CAISO day-ahead prices hit all-time highs for the second time this year during the third quarter, and the frequency of price spikes in the 15-minute and five-minute markets increased, the ISO’s Department of Market Monitoring said in its quarterly market performance report.
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High temperatures in California drove up demand at the beginning and end of August and into September, according to the report. Load peaked at 50,116 MW on Sept. 1, just short of the 50,270-MW peak record set in July 2006. Trading that day also saw day-ahead system marginal prices soar over $200/MWh during a four-hour period and hit $770/MWh in one interval.
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“These outcomes were primarily driven by tight supply conditions as a result of a number of factors in combination with high demand while a significant amount of solar production is ramping down during sunset hours,” the report said. Average 15-minute market prices increased during every month of the third quarter from about $34/MWh in June to more than $45/MWh in September because of higher temperatures and loads.
The Monitor also confirmed that software problems had caused day-ahead prices to hit record highs in the second quarter even after being mitigated. In its second-quarter report, the department had noted that prices should not rise after mitigation and said it was investigating the cause. (See Monitor: CAISO Q2 Prices Hit Record Despite Mitigation.) The third-quarter report said the error was fixed on July 22.
“The ISO has determined that a software error introduced in 2016 resulted in infeasible energy and ancillary service awards for resources in the market power mitigation run but not the binding market run in the day-ahead market,” the Monitor said in the third-quarter report. “The software error resulted in an erroneous increase in supply available in the market power mitigation run, causing prices in that run to be lower than they would have been had all awarded schedules been feasible.”
CAISO is “currently evaluating the impact of this error on the market power mitigation process on affected days,” the report said.
Day-ahead prices appeared to be competitive in most hours, the Monitor said, and total year-to-date wholesale energy costs are close to 2016 totals, after the prices are adjusted for natural gas and greenhouse gas prices. Higher gas prices resulted in larger overall energy costs for 2017.
Transmission congestion was low in the day-ahead market in the Pacific Gas and Electric and Southern California Edison service areas but caused prices to drop about 2% in San Diego Gas & Electric’s area. Congestion in the 15-minute market pushed up prices in PG&E and SCE and decreased SDG&E prices. Frequent congestion on the Doublet Tap-Friars 138-kV constraint created an export-constrained area, undercutting prices in San Diego.
The Monitor said its analysis of natural gas price volatility shows a limited need for increased bidding flexibility created by raising commitment cost and default energy bid caps. CAISO followed the department’s recommendation and reduced the Aliso Canyon real-time gas scalars to zero beginning Aug. 1, raising them again temporarily Aug. 4-7 because of hot conditions.
Congestion revenue rights auctions took in $9 million less than payments to entities purchasing those rights, increasing year-to-date ratepayer losses to $38 million and to more than $680 million since the market began in 2009. The Monitor for more than a year has been calling for CAISO to eliminate CRR auctions. (See CAISO Monitor Proposes End to Revenue Rights Auction.)
The Monitor will discuss the third-quarter report with market participants during a Dec. 20 conference call.
A Nuclear Regulatory Commission official said Tuesday that a team of the federal agency’s reactor safety engineers would likely recommend that the commission continue working on replacing a portion of its inspections with a self-assessment regime for operators of commercial nuclear power plants.
Tony Gody, NRC director of reactor safety in Region II (Southeast), said Dec. 12 that “the working group agrees that self-assessment, if implemented properly, can be very effective in finding latent conditions” and probably will be recommending further exploration of how to get there via a pilot program.
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Gody made his remarks at the end of the agency’s second public hearing in two months on the use of licensee self-assessments in the NRC engineering inspection program and other changes in the reactor oversight process.
The Director of the Office of Nuclear Reactor Regulation formed the working group in February 2017 to review the commission’s engineering inspections that verify the adequacy of facility design, operations and testing, and make recommendations on improving both their effectiveness and efficiency. The commission has a webpage with related documents, including public comment.
The Good and the Bad
“We need to collectively as an industry own our own licensing design basis and regulatory performance,” said Greg Halnon, vice president for regulatory affairs at FirstEnergy, which owns two nuclear power plants in Ohio and one in Pennsylvania. The plants are the Davis-Besse plant in Oak Harbor, Ohio, the Perry plant in Perry, Ohio, and the two-unit Beaver Valley plant in Shippingport, Pa., which collectively generate 4,000 MW.
“We’re not abdicating our responsibility; we’re maintaining and owning that licensing basis,” Halnon said.
Dave Lochbaum, director of the Nuclear Safety Project for the Union of Concerned Scientists, said the 17 years of the reactor oversight process “have resulted in safety improvements, there’s no doubt about that, but achieving success loses value if backsliding occurs. … Our concern is, some of the measures being contemplated are banking on that success at risk of undermining it.”
NRC Inspectors: (L-R) NRC inspectors Robert Krsek, Annie Kammerer and Steve Campbell check emergency diesel generators at the Kewaunee nuclear power plant in Carlton, Wisconsin in 2012, one year before the plant closed | NRC
Gody said that if whoever is doing an inspection or a self-assessment applies scientific principles, “it’s going to be a good inspection or self-assessment. And the fact that your own folks are already so familiar with your procedures, and the fact that your own folks already have computer accounts, already know the processes at the facility, already know the licensing basis, is a good thing and a bad thing.”
The good thing is they’ll be more efficient, he said.
“The bad thing is they may have preconceived conclusions,” Gody said. “It’s critical that when that checklist is developed that critical thinking is considered. If you accomplish that one thing, you potentially eliminate the human factor disposition to not challenge your own conclusions.”
Lochbaum said he wanted to push back on the “fanciful notion that there aren’t any more legacy, latent issues out there. There seem to be plenty of latent issues from long ago that we still haven’t found. Fort Calhoun [in Nebraska] is a perfect example, which shut down in 2011 and didn’t restart for 30 months. During that time, they submitted something like 18 LERs [licensee event reports], with the youngest of those being 15 years earlier, so they were at least 15 years old. Several of those involved engineering issues.”
Getting to the point of metrics, Lochbaum said “we recommended before and recommend again that the NRC should have looked at those LERs to see if the expectations were that the engineering inspections should have or may have identified those before they were found during an extended plant shutdown.”
NEI Supports
The Nuclear Energy Institute supports self-assessments, saying plant operators already do their own inspections in advance of NRC visits. “We believe that licensee self-assessments could be an important part of a modernized approach to engineering inspections. Such a solution would be rooted in our cultural value of self-identifying issues,” Greg Cameron, NEI’s senior project manager for regulatory affairs, wrote the commission in July. “We hold ourselves accountable to identify conditions at our stations early and to resolve them in a timely fashion commensurate with their safety significance; the NRC verifies that accountability through regular resident inspector interactions and the biennial Problem Identification and Resolution inspection. Transitioning from direct inspection to oversight of self-assessment activities, where appropriate, strengthens this accountability.”
Concerns in Mass.
But the self-assessment concept is unpopular with some neighbors of Entergy’s Pilgrim nuclear plant in Massachusetts, one of three plants in the country classified in Column 4 — the worst performers in NRC’s grading system.
A citizens group, Pilgrim Watch, cited an email written by the leader of a federal inspection team, who wrote that “the plant seems overwhelmed just trying to run the station.” The internal email became public mistakenly.
“Pilgrim provides the perfect example why NRC nuclear safety inspections are necessary and why industry self-assessments would be dangerous,” the group wrote NRC. “Pilgrim cannot be counted on to conduct any complete or accurate self-assessment. The NRC’s own records prove that Pilgrim has regularly and consistently failed to follow established procedures, to report problems, or to take corrective actions even when the NRC tells it to do so.”
ALBANY, N.Y. — When pricing carbon into the wholesale electricity markets, remember to keep it simple.
Also: avoid unintentional emissions increases, mind the transmission needed, incent new renewable resources, abate emissions efficiently without hurting consumers, allocate revenues fairly, and leave the legal hassles for the due processes of regulators and NYISO.
Those were some of the stakeholder comments Monday at the first technical conference of the Integrating Public Policy Task Force (IPPTF), which was established in October by NYISO and the state’s Public Service Commission to explore the carbon pricing issue as laid out in a Brattle Group report.
Paul Hibbard of The Analysis Group facilitated two roundtable discussions, each with 23 stakeholders. The morning session addressed border adjustment mechanisms to prevent “carbon leakage,” a parallel increase in emissions in regions neighboring New York.
“You don’t have to have the absolute perfect solution to leakage to go forward,” said Mark Reeder, an economist who represents the Alliance for Clean Energy New York at NYISO. “You just need to get most of the way there. Say if you can knock out 80 to 85% of the leakage problems at a $40 carbon price, you bring it down in essence to the latest we have now with a fairly small [Regional Greenhouse Gas Initiative] price and you’ve done the job.”
In looking at leakage issues in RGGI states and California, Reeder said “the unit-specific approach and the resource shuffling is a real bad idea and does create a lot of problems. The example here is that a nuclear plant in Pennsylvania that’s just selling spot-in in Pennsylvania could sign a contract to sell it to New York, and if New York declares that clean, we could work on that later, but it doesn’t work.”
Resource shuffling refers to the practice of utilities scheduling their lowest-emission generators to serve areas with emissions caps, while letting heavier polluters simultaneously serve customers in other regions.
“It’s important to move forward with carbon pricing principles and not use leakage as a way to delay,” said Gavin Donohue, president of the Independent Power Producers of New York. “We don’t need to reinvent the wheel.”
“You really get different answers depending on how you think about the question,” said David Clarke of the Long Island Power Authority. “For example, if you have a uniform carbon tax on all sectors, you’d be thinking about offsets; you think about where are the places where folks can make the investments that have the largest carbon reduction at the lowest cost.”
Baseline Leakage
“When you’ve got regions surrounding New York with such a wide range of marginal emissions rates, to start with a broad-brush approach, applying the New York rate to all of them will have pretty obvious unintended consequences,” said Stephen Molodetz, vice president of Hydro-Quebec. “Quebec is zero or near zero and Ontario is close to that; then you’ve got PJM, which is a higher emitter than New York.”
Don Tretheway, CAISO senior adviser for market design and regulatory policy, said some power producers outside the ISO have a resource portfolio with a significantly lower emissions profile than the default emissions rate for their region. In those cases, the ISO wants to give them the benefit of having cleaner resources.
“That’s relatively straightforward to implement from a market standpoint,” Tretheway said. “We can have each of the individual resources put their estimate of carbon compliance costs into their energy bids and we can dispatch away and everything works.”
Tretheway noted how the roll-out of the Western Energy Imbalance Market (EIM) further complicated CAISO’s treatment of greenhouse gas costs.
“The complexity CAISO introduced with the Energy Imbalance Market is that, not only did we need to solve to meet load in California that has a [greenhouse gas] program, but we had to actually solve to meet load in other states that don’t, and that’s where we had to separate those greenhouse gas costs into separate bids,” Tretheway said.
Mark Younger of Hudson Energy Economics said “what California is doing now is probably a mistake. [New York] should have a very high bar on resource-specific carbon pricing. Just because you can contract with what is nominally a clean resource, doesn’t mean that you in any way affected what the emissions were in the neighboring area other than by the fact that there was a bigger import to New York, regardless of resource.”
Allocating Carbon Revenue
The afternoon roundtable discussed how — and whether — New York would allocate revenues collected from a carbon pricing scheme.
NYISO Executive Vice President Rich Dewey said, “We’re conflating a couple issues here. First and foremost, we need to decide if there’s going to be a fund. When I think about how the NYISO settlements process works today, that revenue amount only exists for the microsecond it takes to do the calculation in the settlement itself, so there is no actual fund.
“At NYISO we’re not setting the policy, we’re administering the market,” he continued. “Be that as it may, you may have the desire, for the greater good, to create a fund in some capacity. Then we have to decide where is that fund.”
Miles Farmer of the Natural Resources Defense Council said that if the PSC determines what load-serving entities must do with carbon revenues, “that’s bounded under the legal constraints of PSC ratemaking, and you can’t have just general slush funds of money the way that it happens with RGGI.”
NYISO Senior Manager for Market Design Michael DeSocio said that when considering a carbon revenue fund, “we haven’t actually talked about what does the rate look like. And there are components of the rate that go into various funds already — a congestion rent fund, there’s a loss fund — all of that money is already allocated in some way based on various other markets. We want to do this in a way that doesn’t unnecessarily increase the cost to customers.”
Kelli Joseph, NRG Energy’s director of market and regulatory affairs, said that making carbon pricing sustainable requires considering how RGGI moneys have been used for energy efficiency and incenting renewables in to help reduce greenhouse gases.
“The [Brattle] report assumes a certain marginal emissions rate that may not be true over time,” Joseph said. “Over time, those marginal emission rates are going to decrease and there’s probably not going to be anything left to refund because there’s not going to be a lot of carbon-emitting resources on the system.”
Scott Weiner, Department of Public Service deputy for markets and innovation, cautioned roundtable participants about getting caught up in the legal details so early in the planning process.
“It’s going to be a collaborative effort and will be vetted legally,” Weiner said. “We will subject everything to the governance processes of NYISO, so there are a lot of legal issues, and in the absence of specific facts … I urge you to leave the legal discussion to another day.”
Task force co-chair Nicole Bouchez, a NYISO market design economist, said they had decided to cancel the Dec. 18 task force meeting and will next meet on Jan. 8, 2018.
SPP set several new records for wind generation last week, lending further credence to its claims that it can handle wind-penetration levels as high as 75%.
Wind resources peaked at 13,587 MW at 7:55 a.m. on Dec. 4 and then again at 14,150 MW at 9:55 p.m., bettering the old record of 13,342 MW, set on Feb. 9.
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SPP also set new standards for wind penetration (56.25%) and renewable energy penetration (58.23%) Dec. 4. Coal accounted for 28.94% of the energy produced at that time and gas for 11.58%.
The RTO has nearly 18 GW of wind capacity in service and almost 44 GW of additional capacity in all stages of development. Staff said earlier this year it could serve up to 75% of its load with wind energy and other renewable resources. (See SPP Eyes 75% Wind Penetration Levels.)
SPP staff told the Seams Steering Committee (SSC) last week they plan to meet with FERC staff in January to resolve a seams project recently rejected by the commission.
FERC in October nixed SPP’s proposal for regionwide/load-ratio share funding for its portion of two projects with Associated Electric Cooperative Inc. (AECI) and City Utilities of Springfield, Mo. The commission ruled SPP had not shown they were “roughly commensurate with the projects’ benefits.” (See FERC Rejects Cost Allocation for SPP-AECI Seams Project.)
SPP Interregional Coordinator Adam Bell said staff would perform additional analysis on the AECI project before meeting with commission staff. SPP and AECI agreed to build a new 345/161-kV transformer at AECI’s Morgan Substation and uprate an existing transmission line, with the RTO covering $17.1 million of the $18.75 million cost.
“Once we have direction from that meeting, we’ll come back and make a decision on the best way forward,” he said.
A second seams project with City Utilities, the installation of a new 345-kV 50-MVAR reactor at the city’s Brookline substation that was also rejected by FERC, has been included in the 2018 Integrated Transmission Planning Near-Term (ITPNT) assessment.
SPP and AECI are meeting Dec. 20 to discuss a joint and coordinated system planning study. Under terms of their joint operating agreement, the two systems are to conduct such a study every other year.
Bell said the study scopes have varied in the past, from “full-blown joint models to participating in a study SPP is already doing.”
MISO Incurs $5M Hit on Single M2M Flowgate
MISO is on the hook for $6.1 million in market-to-market (M2M) payments to SPP for October, the largest bill in the 32 months since the two grid operators began the coordination process.
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A single flowgate in the Empire District and Westar Energy control zones that was binding for 329 hours in October was responsible for $5.1 million alone. SPP said high wind flows from MISO and local outages made the flowgate difficult to control.
Several stakeholders expressed confusion as to why MISO is not taking steps to resolve the situation on its side of the seam.
“MISO has not come to us and suggested we consider any joint transmission projects to mitigate the congestion,” said David Kelley, SPP’s director of interregional relations. “If it was us, we would go to them.”
Asked for comment, MISO spokesman Mark Brown responded, “As part of MISO’s ongoing planning process, we regularly evaluate historic congestion and assess feasible ways to address those issues.”
Through October, MISO has paid $27.7 million to SPP. The two RTOs began the M2M process in March 2015.
The Illinois Commerce Commission heard two very different views of MISO’s Zone 4 at a workshop last week, with some speakers claiming the region has sufficient reserves and others saying it is in dire straits.
The ICC convened the Dec. 8 workshop to hear continuing discussion on the future of resource adequacy in the RTO’s Southern Illinois zone. The commission will hold another workshop next month and then issue a summary report of stakeholder positions to Gov. Bruce Rauner by Feb. 26. It was Rauner’s office that in part sparked the workshop after sending the ICC an Oct. 26 letter asking the commission to produce a white paper and stakeholder comments on the structural challenges of Zone 4 within five days.
Dynegy representatives repeated warnings that the company could shutter one of its eight plants in Zone 4. The company operates about 6.5 GW of capacity in the zone, which contains 57 utility-scale generating stations with a combined 16 GW of nameplate capacity. Dynegy said unprofitable plants could shut down as early as the 2018/19 planning year unless changes are made to support local generation. Merchant generator owner Rockland Capital also warned in workshop comments that merchant plants will be forced to exit the market in Illinois without MISO capacity market improvements.
“We are the bearers of the risk of deregulation,” said Dean Ellis, Dynegy executive vice president of regulatory and government affairs.
Ellis also criticized the short lead time MISO provides for its annual capacity auction, with the auction taking place in early April and the planning year beginning June 1. “We have to make investment decisions involving millions or tens of millions of dollars with as little as six weeks’ notice,” he said.
Dynegy said MISO and the Organization of MISO States’ (OMS) projected capacity surplus through 2022 includes all of the company’s at-risk downstate generating units — except for Baldwin Unit 3 near St. Louis — as available capacity. The OMS-MISO resource adequacy survey predicts Zone 4 will have an average 2.62-GW surplus through 2022.
The company also warned the ICC not to count on MISO’s system support resource program, which enables the RTO to keep units online for reliability purposes: “It might be asserted that … MISO could invoke its system support resources tariff to require Dynegy to keep one or more of the retiring units in operation, while compensating Dynegy through cost-of-service-based payments under an SSR agreement. However, the MISO SSR tariff as written only provides for generating units to be designated as SSRs in order to maintain transmission system reliability (including compliance with thermal and voltage limitations under applicable NERC standards) and not to maintain resource adequacy.”
MISO Executive Director Melissa Seymour confirmed Dynegy’s assessment, saying the RTO could only pursue SSR agreements in cases where reliability is threatened, but not for resource adequacy.
Ameren Illinois said it didn’t see an immediate need for action, arguing that only mid- and long-term resource adequacy is a concern for the zone.
“There are sufficient resources in the market today, and sufficient resources are forecasted to be available in the market in the next three to five years. Thus, the problem identified is mid- and long-term resource adequacy in MISO Zone 4,” the company said in comments.
AARP Senior Legislative Representative Bill Malcolm said Illinois customers should “celebrate” because energy costs are low and the wholesale market is finally working as designed in Zone 4.
Malcolm urged a slower timeline to develop a resource adequacy solution and recommended a full independent study of capacity in all of Illinois, not just the downstate market.
“This seems to be a solution in search of a problem. There is no urgent issue; we have time,” Malcolm told the commission.
Activist Tracy Fox, representing several community groups in the state, also argued for a measured response and called for an independent analysis. “If you watch these plants, they’re always broke, there’s always a fix on the horizon, and once they get it, they’re broke again,” Fox said.
Speaking on behalf of Rockland Capital, Travis Stewart of Gabel Associates cautioned against a study that relies solely on publicly available data, saying it might not paint a full picture.
RA not a Problem
Jim Dauphinais, representing Illinois Industrial Energy Consumers, said Southern Illinois does not have a resource adequacy problem.
“There has not has been a serious resource adequacy issue in the state since 1998,” Dauphinais said, referring to the premature shutdown of Commonwealth Edison’s two large Zion nuclear reactors.
Malcolm said supplies in the Midwest are so plentiful that We Energies is shutting down its Pleasant Prairie plant in southeastern Wisconsin.
Direct Energy said, if anything, there’s an oversupply issue in Zone 4, noting the $1.50/MW-day clearing prices in MISO’s most recent capacity auction. The retail electric supplier urged the ICC not to “disrupt the entire market and potentially subject customers to escalating and uncontrolled capacity costs.”
“I don’t mean to be critical, but [MISO CEO] John Bear’s letter was weak. It doesn’t present any evidence at all of a resource adequacy problem,” Fox said, referring to a May letter Bear penned to Rauner, urging the state to continue to seek solutions to a possible capacity shortfall after FERC rejected MISO’s separate three-year capacity auction proposal for retail choice areas. She conceded Bear’s point that Zone 4’s resource adequacy conditions change from year to year.
No Greener Pastures
Last month, Dynegy drafted legislation that would have the Illinois Power Agency hold a separate competitive capacity auction for Central and Southern Illinois, but the proposal failed to advance in the Illinois House of Representatives after hearings. (See Dynegy Auction Proposal Fails to Gain Ill. Lawmaker Support.) In workshop comments, Exelon said it generally supported the plan, contending it “would have ensured that Illinois would no longer be subject to the annual one-year cycle of capacity auctions and the volatility that ensues.”
A recent ICC white paper concluded that state has four options: continue to rely on existing competitive forces and market structures; impose additional capacity requirements on load-serving entities; create a reliability portfolio standard; or encourage or require utilities to switch RTOs.
Fox criticized the white paper as too heavy on MISO Zone 4 backstory and light on an examination of the solutions. “We came out with four solutions, but the solutions aren’t analyzed at all,” Fox said.
During a Dec. 4 conference in Indianapolis hosted by EUCI, ICC Commissioner John Rosales said it was interesting that the white paper offered RTO defection as an option while other Illinois generators outside of Zone 4 are considering moving from PJM to MISO. “The grass is always greener on the other side. I hate for that to be the end-all option. That’s the North Korea option. There’s a lot of repercussions to move from one RTO to the other, and I’d hate for that to happen.”
Ameren has also said it believes that reconfiguring RTO participation will “not necessarily guarantee long-term resource adequacy for downstate Illinois.”
Questions Remain as PJM Continues Push for Price Formation Revisions
PHILADELPHIA — Stakeholders hoping to influence PJM’s plans for revising its price formation methodology had better move quickly. RTO staff unveiled their problem statement and issue charge on the topic at last week’s Markets and Reliability Committee meeting and hope to have it approved at the next one on Dec. 21.
“If you are going to follow up … please do so soon,” PJM’s Stu Bresler said of the proposal, which would create a senior task force “investigating energy and reserve price formation enhancements [to] … more transparently reveal the true cost of meeting system reliability needs.”
In advance of a decision looming at FERC to provide price supports for nuclear and coal-fired units, PJM has been campaigning for support of an alternative. It would remove the prohibition on letting inflexible generators — often large coal and nuclear plants — be the price-setting marginal unit in its real-time and day-ahead energy markets. It would also factor in start-up and no-load costs, which are currently set aside.
PJM says these “simplifications” were used during the development of LMPs to reduce the time necessary to successfully dispatch the system. Large inflexible units are often dispatched despite clearing prices that are below their offers and receive uplift payments that compensate them for their costs. Out-of-market uplift payments have been a source of stakeholder frustration for years. (See PJM MRC OKs Uplift Solution over Financial Marketers’ Opposition.)
“From the initial implementation of locational marginal pricing, given that it is an optimization … we made some simplifying assumptions up front,” Bresler said.
PJM’s plan wouldn’t eliminate uplift and calls for making additional lost opportunity cost (LOC) payments for flexible units with lower offer prices to reduce their output to balance load and generation. But the RTO argues that the reduced uplift and LOC payments combined would be a fraction of the current uplift payments.
Still, stakeholders have been cautious to endorse the plan and asked that it not be rushed into implementation.
James Wilson of Wilson Energy Economics, who consults with several consumer advocates within PJM’s footprint, said the RTO’s proposed timeline for completing the task force before the fourth quarter of 2018 is too ambitious.
Joe Bowring, PJM’s Independent Market Monitor, echoed that.
“This is a massive change. There’s no reason to not have thought it through carefully,” he said, listing other market components beyond the energy and reserve prices that would be “impacted” by the change, including financial transmission rights and rules for Capacity Performance, market-power mitigation and uplift.
“I ask you to get stakeholder input and consider other options,” said Greg Poulos, the executive director of the Consumer Advocates of the PJM States (CAPS).
Bob O’Connell of Panda Power Funds asked PJM to “reserve judgments” about what causes and solutions the task force could discuss.
“Impairing flexibility because of the way we’re paying suppliers, that’s something we need to talk about,” he said.
Gabel Associates’ Mike Borgatti requested education for market participants to update their modeling assumptions.
Susan Bruce, who represents the PJM Industrial Customer Coalition, asked that load receive “fair notice” of the changes and a way to measure what the impact will be. “We have a lot of load that’s locked in because of low energy prices,” she said.
DER Charter Endorsed
After several contentious discussions at previous MRC meetings, members endorsed by acclamation the charter for the Distributed Energy Resources Subcommittee, which will consolidate PJM’s efforts on DER.
The charter had been contentious because of an addition that required all rules to “adhere to all pertinent jurisdictions” and regulators. Some stakeholders saw it as stating fact, while others were concerned it could be used to stifle discussion.
Bruce asked the group to be “extremely cautious” and that its proposals could result in costly requirements for “people who are not represented in this effort because they have chosen not to be in the PJM markets.”
PRD Rules Deferred
Stakeholders voted to defer a planned vote on new rules for price-responsive demand (PRD) pending the deliberations of the recently formed Summer-Only Demand Response Senior Task Force.
The RTO wants to change the PRD rules to comply with its CP requirements. PJM’s Pete Langbein attempted to characterize it as “just another [supply-side] option that would be out there that folks could elect to choose.” But state representatives complained that the proposed changes fail to acknowledge PRD’s value.
“It’s not a capacity product. It’s a mechanism to refine the load forecast,” said Morris Schreim of the Maryland Public Service Commission. “It’s not competing with supply.”
He argued against a change in the PRD rules that would “close the door” on solutions in the task force and suggested tabling the vote pending the outcome of the task force. Gregory Carmean, executive director of the Organization of PJM States Inc. (OPSI), agreed with Schreim that “it is time to take a pause,” saying it’s “hard to reconcile” the RTO’s justifications.
Langbein clarified that PRD displaces resources, either generation or demand response, with year-round capacity on a one-for-one basis. “That is the reality,” he said.
Calpine’s David “Scarp” Scarpignato called PRD “inferior” to generation in the context of CP and urged a vote. Waiting will make it harder to adjust the rules later as companies make decisions based on the current rules, he said. “We need this in place for the next [Base Residual Auction].”
EnerNOC’s Katie Guerry said it’s “alarmist” and “unproductive” suggest that all DR on the system would convert to PRD without the rule changes and said she was “looking forward to analyzing the opportunities” through the task force.
“Please participate in that process regardless of what sector you’re in,” she said, because that is where she sees any “real solution” being developed for summer-only DR that can no longer qualify as a capacity resource.
The deferral passed with just enough votes to clear the two-thirds threshold, receiving a 3.44 score (out of 5) in a sector-weighted vote.
Stakeholders Have Questions Before Approving MOPR-Ex
The Monitor will hold a question-and-answer session Tuesday to address stakeholder concerns on its proposed revisions to the capacity construct. The changes to the minimum offer price rule (MOPR) are expected to be brought to a vote at the Dec. 21 MRC meeting.
The IMM’s proposal was the only one to receive more than 50% approval in a poll of the Capacity Construct/Public Policy Senior Task Force, which has been meeting throughout the year to address concerns about market distortions from subsidized generators. The proposal would extend the MOPR to cover all units indefinitely, though it would include several exemptions.
Bowring said the proposal is meant to create an incentive for subsidized units “not to exist in the first place.” He fielded enough questions that stakeholders asked for a separate forum before voting. Jason Barker of Exelon, which had submitted its own proposal to the task force, questioned Bowring’s contention that the proposal is nondiscriminatory.
“Why do you think it’s appropriate to allow an overbuild?” he asked of one of the rule exemptions.
“I hear the point, and you’re right,” Bowring responded. “Let us think about that; it’s a good point.”
“You don’t have an answer to that? We’re going to have to vote on this,” Barker pressed.
“You’re not going to have to vote today,” Bowring replied. “We’ll have something out well ahead of the vote.”
PJM agreed to shorten its Dec. 12 Operating Committee meeting to make time for the Q&A.
For the second time in three months, no proposal from the Incremental Auction Senior Task Force received enough support to be proposed at the MRC, a fact that American Municipal Power’s Steve Lieberman argued should preclude PJM from automatically bringing its proposal for MRC review, even if it was just seven votes shy of the threshold at the task force. But Exelon’s Sharon Midgley moved for a vote on PJM’s Proposal A” and Bruce seconded it. The proposal received a first read and will be voted on at the next MRC.
“This is a compromise … but it’s all in the interest to try to get something before FERC so the issue of excess capacity and the sellback can get addressed, favorably for load,” Bruce said.
CPower’s Bruce Campbell argued the proposal doesn’t maximize the value of IA returns for load and said he was prepared to back another proposal “if others are interested,” but he received no support.
Other Voting Results
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 11: Energy & Ancillary Services; Manual 18: PJM Capacity Market; Manual 27: Open Access Transmission Tariff Accounting; Manual 28: Operating Agreement Accounting; and Manual 29: Billing. The revisions implement PJM’s transition to five-minute settlements under FERC Order 825.
2018 day-ahead scheduling reserve (DASR) requirement. The final DASR calculation dropped to 5.28%, which was even lower than PJM’s preliminary estimates in October. The 2017 DASR was 5.48%. PJM attributed the year-over-year drop to reductions in average seasonal load forecast errors and the forced-outage rate. (See “DASR Requirement Drops Again,” PJM Operating Committee Briefs: Oct. 10, 2017.)
Tariff and Operating Agreement revisions to modify credit requirements for regulation and FTRs:
Regulation credits are accrued daily and billed monthly, while energy charges are accrued daily and billed weekly. Although the regulation-only resources’ credits are much greater than the charges, the weekly bills for charges create a credit requirement, even though the much larger credit is due to the provider at the end of the month. Daily regulation credits will now be included in weekly instead of monthly activity for calculating credit requirements. The change will apply to all resources, not just regulation-only resources.
FTR credit requirements for prevailing paths currently are based on weighted historical congestion on those paths, but transmission system upgrades can reduce congestion, decreasing the value of prevailing-flow FTRs. PROMOD simulation results will now be incorporated into the FTR credit calculator prior to the bid window to incorporate consideration of major upgrades and reduce default exposure to PJM’s members. (See “Give Them Some Credit,” PJM Market Implementation Committee Briefs: Oct. 11, 2017.)
Members Committee
Stakeholders Endorse Consent Agenda
Stakeholders endorsed by acclamation the committee’s consent agenda along with several other OA and Tariff changes:
OA revisions associated with PJM sharing of restoration planning generator data with transmission owners. (See “TOs to Receive Confidential Generation Data for System Restoration,” PJM Operating Committee Briefs: Sept. 12, 2017.)
Tariff revisions related to a proposed change in credit requirements for regulation resources. (See “Other Voting Results” above.)
Tariff revisions to FTR credit requirements to reduce exposure posed by congestion changes resulting from major transmission upgrades. (See “Other Voting Results” above.)
Nominees Approved
Members elected new representatives to the Finance Committee, sector whips and the Members Committee vice chair for 2018. It is the Transmission Owners sector’s year to choose a vice chair, and Chuck Dugan of the East Kentucky Power Cooperative was nominated.
California regulators are set to vote next month on a proposal that community choice aggregators (CCAs) be subject to the resource adequacy requirements of electric utilities.
The California Public Utilities Commission’s approval would require CCAs to comply with resource adequacy rules “in order to ensure that sufficient energy supply for customers is being procured by the appropriate utility.”
Yellow dots = Operational CCAs; green dots = CCAs launched in 2017; blue dots = CCAs in process or being explored | California PUC
The proposal modifies the timelines for the creation of CCAs so that they are coordinated with the annual CPUC and CAISO resource adequacy and reliability programs. It would require CCAs to submit to a process that includes a timeline for submission of implementation plans; a ‘meet and confer’ requirement between the CCA and the incumbent utility that can be triggered by either; a registration packet including a CCA’s service agreement and bond; and a commission-authorized date to begin service.
It also calls for “universal access” to CCAs, equitable treatment of all customers and compliance with state laws regarding aggregated service. All prospective and expanding CCAs would be subject to the requirements for implementation plans received after Dec. 8, 2017.
CCAs are growing rapidly, creating some controversy over the stranded costs for regular utility customers. California legislators expressed surprise last summer when they were told that utility customers will be on the hook for hundreds of millions of dollars in long-term energy contracts procured by investor-owned utilities for customers who have departed for CCAs. (See California CCAs Spur Worry of Regulatory Crisis.)
The idea has been embraced by cities surrounding the San Francisco Bay Area that promote CCAs as “green” electricity programs. It was municipalities in the San Francisco and Los Angeles areas that lobbied for CCAs in response to a failed deregulation effort that in part caused the Western Energy Crisis of 2000/01. AB 117, enacted in 2002, allows local governments to form CCAs by aggregating retail customers and securing electricity supply contracts to serve them. CCAs also exist in Ohio, New York, Massachusetts, New Jersey, Rhode Island and Illinois.
Pacific Gas and Electric, which has opposed CCAs, argued to state lawmakers in August that about $180 million has been shifted from CCA customers to IOU customers — an amount it said will grow to $500 million by 2020.
California CCAs include Apple Valley Choice Energy, CleanPower San Francisco, Lancaster Choice Energy, Marin Clean Energy, Peninsula Clean Energy in San Mateo County, Redwood Coast Energy Authority, Silicon Valley Clean Energy and Sonoma Clean Power.
WASHINGTON — A panel on investing in grid innovation and clean energy infrastructure last week gave Congress low marks and said emerging economies are proving quicker to adopt some technologies. But speakers at the GridWise Alliance’s GridCONNEXT conference said they are bullish on the future.
David Yeh, a White House adviser during the Obama administration who is now managing director of Capitol Hill, an advisory firm for high net worth individuals, global asset managers and start-ups, said he is not overly concerned with the Base Erosion Anti-Abuse Tax (BEAT) provision in the tax bill passed by the Senate earlier this month. Some renewable advocates fear the language, which is intended to prevent multinational corporations from moving profits and jobs out of the U.S., will reduce the value of wind and solar tax credits.
“Right now clean energy, especially at the utility scale, is competitive, if not cheaper than, fossil fuel energy. So, you can talk about regulation; you can talk about policy. But economics will trump all of that.
“This year, clean energy funds raised about $5 billion, while fossil fuels have raised about $2 billion. That’s showing what the demands are from the … capital providers [and allocators] of this world. … These are sovereign wealth funds; these are pensions; these are large, super high net worth families. … This is how the capital markets — and these are capital markets that start with a ‘T’ — trillions — view clean energy infrastructure. When they move their allocation from 1% to 5%, that’s a game changer. And they’re moving towards that.”
Nancy Pfund, founder and managing partner of DBL Partners, predicted that there will be few gas-fired peaking plants built in California in the future.
“They’re expensive. People don’t like them. They’re [crude] compared to solar and storage or wind or demand response or any combination. That’s an example that you have to let go of what the 20th century was all about. This is really different and if you stand in the way … of consumers who want their solar or want batteries, they are going to run you over.”
An ‘F’ for Policymakers
Policymakers in D.C. haven’t heard that message, however, she said, as reflected in “the $4 billion worth of annual subsidies that the fossil industry gets.”
“If the people on Capitol Hill were in a public policy class or business school course, they would get an ‘F’ because [they are subsidizing] an industry that’s 100 years old. I think anyone in our [clean energy] industry would say we would love a level playing field. Get rid of all incentives. But it’s kind of a ‘David and Goliath’ story at this point.”
Puon Penn, executive vice president and head of technology capital for Wells Fargo, said investors would be wise to look past the U.S. to China and other growing economies that have committed to abandoning the internal combustion engine in favor of electric vehicles.
“Do you think the [original equipment manufacturers] … the Fords and the GMs are looking at the United States as their primary market today? They sell more vehicles in China. And if you’ve got to make electric vehicles for the Chinese market, you’re damn well not going to make a bunch of internal combustion vehicles for the United States. You’re just going to build one platform that you’re going to distribute across the planet. It’s inevitable. But people are still behaving like we’re still [the] Jolly Green Giant walking the earth and determining the order of things. We’re not anymore.”
Penn said new technologies are allowing greater capacity utilization in the electric industry than in the past. “There’s no other industries where you have high [capital expenditures] and such low capacity utilization,” he said. “Today we do have the wherewithal to increase capacity utilization and therefore benefit the entire economy.”
WASHINGTON — Speakers at the GridWise Alliance’s GridCONNEXT conference last week left no doubt: Electric storage is long past the “tipping point.”
Moderator Ram Sastry, vice president of infrastructure and business continuity for American Electric Power, had posed the question: “Are we going to see large-scale deployment of energy storage systems? And if not, what’s stopping that?”
“I think we’re at or past that tipping point,” responded Andy Marshall, practice director for distributed energy resource management at Landis & Gyr. “I think you see the flexibility of storage and its ability to get deployed relatively quickly. You have not only the stuff that’s going on down in Australia, but you also have the things that are happening most recently in California.”
On Dec. 1 — the first day of summer for Australia — Tesla turned on a 129-MWh lithium ion battery, the world’s largest, to help the nation’s fragile electric grid. California deployed 100 MW of storage in just six months in response to natural gas constraints following the Aliso Canyon leak.
Praveen Kathpal, vice president of AES Energy Storage, said “the technology is mature,” noting that his company entered the business a decade ago. AES claims 500 MW of storage already deployed or in development.
“There haven’t been any components that needed to be invented for any of the deployments that we’ve done, because they’re all based on lithium ion battery technology, which was commercialized 25 years ago and has benefited from its use in the consumer electronics and transportation sector,” Kathpal said.
“The tipping point we see in storage is really meshing with some of the other megatrends facing our industry right now. We have the accelerated growth in renewables, and we also have the electrification of more sectors including transportation.”
Kathpal predicted new storage technologies will break below the current pricing floor for lithium ion. “So, 10 years from now, do I think we’ll have a commercially available storage technology that’s below $100/kWh? Sure. And that’s exactly why at AES the technology platform we’ve developed is forward compatible with technology change.”
“I think you could argue that the tipping point was several years ago when big PJM systems started to come online,” said Luke Witmer, lead research engineer for Wärtsilä’s Greensmith Energy. “More and more markets continue to value the fast-ramping and bidirectional capability that energy storage provides. And I think as … systems continue to decline in cost, we will compete in more and more markets. A lot of the market prices basically clear according to the natural gas price. … So it’s really just a matter of getting renewables plus storage to below that threshold in more and more places.”
Richard Brody, director of sales and marketing for Lockheed Martin Energy’s energy storage unit, said storage is still relatively expensive when compared with energy efficiency and demand response.
“Whether we’re talking about a C&I customer or a distribution utility, when we come look at an energy problem, we look not just at storage, but we start with efficiency, permanent load reduction, load control, demand response, demand management, grid analytics — all the tools you can bring to solve an energy problem. … We tend to look at other things first because storage — despite the declining costs — remains the most expensive way to address these problems.”
But he is nevertheless bullish on storage. “In terms of the tipping point — oh yeah, we’re passed it. This is a rapidly growing market.
“We’re seeing very strong growth in interest in doing large solar and wind coupled with storage. Most of the large developers we’re working with aren’t contemplating any large development of solar — and increasingly wind — without some way to firm it up with a fairly significant storage system.”
Brody said the demands are exceeding the four-hour maximum life for lithium ion batteries. “We’re looking at much more ambitious efforts that would require the attributes of a flow battery, which is a minimum of six to 12 hours of energy.”
A Sierra Club report released last week that said captive customers of SPP utilities are paying for uneconomical coal plants has drawn considerable pushback from the RTO and some of its members.
But the head of SPP’s Market Monitoring Unit (MMU) says the environmental group has a point in its criticism of utilities that self-commit coal generators when the RTO’s market prices don’t cover their operating costs.
When a utility self-commits a unit, it operates the plant regardless of whether SPP’s market clearing prices are sufficient to cover the plant’s marginal costs. Although self-committed units are ineligible to receive make-whole payments from SPP, the Sierra Club says, some units are apparently recovering losses from captive customers through state ratemaking proceedings.
The Sierra Club report, “Backdoor Subsidies for Coal in the Southwest Power Pool,” alleges that utilities in the footprint operate coal plants outside the wholesale markets, generating $300 million in excess costs that consumers were forced to pick up in 2015 and 2016.
SPP and its members responded by saying the Sierra Club’s analysis relied heavily on wholesale rates, which aren’t the same as retail rates that are subject to public policy and regulations. Nor do wholesale rates consider the cost of long-term supply contracts or ensuring grid reliability, they said.
Keith Collins, executive director of the MMU, says that while the report took some of the MMU’s observations out of context, self-commitment is a problem in the RTO’s markets. MMU staff raised the issue in their 2016 State of the Market report, which Collins reviewed with SPP’s Board of Directors and Members Committee in July.
The Sierra Club said it conducted a “high-resolution analysis” of 14 coal plants in SPP’s footprint. It used hourly market data to develop each plant’s cash flow analysis.
“All 14 units operated for extended periods of time when, objectively, it would have been less expensive for the electric bills of utility customers for the plants to sit idle,” the group’s report said. “The utilities that own each of the 14 coal units we examined would have saved its customers money if the coal units had operated less often.”
The report said all but one of the 14 units studied were owned by state-regulated utilities, municipal utilities or an electric cooperative with captive customers.
Utilities should be purchasing electricity for its captive customers in the SPP Integrated Marketplace (IM), the report said. But it said some utilities “appear to be going back to state commissions and using rate cases and other dockets to obtain ratepayer-funded subsidies for costs incurred in operating otherwise uneconomic coal plants.”
“In the SPP market, where nearly half of the resources are self-committing, how much of an energy market can SPP really be claiming to operate?” the report asked. “The consequence of these facts is that the SPP Integrated Market is possibly a market in name only. The impact of utility self-commit and underbidding energy offers within the SPP IM might be the most anticompetitive and anti-consumer behavior in any integrated electricity market anywhere in North America.”
The report also says self-committed coal units are denying revenues to independent merchant generators. “RTOs are supposed to create nondiscriminatory rates, but allowing coal units to self-commit discriminates against those operators that don’t have captive customers to fund a ratepayer subsidy. Moreover, it is discriminatory and unreasonable for the market to ask one subset of customers to pay above-market costs while all other customers pay market costs.”
Collins told the board and members that self-commitment of resources has declined but is “still very big.”
“When resources are self-committing, it can put downward pressure on prices also,” he said at the time, referring to the effects of incorporating uneconomic resources in wholesale prices.
“The point of the [Sierra Club’s] report is consistent with what we noted in the 2016 annual report,” Collins told RTO Insider. “Self-commitment can distort the market. It’s a message we’ve been presenting as well.”
The MMU report noted generation offers in the day-ahead market averaged 48% as “market” commitments and 35% for “self-commit” in 2016. Those numbers were 46% and 39%, respectively, in 2015. Outages accounted for the remainder.
The Sierra Club report quoted the MMU report, which said plants self-commit because of contract terms, low gas prices “that reduce the opportunity for coal units to be economically cleared in the day-ahead market,” long start-up times, and “a risk-averse business practice approach.”
Collins took exception to the Sierra Club’s claim that “reliability isn’t one” of the reasons why a unit might self-commit.
Although the MMU’s report didn’t cite reliability, Collins said, “reliability could play a factor where some of these resources self-commit. Our report identified a set of reasons for self-committing, rather than a complete list.
“We have been discussing this essentially since I’ve been here,” said Collins, a former FERC staffer who joined SPP in June from CAISO. “What are the factors [behind self-commitment]? What can we do to promote more market commitment? Some of it is education and creating awareness. At least there’s a dialogue there that’s begun.”
SPP Disagrees
SPP General Counsel Paul Suskie said in a statement that the RTO disagreed with the report’s fundamental assertion that “utilities’ option to either self-commit resources or purchase from the market equates to a subsidy and undermines the effectiveness and cost-efficiency of SPP’s Integrated Marketplace.”
Suskie said that “assessing the market’s fairness and effectiveness based on wholesale cost of electricity to consumers does not take into consideration a number of factors that may lead utilities to self-commit.” He listed contractual obligations, capital investments, public policy and fossil fuels’ contribution to renewable resources’ deliverability as among those factors.
“Our day-ahead market has functioned successfully for four years and, in that time, has reduced the cost of energy in our region by more than $1.25 billion while continuing to ensure the reliability of the grid,” Suskie said.
Peter Main, a spokesman for SPP member Southwestern Electric Power Co., said the company bids its generation into the RTO’s markets under its market protocols and will continue “to seek opportunities” to produce net energy revenues benefiting its customers.
“The Sierra Club report does not provide an accurate portrayal of the incremental (variable) costs and revenues associated with offering generation into the SPP Integrated Marketplace,” Main said in a statement.
Plant Operators Dispute Findings
According to the report, SWEPCO’s Dolet Hills and Pirkey plants in the East Texas-Louisiana region burdened customers with $210 million in costs in 2015 and 2016. However, SPP said the plants serve load in “locations in northeast Texas without significant wind.”
Oklahoma Gas and Electric, which owns two of the plants identified in the study, has said the units stopped self-committing into the market more than two years ago. Two other generators — Entergy-owned or co-owned plants in Arkansas — serve load in MISO.
Al Armendariz, with the Sierra Club’s Lone Star chapter, said he was confident the group has a “good handle on the cost to run these coal plants in SPP.”
Armendariz, who worked in EPA under President Barack Obama, said the Sierra Club compared the SPP LMPs paid to power plants in the immediate vicinity of the coal plants studied. The organization obtained operating data from S&P Global Market Intelligence, the U.S. Energy Information Administration and SPP in running its analysis.
“Our report is really a comparison of the revenue for electricity, compared to what it costs to actually run the power plant,” Armendariz said.
Rule Changes Sought
The Sierra Club would like to see several things happen, Armendariz said. “We think SPP should clarify its rules to require power plants to bid in their real cost of fuel and other variable [operations and maintenance] … in the day-ahead market.”
Armendariz also said the Sierra Club would like to see state commissions in SPP’s footprint “investigate this problem of self-commitment and disallow the recovery of costs borne by consumers when uncompetitive coal plants are operating.”
“Vertically integrated utilities should not be forcing their customers to pay the variable costs,” he said. “State commissions should not allow the recovery of those costs through the rate base.”
Asked whether the group planned to file a complaint with FERC, Armendariz told RTO Insider that the Sierra Club “is evaluating all avenues of legal recourse that may be available to rectify the problems.”
Both Armendariz and Collins agreed the problem of self-commitment is not unique to SPP. Collins said he saw self-dispatch at CAISO and “knows” it occurs in other markets. Armendariz said although uncompetitive coal plants are running in “virtually every market … the problem seems most acute in SPP.”
The MMU believes that will change as market participants continue to familiarize themselves with SPP’s day-ahead and real-time markets, which have been in operation for less than four years.
“It appears that resource owners are becoming more confident in the market and allowing the market to commit the resource instead of self-committing their resource,” the State of the Market report said.
The Monitor also said the market systems’ optimization algorithm is restricted to a 48-hour window. “Hence, large baseload resources with long-lead time and substantial start-up costs may not appear economic to the day-ahead market commitment algorithm,” the report said.
Collins said SPP’s Market Working Group has discussed a potential multiday optimization approach. A Tariff change has yet to materialize, he said, “but that could help address some of the concerns.”
