MISO last week said it is reviewing stakeholder proposals to improve load forecasts and plan hourly energy delivery on its evolving system, rather than obtaining more forecasts from a Purdue University group.
Executive Director of System Planning Aubrey Johnson said CEO John Bear this summer asked to hold off on committing to continued use of the Purdue State Utility Forecasting Group’s independent load forecast so the RTO could collect alternative proposals for load forecasting from stakeholders.
“He asked us to step back and think about what we’re trying to accomplish,” Johnson said during a special Sept. 7 load forecasting workshop.
In the face of stakeholder criticism, MISO in June abandoned a proposal to have its 140-plus load-serving entities annually assemble four distinct 20-year load forecasts to align with each Transmission Expansion Plan. (See MISO Nixes LSE Load Forecast Plan.) However, stakeholders are now asking for more discussion about MISO’s alternative plan to order four versions of the Purdue forecast, each tailored to one of the futures used to inform MTEP.
MISO said it still plans to pursue four 20-year versions of Purdue’s forecast beginning with the 2020 MTEP, but now it says it wants the university to include monthly forecasts specific to each of the MTEP futures. The RTO is also looking into having third parties supply load shape information on behind-the-meter generation, electric vehicles, energy efficiency, demand response and distributed energy resources.
But MISO said it has been receiving alternative forecasting proposals from stakeholders since last month. Johnson said the RTO is currently working on ways to evaluate the proposals against one another and invited stakeholders to submit more through this week.
MISO now plans to make an announcement on a new load forecasting approach at the November Planning Advisory Committee meeting after holding two more workshops with stakeholders, Johnson said.
“What we’re attempting to do is start a conversation about … why” the forecast needs to change, Johnson said of the workshops.
‘All Hours’
MISO currently plans energy supply around a yearly peak hour on the hottest summer day in its forecasting, though RTO leadership has repeatedly said there is increasing evidence that peak risk occurs throughout the year in all seasons.
“All hours matter in this conversation. In the past … it’s been one peak hour, one dispatch,” said Director of Policy Studies J.T. Smith. “There are a lot of hours and generation mixes that are not being looked at.”
| MISO
Smith said MISO’s current load modeling relies only on historical load shape data, but even MISO’s air conditioning load shape will shift in part because of smart thermostats and hotter days.
MISO adviser Ling Hua said consumption patterns are changing from that of a “sit-down restaurant where the lunch and dinner rushes can be anticipated” to that of a neighborhood bakery.
“In the neighborhood bakery, people walk in and walk out at any time,” Hua said.
“There are risks in the planning environment that we’re not capturing today,” Smith said. “We’re seeing a very baseload-heavy environment turn into something not so baseload-heavy.” In the future, MISO may need to plan transmission for a more localized system, Smith said.
Monthly Forecasts
Hua said MISO hopes to have a 20-year forecast comprising monthly load peak demand and energy forecasts for a “more complete picture of the footprint.” She said the RTO needs more information, including energy efficiency, electric vehicle and load data from non-planning resources such as DR, DER and storage. “Those are really the disruptive technologies right now.”
But she also cautioned MISO not to overburden LSEs with data collection.
Some stakeholders continued to question why MISO needed such a detailed load forecast.
Indiana Utility Regulatory Commission staffer Dave Johnston pointed out that load forecasters failed to foresee the Great Recession that sunk load growth from about 2% to about 0.5% and the shale gas revolution that made natural gas so popular as a fuel source.
“I just throw those out as how different the load forecast can be,” Johnston said. “The need for transmission projects is low because we’re in this low growth era. … Do you have an idea of demand growth … 10 years in the future?”
Smith conceded the impossibility of predicting some trends but said that shouldn’t deter MISO from adopting a more comprehensive approach. He said it may end up that load growth becomes decoupled from economic growth.
“I’m not saying I’m going to be exactly right in my forecast. What I’m looking for is a breakdown of the information,” Smith said.
Alternatives
One stakeholder group has already offered an alternative to MISO’s forecasting proposal.
Members of the Coalition of Utilities with an Obligation to Serve in MISO (CUOS), an ad hoc group of MISO utilities and regulators that has been meeting since 2014, support providing one 20-year baseload forecast that includes monthly non-coincident peak forecasts and monthly energy forecasts. The LSEs’ forecasts would only be used in the MTEP “business as usual” future scenario.
Representing the group, WPPI Energy’s Valy Goepfrich said LSEs could pull from their forecasts and submit separate data on demand served by demand resources, energy efficiency planning resources and behind-the-meter planning resources. She added that, under the CUOS proposal, LSEs would not provide data on demand served by non-planning resources or energy efficiency programs.
Goepfrich stressed that LSE data is integral to whatever forecasting method MISO settles on.
“The LSEs have the best access to their data. That data is proprietary,” Goepfrich said.
Gov. Jerry Brown on Monday signed legislation requiring California to get 100% of its power from renewable and other zero-carbon resources by 2045. He also issued an executive order for the state to achieve carbon neutrality by the same year.
Brown’s actions came as he readied to host a global climate summit in San Francisco and further positioned himself as a policy counterweight to President Trump, who is seeking to withdraw from the Paris Agreement on climate change and undo EPA’s Clean Power Plan.
California Gov. Jerry Brown signed SB 100, a bill that requires the state to have a 100% carbon-free electricity grid by 2045. | Governor’s office
“California is committed to doing whatever is necessary to meet the existential threat of climate change,” Brown said in his signing message for SB 100. “This bill, and others I will sign this week, help us go in that direction. But have no illusions, California and the rest of the world have miles to go before we achieve zero-carbon emissions.”
In addition to requiring investor-owned utilities, publicly owned utilities and community choice aggregators to obtain 100% of their energy from renewables by 2045, the new law sets milestones along the way: 40-44% by 2024; 45-52% by 2027; and 50-60% by 2030. (See Calif. Clean Energy Measure Goes to Governor.)
When the law takes effect in January, California will join Hawaii as the second state to declare its intent to rely entirely on renewable resources such as wind, solar and hydropower.
Brown, meanwhile, will take center stage at the Global Climate Action Summit, with its main events happening Sept. 12-14 at San Francisco’s Moscone Center.
The summit will feature civic and industry leaders from around the world discussing topics such as investments in clean energy, the switch to electric vehicles and the health of the planet’s oceans. Portions of the event will stream live on YouTube, Facebook and Twitter.
The summit and SB 100 are part of Brown’s larger push to deal with climate change as he gets ready to leave office at the end of this year.
In his signing message for SB 100, for instance, Brown reiterated his support for a Western RTO. A bill to begin the process of transforming CAISO into an RTO faltered in the State Senate this year. Similar efforts to create an organized market in the West failed in the two prior years as well. (See related story, Western RTO Proponents Vow To Keep Trying.)
“We must join our neighbors in a power system that integrates utilities across the West,” Brown said in the signing message. “A regionalized electric grid would enhance California’s low-carbon grid by allowing us to share renewable resources with our neighboring states, while reducing costs and increasing resiliency of our grid.”
FERC on Thursday sidestepped yet another dispute between Public Service Electric and Gas and Consolidated Edison, saying a fight over the fate of their shared transmission lines between New Jersey and New York should be resolved in federal court.
The dispute — over two underwater transmission lines compromised by a pier collapse — is evidence of the continuing bad blood over Con Ed’s April 2017 termination of the “wheel” it used to move power from upstate New York to New York City via northern New Jersey.
The damaged B transmission line runs from under the Newport Marina in Jersey City, N.J. (foreground) through Manhattan (background) to Brooklyn. | Newport Associates Development Co.
In May, PSE&G filed a complaint alleging that Con Ed was violating the NYISO Tariff by failing to cooperate in removing dielectric fluid and the transmission cables from the 345-kV B and C lines after B was damaged by a pier collapse in Jersey City, N.J. The lines were built in 1972 and 1980, respectively, to facilitate the former wheeling arrangement.
Federal Court Suit
In June, Con Ed countered by filing suit in U.S. District Court in New Jersey, accusing PSE&G of violating their interconnection agreement by refusing to put the lines back into service.
In a Sept. 6 order dismissing the complaint, FERC said it did not have exclusive jurisdiction over the dispute and declined to assert primary jurisdiction, leaving the matter for the federal court to decide (EL18-143).
The B Line starts at PSE&G’s Hudson Generating Station in Jersey City and terminates at Con Ed’s Farragut Substation in Brooklyn, while the C Line starts in Brooklyn and terminates at PSE&G’s Marion Substation in Jersey City. The transmission lines are housed inside steel pipes encased in concrete.
A 700-foot section of B was damaged in two pier collapses a decade ago, and in 2016 the New Jersey Department of Environmental Protection informed PSE&G that the two lines could be leaking dielectric fluid, an oil used to regulate the temperature inside the steel pipes. The marina owner was sued to remove tons of debris to allow investigation, which showed B to be leaking a gallon of fluid a day. The C Line was de-energized to facilitate the investigation.
Both utilities reported B repaired in August 2017, and they both agree that neither line is leaking now. The U.S. Coast Guard, however, requires the companies to fix the leakage such that dielectric fluid is not seen on the surface of the Hudson River for 15 consecutive days, a requirement they have yet to meet.
‘Pitting Corrosion’
PSE&G said the leak occurred because of “pitting corrosion” after the pier collapse exposed about 700 feet of the steel pipes to river water. Although the initial leak was fixed with the replacement of a 10-foot portion of steel pipe, PSE&G said additional leaks are likely in the unrepaired pipes.
PSE&G asserted that it has authority to unilaterally drain the fluid and remove the transmission cables from its portion of the lines. Con Ed insists its interconnection agreement with PSE&G prohibits it from unilaterally taking the lines out of service; it wants to reintroduce dielectric fluid and re-energize the lines to conduct a test that the Coast Guard proposed.
State and RTO officials lined up on opposite sides of the dispute, with the New Jersey Board of Public Utilities filing comments supporting PSE&G’s complaint, and NYISO and the New York Public Service Commission filing protests opposing it.
NYISO and the PSC said that as interregional transmission facilities, the lines support grid resilience by providing the ISO and PJM with operational flexibility between their service areas. NYISO said its joint operating agreement with PJM allows use of all the phase angle regulators and transmission lines at their border in an emergency.
NYISO also argued that PSE&G’s underlying reason for seeking to remove the lines is that it wants to replace the lines with transmission facilities that will allow it to have more operational control, increasing their commercial value.
PJM said “there is no reliability criteria violation associated with retiring the [B-C lines], even under peak summer conditions,” and that it does not rely on the lines as a part of its black start plan. The RTO also said, however, that if there are resilience benefits “and it is determined to be advantageous to maintain or replace these tie lines,” the utilities should equitably share the cost.
FERC sided with Con Ed in concluding that the B-C interconnection agreements remain effective through 2020.
The commission said it would not assert primary jurisdiction in the dispute because the issue did not raise a policy issue important to its regulatory responsibilities and that “the unique facts and contractual dispute in this case are not broadly applicable to the commission’s policies on interconnection agreements or reliability requirements.”
WASHINGTON — Seeking to persuade a change in FERC policy, the Edison Electric Institute has released a white paper by former Commissioner Suedeen Kelly that proposes raising the hurdles for those challenging transmission owners’ returns on equity.
Kelly, a partner with Jenner & Block who served on the commission from 2003 to 2009, says the commission’s policy of setting ROE complaints for hearing concurrently — or “pancaking” — has increased litigation costs and created uncertainty for TOs.
The iterative filings are a result of FERC’s inability to resolve the cases before the expiration of the 15-month limit on ROE refunds. The pancaked complaints are generally filed shortly after the expiration of the refund period in the earlier, still-pending complaints. (See Playing the ROE Slot Machine.)
“Section 206 of the Federal Power Act mandates a threshold that FERC find that an existing rate is unjust and unreasonable before setting a new rate,” Kelly writes. “By setting complaints for hearing concurrently, without first ensuring that they meet the Section 206 threshold, FERC has created a policy that is not supported by the law, is inconsistent with the intent of Congress, is not workable in practice, and undermines regulatory expectations for a stable and predictable ROE.”
The paper largely repeats arguments Kelly made unsuccessfully in a 2016 EEI protest in the fourth complaint against the New England Transmission Owners (EL16-64).
It cites the “increasing number” of Section 206 complaints FERC has received since 2011. EEI says there were between five to nine complaints filed annually in 2012-2016 and 10 complaints filed in 2017.
FERC declined a request for comment.
In Opinion 531 in June 2014, FERC unanimously adopted a two-step discounted cash flow analysis for determining electric transmission ROEs. Long used for natural gas and oil pipelines, the methodology incorporates long-term growth rates.
The commission then voted 3-1 over its first application of the new formula, tentatively setting the ROE for New England TOs at three-quarters of the top of the “zone of reasonableness,” a departure from the prior practice that used the midpoint in the range. (See FERC Splits over ROE.)
‘Seven Years and Counting’
EEI cites the New England TOs’ case to illustrate its concern over FERC’s procedures.
It resulted from a September 2011 complaint by New England state officials and others that FERC set for hearing seven months later. The administrative law judge proceedings lasted more than a year, resulting in an ALJ initial decision in August 2013.
Opinion 531, almost 11 months later, was followed by a paper hearing that resulted in Opinion 531-A in October 2014, in which the commission decided that gross domestic product is the appropriate long-term growth rate to use in the analysis. In Opinion 531-B in March 2015, the commission rejected rehearing requests, prompting a petition to the D.C. Circuit Court of Appeals, which remanded the case (Emera Maine v. FERC) back to the commission in April 2017.
The court said FERC had failed to establish that the New England TOs’ existing ROE was not just and reasonable before imposing a new one. (See Court Rejects FERC ROE Order for New England.) The case remains pending.
“In sum, the process leading to Opinion No. 531 took over two and a half years,” EEI said. “In the meantime … four subsequent complaints were filed, effectively extending the period under which the New England Transmission Owners’ ROE is subject to litigation to almost seven years (and counting).”
Higher Threshold Sought
Kelly said the commission has been too permissive in setting ROE challenges for hearing.
“Currently, FERC’s practice is to set an ROE complaint for hearing based merely on the presentation of a new discounted cash flow analysis that produces a lower number than the rate on file. This threshold is too low and invites frequent initial and pancaked complaints.”
In response to questions from RTO Insider, Kelly said, “We suggest that where an ROE remains within the zone of reasonableness, a complainant must do more to show that in the particular circumstances of that utility or group of utilities, the evidence shows that the zone of reasonableness is not a reliable indicator of the range of just and reasonable rates. To do otherwise makes the zone of reasonableness almost meaningless as a tool for both the commission and transmission owners and injects significant uncertainty into FERC’s ratemaking processes.”
Attorney David E. Pomper of Spiegel & McDiarmid, who argued the Emera case for Massachusetts, said EEI’s suggestion runs counter to the D.C. Circuit’s affirmation that FERC need not “show that an existing rate is ‘entirely outside the zone of reasonableness’ before it can exercise its Section 206 authority to change that rate.”
“I don’t think they’re going to get the D.C. Circuit to reverse on that,” Pomper said in an interview.
Symmetry
Kelly disagrees with FERC’s reasoning that it must allow the pancaked complaints because Congress intended “symmetry” between the rights of utilities to file for rate increases under FPA Section 205 and the rights of complainants to seek rate cuts under Section 206. “Congress explicitly established different procedures and different burdens of proof” under the two sections, Kelly said.
Section 205 allows a utility to seek new rates at any time, with FERC in what the D.C. Circuit has termed a “passive and reactive role” of determining whether the new rates are just and reasonable. Under Section 206, FERC may change rates on its own motion or in response to a complaint, but only after first finding the existing rate unjust and unreasonable — the requirement the D.C. Circuit said FERC failed to meet in Emera.
“FERC has stretched the intent of Congress by failing to reconcile its justification for allowing pancaked complaints with the legislative history behind the adoption of the 15-month limit on refunds explicitly included in the statute,” Kelly said. “It has also ignored the critical differences in procedures and burdens of proof between FPA Sections 205 and 206.”
Pomper disagreed with Kelly’s interpretation of Congress’ balancing of Sections 205 and 206. “The cost of capital can change rapidly,” Pomper said. While rates have been relatively stable since the inflationary 1970s, “with large federal deficits that might change,” he said.
Kelly argues that in considering whether to set ROE complaints for hearing, FERC should consider how much time has passed since the existing rate was approved and set “a pragmatic time-based threshold within which it will not entertain a new ROE complaint absent extraordinary and compelling circumstances.”
“In the MISO case, complaint No. 2 was filed [and] set for hearing before we had an outcome in complaint No. 1,” said Nina Plaushin, vice president of regulatory, federal affairs and communications for ITC Holdings, in an interview. “So how did FERC determine that that ROE was unjust and unreasonable?”
Chilling Investment?
EEI says the rise in ROE litigation is creating “unpredictability and instability” in returns for transmission assets. Asked for evidence that the uncertainty is making it difficult to raise investment capital, EEI cited only a 2015 report by Wolfe Research, which concluded — based on Opinion 531 and the commission’s rulings on unrelated matters — that “FERC is increasingly out of touch with investors.”
Historical and projected transmission investment (nominal dollars) | EEI
Pomper said there is no evidence TOs are having difficulty raising capital, citing the high level of transmission construction and legal fights over rights of first refusal to build projects. At the annual EEI Financial Conference, “you will see many, many presentations saying ‘look at how much FERC exposure we have,’” Pomper said. “If it was really a negative, you wouldn’t see them touting the investments.”
Plaushin, president of the transmission owner advocacy group WIRES, acknowledged that “it hasn’t been that challenging to get debt.”
“Are people having trouble [raising] equity?” she continued. “I think it’s a very difficult thing to prove or disprove one way or the other.”
There is no doubt, however, that FERC’s ROE determinations can have an impact on utilities’ earnings. In a report following the Emera ruling, Wolfe said an increase of 100 basis points is worth about 3% in earnings per share for Eversource Energy and Avangrid and about 1% for Alliant Energy and Ameren.
Discovery Delays
EEI’s paper contends FERC’s discovery proceedings are causing delays, saying ROE is “a single issue that should not require extensive discovery or lengthy and protracted full trial-type hearings to resolve. FERC has utilized specially designed and narrowly tailored procedures in other, more complex contexts.”
Kelly said FERC should consider shortened discovery and testimony procedures rather than treating ROE hearings like a full rate case. “In a full rate case, the prudence and amount of various cost inputs are determined individually and can require extensive discovery and testimony. Most utilities now have formula rates that predetermine prudence and flow through costs without further review, absent a challenge,” Kelly said.
Pomper responded: “It’s precisely because you’ve got formula rates, where there are only a few stated elements left to be determined by the commission, that we’re now focusing on ROE. It used to be when utilities had stated rates that you’d have few [Section] 206 proceedings because lots of things were changing. Even if cost of capital was going down, other costs were going up.”
As for the length of the proceedings, Pomper says, “I wish it could go faster … but it’s not out of line with how FERC decides all kinds of cases.”
Wrong Problem
Pomper said EEI is “addressing the wrong problem,” saying the real issue is the “range-based” methods used to set ROEs for RTO-wide rates in ISO-NE and MISO, which consider the highest and lowest rates among a utility’s “proxy group.”
“It’s essentially random. It’s completely bogus math and statistics,” Pomper said.
Using the median in all cases would make results “stabler from case to case. You wouldn’t have the reason to come in with a new complaint,” Pomper said. “Fix the method and the procedure would follow.”
Former FERC Chairman Jim Hoecker, now counsel to WIRES, said the group was seeking stability and predictability when it filed its 2013 petition for a policy statement, which led to Opinion 531.
“I know that [then-Chair] Cheryl [LaFleur] struggled really hard in 531 to try and achieve that,” he said in an interview. “But as in all things at the commission, it’s a matter of compromise.”
Plaushin praised Opinion 531 for providing justification for awarding higher ROEs on transmission than states approve for less risky distribution projects. “I don’t want to be negative about the commission because … they made a genuine attempt to work this out,” she said. “Unfortunately, it wasn’t effective the way they wanted it to be and so now [because of the remand] we need a new solution.
“Why we’ve had a delay this long in responding to the remand, I don’t know. It’s been a while.”
Plaushin said although many ROE cases involving individual utilities have been resolved through settlements, that is not practical for the regional ROE cases in MISO and ISO-NE.
“When you’re talking about regional cases with so many utilities involved, it’s very difficult to do a settlement, especially when in some of those cases there are state regulators who are the ones who would have to settle. And, of course, why would they settle for a number that’s higher than what they granted in their own state [for distribution assets]?”
As to those who suggest eliminating pancaked complaints by extending the refund period beyond 15 months, Plaushin said, “I think that we need to be intellectually honest about” what the revised limit should be. “Four complaints — is [that] too long to extend the refund period?
“Obviously the solution to all this is to get these cases adjudicated quicker,” she added. “That would solve a lot of problems for everyone.”
PJM and Monitoring Analytics, its Independent Market Monitor, have agreed on a deal that will extend the Monitor’s contract through 2025 and require the Monitor to submit to an annual independent audit. The agreement was filed for FERC approval Friday (ER18-2402).
In a concurrent filing, the parties also agreed the Monitor will provide to PJM more of the data market participants submit into MIRA, the Monitor’s online database, so participants don’t have to send the data to both the RTO and the Monitor. The additional sharing includes data used in generators’ fuel-cost policies. The filing also requires both parties to inform the other of changes to their systems (ER18-2403).
The new audit requirement “provides for a review intended to ensure that the services being provided to PJM by Monitoring Analytics are being completed consistent with the systems and controls in place for the provision of those services, similar to the reviews PJM conducts of its own systems and controls,” the RTO said in the filing.
The Monitor’s current contract runs through 2019, and stakeholders — particularly state regulators and consumer representatives — have been urging the parties to come to agreement early. (See “IMM Support,” Advocates Push PJM Board for Explanations at Annual Meeting.)
The early agreement also avoids some of the drama of the previous contract, which began in September 2013. As the initial six-year contract, which went into effect on June 30, 2008, neared its expiration, PJM’s Board of Managers announced plans in March 2013 to issue a request for proposals. The Organization of PJM States Inc. joined industrial consumers and cooperatives in protesting the decision, and the parties eventually agreed to an extension. By PJM’s annual meeting in October, a potential crisis had passed. (See Board, OPSI Bury the Hatchet over Monitor Contract.)
FERC on Thursday rejected financial stakeholders’ request for rehearing of its Feb. 20 ruling reducing the number of bidding nodes for virtual transactions (ER18-88-002).
The commission also upheld its rejection of PJM’s proposal to allocate uplift to up-to-congestion transactions (UTCs) as it does to increment offers (INCs) and decrement bids (DECs) (ER18-86).
Virtual Transaction Nodes
The commission said that XO Energy and the Financial Marketers Coalition merely rehashed arguments they had made against the node reduction proposal. (See FERC OKs Slash in Virtual Bidding Nodes for PJM.)
The changes reduce by almost 90% the number of bidding nodes, limiting INCs and DECs to those where either generation, load or interchange transactions are settled, or at trading hubs where forward positions can be taken. They also barred UTCs from zone, extra-high-voltage and individual load nodes. The changes reduced the number of INC/DEC trading nodes from 11,727 to 1,563, and UTC nodes from 418 to 49.
PJM said this trading pattern is “indicative of the low-risk positions that can be extremely lucrative without adding commensurate value to the market,” justifying its proposal to reduce the trading nodes for UTCs. | PJM
FERC did accept PJM’s request to change the effective date for the changes from Jan. 16 to Feb. 22, 2018. PJM said it intended to make the changes prospectively and that in its Dec. 22 response to a deficiency letter the RTO had neglected to change its requested effective date. PJM said the January date would be disruptive to the market, as it would have to remove all virtual transactions at points no longer eligible for bidding and re-execute the day-ahead market.
Commissioner Cheryl LaFleur issued a partial dissent, repeating her assertion that PJM had not justified reducing nodes for UTCs.
“As I stated in my partial dissent, I believe that UTCs provide value to the market and that reduced granularity in their use is a move in the wrong direction,” she said. “I would, however, be open to other solutions more targeted to the specific problems that PJM has identified.”
Uplift for UTCs
PJM complained that in its Jan. 12 rejection of the RTO’s uplift proposal, FERC dismissed the proposal outright, without setting it for hearing, or considering parts of the proposal separately. (See FERC: PJM Uplift Proposal for UTCs Falls Short.)
PJM claimed that, unless its filing was deficient, the commission could only accept the proposal or suspend it for hearing. But FERC said it was under no obligation to set the proposal for hearing. The RTO failed to demonstrate that the proposal would result in just and reasonable rates under Federal Power Act Section 205, the commission reiterated, “as it proposed to treat different financial transactions, with differing characteristics and effects, as if they were the same.”
However, FERC did reverse itself to accept PJM’s proposal to exclude internal bilateral transactions from uplift calculations, which the RTO said the commission should have considered separately. The commission directed PJM to submit a compliance filing in 30 days implementing the change.
PJM can still propose a different way to allocate uplift to UTCs, as FERC had dismissed the proposal without prejudice. “We also note, however, that any such hypothetical, future filing must address the concerns noted above, including the commission’s concern with PJM’s proposal to allocate uplift to a UTC as though it were two separate transactions, an INC and a DEC,” the commission said.
WASHINGTON — Public power representatives reiterated their case against mandatory capacity markets last week, teaming with wind and solar advocates for a one-day conference as a forum for their criticism.
“After spending or committing over $130 billion … in capacity payments in ISO-NE and PJM, I can safely say that almost nobody is happy with the state of those markets, which remain in a state of flux,” Sue Kelly, CEO of the American Public Power Association, told the inaugural Future Power Markets Summit.
“We think it’s time to rethink them. We believe that a resource adequacy regime that’s based on longer-term planning, bilateral contracting [as in MISO and SPP] and increased respect for state and local decision-making and autonomy — with a residual market capacity market for those who feel the need to go there — actually makes more sense,” she said during a lunch keynote at the conference.
Brian Forshaw, who represents public power systems at the New England Power Pool, used almost identical language. “The consensus of stakeholders throughout the [New England] region is that out of all of our market constructs, the energy market is probably the only one that’s working reasonably well,” he said. He acknowledged concerns that the region is “overly reliant” on natural gas.
James Wilson, a consultant who has worked for environmental groups and state consumer advocates in PJM, lamented that the capacity market — intended as “training wheels” to be removed once the markets found their balance — have remained, saying he would prefer an energy-only market.
Jay Morrison, vice president of regulatory issues for the National Rural Electric Cooperative Association (NRECA), compared capacity markets to a different method of conveyance, likening RTOs’ efforts to tweak the markets to attempting to convert a Ford Pinto into a Formula One race car. “It’s the wrong tool,” he said.
Not everyone at the Sept. 5 conference was critical, however. Katie Guerry, vice president of regulatory affairs for demand response aggregator EnerNOC, noted that DR gets virtually all of its revenue from the “availability payment” from capacity markets and very little from energy or ancillary services.
Although PJM’s capacity market “is the subject of a lot of concern and criticism, it is the gold standard when you go into countries around the world,” Guerry said. She noted that Alberta is adopting a capacity market with DR on the supply side, like PJM.
Aside from losing DR revenue, “it would significantly increase our costs to serve if there were no centralized markets at all,” Guerry said. “It would be very prohibitive for us.”
The conference, which attracted about 80 people, came after a summer that observers expected to stress test ERCOT’s energy-only market because of its reduced capacity reserves. In addition to APPA and NRECA, the summit’s sponsors were the American Wind Energy Association, American Council on Renewable Energy, Solar Energy Industries Association, Large Public Power Council and Energy Systems Integration Group, a nonprofit educational association for engineers, researchers, technologists and policymakers.
Texas survived the summer with surprisingly modest prices and no generation shortfalls, thanks to better-than-expected generation performance and an early summer system peak that took advantage of above-normal wind.
The capacity market provides certainty that resources acquired will be available, Garza said. “In ERCOT you don’t get that certainty. And [certainty] comes with some cost: Any of us who have a fixed-price mortgage are paying for that certainty.”
Fallacy of Fungibility
The latest challenge for capacity markets has been the effort to accommodate state preferences for renewable and nuclear generation without suppressing auction prices.
Morrison said state subsidies are only an issue because of the fallacy that capacity is a single fungible product.
“The RTOs do a good job of focusing on short-term reliability and low short-term marginal costs, and that’s great. But we need a lot more than that. We need long-term reliability; long-term price stability; environmentally favorable resources,” he said. “And if the one product that’s available is this fungible capacity product that the RTO has bought because they know better than us and our states, that doesn’t meet our needs.”
In June, FERC ordered PJM to expand its minimum offer price rule (MOPR), which now covers only new natural gas generation. The commission’s 3-2 ruling rejected both PJM’s capacity repricing proposal and the Independent Market Monitor’s MOPR-Ex proposal. (See PJM Unveils Capacity Proposal.)
Wilson was optimistic about the “resource specific” fixed resource requirement (FRR) proposal that he and consultant Rob Gramlich developed on behalf of environmental groups and the D.C. Office of the People’s Counsel.
“With a strong MOPR and this resource-specific FRR, we can have our RPM [Reliability Pricing Model] capacity market that is completely free of the impact of any subsidized resources because [they have] all been pulled out. It’s only the competitive resources [that remain]. And off to the side [are] those policy resources … they’re matched up with a commensurate amount of load, so customers are not paying twice. We’re … potentially getting to a pretty good place if we can make this FRR RS-thing work.”
Attorney Susan Bruce, who represents the PJM Industrial Customer Coalition, was less sanguine. “This is a case where there’s no good answer from my clients’ perspective. [We’re] just trying to find the least bad option,” she said.
She and Guerry expressed concerns over the modified FRR suggested by FERC.
“The FRR alternative, at least as it was put into the stakeholder process, would provide a very easy platform to sort of sink centralized capacity markets,” she said, predicting it would result in a “patchwork quilt of state policies” and a temptation to save uneconomic resources.
Guerry said the FRR alternative “makes us very nervous,” noting bilateral trades “are not transparent” to her company.
“Bilaterals are perfectly transparent to those in the market,” Wilson insisted.
But Devin Hartman, manager of electricity policy at the free market think tank R Street Institute, also was skeptical. He said it’s unworkable to administratively correct for subsidies in a pricing mechanism, calling it “a recipe for unintended consequences.”
“What constitutes a material subsidy?” he asked. “We’re going to have some fun with that — in perpetuity. It’s important to recognize that these markets have always had subsidies. Every resource has some degree of price subsidy. I don’t see how [PJM Monitor] Joe Bowring is going to come up with a screen to price correct for Price-Anderson,” referring to the law limiting liabilities for nuclear plant operators. “Where are you going to draw the line?”
Three times in three years, proponents of an organized market in the Western Interconnection have tried and failed to turn CAISO into an RTO.
Opponents say it’s time to give up, but supporters of CAISO regionalization say they’ll likely keep at it until they succeed.
Zichella | NRDC
“The benefits of a regional grid integration are so great that, frankly, we’re talking about something inevitable,” said Carl Zichella, western transmission director at the Natural Resources Defense Council. The environmental group was a main backer of this year’s CAISO regionalization effort along with Gov. Jerry Brown and ISO leadership.
The movement’s supporters argue that the future of renewable energy lies in Western states trading wind, solar and hydropower resources across state lines as easily as energy is now distributed within California.
Zichella said proponents believed they had a combination of Democratic and Republican votes needed for their measure — AB 813 — to pass the State Senate this year but that Democratic leaders wouldn’t let the bill out of the Senate Rules Committee on the last night of the State Legislature’s 2017/18 session on Aug. 31.
The bill would have started the process of turning CAISO into an RTO by initiating changes in its governance structure.
It languished in the Rules Committee, where Senate leaders had sent it, and never reached a floor vote because of a lack of Democratic unity on the bill, advocates on both sides of the issue said.
“In California, we feel like there’s a future for this legislation,” Zichella said. “We’ll probably take another run at it.”
Freedman | UC Berkeley
Matthew Freedman, a staff attorney for The Utility Reform Network (TURN), said he hopes that won’t happen. The ratepayer advocacy organization strongly opposes an effort to make CAISO a multistate organization.
“The Legislature has emphatically rejected regional proposals put forth by the governor over the last several years, which suggests it’s time to consider alternative approaches to regional coordination,” Freedman said.
Those alternatives could take multiple forms, including expanding the Western Energy Imbalance Market to include more participants and moving it from a real-time exchange to a day-ahead market, he said.
“We’d prefer incremental steps toward regional coordination” that are easier to undo if necessary, the lawyer said.
TURN and other opponents are against the idea of changing CAISO’s governance structure from one overseen by officials in Sacramento to a multistate conglomerate with an independent board of directors that they contend would be more susceptible to meddling from Washington and to influence from the coal-burning states of the Interior West.
The governor is termed out of office this year, and his replacement will be elected in November.
Brown has been the main proponent of regionalization as a means to further his green energy goals across the West, Freedman noted, but “he won’t be the governor in January,” when the Legislature reconvenes for the start of a new two-year session.
Whether a new governor will support CAISO regionalization remains to be seen.
It’s also unclear if a majority of Democratic lawmakers can be persuaded to vote for a measure that would remove CAISO’s leaders from their oversight and is opposed by labor unions, publicly owned utilities and other powerful interests, Freedman said.
Many Democrats, who control the Legislature, had reservations about AB 813 and didn’t want to be forced to vote against it on the Senate floor for fear of angering the governor, he said.
Senate President Pro Tempore Toni Atkins may have kept the bill in the Rules Committee, but she wouldn’t have done so without her caucus’s backing, Freedman said. “Had there been an overwhelming amount of support, she would not have held it,” he said.
WASHINGTON — Former FERC Chairman Pat Wood III used his keynote speech at last week’s Future Power Markets Summit to “re-serve the Kool-Aid” on the value of competitive markets threatened by state subsidies and the Trump administration’s push for price supports for coal and nuclear generation.
He referred to the “economic carnage” caused by the over-budget Vogtle and Summer nuclear plants in Georgia and South Carolina and the Kemper “clean coal” project in Mississippi, citing estimates that they will saddle ratepayers in the cost-of-service Southeastern states with $123 billion in excess costs over 40 years.
Wood contrasted that with the savings seen in ERCOT’s competitive energy-only market, where retail power prices have declined to about 8 cents/kWh, down from 10.5 cents before competition. Wood credited the savings to cheap wind and natural gas generation, dozens of competitive retail suppliers and lower profit margins.
“When I was a regulator, we would give a utility a 16% pretax rate of return on equity. … When I was [chairman] at Dynegy, we were happy to get 3[%].”
The conference was sponsored by the American Wind Energy Association, American Council on Renewable Energy, Solar Energy Industries Association, American Public Power Association, National Rural Electric Cooperative Association, Large Public Power Council and Energy Systems Integration Group (ESIG), a nonprofit educational association for engineers, researchers, technologists and policymakers. (See related story, ‘Almost Nobody is Happy’ with Capacity Markets at Conference.)
Wood told the 80 attendees he feared grid modernization could lead to a “gold plating” of the distribution and transmission systems that erodes the savings from cheap natural gas and renewable generation. “I don’t want to see all the savings I get from crunching down on the [generation] be offset by adding a lot to” transmission.
Beth Garza, director of ERCOT’s Independent Market Monitor, expressed a related concern. “We can spend dimes on transmission to save dollars in generation costs, and we’ve done that,” she said, referring to the competitive renewable energy zone (CREZ) transmission built to deliver West Texas wind. “I think, though, that over the years … we’ve reached a point now where we’re starting to spend quarters on transmission to potentially [save] quarters on the energy side. I’m not sure there’s the appropriate discipline and review on the regulatory side to bring those two in balance.”
Garza also questioned the distinction between “the big poles and wires [transmission] and small poles and wires [distribution].”
“Distribution utilities have a fixed investment in the small poles and wires and transformers and that is recovered through a variable rate, and so of course they don’t want people with PVs on their roof diminishing their consumption and diminishing their payment,” she said. She suggested the variable rates on distribution be replaced with fixed rates to acknowledge that both transmission and distribution enable the connection between customers and resources.
Jeff Bladen, MISO’s executive director for market design, discussed three “mega trends” that he said must be addressed by RTO markets: digitalization, including the Internet of Things; decentralization of generation; and “demarginalization” resulting from the rise of low- and no-marginal-cost resources.
“Our markets are moving away from the marginal cost of energy being the primary means for signaling the operational needs of the grid,” he said. “As we move forward, our history of everyday scheduling our generation and forecasting our load is beginning to switch. We’re going to look at a future where much more of our supply is a forecast and much more of our demand is something we try to schedule — digital devices and the like.”
Robin Hytowitz, an electrical engineer for the Electric Power Research Institute, noted that FERC-jurisdictional RTOs and ISOs “have started to integrate fixed operating costs from fast-start resources into prices.”
But she lamented that “demand-side bidding versus retail choice isn’t very active in most markets.”
“I think that actually having a demand curve for these markets would help advance some of the price formation efforts. So, we could get the demand side in addition to the supply-side curve.”
Mark Ahlstrom, board president of ESIG, argued for maximizing the granularity and flexibility of resources that provide ancillary services.
“Suppose I need 100 MW on reserve and in order to qualify to even offer it into the market, I have to be able to provide a four-hour sustained duration. Do I really want to have one product — 100 MW for four hours of sustained duration? Or would I rather have four 100-MW units that can each sustain duration for only one hour? I would argue that — without question — you want the latter, because … I can also use those building blocks in other ways.”
Ahlstrom said although more granular resources should be cheaper, pricing them is a challenge.
“Any time we block those capabilities into hourly type products or anything like that in order to price them … we are leaving a lot of the capability and flexibility on the cutting room floor. An engineer in the control room would like to have continuous control over everything if we can figure out how to run markets that way.”
Ahlstrom said he previously thought it unwise to combine storage with a renewable resource because it increases the cost of energy. “The market should be the cheapest source of flexibility if it’s working right,” he said.
“I’ve had to eat my words on that because we’re seeing huge demand; we’re going to see a ton of these hybrid projects,” he continued. “And why is that? It’s because in the markets as they’re operating today, it’s way too tough to get through the interconnection process and connect new resources separately. … A lot of this is a reflection that we can’t just have a frictionless way of adding resources to the markets.”
FERC Chairman Kevin McIntyre has defended Chief of Staff Anthony Pugliese, saying his controversial remarks did not reflect commission policy or threaten its independence and impartiality.
Rep. Frank Pallone (D-N.J.) and Sen. Maria Cantwell (D-Wash.), the ranking members of the House and Senate energy committees, sent McIntyre a letter Aug. 22 complaining of Pugliese’s “highly partisan political remarks” at a conference of the American Nuclear Society in August and in an interview with right-wing media outlet Breitbart in July.
On Thursday, Cantwell released McIntyre’s Aug. 24 response, in which he praised Pugliese’s “outstanding management skills and his unparalleled talent for coordinating the activities of a complex, multi-faceted agency.”
Pallone and Cantwell cited Pugliese’s praise of President Trump and criticism of Democratic governors for blocking pipelines. They also cited his statement to ANS that FERC is working with the Department of Energy and National Security Council on the Trump administration’s proposal to provide price supports for at-risk coal and nuclear generators. (See Democrats Call Out ‘Partisan’ Remarks by FERC Chief.)
Pugliese, a former lobbyist in Pennsylvania’s capital, and an unsuccessful state legislative candidate, joined FERC in August 2017 after a stint at the U.S. Department of Transportation as a member of Trump’s so-called “shadow cabinet.”
McIntyre said he had authorized Pugliese to make the Breitbart and nuclear conference appearances but that “the specific subjects of his remarks were not subject to review and were not identified in advance.”
The chairman said none of Pugliese’s comments reflected FERC policy because “the commission speaks exclusively through its orders. Consequently, neither the public statements of Mr. Pugliese nor those of any other FERC staff member can state the views of the commission, particularly in connection with proceedings on which the commission has not issued an order on the merits.”
“While I understand your concerns, I can assure you that this commission remains independent and impartial,” McIntyre said.
McIntyre joined in a 5-0 vote in January rejecting Energy Secretary Rick Perry’s Notice of Proposed Rulemaking to save at-risk coal and nuclear plants and instead opened a docket to consider resilience concerns (AD18-7). In June, however, Trump ordered Perry to save coal and nuclear plants under an obscure Korean War-era law. (See More Questions than Answers for FERC, RTOs on Bailout.)
In his response to Cantwell, McIntyre said commission staff “has not discussed the merits of any ‘grid resilience’ proposal that would seek to prefer one form of generation over another with executive branch officials. Commission staff does, however, have regular contact with our counterparts in the Department of Energy on a host of matters of shared responsibility including intelligence, personnel and legal process.”
Cantwell said in a statement that she was encouraged “to hear Chairman McIntyre clarify that the commission’s official orders, like the 5-0 rejection of the Trump coal bailout, are what count. However, speeches and interviews by the commission’s top staffer that are laced with bad-faith partisan attacks serve to undermine FERC’s traditional impartiality and neutrality.”
Pallone said he was “disappointed that [McIntyre] failed to acknowledge that the partisan comments of his chief of staff, Anthony Pugliese, were wholly inappropriate, unhelpful and distasteful. To my knowledge, no other FERC chief of staff under either Republican or Democratic administrations has used that position as a platform for partisan attacks.”
