees are suitable. He said PJM should “stay in our lane,” and Gloria Godson, vice president of federal and PJM policy for Exelon’s Pepco Holdings Inc., agreed.
However, Sharon Segner, vice president of power development for LS Power, disagreed.
“We have a lot of reservations about that policy. If PJM is going to take [the opposite perspective of] every other RTO on cost containment, that’s a discussion that should go on with FERC,” she said.
She and West Virginia Consumer Advocate Director Jackie Roberts said they were willing to pay extra to develop a “robust” independently administered evaluation process. Roberts suggested a plan in which proposals would be requested during a certain time frame and submitted using the same form so they could create “an apples-to-apples” comparison. The current system allows developers to submit proposals in any form they wish.
“If my money’s being spent, I want to know that the most creative solution is being proposed and that everybody is on a level playing field to fix that solution. This is what all businesses do, and the fact that it has not come to transmission planning is because PJM has been trying very hard to fix its time constraints,” Roberts said. “You just don’t have time for that, but others do. … I’m convinced that consumers will be better served by a real bid process that puts the risk of the business on the people making the bids, who are the people who know what the risks are and should bear them. That’s something that I’m willing to get my checkbook out for.”
EPA will repeal the Clean Power Plan, saying the Obama administration’s call for switching to more natural gas and renewable generation exceeded the agency’s authority.
According to a draft rule leaked last week, EPA will contend that Section 111(d) of the Clean Air Act requires emission regulations be based on reductions that can be applied at a single source.
“Instead, the CPP encompassed measures that would generally require power generators to change their energy portfolios through generation-shifting (rather than better equipping or operating their existing plants), including through the creation or subsidization of significant amounts of generation from power sources entirely outside the regulated source categories, such as solar and wind energy,” said the 43-page proposal, which numerous news sources obtained last week.
That is the same interpretation of Section 111(d) that EPA Administrator Scott Pruitt espoused as Oklahoma attorney general, when his state and more than two dozen others challenged the CPP in court. In August, after President Trump issued an executive order directing EPA to review the CPP, the D.C. Circuit Court of Appeals agreed to hold the challenges in abeyance. (See Trump Order Begins Perilous Attempt to Undo Clean Power Plan.)
President Trump signing his executive order seeking to undo the Clean Power Plan as coal miners, Interior Secretary Ryan Zinke, EPA Administrator Scott Pruitt and Vice President Mike Pence watch.
Pruitt told a gathering in Hazard, Ky., on Oct. 9 that the repeal will be formally announced on Tuesday. “Here’s the president’s message: The war on coal is over,” Pruitt said.
“Regulatory power should not be used by any regulatory body to pick winners and losers,” Reuters quoted Pruitt. “The past administration was unapologetic. They were using every bit of power, every bit of authority to use the EPA to pick winners and losers on how we generate electricity in this country. And that’s wrong.”
An EPA spokeswoman last week declined to comment on the authenticity of the leaked draft but issued a statement saying, “Any replacement rule that the Trump administration proposes will be done carefully and properly within the confines of the law.”
Building Blocks
EPA said it will seek to repeal the rule because two of the three “building blocks” in the CPP — switching from coal to natural gas and to renewables from fossil fuel plants — exceed the agency’s authority. The third building block, improving the heat rate of coal-fired plants, “could not stand on its own,” EPA said.
“Any potential future rule that regulates [greenhouse gas] emissions from existing EGUs [electricity utility generating units] under CAA Section 111(d) must begin with a fundamental re-evaluation of appropriate and authorized control measures and recalculation of performance standards,” it said.
Going forward, EPA said it will interpret the CAA’s “best system of emission reduction” as referring to measures “that can be applied to or at an individual stationary source. That is, such measures must be based on a physical or operational change to a building, structure, facility or installation at that source, rather than measures that the source’s owner or operator can implement on behalf of the source at another location.”
Repeal and what?
Now that Pruitt has decided on his legal strategy for undoing the CPP, he must develop an alternative response to the Supreme Court’s 2007 ruling that carbon dioxide is a pollutant that EPA must regulate. The draft indicated EPA will not seek to reverse the agency’s 2009 finding that GHGs endanger public health. “The substance of the 2009 endangerment finding is not at issue in this proposed rulemaking, and we are not soliciting comment on the EPA’s assessment of the impacts of greenhouse gases with this proposal,” the draft said.
The agency said it will solicit comments in an Advanced Notice of Proposed Rulemaking “in the near future” on systems of emission reduction applicable at individual sources. Developing a replacement regulation could take years.
The new interpretation will “substantially [diminish] the potential economic and political consequences of any future regulation of CO2 emissions from existing fossil fuel-fired EGUs,” the agency said.
EPA’s new regulatory impact analysis projects the repeal will save $3.7 billion in compliance costs in 2020, rising to $33.3 billion in 2030, while forgoing pollutant benefits of $1.6 billion to $21.5 billion over the same period. The analysis, which is based on a 3% discount rate, includes only the benefits of reducing CO2, unlike the Obama administration’s estimate, which also included the co-benefits of reduced SO2 and NOX emission reductions.
The Obama EPA said the CPP would produce net benefits of $26 billion to $45 billion in 2030.
The CPP would have required a 32% cut in emissions below 2005 levels by 2030. EPA previously estimated that “inside-the-fence-line” plant modifications, such as equipment upgrades and adoption of best practices, would improve average coal plant heat rates by 4%.
‘Wholesale Retreat’
Former EPA Administrator Gina McCarthy, who shepherded the CPP during the Obama administration, blasted her successor’s proposal.
“A proposal to repeal the Clean Power Plan without any timeline or even commitment to propose a rule to reduce carbon pollution isn’t a step forward; it’s a wholesale retreat from EPA’s legal, scientific and moral obligation to address the threats of climate change,” she said in a statement.
McCarthy also made an apparent reference to Energy Secretary Rick Perry’s Sept. 28 directive to FERC urging it to ensure that nuclear and coal generation in deregulated states with 90-days on-site fuel supply receive “full recovery” of their costs. (See related story, ICF Analysis: DOE NOPR Cost Could near $4B/Year.)
Coal plant | NOAA
McCarthy said the administration “is using contrived problems with our energy system to take money out of consumers’ pockets and giving it to fossil fuel companies, so they can force a shift away from clean energy and back to dirty fossil fuel. That not ‘back to basics,’ that’s just plain backwards.”
Clean Energy ‘Accelerating’
Some environmentalists have said a plant-specific approach could make a significant dent if it went beyond efficiency improvements to include switching to natural gas or installing carbon capture — though it would be more expensive.
Despite the repeal, “the transition to a clean energy future is accelerating,” insisted Charlie Jiang, a climate and energy associate for the Environmental Defense Fund, wrote in a blog post.
He cited carbon-reduction pledges announced by states and cities in response to Trump’s decision to withdraw from the Paris Agreement, and utilities’ continued move to renewables from coal. Wind and solar comprised more than 60% of utility-scale generating capacity added in 2016; in March, wind and solar totaled more than 10% of U.S. electricity generation for the first time ever.
As of the end of 2016, CO2 emissions from U.S. generators was already 25% below 2005 levels, “meaning the power sector is already almost 80% of the way to achieving the Clean Power Plan’s 2030 targets,” Jiang said.
Industry also is making the switch. At a House Energy and Commerce Committee hearing last week, a Walmart executive said the company seeks to obtain half of its energy from renewable sources 2025 — up from 25% in 2015. “It is a win-win,” said Mark Vanderhelm, Walmart’s vice president of energy. “Green power is more cost effective than brown power.” (See Consumer Advocates Slam Perry NOPR, RTOs, FERC.)
Left to right: Zinke, Pence, Trump, Perry and Pruitt
In addition, the Trump administration’s efforts to reverse Obama’s environmental rules have run into opposition in the courts. Last week, a federal magistrate in California vacated the Interior Department’s plan to delay implementation of rules curbing flaring of methane — the third time in three months that environmental rollbacks have been rejected by courts, according to a report in The New York Times. The administration also has withdrawn three rule changes in the face of legal challenges, the Times reported.
Consumer advocates on Thursday urged Congress to pressure FERC to improve the RTO stakeholder process and reject Energy Secretary Rick Perry’s directive to rescue at-risk coal and nuclear generation in competitive markets.
The House Energy and Commerce Committee hearing was called to consider consumers’ ability to participate in RTO/ISO decision-making. But the witnesses — and some Democratic committee members — also used the opportunity to tee off on Perry’s Sept. 29 Notice of Proposed Rulemaking, which would require RTOs to provide “full recovery of costs” for generators with a 90-day on-site fuel supply that are not subject to state or local cost-of-service rate regulation. (See FERC’s Independence to be Tested by DOE NOPR.)
Testifying before the House Energy and Commerce Committee Thursday were (from left) PJM Independent Market Monitor Joe Bowring; Rebecca Tepper, Consumer Liaison Group for ISO-NE; Mark Vanderhelm, Walmart; John Hughes, Electricity Consumers Resource Council;Stefanie Brand, N.J. Division of Rate Counsel, and Tyson Slocum, Public Citizen.
No one at the Energy Subcommittee hearing spoke in favor of Perry’s proposal, which called on FERC to develop a final rule providing RTOs with direction within 60 days. (Perry will be testifying before the committee next week.)
Consumer advocates from New Jersey and Massachusetts and representatives for Public Citizen and industrial consumers testified along with PJM’s Independent Market Monitor.
Slocum
Tyson Slocum, director of Public Citizen’s Energy Program, was the most critical witness, citing a “triple threat” to consumers posed by “political efforts by owners of mismanaged and uneconomic generation seeking subsidies; regional transmission organizations constructed to serve transmission and generator interests at the expense of the public interest; and a FERC that fails to uphold just and reasonable rate design, oversight and enforcement.”
No to Coal, Nuclear Subsidies
Slocum said Perry’s proposal “reads more like a President Trump tweet than a reasoned, serious policy proposal,” joining other witnesses in rejecting Perry’s claim of a resiliency “crisis.”
“Even more shocking than the Department of Energy’s proposal is FERC’s response to fast-track its consideration, with its order giving the public only 21 days to provide initial comments on the DOE rulemaking,” Slocum said.
Bowring
PJM Monitor Joe Bowring said the RTO’s market “has resulted in a reliable system despite significant changes in underlying market forces … [working] flexibly to address both market exit and entry without preferences for any technologies.”
He dismissed concerns over fuel diversity, saying PJM’s is higher than ever.
“There is no reason to intervene in the markets in order to provide reliability and resilience,” he said. Concerns over natural gas supply interruptions would be better addressed through “a careful evaluation [of] the reliability of gas pipelines, the compatibility of the gas pipeline regulated business model with the merchant generator market business model, the degree to which electric generators have truly firm gas service and the need for a gas RTO to help ensure reliability,” he said.
Hughes
John P. Hughes, CEO of the Electricity Consumers Resource Council, which represents industrial consumers, said the NOPR would result in “the destruction of the competitive wholesale electric markets.”
By proposing out-of-market payments to prevent plant retirements, he said, “DOE is saying manufacturing jobs are not as important as the jobs at economically obsolete coal-fired and nuclear power plants — plants for which the market has already provided much more economic alternatives.
“We know that coal-fired and nuclear plants are not immune from so-called Black Swan events such as hurricanes, tornadoes, earthquakes and tsunamis,” he added.
Hughes said grid operators can ensure sufficient supplies of “essential reliability services” such as frequency response through markets and without subsidies.
He criticized FERC, saying it “backtracked from its policy to favor market-based solutions over command-and-control” when it issued a proposed rulemaking in November 2016 requiring all new generators to provide primary frequency response. (See FERC: Renewables Must Provide Frequency Response.)
A FERC spokeswoman said the commission had no response to the criticism at the hearing.
Mark Vanderhelm, Walmart vice president of energy, also made a plug for markets. “When we compare our cost per kilowatt-hour in 2016 to our cost per kilowatt-hour in 2007, we find that our cost in customer-choice jurisdictions decreased by almost 7% on average. In contrast, our cost in jurisdictions without customer choice increased by 14%,” he said.
‘Arbitrary’ Fuel Requirement
Slocum said DOE’s call for 90 days of on-site fuel was “arbitrary.” He noted that during Hurricane Harvey, the coal piles at NRG Energy’s W.A. Parish plant in Texas were so soaked with water that the plant switched two units to natural gas for the first time since 2009, and that Florida lost much of its nuclear generation during Hurricane Irma because of precautionary shutdowns and mechanical problems.
Green
Rep. Gene Green (D-Texas) noted that NRG’s San Jacinto natural gas plant kept operating despite receiving 47 inches of rain. “Natural gas was by far the largest [electric] provider during the storm, although I can also say our nuclear power plant in Southeast Texas continued to function very well,” Green said. “It’s frankly just not the case that increasing natural gas-fired plants is threatening reliability of the grid.”
Rep. Frank Pallone (D-N.J.) criticized what he called Perry’s “ill-conceived and wholly unjustified effort to commandeer” the FERC rulemaking process.
“Subsidizing noncompetitive generation for a small, if any, grid benefit at massive expense to consumers is wrong,” Rep. Paul Tonko (D- N.Y.) said. “And it definitely should not be done through a rushed process.”
Energy Subcommittee Vice Chairman Pete Olson (R-Texas) also indicated concern over the proposal, citing FERC Commissioner Robert Powelson’s speech to the Organization of PJM States Inc. (OPSI) annual meeting Wednesday, at which he stressed FERC’s independence and sought to reassure those who fear the rule would destroy competitive markets.
“[Powelson] said regarding concerns if the rule does undo competitive markets, quote, ‘When that happens, we’re done. I’m done,’” Olson recounted.
“Wow!” Olson added. “That is pretty strong.”
Commissioner Cheryl LaFleur seconded Powelson’s vow “not to destroy” the markets, tweeting, “Great message!”
Consumers’ Voice in Stakeholder Process
The witnesses were also critical of FERC’s and RTOs’ efforts on behalf of consumers.
BrandTepper
Stefanie Brand, director of the New Jersey Division of Rate Counsel, and Rebecca Tepper, chairman of ISO-NE’s Consumer Liaison Group, said RTOs should explicitly consider consumer costs in their policymaking and transmission planning, noting that generation and transmission costs account for 60% of customers’ bills in their states.
They said RTOs should provide dedicated funding to ensure consumer advocates can attend stakeholder meetings — as enjoyed by the Consumer Advocates of PJM States and the New England States Committee on Electricity.
Tepper, chief of the Massachusetts attorney general’s energy and telecommunications division, said RTOs should provide cost impact analyses on all major proposals and require that at least one RTO board member has “experience in consumer issues” or serves as a consumer liaison.
Slocum, who criticized RTOs as “political entities designed to serve entrenched economic interests,” called for increased transparency, saying stakeholder meetings should be recorded and transcribed and that RTOs be subject to the Freedom of Information Act.
He also called for splitting RTO functions to limit management’s role in stakeholder meetings; establishing a two-year “revolving door” prohibition on state regulators and utility executives going to work for an RTO; and barring entities under RTO jurisdiction from serving as financial sponsors of RTO special events.
He had specific criticism for PJM’s sector-weighted voting process, which he said appears “to be designed for the primary purpose of expanding the voting power of transmission owners and generators, and diminishing the voting power of end users.”
“End users actually represent half of the energy system, and should therefore represent half of the weighted sector voting rights,” he said. PJM’s consumers are grouped in the End Users sector, and receive a 20% weighting like the four other sectors: Transmission Owners, Generation Owners, Other Suppliers and Electric Distributors.
Asked to respond to the criticism, PJM spokesman Ray Dotter said the RTO saves consumers $3 billion annually and runs an “open and inclusive” stakeholder process.
“PJM’s governance is designed to ensure that no membership sectors have undue influence and has been approved by the FERC. At the same time, our independent board is empowered to act without the consent of members when it determines that market rule changes are necessary – and it has done so,” Dotter said in a statement. “Nevertheless, such rule changes must be considered and approved by the FERC.”
Transmission Spending
Pallone
Rep. Pallone asked Brand about a report released Sept. 29 by American Municipal Power that found more than half of the $24.3 billion in transmission projects in PJM since 2012 were supplemental projects initiated by TOs and not required to comply with RTO or federal reliability requirements. (See Report Decries Rising PJM Tx Costs; Seeks Project Transparency.)
Brand said the TOs propose supplemental projects “because they’re incredibly lucrative.”
“Returns on transmission are huge, so everyone wants to build whatever they can,” she said. “The need for the projects is not adequately reviewed at PJM. … The returns that are granted by FERC for transmission are completely off the charts. Some utilities are getting close to a 12% return on these projects, which in this economy is a bit crazy.”
FERC
Brand, speaking on behalf of the National Association of State Utility Consumer Advocates, said FERC also needs to do more to create “consumer friendly” proceedings. “Nearly all proceedings are conducted on paper, with limited opportunity for public input. Evidentiary and public hearings are rare. … There is no opportunity for cross-examination if factual certifications are submitted, and there is no oral argument on the legal or policy issues.”
Slocum repeated his call for FERC to provide funding for intervenors representing the public before the commission so that they can afford attorneys and expert witnesses.
CAISO is facing criticism over fundamental aspects of an initiative meant to keep needed generating resources from retiring prematurely, with state regulators saying the program will fail to meet its goals and others questioning the ISO’s rationale for the plan.
The ISO faces the challenge of aligning the risk-of-retirement program with resource adequacy (RA) contracting in order to prevent double-paying resources for reliability. Market participants have carefully analyzed the plan’s two proposed windows in April and November of each year to apply for a Capacity Procurement Mechanism Risk-of-Retirement Enhancements (CPM ROR) designation. (See CAISO Finalizes Risk-of-Retirement Program Changes.)
The La Paloma generating plant filed for bankruptcy in late 2016 after being refused permission to suspend operations | Kern County Public Health Services Department
In comments filed this week regarding CAISO’s draft final proposal for the program, the California Public Utilities Commission and Office of Ratepayer Advocate (ORA) said they oppose the current version of the initiative, which the Board of Governors is due to vote on at its Nov. 1-2 meeting.
PUC staff in comments said that inclusion of the April window within the CPM ROR process gives resources undue insight into RA program price discovery. The process must also better align with the ISO’s Reliability-Must-Run and Temporary Suspension of Resource Operations (TSRO) initiatives, the agency said.
The agency said it “remains concerned that moving a CPM ROR determination to a date prior to the conclusion of the year-ahead procurement process will result in front-running the RA bilateral procurement process.”
CAISO has altered the cost threshold requirement for obtaining a “Type 2” designation during the April window, rolling back a previous stipulation that a resource may not submit an ROR request for April unless its costs exceed the CPM soft offer cap. Type 2 refers to a request by an RA or a non-RA resource for designation in the calendar year following the current RA compliance year.
The latest proposal would require that a resource attest that it “reasonably believes” its annual fixed costs meet or exceed certain price thresholds.
But the PUC said that “this change to the proposal does not further mitigate the issue of front running the RA procurement process. If anything, it does the opposite because a generator no longer must demonstrate that its costs are above the soft offer cap, but to only attest that its costs exceed the relevant thresholds.” The agency said that resources could use market power to achieve the procurement vehicle that yields the most revenue.
‘Other Flaws’
The ORA said it does not support the proposal “because it is unlikely to effectively address the issue of early retirement of resources and could significantly increase ratepayer costs.” It said it believes that the program would allow resource owners to know if they are eligible for CPM payments before the RA contracting period begins. Because CPM generally pays more, that would unfairly tilt the bargaining process between load-serving entities and CPM resources.
“Other flaws of the draft final proposal include its failure to define resource retirement, its reliance on anecdotal information rather than a quantification of the currently known risks associated with resource retirements, and the proposal to provide capacity payments to resources before they are needed for reliability,” the ORA said.
The Western Power Trading Forum (WPTF) criticized fundamental elements of the proposal, saying it is struggling to see how the current proposal was not RMR with more obligations on the retiring resource.
WPTF said CAISO should introduce two windows to submit offers for CPM ROR designation “with no obligation to prove costs are above an artificial, irrelevant dataset.” It said the proposal to compare a resource’s costs with average RA contract prices is “ridiculous” since the average price has nothing to do with the current RA market in any one area.
Calpine said that while some resource owners may find the ISO’s modifications workable, Calpine does not.
“The time-crunch imposed on resources is only exacerbated when one imposes a ‘no front-running’ ban on backstop procurement,” Calpine said, calling it a “timing dissonance” that features in other CAISO retirement-related programs as well.
In March, the CAISO board approved the ISO’s request to designate two Calpine natural gas-fired plants in Northern California as RMR despite criticism from several stakeholders. (See CAISO RMRs Win Board OK, Stakeholders Critical.)
NRG’s Encina natural gas plant
While the company does not object to the plan, it does not think the program will be used in any meaningful way by resources making rational business planning decisions. Requests for compensation must be reviewed by FERC, so resources would not know their cost recovery until well into the CPM contract.
CAISO has also proposed that CPM designations become mandatory as RMR designations are, but Calpine opposes that change.
Some Support
The Six Cities group of Southern California municipal utilities said it generally supported the proposal, but suggested some modifications, while CAISO’s Department of Market Monitoring did not oppose it.
The department said the proposal allows resources to know earlier in the year whether they will receive a CPM designation, making it a more viable option for resources considering retirement.
“This is an improvement over the current risk-of-retirement CPM process which occurs too late in the year to be of practical use,” the department said. “Several aspects of the proposal reduce the likelihood that a resource will submit inefficient retirement requests.”
Southern California Edison supported the proposal, while Pacific Gas and Electric said it has “not addressed the current CPM limitations that resulted in using the CAISO reliability-must-run tariff provisions for reliability procurement.”
