FERC last week ended a seven-year-old dispute over cost allocation for three Virginia Electric Power Co. transmission undergrounding projects when it accepted a compliance filing and denied related rehearing requests (ER18-318, EL10-49, et al.).
At issue was whether Old Dominion Electric Cooperative and North Carolina Electric Membership Corp. (NCEMC) should be required to pay the additional costs of undergrounding VEPCO’s Pleasant View, DuPont Fabros and Garrisonville projects.
VEPCO’s filing revised its tariff to remove, extending back to March 17, 2010, the incremental costs of undergrounding the projects, and instead charged those costs to wholesale transmission customers in Virginia, which had mandated the undergrounding. In response to a conditional protest by NCEMC, the tariff was amended to exclude NCEMC and all other North Carolina wholesale customers from the undergrounding costs in light of another FERC decision on the issue last October affirming that North Carolina customers would bear no additional costs. (See FERC Upholds Cost Allocation on Va. Tx Undergrounding.)
The commission last week denied rehearing requests from VEPCO, which had argued against excluding several costs from the allocation. FERC said it was reasonable to exclude any costs that had not been shown to be directly related to constructing the projects underground.
The commission also denied rehearing requests from ODEC, Northern Virginia Electric Cooperative and Virginia Municipal Electric Association No. 1. FERC said it had already determined it appropriate to allocate incremental undergrounding costs to all Virginia customers in the Dominion zone, and that the only issue set for hearing was the appropriate amount of the costs to be allocated among those customers on a load-ratio share basis.
VALLEY FORGE, Pa. — PJM has altered one of its recommended revisions to its capacity auction demand curve in response to stakeholder pressure, and a coalition of generators is pushing for other changes.
Staff have agreed with stakeholder requests to recommend moving the curve 1% left, negating a 1% shift to the right when the curve was last analyzed in 2014 and reducing excess capacity. The recommendations are part of PJM’s quadrennial review of the variable resource requirement (VRR) curve in its Reliability Pricing Model capacity market construct.
The announcement came at a Friday meeting of stakeholders interested in revisions to the curve. Tanya Bodell of Energyzt also provided an analysis funded by the PJM Power Providers Group (P3) that argued for retaining the current model of combustion turbine as the curve’s reference resource. A reference resource is representative of a peaking unit in the energy market that derives a significant portion of its revenues from the capacity market.
PJM is recommending switching from the Frame F to the Frame H of a General Electric turbine based on an analysis it commissioned from the Brattle Group, but Bodell said Frame F allows for flexibility and modularity, which is currently favored over unit size by market participants. Characteristics of the Frame H units are “so 2000s,” she said, because they’re designed and being used for “large, baseload combined cycle applications.” She noted that no Frame H units are being installed as CTs in PJM’s territory, and there is no evidence they will be, while Frame F units are. The mismatch would result in an inappropriate demand curve, she said.
“Going solely for the least-costly estimated technology can really squeeze out a lot of innovation and a lot of long-term gains that you can get from new technologies that are coming in,” Bodell said.
Erik Heinle of the D.C. Office of the People’s Counsel thanked Bodell for the presentation and said it’s “worth considering” proposals for the F and the H frames as either CTs or CCs.
PJM is targeting Oct. 12 to make its filing for FERC approval, and seeking endorsement votes by the Markets and Reliability Committee on Aug. 23 and the Members Committee during a Aug. 31 teleconference.
VALLEY FORGE, Pa. — With the opening of PJM’s next long-term transmission proposal window looming less than four months away, it remains unclear whether the RTO will have new rules in place for evaluating and selecting market efficiency projects.
That would mean that any rule changes discussed by the Market Efficiency Process Enhancement Task Force since February that aren’t in place by the window’s Nov. 1 start will have to wait another two years for the Regional Transmission Expansion Plan’s next window.
After a three-hour meeting on Thursday, stakeholders remain at odds about how to move forward. A nonbinding poll showed stakeholders were unable to find at least 50% consensus on any of six solution proposals to address how PJM evaluates and chooses the discretionary transmission projects, which aren’t necessary for reliability but are meant to reduce congestion costs.
The Package A proposal received 49% approval, but stakeholders remained at odds over whether to exclude facility study agreements from the base case unless needed for reliability; whether to use a $10 million versus $20 million threshold on project re-evaluation criteria; and how to calculate energy benefits.
Given the intractability, PJM’s Brian Chmielewski, who oversees the task force, said the group should not forward all six proposals for consideration at the July 12 Planning Committee meeting, but instead attempt to sort through the polling results to assemble three new proposal packages. Stakeholders allowed Chmielewski to create the composite proposals but then balked at sending just those three to the committee.
LS Power’s Sharon Segner said the changes were significant enough for the task force to take another poll, which was supported by representatives from transmission owners Public Service Electric and Gas and American Electric Power. Chmielewski expressed concern about the further delay.
“If we do another poll, we lose the Nov. 1 effective date,” he explained, because there won’t be enough time to get it through the stakeholder endorsement process and receive FERC approval. “Slowing down a month means you miss another two years of new rules. … I think we should go to that [PC] meeting with the intent of having a first read” and take the committee’s input, he said.
Segner suggested adding the new rules to the upcoming window after it opens if FERC would approve such a move, but GT Power Group’s Dave Pratzon expressed concern that such late changes could disadvantage bidders.
Pauline Foley, PJM’s counsel, said she wasn’t “comfortable” with making a determination on whether PJM would be willing to ask FERC for a waiver to grant the approval in less than 60 days. PJM’s Asanga Perera added that other stakeholders might complain about the bidding rules potentially being changed halfway through the process. The window runs through February.
“I don’t think it’s just PJM’s call,” Perera said.
On Friday afternoon, RTO staff opened a poll on the three new proposals and gave stakeholders until noon on Wednesday to respond, giving staff enough time to compile and report the results at the PC.
Fuel security was at the top of the agenda during the annual summer meeting of the New England Power Pool Participants Committee, which also featured presentations by ISO-NE’s external and internal Market Monitors.
Members attending the June 26-28 committee meeting at the Water’s Edge Resort and Spa in Westbrook, Conn., also voted to change NEPOOL rules to formalize the policy of banning the press from their meetings. NEPOOL is the only RTO/ISO stakeholder body in the country that bars the public and press from meetings.
The vote, which approved changes to committee bylaws and the Second Restated NEPOOL Agreement, passed with 79% in favor in a sector-weighted vote, according to a notice of action taken at the three-day meeting. The changes add a definition of “press” and bar anyone working for the news media from becoming a NEPOOL member or alternate for a participant.
Three members of the Members Subcommittee disagreed with the Participants Committee’s recommendation on the changes and made a dissenting proposal that would have made the press eligible for a non-voting membership for a $5,000 application and an annual fee. It failed with only 27% in support, with only the end-user sector strongly in support.
RTO Insider prompted the vote by having a reporter who lives in Vermont apply for committee membership as an end-user customer in March. NEPOOL has not acted on the application.
“As you know, your application raised some interesting issues for the Participants,” Day Pitney attorney Pat Gerity, who serves as legal counsel to the Membership Subcommittee, wrote in an email last week. “They continue to work through those. Thus, the status of your application is that it is still pending.”
The changes have been submitted to the entire membership for a mail ballot ending this week. Assuming approval, they will be submitted to FERC.
Consent Agenda
The Participants Committee unanimously approved two items on its consent agenda:
Revisions to the Tariff and Market Rule 1 to modify the allocation of costs of the Forward Capacity Auction and annual reconfiguration auction to improve the alignment with the auction clearing methodology under the marginal reliability impact demand curves. The changes include a new definition for “estimated capacity load obligation” and replace the use of the net regional clearing price and residual capacity transfer rights in the Forward Capacity Market settlement. The RTO will request an effective date of June 1, 2021, for the 12th Capacity Commitment Period. (Separately, the committee approved related changes to the RTO’s Financial Assurance Policy.)
Retirement of Appendix C (Demand Response Holidays) of Operating Procedure 14 (Technical Requirements for Generation, Demand Resources and Asset Related Demands) to reflect the removal of demand response holidays because of the implementation of price-responsive demand, which had been recommended by the Reliability Committee on June 12.
No to New Winter Reliability Program
A proposal to re-establish a winter reliability program for future winter periods failed to pass, garnering only a 50% vote in favor. Energy New England (ENE), a Massachusetts cooperative owned by the municipalities Braintree, Taunton, Concord, Hingham and Wellesley, proposed the measure.
ENE proposed continuing the same program rules as were used for winters 2015/16 and 2017/18. It said the Pay-for-Performance program, which took effect June 1 to replace the winter program, provides “little incentive to materially increase stored fuels” because rates are too low and there is excess cleared capacity for winter 2018/19. The PFP program increased financial incentives for resource owners to make investments to ensure their resources’ reliability during periods of scarcity.
ENE said the winter reliability program should remain in effect until implementation of a “market-based solution.”
The proposal previously failed to gain endorsement by the Markets Committee, winning less than 30% support.
Fuel Security
Fuel security occupied most of the agenda for the second day of the meeting, with Paul J. Hibbard of Analysis Group moderating presentations by Professor Anji Seth of the University of Connecticut Institute for Resilience & Climate Adaptation and Phyllis Yoshida, Sasakawa Peace Foundation USA’s senior fellow for energy and technology and former Department of Energy deputy assistant secretary for Asia, Europe and the Americas.
Seth’s report addressed climate change, concluding that many currently rare extreme events will become more commonplace over the next few decades as the climate adjusts to greenhouse gases already emitted, while natural variability could amplify or suppress the warming signal regionally.
Yoshida looked at the impact of the Fukushima nuclear accident on Japan’s energy systems and extrapolated lessons for New England on how a region with insufficient domestic resources can provide a resilient energy supply in the face of unexpected events. She recommended that policymakers ensure that electricity and natural gas market deregulation is transparent, increases competition and creates opportunities for new actors and new technologies and practices.
External Monitor’s Fuel Security Assessment
ISO-NE’s External Market Monitor David Patton of Potomac Economics gave a presentation on his firm’s 2017 State of the Market report, which included a fuel security assessment for a two-week period of severe winter weather.
The EMM’s baseline scenario found that more than two-thirds of all potential LNG and oil storage capability will be needed if the Everett Marine (Distrigas) LNG terminal retires. Under a “severe pipeline contingency,” the market will be slightly short with Distrigas in 2023/24 and short by the equivalent of 2,500 MW for two weeks without the facility, Potomac Economics said.
Potomac Economics’ analysis of a two-week severe winter period found that more than two-thirds of all potential LNG and oil storage capability will be needed if Distrigas retires. In its pipeline contingency scenario, the Monitor found the market will be slightly short with Distrigas in 2023/24 and short by the equivalent of 2,500 MW for two weeks without the facility. | Potomac Economics
“Although the oil storage capacity and LNG import capability are high enough to satisfy the demand for these fuels during a severe winter event, it would require very high utilization rates — above those observed in the past,” the EMM said.
The system is projected to require a very high percentage of this capability if the Distrigas terminal is retired, the report said. “Additionally, even if this terminal does not retire, the demand for oil and gas will exceed the available supply under a severe pipeline contingency in the 2023/24 cold snap scenario. This suggests that under these conditions, ISO-NE would lose its ability to serve the load for an extended time frame.”
Continuing a long-term trend, New England saw the lowest electric demand in at least 18 years in 2017, driven by an increase in energy efficiency and, to a lesser extent, behind-the-meter solar. | ISO-NE
The EMM said “market design changes may be needed to ensure that generators have incentives to conserve limited fuel supplies and allow market prices to efficiently reflect these fuel limitations.”
2017 Wholesale and Capacity Market Costs Rise Sharply
Jeff McDonald, the RTO’s vice president for market monitoring, presented the Internal Market Monitor report on 2017 market performance, which found that “energy, capacity and ancillary service markets performed well, exhibiting competitive outcomes.”
New England’s fuel mix in 2017 was similar to that since 2015, with natural gas claiming a 48% share of energy generation and 39% of capacity.| ISO-NE
Wholesale electricity prices reflected changes in underlying primary fuel prices and electricity demand, with costs last year totaling $9.1 billion, up 20% from the previous year, the report said. Capacity market costs were up 93% to $2.2 billion because of higher prices in FCA 8 in 2014, which covered the 2017/18 CCP.
The IMM reported 2017 energy market costs totaled $4.5 billion, up 9% from the previous year, while natural gas price averaged $3.72/MMBtu, up 19%. Electricity demand declined 2% for the year, and in Q3 dropped 8%, which helped offset the impact of higher natural gas prices.
New England’s fuel mix in 2017 was largely unchanged since 2015, with natural gas claiming a 48% share of energy generation and 39% of capacity.
Continuing a long-term trend, New England saw the lowest electric demand in at least 18 years in 2017, driven by an increase in energy efficiency and, to a lesser extent, behind-the-meter solar, the report said.
High uplift costs, market power and the capacity market highlighted the External Market Monitor’s concerns in the 2017 State of the Market report for ISO-NE.
Monitor David Patton of Potomac Economics briefed stakeholders on the report at the annual summer meeting of the New England Power Pool Participants Committee last week.
The Monitor said the energy and capacity markets were competitive, with little evidence of withholding, and that market mitigation was infrequent and effective. However, the pivotal supplier analysis found market power under high-load conditions and in the Boston area — the latter of which will diminish with the completion of the Greater Boston Reliability Project and the addition of the Footprint Power combined cycle plant.
A graph of Structural Market Power Indicators shows that market concentration has changed very little from 2016 to 2017 in each of the four New England regions. | Potomac Economics
The only mitigation measures that have not been fully effective are those on resources frequently committed for local reliability. “Although the mitigation thresholds are tight, the suppliers have the incentive to operate in a higher-cost mode and receive higher NCPC [net commitment-period compensation] payments,” the report said.
| Potomac Economics
The NCPC payments contributed to high uplift charges of 42 cents/MWh last year, the Monitor said, more than double that for NYISO ($0.24/MWh) and MISO ($0.16/MWh).
The issue prompted two of the Monitor’s eight recommendations, most of which were repeated from its 2016 review. It said the RTO should change the allocation of “economic” NCPC charges consistent with “cost causation” principles and use the lowest-cost fuel — or lowest-cost configuration for multi-unit generators — when making commitments for local reliability.
Reserve Markets
The Monitor also made two related recommendations to reduce uplift, saying the RTO should eliminate its forward reserve market and create a day-ahead operating reserve market co-optimized with the day-ahead energy market.
It said more than three-quarters of day-ahead NCPC charges result from local second contingency protection and system-level 10-minute spinning reserve requirements. Because there is no day-ahead operating reserve market, the Monitor said, the costs are not reflected efficiently in day-ahead prices, resulting in excess reserve commitments and depressed reserve prices.
Creating a day-ahead reserve market would allow the elimination of the forward reserve market, which the Monitor said has “resulted in inefficient economic signals and market costs.”
Capacity Market Concerns
Capacity market issues prompted three recommendations, including a call for market changes to complement the Pay-for-Performance program that began June 1 to ensure fuel security under severe winter conditions.
The Monitor said that although PFP will provide incentives for generators to procure fuel for severe winter conditions, “it will not provide the planning and coordination that may be necessary to ensure that ISO-NE’s seasonal reliability criteria are satisfied. Thus, the ISO should evaluate whether it has seasonal planning needs for the winter that must be met to satisfy its overall reliability criteria.”
It also said it should replace its descending clock auction with a sealed bid procurement and reduce the availability of information about qualified supply before the auction. The current structure provides suppliers with information they can use to recognize when they can benefit by raising capacity prices, it said.
The Monitor recommended several changes to the RTO’s minimum offer price rule (MOPR): eliminating performance payment eligibility for units subject to the rule; capping the minimum price at the net cost of new entry; and exempting resources resulting from unsubsidized private investment.
Under PFP, the Monitor said, most of the value of capacity will come from performance payments. But because resources that skip the capacity auction can still earn the payments by producing energy during shortages, “the MOPR will not likely be an effective deterrent under the PFP framework. In addition, an uneconomic entrant will be able to depress capacity prices without selling capacity because it will lower the expected number of shortage hours.”
The report notes that unlike other RTOs, ISO-NE’s MOPR lacks a competitive entry exemption, which could interfere with private investment in new resources.
And it said the MOPR could raise prices substantially above net CONE (currently about $8/kW-month) because it sets the offer floor at the new resource’s actual entry cost. That could prevent state-sponsored resources from clearing in the Forward Capacity Auction, with the RTO instead clearing a conventional resource. Under the recently approved Competitive Auctions with Subsidized Policy Resources (CASPR) program, “clearing unneeded conventional resources will compel the sponsored resources to pay lower-cost existing resources to retire,” the Monitor said.
In addition to its formal recommendations, the Monitor also noted that several new resources that obtained capacity supply obligations (CSOs) have been delayed in recent years, with some failing to deliver their capacity during the capacity commitment period (CCP).
Consistent delays in delivery of resources have significant implications for market outcomes and efficiency and affect other participants, the Monitor said. “Delayed new projects lower the prices in the FCA(s) in which they cleared, and as a result, FCA prices do not reflect the actual realized supply and demand and the reliability of the system. In addition, other resources that obtained a CSO in the FCA with delayed resources would face additional performance-related risks under the PFP framework,” it said.
The Monitor said it supports the RTO’s efforts to develop tougher penalties for delayed resources but also encouraged it to consider switching to a prompt market, with the auction conducted immediately before the commitment period.
Coordinated Transaction Scheduling
The report recommended the RTO find ways to improve its price forecasting under its coordinated transaction scheduling (CTS) with NYISO, finding that real-time transactions between the two regions went in the wrong direction in 44% of intervals in 2017.
Although CTS’ performance improved last year, the savings were reduced by a small number of intervals with errors of more than $20/MWh.
The Monitor said errors in load forecasting and wind forecasting were the biggest problem, responsible for 23% of price forecast errors. Differences in timing and ramp profiles was the second largest contributor, causing 22% of pricing errors.
MEXICO CITY — Mexican President-elect Andres Manuel Lopez Obrador has been called a populist, a nationalist, a socialist and, because of his anti-establishment reputation, a mirror image of Donald Trump. That could be bad news for Mexico’s fledgling competitive electric market.
Lopez Obrador has said he wants to evaluate the energy liberalization of 2013-14, which opened the state-run petroleum and electric industries to foreign investment. Although the president-elect’s focus has been on the country’s oil resources, that doesn’t make those involved in the electric reforms feel much better.
“It’s super uncertain,” said Jose Maria Lujambio Irazabal, a legal counsel deeply involved in the energy reforms, now engaged in private practice in Texas. Offering a more optimistic note, he added, “There’s no immediate interest in changing anything. It’s not politically attractive.”
“Everybody has said they want money to come to Mexico,” said Duncan Wood, director of the Wilson Center’s Mexico Institute during a Gulf Coast Power Association breakfast last week. “It’s not a nationalist idea to say foreign money is bad, except in the energy sector, and oil and gas in particular.”
David Shields, who runs a Spanish-language website devoted to analysis and opinions on energy issues, said the opposition to foreign investment stems from U.S. companies’ expropriation of natural resources south of the border during the early 1900s. “Current leftist thought is that foreigners shouldn’t have [the oil],” Shields said.
Lopez Obrador, more popularly known as AMLO, campaigned on promises to reduce economic inequality, combat corruption and reduce narco violence. Wood said his message was consistent with his previous two runs for the presidency in 2006 and 2012. But this time, AMLO’s message resonated with Mexicans resentful of the elites and tired of the status quo.
He won almost 54% of the vote in a field with four other contenders.
“You have to go to an Andres Manuel rally just to experience it,” said Wood, who was among the 80,000 that filled the Zocalo, Mexico City’s main square, for the president-elect’s victory speech July 1. “They’re emotionally exhausting. You get there, and everyone is screaming, ‘Presidente! Presidente!’”
AMLO’s National Regeneration Movement party (MORENA) formally created only four years ago, also won majorities in both houses of the national legislature and took five of the nine governorships that were up for grabs. With the party near a super-majority, which it could gain in the 2021 midterms, locals are already talking about constitutional changes that could lead to a second term for Lopez Obrador and the possible extinction of the PRI and PAN parties that have ruled Mexico for 89 years.
“Andres Manuel studies history,” Wood said. “He wants to be a great presidente. He wants a legacy. He wants to go down in history and be remembered by the history books as someone who improved the country.”
Taking on Pemex
Wood said AMLO’s objective is to have MORENA become a “truly hegemonic” party that dominates Mexican politics for years to come. That means taking on a pair of institutions that have come to symbolize Mexican corruption, the government and Pemex, the national petroleum monopoly.
AMLO’s administration, which won’t take office until Dec. 1, has said it wants to review each of the 107 energy-related contracts the government has signed with ExxonMobil, Chevron and more than 70 other foreign companies to seek out corruption. Suspicious of the private-equity interests backing some of the contracts, the incoming government also wants to suspend new oil and power auctions during the transition, an action Wood says President Enrique Pena Nieto is likely to agree to as a sign of goodwill.
“It’s not the contract; it’s how [the companies] got the contract,” Wood said. “In that way, [the government] could choose one company and make them the scapegoat. Then [it] can tell the public, ‘We fixed it.’
“Will that freak out investors? Yes, but it won’t be a disaster,” he said. “Those 107 contracts are already starting to pay off. The rig count has gone up for the first time in years. Andres Manuel will start receiving the benefits of energy reform. Revenues are coming into the coffers. He doesn’t have any interest in canceling those contracts. When they say there won’t be any more bidding, that might be the truth.”
Power Contracts More Transparent
While most of the contracts are oil and gas exploration and production deals, they also include clean-energy certificates and energy and capacity contracts. Power industry insiders say their contracts are more transparent than those in the oil and gas sector, and they remain confident they will remain a lower priority for AMLO. They note that the subsidized electric industry provides cheap power, while Pemex is seen as extracting value from the nation’s resources.
“In our view, the electric industry is in a less vulnerable position than the oil and gas industry, but we’ll be monitoring it very closely,” said Laurie Fitzmaurice, vice president of development for EDF Energy’s Mexico business.
EDF has a sizeable presence in Mexico, with 391 MW of wind generation operating, 90 MW of solar under construction and more than 1 GW of wind and solar in development. Fitzmaurice said EDF has been in Mexico for more than 15 years and intends to remain “for the long term.”
“Signals sent by the incoming administration and the support of industrials and the local business sector have been positive,” she said, noting that the industry is in the middle of another power auction, with economic bids due in November and contracts to be awarded in February.
Peter Nance, managing director of Que Advisors, is among those taking a wait-and-see attitude. He expects the oil-and-gas sector to undergo the new administration’s initial scrutiny. “The [power] auctions have been successful in attracting capital,” he said.
“Our job for the next six years is to explain the importance of the power reforms,” said Ruth Guevara, a founding partner with Zumma, an energy consulting firm.
Nance and others point out that foreign investment will be important if AMLO wants to balance the budget and provide subsidies and other income support for low-income farm workers.
“They will need the money for the federal budget,” Lujambio Irazabal said. “The key is low [electric] prices for the end users. We’ve always had subsidies, and we’ll always have subsidies.”
“Electricity is less controversial in the public eye than oil contracts,” Wood said. “There has to be some kind of gift to the Mexican electorate, and that will be continuation of subsidies for small Mexican consumers.”
The government has long subsidized electric rates for its smallest consumers on the backs of large users, and Wood said AMLO has had a long history of fighting for lower prices. In the mid-90s, AMLO organized protests against excessive fees being charged to consumers in his home state of Tabasco, protests that continue today.
“You will see that powerful, centralized government is going to be crucial to managing the energy sector,” Wood said.
He said whomever is chosen for energy secretary will be secondary to the president-elect. However, AMLO’s early choice for the position, Pemex veteran Norma Rocio Nahle Garcia, is not the open-market economist Wood was hoping for. “Her vision is definitely of the old style of Mexican politics,” he said.
And change may not be what Mexico’s economy, the world’s 13th largest, necessarily needs at this point, Wood said.
“Cheap power is fundamental to Mexico’s economic competitiveness,” Wood said. “Andres Manuel knows he needs one thing. He has political dominance, but he needs economic stability. He’s not going to change very much.”
ERCOT is leaving significant amounts of money on the table by not using real-time co-optimization (RTC) of energy and ancillary services in its market operations, a study by the ISO’s Independent Market Monitor has concluded.
In its study filed last month with the Public Utility Commission of Texas, the Monitor found ERCOT last year could have realized savings of $257 million in congestion costs, $155 million in ancillary services costs, about $4/MWh in energy costs and $10 million to $12 million in production cost savings (Docket No. 47199).
The Monitor recommended ERCOT and the PUC implement RTC “as expeditiously as possible.” Noting that ERCOT has said it will cost about $40 million and take four or five years to begin using the process, the Monitor said the annual production cost savings and its analysis “provides quantitative evidence of [RTC’s] benefits and improved market efficiencies … [that] more than justify the implementation costs.”
“It’s the key missing link in our market,” IMM Director Beth Garza said last month in Houston. “Our market is dependent on pricing during significant scarcity intervals. My fear is that as we get to the point where we see tighter reserve margins, the likelihood of scarcity pricing increases. And high prices are an indication of the ineffective allocation of reserves.”
The Monitor has consistently recommended the use of RTC since the nodal market went online in 2010, calling it “foundational” to efficient pricing. (See “Monitor Says Wholesale Market ‘Performed Competitively’ in 2017,” ERCOT Briefs.)
The Monitor used historical offers and commitment status of resources from 2017 to simulate the effect RTC would have had on dispatch, prices, costs and system conditions, assuming that market participant behavior would remain unchanged.
It found that “jointly optimizing all products in each interval allows [ancillary services] responsibilities to be continually adjusted in response to changing market conditions.” It also said that RTC improves the accuracy of shortage pricing, pointing out that even using data from a year with high installed reserves, it found there were many intervals where average load prices implied scarcity.
“With RTC, however, the number of those intervals decreased significantly,” the Monitor said. “In an energy-only market that depends on scarcity pricing signals to provide incentive for proper levels of investment, it is important the scarcity pricing reflects actual scarcity rather than the inefficient assignment of reserve capacity.”
The analysis also revealed a “significant improvement” in system reliability because of reduced overloading on network constraints and a reduced use of regulation-up service.
As part of the PUC docket, ERCOT staff also filed a report on co-optimization’s operational benefits and its expected effect on reliability unit commitment (RUC) and supplemental ancillary services markets (SASMs). Staff filed a separate report addressing the benefits of incorporating marginal losses into security-constrained economic dispatch.
ERCOT’s analysis anticipates significant operational benefits from RTC’s implementation, including the timelier procurement of additional ancillary services, more effective congestion management, less manual actions by operators and “an improved management of resource-specific capabilities in assigning and deploying” ancillary services.
Staff said ERCOT has executed 391 SASMs covering more than 2,200 operating hours at average clearing prices of $100/MWh more than the corresponding day-ahead price since the nodal market began. When priced at the $100/MWh premium, they said, the megawatts procured in the SASMs resulted in an $11 million difference.
| MapSearch
The ISO’s scarcity pricing study indicated it will likely realize production cost savings and reduced consumer costs by incorporating marginal losses in system dispatch decisions. The analysis also projected increases in unit make-whole payments and start-up costs, “which could indicate possible additional costs if marginal losses are implemented.”
The PUC last year directed ERCOT and the Monitor to produce the studies as part of its efforts to improve market performance. The Monitor has made the simulation program code, data and use instructions available on ERCOT’s website.
July Begins with Another Monthly Demand Record
ERCOT wasted no time setting a new monthly demand record for the third straight month when the system recorded demand of 69.6 GW on July 3 during the 4-5 p.m. hour. July’s previous high was set last year at 69.5 GW.
System demand also topped the old record during the 5-6 p.m. hour.
The ISO has now recorded four new monthly highs this year. Staff has forecasted demand will exceed 70 GW in July and August, with a new summer peak of 72.97 GW expected next month.
Real-time prices topped out at $71.85/MWh during the interval ending at 2:30 p.m. on July 3.
The grid operator has yet to issue a conservation appeal this summer. It says it has 78.2 GW of capacity available, with a planning reserve margin of 11%. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)
Garland Generating Units Return to Mothballs
ERCOT has approved two separate requests by the city of Garland to return 572 MW of generating capacity to mothball status this fall.
The ISO on Friday approved a notification of suspension of operations (NSO) for two units at Garland’s Spencer plant, effective Oct. 3. The two gas-fired units have a total capacity of 118 MW.
ERCOT earlier had approved an NSO for the city’s 454-MW, coal-fired Gibbons Creek facility, effective Oct. 1.
The grid operator determined the generation resources were not necessary to support transmission system reliability during their unavailability.
Both units were returned to seasonal status this spring.
VALLEY FORGE, Pa. — Facing what they called an “impasse” in stakeholder negotiations that began more than two years ago, PJM staff attempted to suspend the Transmission Replacement Processes Senior Task Force (TRPSTF) on Thursday, seeking to cease meetings until FERC responds to two compliance filings on the issue.
“It’s clear that we made progress here … [but] it appears that we are effectively at an impasse,” PJM attorney Chris O’Hara said in the early afternoon of what was scheduled as an all-day meeting, adding that it is “important that we get more guidance” from FERC. He confirmed the decision to suspend the task force was “informed by comments from [CEO] Andy” Ott.
Following stakeholder criticism, the group’s chairman said Friday that at least the next meeting, on July 31, will go on as scheduled.
PJM and its transmission owners submitted the filings in March in response to a commission ruling that TOs weren’t properly complying with their obligations under Order 890 to provide stakeholders with adequate information on “supplemental” projects — transmission expansions or enhancements not required for compliance with reliability, operational performance or economic criteria. (See Group Contests ‘Supplementals’ Ruling as PJM, TOs Advance.)
The ruling allowed for moving TOs’ responsibilities from the Operating Agreement to a new Attachment M-3 in the Tariff, but PJM and the TOs requested additional detail on how and when projects would receive stakeholder consideration.
“We are resource-limited at PJM,” O’Hara said, echoing comments Ott made at the Members Committee meeting on June 21, when the CEO took the unusual step of directly addressing members prior to a final vote on incorporating cost-containment measures into competitive bidding for transmission projects. Ott warned that implementing the measures would force staff to triage other revisions to the Regional Transmission Expansion Plan. (See Cost Containment Clears MC Vote Despite PJM Plea.)
“Stakeholders have indicated that their highest priority is that we focus on cost containment and [return on equity] capital structure commitments,” O’Hara said. “We have to dedicate our resources to implementing the processes that are on the table.”
Stakeholder Reaction
Many stakeholders were shaken by the announcement.
“I am baffled by the conclusions that a vote on anything at the [MC] indicates a stakeholder preference or prioritization. That is not what was in front of the membership. That is not what we were voting on,” said Carl Johnson, who represents the PJM Public Power Coalition.
American Municipal Power’s Steve Lieberman said the stakeholder process is designed for up-or-down votes on single issues, not votes that “enact a change in lieu of something else.”
Adrien Ford of Old Dominion Electric Cooperative said she was “taken aback” by the decision being made “without input from stakeholders.”
“It’s just a little disappointing to me right now,” added Ford, who joined ODEC a year ago after almost nine years with PJM. “This is unprecedented.”
AMP’s Ed Tatum said he was attempting to sort through his reactions to respond thoughtfully and “not in pure anger.”
“I’m pretty pissed off about this … but I think you probably already know that. The whole idea that we just stop a process here without the senior committee looking at it — that’s a bit tough. It goes against anything we’ve ever done in the stakeholder process,” he said. “PJM is once again jumping into a situation and preventing the process from moving toward a natural conclusion. You have done the PJM stakeholder process a great disservice today.”
The decision came unexpectedly in a meeting that started with reviewing proposals for the end-of-life supplemental project process. Supplemental projects are developed by incumbent TOs outside of PJM’s scrutiny because they are not required to fulfill any reliability obligations from NERC, FERC or the RTO. They’re paid for by the ratepayers in the TO’s zone but included in the RTEP for planning purposes. AMP and other stakeholders have argued that TOs are increasingly finding ways to funnel projects into those categories to build them without competitive bidding. (See Report Decries Rising PJM Tx Costs; Seeks Project Transparency.)
AMP and ODEC had offered a “hybrid” proposal on how PJM and TOs should implement their compliance filings. They discussed where the proposal aligns with and differs from the plans already outlined by PJM and the TOs.
O’Hara later attempted to end the discussion after TOs reiterated their refusal to negotiate anything beyond the filings. “I actually expected to spend hours with the comments and positions, and this was surprisingly short,” he said.
Tatum noted that stakeholders could have bypassed the task force and taken their proposals directly to the MC and the Markets and Reliability Committee. “We chose not to do that because we respect the stakeholder process, and I wish PJM had the same amount of respect for it,” he said.
Tatum was among the supporters of the cost-containment proposal, whose opponents have argued its sponsors violated the stakeholder process by bringing it directly to the MRC without any vetting through lower committees.
O’Hara later walked back his statement that the cost-containment vote at the MC indicated it was stakeholders’ highest priority. But he pointed out there is just one month to get a TRPSTF solution approved and implemented before the next RTEP cycle.
“We can’t build a consensus here. We need to focus on implementing what the commission ordered. We have resources; we just can’t have them going in two different directions,” he said.
‘Much Ado About Nothing’
PJM’s Ken Seiler, who chairs the Planning Committee, explained that staff are already dealing with implementing the cost-containment proposal and Attachment M-3, along with considering the grid resilience concerns, five separate planning models and “hundreds” of generation interconnection requests, all “without upsetting the apple cart.”
“Your assessment that consensus isn’t going to happen here is indeed correct, but we’ve known that for two years,” Tatum said, adding that he takes issue with the reasoning for waiting until FERC responds. “The purpose of this effort is to give stakeholders an opportunity to say what they would want to see to understand TO end-of-life project decisions.”
O’Hara said it might be “much ado about nothing,” as PJM expects FERC to respond soon.
Ford asked that no meetings be canceled until the MRC, which created the task force, has a chance to consider the issue. Greg Poulos, executive director of Consumer Advocates of the PJM States, asked that PJM write out an explanation of its reasoning that he can share with his members.
When pressed by Tatum, PJM’s Janelle Fabiano — an in-house expert on Manual 34, which spells out the stakeholder process — said she would “imagine there will be an announcement” at the MRC but wouldn’t commit to anything without discussing the issue with other staff.
O’Hara said Thursday that the RTO must receive the commission’s responses to the compliance filings at least five business days before the task force’s next scheduled meeting, on July 31, to avoid cancellation.
But PJM’s Fran Barrett, who chairs the TRPSTF, sent an email to stakeholders on Friday confirming a discussion at the MRC on July 26 and clarifying the TRPSTF will still hold its July 31 meeting. Barrett was unable to attend Thursday’s meeting.
“At that meeting, we will further discuss my recommendation as conveyed by Chris O’Hara yesterday that we seek guidance from the MRC whether to suspend TRPSTF meetings pending FERC action on the submitted compliance filings, complaints and request for rehearing,” he wrote. “In addition, we will discuss whether there is a workstream that we could focus productively upon that is distinct from the pending TO, PJM and transmission customer filings associated with Docket [EL16-71] and the Attachment M-3, such as end-of-life criteria for baseline upgrades.”
In what spelled a victory for CAISO’s Department of Market Monitoring, FERC on Friday approved a set of changes to the ISO’s congestion revenue rights auction to address a market the Monitor and state regulators contend forces ratepayers to become unwitting partners in losing transactions.
Ratepayer auction revenues compared with congestion payments for auctioned CRRs | CAISO Department of Market Monitoring
The most significant — and controversial — change approved by FERC limits allowable source and sink pairs for CRR transactions to those that align with typical supply delivery paths. Transactions using non-delivery sources and sinks currently (such as between two generator locations) represent about 81% of the auction shortfall, the ISO noted in arguing for the change. FERC acknowledged that the elimination of some source-sink pairs from the auction process will limit market participants from using certain non-delivery paired CRRs as hedges.
Protesters failed to persuade the commission that the changes were discriminatory or violate open access by eliminating legitimate financial hedging opportunities. CAISO received pushback on the proposal during its development because it staunches a lucrative flow of profits to financial traders, but ISO said the current structure pays out about $100 million a year more in CRR revenues from the day-ahead market than bidders paid in the CRR auction.
Other parties offered alternative proposals to address the revenue shortfall, including changes to CRR modeling and different auction structures. But FERC said the question before it was whether CAISO’s proposal is just and reasonable, not “more or less just and reasonable than protesters’ proposed alternatives.”
“We note that CAISO has an ongoing stakeholder process, which is the appropriate forum for market participants to discuss any further changes to CAISO’s CRR auction process,” FERC said (ER18-1344).
“We find that, on balance, the potential loss in market functionality is acceptable given the scope of the auction revenue shortfall CAISO is attempting to remedy,” the commission said.
Another Tariff change will require the CRR process to use an annual transmission outage reporting requirement more closely aligned with day-ahead models, alleviating the auction shortfall and making expected payouts to CRR holders more predictable and less volatile. CAISO’s analysis had found that a misalignment between transmission outage reporting data and the auction model was another key driver of the auction shortfall. Outages that impact congestion and capacity in the day-ahead process were not reflected in the CRR auction model, causing the system to be modeled with fewer constraints.
Under the changes approved by FERC, participating transmission owners must submit all known and planned maintenance outages affecting the CRR process for the following year by July 1, earlier than the current requirement of Oct. 15. While this change had support among several trading and energy companies, Pacific Gas and Electric and Southern California Edison said the reporting is too early and might reduce the flexibility of market participants to schedule outages. FERC said the new outage requirement will increase auction flexibility.
Among the protesters to the proposal as filed were the Western Power Trading Forum, Calpine, DC Energy and Vitol, who said CAISO’s changes will restrict legitimate hedging activity. CAISO referred to the changes approved by FERC last week as “Track 1A,” which the Board of Governors approved in March. (See CAISO Moves Ahead With Market Changes.)
More Changes Afoot
The CAISO board last month approved “Track 1B” changes to tackle who pays for revenue inadequacy, which now go to FERC for approval. (See CAISO Board Approves More CRR Auction Changes.) The 1B changes alter the current process in which all revenue inadequacy is allocated to measured demand, which includes electricity load and exports. That process does not consider the location of constraints on the system and creates an incentive to profit from differences between the CRR auction model and the day-ahead market model.
A second component of the 1B changes reduces the amount of system capacity released in the annual process from 75% to 65%, to provide greater assurance that CRRs obtained in the annual process will be feasible in the monthly process and reducing the amount of payment reductions resulting from revenue inadequacy charges.
The changes approved by FERC last week will be in effect for the 2019 CRR auction, which begins this month. The Track 1B changes are targeted to improve efficiency of the monthly CRR auctions to be held in 2019.
CAISO unveiled its plan to overhaul CRR auction earlier this year in response to a long-running complaint by its Monitor, which argued that financial interests have saddled ratepayers with more than $500 million in excess CRR-related costs over the past five years. (See CAISO Overhauling CRR Auctions.)
HERSHEY, Pa. — New Jersey Board of Public Utilities President Joe Fiordaliso is so exasperated by PJM that he’s considering pulling the state from the RTO. And New Jersey is not alone in its frustrations, regulators said at the Mid-Atlantic Conference of Regulatory Utilities Commissioners annual meeting last week.
“I will not allow New Jersey to be the Cinderella of PJM,” Fiordaliso said in an interview he sought out with RTO Insider. “It’s not rocket science to make people feel a part of the process. I don’t feel a part of the process. … Pick up the phone. … That’s all we want.”
Cinderella’s story, of course, ended happily. Fiordaliso’s mood last week was more like Patrick Swayze’s declaration in Dirty Dancing: “Nobody puts Baby in a corner.”
Fiordaliso said he doesn’t feel PJM is “serving New Jersey well” and that he’s “been disturbed about it since I assumed the [BPU] presidency” in January. And while he proudly states that the Garden State is one of PJM’s “founding fathers” — “the ‘J’ stands for New Jersey,” he reminds — the tension could be the beginning of the breakup.
“I’m exploring it, let’s put it that way,” he said of whether he would push the state toward leaving the RTO.
“I have to work what’s in the best interest of the ratepayers and the citizens of the state of New Jersey. If I don’t feel that PJM is providing that, then I have to start looking at other options. … If PJM is not in my corner on that, then I guess we have nothing to talk about.”
Other States
Although he declined to name anyone else, Fiordaliso indicated other PJM states may share his perspective. While commissioners in other states weren’t as outspoken, several said they shared his frustrations.
“I think you would find a number of states that certainly would have the same concerns that he has,” said Illinois Commerce Commissioner John Rosales, the president of the Organization of PJM States Inc. (OPSI). “I’ve made this clear to [PJM CEO] Andy [Ott] that the communication could be better.”
“With regard to people being frustrated enough to consider other options, I will say it’s been bandied about a bit,” said a Maryland Public Service Commissioner who spoke on condition of anonymity. “I’m not sure Maryland is there quite yet, but if the states are pushed too far, I think more than a few states will come to similar conclusions. … There’s a lot of frustration with an entity like the market operator trying to mitigate or overcome state policies. States are sovereign states, and they have every right to set their own policy. We don’t obtain that right from the market operator. The states don’t exist to serve the market; the market exists to serve the states.”
W.Va., Pa. Staying Put
Regulators from West Virginia and Pennsylvania said they are not considering leaving the RTO.
West Virginia Public Service Commissioner Brooks McCabe said he has heard no discussions about his state considering leaving PJM. He advised states to “keep the powder dry; don’t get into fights you don’t need to get into.”
The Pennsylvania Public Utility Commission said in a statement that it “values the role that PJM plays in the wholesale markets. Pennsylvania is not considering withdrawing from the RTO.”
However, there are tensions in Pennsylvania as well.
The Pennsylvania legislature’s Nuclear Energy Caucus said in a Feb. 9 letter that the lawmakers are “losing confidence in the ability of wholesale electric markets to … ensure stable prices for our citizens and a reliable and resilient electrical grid.” (See PJM Responds to Pa. Concerns About Baseload Plants.)
PUC Vice Chairman Andrew Place told RTO Insider in May that he agreed with FERC Commissioner Robert Powelson, a former Pennsylvania regulator, that there is an “erosion of confidence” in RTO stakeholder processes. Place said “PJM is swimming and drowning in capacity” and that its capacity repricing proposal “only worsens that.” (See Powelson: ‘Erosion of Confidence’ in Stakeholder Process.)
FERC on Friday rejected PJM’s repricing proposal and instead ordered the RTO to expand its minimum offer price rule to include existing generation receiving state subsidies — including New Jersey’s and Illinois’ nuclear plants and generation supported by renewable portfolio standards. (See FERC Orders PJM Capacity Market Revamp.)
Commissioner Cheryl LaFleur, who dissented, said the ruling could force states into “reregulation.”
“I am particularly troubled that, as a result of today’s order, the commission will be hamstrung in its ability to openly and honestly engage with the states about whether this proposal will meet their needs, and how they might operate under this construct,” she wrote.
PJM Responds
PJM spokeswoman Susan Buehler said in a statement that the RTO is a “customer service organization” and is “always striving to enhance our communications.”
But because of the diversity of PJM — 13 states and D.C. — she said, “It is likely on any given matter one or more states may have a view opposite of PJM and possibly opposite other states. We attempt to find solutions that work for all interested stakeholders and members. PJM is independent of our members and stakeholders; we execute our mission of reliable operations, nondiscriminatory markets and long-term transmission planning.”
‘Very Disappointing’
Illinois’ Rosales told RTO Insider in May he agreed with criticism that PJM has not been sufficiently responsive to the states, calling the RTO’s capacity repricing filing “very disappointing.”
Rosales said he is not pushing for Illinois to withdraw from PJM but would not “hinder” it. Commonwealth Edison, a utility owned by Exelon, is the sole PJM member serving load in Illinois.
“We would not stand in their way if they decided they wanted to go to MISO,” Rosales said, adding that the idea of Illinois creating its own single-state RTO has “never come up … in conversations with this commission.”
Commonwealth Edison did not respond to a request for comment.
Rosales said communication has improved since PJM’s annual meeting in May. He said he had a one-on-one meeting with Ott there, and “it seems to be going a little better.”
However, for the first five months of this year, “I can understand the states saying that we’re really having bad communications,” he said. The issue, he said, was that PJM often sends mid-level envoys to meetings who can only communicate messages, rather than decisionmakers who could answer for the RTO. That lack of direct engagement has improved, he said.
“It always seemed like they wanted to [improve], but let’s see where they go from here,” he added.
McCabe: Stay Engaged
West Virginia’s McCabe said the states have issues “that we can effectively address” with PJM.
“Just because we have disagreements doesn’t mean we have to get mad and leave the discussion. I am one for staying at the table. I’m very comfortable in a somewhat contentious environment as long as everyone is at the table and really trying hard to not just clarify their positioning properly but to understand the position of the opposing parties. We need to focus more on that,” he said. “At some point, we’ll have to make some of those tough decisions, but I think we have time.”
Fiordaliso said he believes he’s getting “lip service” and “being patronized” by PJM. Specifically, he feels PJM failed to defend the state in a recent FERC fight with NYISO over transmission construction costs. (See PSE&G on the Hook for Bergen-Linden Costs.)
“We feel that PJM should be supporting New Jersey’s position regarding another entity,” he said. “They submitted a letter in support but never used the word ‘support.’ That’s disturbing to me. … We would like more support. Shouldn’t PJM be defending N.J.’s position? … I’m sure they listen, but I wonder how much they hear.”
He recounted an April OPSI meeting in Jersey City that he said PJM decision-makers did not attend. “We’re looking at [these] beautiful Lower Manhattan lights, and I jokingly say to my colleagues in OPSI, ‘Look at those lights. New Jersey ratepayers are paying for them,’” he said. “I don’t mind New Jersey paying for what it gets, but I’m not willing to pay for what New York gets.”
Buehler said transmission cost allocation is beyond PJM’s authority. “Understandably, there are many factors to consider and many equity implications related to FERC’s goal in establishing cost allocation — ensuring that the beneficiaries of transmission reinforcement, either systemwide or specific, are assigned the cost obligation,” she said.
Fiordaliso wants more individual and direct communication from PJM in ways that make states feel like “partners” in the market and said he doesn’t feel RTO staff want to do that. He acknowledged that disagreements are inevitable but said, “Many times out of disagreement comes a better product.”
“I would like to see them to say, ‘You know what, New Jersey? Some of your ideas maybe are pretty good. Let’s see what we can work out,’” he said. “I find us more in contention with PJM rather than in cooperation with PJM. And that disturbs me.”
He said he purposefully declined PJM’s invitation to a luncheon it was hosting at last week’s MACRUC meeting because “I’m annoyed.” He questioned why PJM staff did not inquire why he didn’t attend. He conceded that they probably didn’t get the message and don’t have a “next step” planned.
PJM’s size may play against it, as there are “diverse interests between the many states,” he said, but added that staff have “an obligation, as we do, to try to get us all together.”
“Might I be wrong? Maybe I am. But they have to show me I am wrong,” he said. “My door is always open. My phone works. Call me. Come to my door. I’m willing to meet you more than halfway.”
