WASHINGTON — The Market Monitors for CAISO and PJM told a House subcommittee Wednesday that their respective financial transmission rights markets are significantly flawed and need fixing, although they stopped short of asking for congressional action.
Appearing before the House Energy Subcommittee, Eric Hildebrandt, director of CAISO’s Department of Market Monitoring, said electricity ratepayers in RTOs/ISOs nationwide are not receiving the full amount of congestion revenues as intended, losing more than $400 million a year instead.
After allocating an initial round of FTRs to load-serving entities that use the instruments as a hedge, RTOs auction off additional FTRs to third parties, typically sophisticated financial entities seeking to speculate on the potential to collect high rents from congested transmission segments.
“Unfortunately, revenues that ISOs collect from auctioned FTRs are consistently much lower than what the ISOs pay out to entities purchasing these FTRs,” Hildebrandt said. “This makes FTRs highly profitable for financial entities, but these profits directly reduce the congestion revenues that would otherwise be refunded back to transmission ratepayers.” He said that ratepayers only receive 52 cents in auction revenues for every dollar an RTO/ISO pays out to FTR holders, representing a nearly 100% profit for buyers.
In written testimony, PJM Independent Market Monitor Joe Bowring explained his RTO’s auction revenue rights construct before echoing Hildebrandt’s criticism.
“The current ARR/FTR design does not serve as an efficient way to ensure that load receives all the congestion revenues or has the ability to receive the auction revenues associated with all the potential congestion revenues,” Bowring said. “The goal of the ARR/FTR design should be to return 100% of the congestion revenues to the load. But the actual results fall well short of that goal.”
Opposing Hildebrandt at the hearing was TPC Energy CEO Noha Sidhom, appearing on behalf of the Power Trading Institute.
“The problem [in CAISO] is not with the FTR product; the problem is with the market design,” Sidhom said. “They’ve got significant modeling issues. … There’s something wrong with their pricing model. Also their outage scheduling is a real problem.”
Sidhom said that more than 50% of network outages are not identified in time to be modeled in the ISO’s FTR auctions. These problems result in inadequate revenues to ratepayers, but “you absolutely need the auction, because the auction is how you actually price the allocated rights.”
“It’s absolutely incorrect that the allocated FTRs are priced based on the auction,” Hildebrandt responded. “They’re allocated out, load-serving entities hold them and they get paid the congestion revenues.” Those who purchase FTRs through the auctions pay nearly half the price, and “the payout directly reduces the pot of congestion revenues that otherwise get fully refunded back to transmission ratepayers,” he said
He also disputed that the problem was unique to CAISO, saying it exists in every RTO/ISO in the U.S., although he admitted it is more severe in California. In his letter to the subcommittee, Bowring said that PJM ratepayers have missed out on more than $1.7 billion in congestion revenues over the last seven planning cycles.
The hearing was the latest in the subcommittee’s “Powering America” series, which has included discussions on reliability in the wake of a severe hurricane season, consumer advocates in energy markets and the Public Utility Regulatory Policies Act. Several congressmembers at the hearing admitted they were unfamiliar with FTRs and other virtual transactions, asking for basic explanations of their role in electricity markets.
The panelists also included Red Wolf Energy Trading CEO Wesley Allen, PJM General Counsel Vince Duane, former FERC General Counsel Max Minzer and Chris Moser, senior vice president of operations with NRG Energy.
FERC on Monday ordered settlement judge procedures for a dispute involving an American Electric Power subsidiary’s transmission rates (EL17-85).
In August, East Texas Electric Cooperative (ETEC) and Northeast Texas Electric Cooperative (NTEC) filed a joint complaint asking the commission to reduce Southwestern Electric Power Co.’s (SWEPCO) current base return on equity from 11.1% to 8.41% — a 269-basis-point reduction. In granting the co-ops’ request for a hearing on the issue, the commission set a refund effective date of Aug. 31, 2017.
East Texas Electric Cooperative member Cherokee County Electric Cooperative transmission lines | Cherokee County Electric Cooperative Association
ETEC and NTEC buy power from SWEPCO under a revised supply agreement among the three parties, while NTEC and SWEPCO also have a separate agreement. The 11.1% base ROE in the contracts originated in a formula rate settlement filed by SWEPCO in 2001 for the NTEC contract, and the utility carried over that rate when it filed the ETEC-NTEC agreement in 2009.
The co-ops now contend that capital costs for electric utilities have declined significantly since the ROE was set in the initial agreement. As a result, their ratepayers are overcompensating SWEPCO by $2.43 million annually.
Linemen for Sam Houston Electric Cooperative, a member of the Northeast Texas Electric Cooperative, work on a line | Sam Houston Electric Cooperative
ETEC and NTEC filed testimony from independent consultant J. Bertram Solomon, who argued the 11.1% ROE rested on the commission’s previous one-stage discounted cash flow (DCF) methodology and outdated assumptions about utility debt costs. Updated financial data and the two-step DCF method adopted by FERC in 2015 produced a zone of reasonableness of 6.42 to 10.62% and a median of 8.41%, Solomon’s analysis showed.
SWEPCO asked the commission to dismiss the co-ops’ complaint, saying the 8.41% ROE falls 216 and 191 basis points below the ROEs the commission approved in previous cases involving ISO-NE and MISO, respectively. The utility requested FERC delay any proposed refund effective date by five months, if it set the complaint for hearing.
The commission said it found the co-ops’ DCF analysis to be “adequate” in establishing a sufficient case that SWEPCO’s cost of equity “may have declined significantly below the level of its existing 11.1% base ROE.” FERC said it was unpersuaded by SWEPCO’s arguments against the zone of reasonableness, and it rejected the utility’s request to delay refunds.
“We find no merit in [SWEPCO’s] assertions that the commission should delay any appropriate relief to [its] customers,” FERC said, “and we expressly decline to do.”
The commission said that barring a settlement agreement, it expects to issue a decision by Sept. 30, 2019.
ETEC separately filed complaints against SWEPCO and three other AEP subsidiaries in June, arguing the companies’ base ROE in SPP’s AEP West pricing zone should be reduced from 10.7% to 8.36%. FERC earlier this month established hearing and settlement judge procedures in that case (EL17-76). (See AEP Base ROE Complaints Ordered to Settlement.)
FERC on Tuesday approved NYISO’s request for a 30-day extension for submitting additional reliability-must-run tariff revisions. The ISO must now file the changes no later than Jan. 16, 2018 (ER16-120).
The ISO said the additional time would enable it to develop compliance revisions that fully address the directives and allow New York stakeholders an opportunity to review any changes and provide feedback. It also said the extension would help it avoid disputes with stakeholders and obtain input from its Independent Market Monitor.
The D.C. Circuit Court of Appeals on Tuesday denied Kansas regulators’ challenge to a 2014 FERC order approving SPP’s merger with the Integrated System (IS) (15-1447).
SPP & the Integrated System | SPP
In its petition for review, the Kansas Corporation Commission contended that FERC’s approval of the merger allowed SPP to integrate Basin Electric Power Cooperative and Heartland Consumers Power District into its transmission footprint under agreements that shielded the two new members from paying certain transmission facility costs (ER14-2850, ER14-2851).
The Kansas commission argued that FERC “wrongly accepted a rate structure that disadvantaged the SPP participants” and “unreasonably accepted” what it called faulty data in the RTO’s calculation of the merger’s benefits.
At issue was the allocation of costs for SPP legacy facilities in the agreement between the RTO and the Integrated System parties. The KCC said FERC’s approval would establish inequitable precedent that entities desiring to join an RTO can negotiate “sweetheart deals” in exchange for reducing administrative rates.
In an opinion authored by Senior Judge Stephen F. Williams, the court rejected the KCC’s request to review FERC’s decision, saying the court found no basis for a claim of undue discrimination.
“Kansas argues, in effect, that by accepting these provisions, SPP got taken for a ride,” Williams wrote, pointing to a KCC expert’s calculations that SPP would have received almost $360.5 million in revenue (net present value) over 10 years were the Integrated System parties required to pay for the use of its legacy facilities. The system comprises its own transmission zone within SPP’s footprint, which is divided into 18 different zones.
While a Brattle Group study of the merger estimated the RTO would reap $220 million in benefits over 10 years, the KCC said the foregone revenue meant the integration will actually cost existing SPP members almost $141 million during that period.
1. SPP said the addition of the Integrated System would produce net benefits of almost $220 million over 10 years. The Kansas Corporation Commission said the integration actually will cost existing SPP members $141 million. | Kansas Corporation Commission
The court noted FERC’s determination reflected “prior investment decisions and the fact that existing facilities were built principally to support load within the [pre-merger SPP] sub-region,” and said the commission’s approval of similar arrangements “has withstood judicial review in analogous circumstances.”
“FERC accurately described the agreement as reciprocal,” Williams wrote. “It would be difficult to label it otherwise, as the agreement and FERC’s approval assigned each side’s legacy costs to the power consumers in that side.” He said the arrangement’s reciprocity undermined the KCC’s contention that SPP left $475 million (nominal) lying on the table.
“Kansas never suggests any reason to believe that the IS parties would have agreed to share SPP members’ legacy costs without demanding that SPP members share the IS parties’ legacy costs,” Williams wrote.
The court also said the KCC overlooked other benefits to the merger, such as increased efficiency and reliability; improvement in SPP’s dispatch of power on its western edge; and a lower price of energy by virtue of reduced generation curtailment.
Williams said the Kansas regulators’ claim of lack of access to the Brattle study was “somewhat exaggerated.” The commission had access to a redacted, electronic version before the start of the FERC proceedings and other public data, he said, but it never pinpointed either a special reason to question the study “or some debilitating feature of the redaction.”
The KCC also asserted its expert’s testimony was “simply ignored” by FERC in disputing the proposed integration and SPP’s cost/benefit analysis.
“Not true,” Williams wrote. “As the … discussion demonstrates, the testimony was considered, but rejected on the merits.”
The court also found no fault in FERC’s decision not to order a hearing on the issue, noting the Kansas regulator was unable to point to any vulnerability in SPP’s expert witness testimony that could have been “better resolved” with cross-examination rather than the analysis of written testimony.
“We therefore find no abuse of FERC’s discretion,” Williams wrote.
A KCC spokesperson said the commission is still reviewing its options.
FERC approved cost allocations for projects involved with northern New Jersey’s Bergen-Linden Corridor (BLC) last week (ER17-725) but left room for revisions based on a challenge to the original allocation (EL15-67).
In last week’s order, FERC denied requests for clarification and rehearing and accepted PJM’s Tariff revisions that allocate costs for the BLC projects to Neptune Regional Transmission System, Hudson Transmission Partners and Linden VFT.
FERC’s offices in Washington, D.C.
Linden and the New York Power Authority had requested clarification on PJM’s allocations. NYPA noted that Hudson’s responsibilities for the projects increased by $10.17 million after the company previously carried no responsibility for the upgrades. PJM failed to explain how modeled flows on the system could have changed so significantly since the RTO last performed its analysis, the agency contended. Hudson owns the merchant transmission facility NYPA uses for energy exports into New York City.
Linden argued that the solution-based distribution factor (DFAX) method bases its allocation on power flow, making it “particularly ill-suited” for non-flow-based projects, like the BLC.
FERC dismissed these complaints, explaining that they “challenge the cost allocation method in PJM’s Tariff rather than whether PJM properly applied its Tariff,” but it conditioned the approval on the outcome of Linden’s separate challenge to the allocation method itself.
“We find that PJM has correctly applied its Tariff, and the question of whether the Tariff provision regarding cost allocation is just and reasonable is pending before the commission in other proceedings,” the order said.
FERC Commissioner Cheryl LaFleur concurred with the order but wrote separately to note her dissent on the denial of Linden’s original challenge to the allocation methodology. Several organizations, including NYPA and Linden, requested rehearing of the issue, which FERC granted in June 2016.
New York is fine-tuning plans for meeting its 2030 renewable energy target and closing the books on the energy efficiency programs that it has used since 2008.
The New York Public Service Commission earlier this month approved orders implementing the second phase of the state’s Clean Energy Standard (CES) and approving the conclusion of its Energy Efficiency Portfolio Standard (EEPS).
| NY DPS Webcast
The CES adopted last year by the PSC mandates that 50% of the electricity used in New York be generated by renewable energy sources by 2030. In a Nov. 16 order, the PSC largely approved its staff’s recommendations for implementing Phase 2 of the CES, which will add quarterly renewable energy credit (REC) auctions (Case 15-E-0302).
The order also continues limits on the sale or transfer of Tier 1 RECs and institutes a “divergence test” to identify and correct REC supply/demand imbalances.
The New York State Energy Research and Development Authority will continue monitoring generators’ carbon emissions, managing REC procurement and setting Renewable Energy Standard (RES) targets for load-serving entities three years in advance.
Rhodes | NY DPS Webcast
PSC Chair John Rhodes said the new order “sets out the procedures and methods and fund management rules for NYSERDA to implement the next phase of the Clean Energy Standard, and including, importantly in my view, providing rolling future visibility for the Renewable Energy Standard targets for 2018 through 2021.”
Burman | NY DPS Webcast
Commissioner Diane Burman abstained, saying the PSC’s instructions were “not detailed enough.”
The order “still is leaving holes for decision-making that I’d like to see a lot more finality in, including the state energy plan and other things we need to address more holistically,” she said.
Under the new rules, NYSERDA will offer for sale all the Tier 1 RECs in its account quarterly, with unsold RECs offered in the next auction. NYSERDA had two auctions in 2017, one each at the end of the first and third quarters.
The quarterly sales will allow LSEs “greater awareness of the actual load served during the preceding quarter, which may encourage LSEs to purchase NYSERDA’s RECs when offered, thereby improving NYSERDA’s cash flow and reducing NYSERDA’s working capital requirements,” the commission said.
The commission rejected a request by the state’s utilities to allow LSEs to trade NYSERDA-procured Tier 1 RECS for the 2018 compliance year, continuing the existing ban. “A near-term change in REC sales and trading under the Renewable Energy Standard program would be out of alignment with the [Value of Distributed Energy Resource Proceeding, Case 15-E-0751] order and the expected evolution of REC trading rules in future years,” the commission said. “The implementation of the quarterly REC sale process will limit the potential exposure of an LSE over- or under-procuring RECs from NYSERDA, thus eliminating the need of trading NYSERDA-purchased RECs among LSEs.”
The commission also rejected proposals by environmental groups that the 2018-2021 targets be evenly distributed to allow developers to take advantage of expiring federal tax credits. Instead, the commission continued the state’s back-loaded approach, saying it “is based on the expected three-year development and construction cycle between the receipt of a NYSERDA award for Tier 1 RECs and a facility’s ability to start producing RECs upon commercial operation. In other words, the targets reflect realistic expectations regarding availability of Tier 1 RECs as the RES program ramps up.”
The PSC disagreed with the environmental groups’ criticism that the staff proposal lacked LSE targets through 2030. “Providing a mandated trajectory out through 2030 at this time would undoubtedly require adjustments in the later years to account for changes in statewide electric load, and other factors. … Therefore, the trajectory through 2021 for the revised LSE targets provided in the Phase 2 proposal is deemed sufficient to provide enough certainty for planning purposes for LSEs, renewable developers and other market participants.”
As part of its annual compliance reporting, NYSERDA will publish its methodology for calculating the statewide fuel mix to provide “transparency in accounting for the historic renewable baseline, the mandated targets, the voluntary market and other activities for measuring progress towards the 50-by-30 goal,” the commission said.
Palmero | NY DPS Webcast
NYSERDA will report on the program’s finances, including REC sales, alternative compliance payments, program expenses and surpluses or shortfalls, annually. If any cumulative surplus is more than 25% of the contractual Tier 1 REC payment obligation to generators for the current year, NYSERDA must propose a use for the excess portion that is in the ratepayers’ interest.
“We don’t expect there to be a lot of [alternative compliance payments], at least in the near term, because we’re trying to match the amount of RECs that will be available to the LSE obligation, but if there is a fund sitting there, NYSERDA will propose what they will do with the excess,” said Christina Palmero, deputy director of the state Department of Public Service’s Office of Clean Energy.
NYSERDA also was directed to develop criteria for combining aggregated and co-located facilities into a single Tier 1 bid for 2019. “Allowing aggregated and co-located facilities to bid as single facility for Tier 1 solicitations appears to be a prudent addition to the rules,” the commission said.
Concluding the Energy Efficiency Portfolio Standard
In a separate order, the PSC also voted to conclude the EEPS program and award 11 investor-owned utilities $56.5 million in shareholder incentives for meeting the electric savings targets and $12.4 million for meeting gas targets (Case 07-M-0548).
| NY DPSSayre | NY DPS Webcast
“EEPS was a good program and a successful program and we’ve learned from it,” Commissioner Gregg Sayre said. “I believe our replacement programs are better.” The commission’s Reforming the Energy Vision order of 2016 requires each utility to submit an annual Distributed System Implementation Plan and Energy Efficiency Transition Implementation Plan showing how they propose to meet the energy efficiency budgets and targets set by the PSC.
The program paid most utilities $38.85/MWh for reduced consumption. Consolidated Edison was paid $100,000/MW, capped at $5 million (50 MW) annually. All but Orange and Rockland Utilities (98%) exceeded their electric targets for the program.
Burman dissented, saying the commission had to learn from EEPS “the need to be more prudent and measured in making our demands, the need to be more realistic and thoughtful ahead of time about how quickly goals can be accomplished, and the need to truly understand what the financial implications may be to run the programs, and to prepare in case programs are more in demand than anticipated.” [Editor’s Note: An earlier version of this article failed to note that Burman had voted no and improperly prefaced her quote by saying “the commission had learned” from EEPS.]
The order directs utilities to file an EEPS financial reconciliation report no later than June 30, 2018, documenting program expenditures, unspent funds and accrued interest.
RG&E, NYSEG Face Penalties over Wind Storm Response
The commission also completed its investigation into the March 8 wind storm that left 123,000 Rochester Gas and Electric customers and 48,000 New York State Electric and Gas customers without power, finding the companies are liable for millions in penalties for violating their emergency response plans (Case 17-E-0594).
wind storm damage | Avangrid
The commission said both companies failed to fully secure downed wires reported by municipal officials within the required 36-hour period; to keep the public informed about restoration times; and to coordinate communications with customers on life-support equipment.
In addition, the commission said RG&E: began its damage assessment too late; failed to create a list of critical facilities such as fire and police stations to be prioritized in restoration efforts; did not update its automated voice messaging services to reflect storm conditions; and did not staff its call center adequately.
The commission directed the companies to respond within 30 days to show why penalties should not be initiated and show how they will improve their response.
The commission said National Grid was not subject to penalties because it restored more than 90% of its 113,000 outages within 36 hours.
Other Rulings
The PSC also approved:
ORU’s plan to spend $98.5 million to install smart meters for all its electric and gas customers. The new meters are expected to produce a net benefit of nearly $16 million. The utility will replace approximately 230,000 electric and 135,000 gas meters (Case 17-M-0178).
NYSEG’s and RG&E’s plans to offer light-emitting diodes (LED) street lighting to municipal customers. Replacing all of the utilities’ combined 93,000 old-style street lights could save municipalities as much as $5.8 million a year based on reduced costs of $63 per light. Street lights may account for up to 40% of total electricity use for a local government, but prior rules required municipalities to take ownership of the lights to switch to LED. The order allows municipalities to switch to the cheaper LEDs while NYSEG and RG&E retain the responsibility for maintaining them (Cases 16-E-0710, 16-E-0711).
It seems little connected to SPP’s Z2 process goes off without a hitch these days.
A mismatch between posted Z2 reports and invoices sent this month forced the RTO to email members Nov. 17 to “dispel any confusion that may have resulted.”
The invoices included Z2 billing amounts for the historical period (March 2008-August 2016) and September 2017. However, they did not include the interim months (September 2016-August 2017) “due to administrative issues,” SPP said. The RTO did not explain the problem.
SPP said it would ask FERC to waive its one-year resettlement window to permit including the September 2016 Z2 amounts on a future invoice. Z2 amounts for October 2016 and resettlements for November 2016-July 2017 will be included on the invoice sent in December.
Attachment Z2 of SPP’s Tariff assigns financial credits and obligations for sponsored transmission upgrades.
SPP this September completed a resettlement of the revenue crediting amounts under Attachment Z2 for the March 2008-August 2016 historical period, a move made necessary because of corrections and true-ups to the data that were identified before the first settlement of the charges. (See “More Z2 Woes; SPP to Resettle 9 Years of Data,” SPP Markets and Operations Policy Committee Briefs: July 11-12, 2017.)
In September 2016, the RTO identified about $200 million in revenue credits to be collected for transmission upgrades under Z2. The bills covered eight years of credits and obligations for 2008-2016 when staff failed to apply credits, complicating the task of trying to accurately compensate project sponsors and claw back money from members with debts for the upgrades. (See Preliminary Z2 Bills Released; Task Force Develops Options for Waiver Requests.)
Dynegy’s most recent bid to develop a specialized capacity market for downstate Illinois has failed to gain traction in the state’s legislature, but the conversation around the region’s resource adequacy is far from over.
The legislation (SB 2250/HB 4141), which would have created a separate competitive capacity auction for central and southern Illinois administered by the Illinois Power Agency, failed to advance after hearings this month.
Dynegy last month characterized the competitive auction as “subsidy-free” and “fuel-neutral.” It was expected to translate into higher clearing prices.
“It didn’t move but that doesn’t necessarily mean it’s dead. I think they will try again in the legislature in 2018,” said Jessica Collingsworth, an energy analyst with the Union of Concerned Scientists. “Coal is on its way out, and Dynegy is holding on for as long as it can. … I think it may be the same exact bill [in the future]. They seem to have stuck with that on the legislative angle.”
Dynegy did not respond to a request for comment on its next steps. The company has said the “lack of a functioning capacity market” in MISO’s Zone 4 is to blame for power plant closures and, in turn, increased electricity bills as shortage pricing is imposed in the absence of sufficient baseload generation.
The Houston-based company said the legislative proposal was meant to address electric reliability and price stability in Zone 4. Last year, FERC rejected MISO’s separate three-year forward capacity market design for deregulated portions of its footprint.
No Support for NOPR
Although coal-fired generation represents more than one-third of Dynegy’s capacity, the company does not support the cost recovery for coal and nuclear facilities proposed by Energy Secretary Rick Perry (RM18-1). (See FERC Flooded with Comments on DOE NOPR.)
“Even from the perspective of a coal generator, the proposed rule should not be adopted because it would substantially, and potentially irreversibly, harm the nation’s competitive electricity markets,” Dynegy wrote. While acknowledging the NOPR would solve its price problems in MISO, the company nevertheless said it amounts to a “reregulation of coal and nuclear facilities that would severely harm, and potentially represent a death blow to the competitive markets that [FERC] has worked hard to develop.”
Dynegy CEO Robert Flexon said the separate auction would safeguard against distorted prices from regulated utilities.
“Under the status quo, the viability of existing plants that are fully environmentally compliant is threatened, as are thousands of local jobs and support functions. This legislative proposal would help safeguard our downstate plants without the use of subsidies, while encouraging investment in all sources of power supply — including conventional generation, demand response and renewables.”
Collingsworth noted the legislation did not require Dynegy to keep any of its coal plants operating.
“Even if a bill were to pass, there’s no guarantee from Dynegy that these coal plants will stay open,” she said. “So what happens if we give them a bailout, and they only keep two plants open and run them harder? That’s still closing plants in communities.”
Collingsworth believes increased renewables and storage can be profitable even considering Zone 4’s deregulated market.
“I think people want solar on their roof. And I think that if they can’t have that, they want to buy into a community solar program. I think there is a lot of opportunity with the Future Energy Jobs Act. We have not even touched the surface of our solar potential in central and southern Illinois,” she said.
Dynegy has warned that another 30% of total downstate resources could retire over the next three years “due to an inability to cover operating costs.”
Dynegy has at least partial ownership in eight Zone 4 power plants totaling 6,500 MW, making it responsible for nearly 50% of electricity production in the local resource zone. Zone 4 currently has 57 utility-scale generating stations with a combined 16 GW of nameplate capacity.
Edwards Station | Iron Hustler Excavating
The largest recent capacity declines in Zone 4 can be attributed to the retirement of Dynegy coal-fired generation. In the last two years, the company has shut down a combined 1.25 GW of coal-fired generation: the 500-MW Wood River power station in Alton, 617 MW at the Newton power plant and 136 MW at the Edwards plant in Bartonville.
Whitepaper, Workshops
MISO this year maintained there is no reliability issue Zone 4, predicting a 0.7-GW capacity surplus in the region in 2018, up from the 1.6-GW shortfall the grid operator predicted for 2018 in its 2016 resource adequacy survey produced in cooperation with the Organization of MISO States. (See Capacity Survey Shows MISO in the Black.)
“MISO’s recent 2017 OMS-MISO survey results suggest that Zone 4 capacity requirements will continue to be met through 2022. Planned transmission and generation provide additional reason for optimism in this regard,” the Illinois Commerce Commission wrote earlier this month in a white paper requested by Gov. Bruce Rauner as a response to MISO’s appeal for a resource adequacy plan.
The commission’s report said the state has four options to address resource adequacy in central and southern Illinois: 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. Dynegy last year proposed legislation that would transition the entire state into PJM’s markets. (See Dynegy Introduces Bill to Move All of Ill. Into PJM.)
MISO officials will participate in a pair of workshops on Zone 4 resource adequacy beginning Dec. 7 at the ICC’s offices. Stakeholder comments on the challenges of Zone 4 are due to the commission on Nov. 30.
Illinois EPA Rule Change Still in the Works
Meanwhile, Dynegy continues to work with the Illinois Environmental Protection Agency to revise the state’s Multi-Pollutant Standard, a 2006 clean air standard for coal plants. The company is advocating that an annual cap on sulfur dioxide and nitrogen oxide emissions be imposed on the state’s coal fleet as a whole, rather than on individual power plants. If approved, the new sulfur dioxide limit would be almost double what Dynegy emitted last year, while the nitrogen oxide cap would be 79% higher. The caps would not be decreased should Dynegy retire or mothball any plants.
The new rule was initially expected to be adopted this month, but the Illinois Pollution Control Board now plans to hold hearings on the change on Jan. 17 in Peoria and March 6 in Edwardsville. Peoria is near the shuttered Edwards plant, while Edwardsville is close to the vacated Wood River plant.
“This is going to give these communities a chance to speak out,” Collingsworth said. “It was so fast. I think the environmental community played a role in saying, ‘Whoa, pump the brakes’ and delayed this. You do need to have public input in this.”
The Illinois Clean Jobs Coalition said the revision would result in “massive new air pollution for the state of Illinois and beyond.”
VALLEY FORGE, Pa. — The results are in, but will they make a difference?
At its final scheduled meeting, PJM’s Capacity Construct/Public Policy Senior Task Force (CCPPSTF) last week reviewed the results of a vote on proposals to re-envision the RTO’s capacity market structure. With 63% in favor, the Independent Market Monitor’s extended minimum offer price rule (MOPR) was the only proposal to receive a simple majority. The closest contender was PJM’s two-stage repricing proposal, which received 26.1% approval. (See PJM Drops MOPR in Capacity Talks; Dayton Withdraws.)
Because the vote was binding, the Monitor’s package will have a first read at the Dec. 7 meeting of the Markets and Reliability Committee with an endorsement vote planned for the next MRC on Dec. 21. No other proposal can be considered until the Monitor’s package is voted down. PJM is holding two MRC meetings in December because the November meeting was pushed into next month to account for the Thanksgiving holiday.
The popularity of the Monitor’s proposal is somewhat deceiving. As part of the vote, stakeholders also responded to a nonbinding poll on whether making a change was preferable to maintaining the status quo. That poll found 64% in favor of maintaining the status quo.
The results suggest that after more than a year of debate on the issue, stakeholders feel they haven’t found anything better than the current situation, but they continue to fear their preference won’t prevent PJM from filing something for approval from FERC. PJM’s Stu Bresler balked when asked whether the RTO would commit to the status quo.
“Out-of-market subsidies present a threat to the ability for the wholesale market to perform its intended function,” Bresler said. “We have a strong desire to protect the market. … If I’m asked to interpret the results of the poll … I don’t think necessarily it would keep PJM from taking action that needs to be taken at FERC to defend the market from these kinds of actions.”
He said it “remains to be seen … whether we’ll be able to indicate prior to the vote what PJM’s recommendation” to the Board of Managers will be.
PJM’s Dave Anders, who coordinates the CCPPSTF, suggested stakeholders voice their preferences directly to board members at the MRC or by writing letters to the board.
Although the Monitor’s proposal had shown strength in an earlier poll, some stakeholders seemed surprised at its continued support in the final vote. (See PJM Pressed on Plans to File Capacity Changes.) Calpine’s David “Scarp” Scarpignato asked if there is any remaining opportunity to revise the MOPR proposal before seeking MRC endorsement. Anders said the plan would follow the usual path of proposals, meaning that any proposed changes would need to occur at the MRC.
Duquesne Light’s Tonja Wicks confirmed that her company maintained its support for the status quo, a position she had previously enunciated.
“We voted down every single proposal because we wanted to vote our conscience,” she said.
Adrien Ford of Old Dominion Electric Cooperative said the results indicate support for “a more pure approach” to securing the market than a two-stage repricing mechanism that “de-links” the offer price from the probability of clearing the auction.
Susan Bruce, who represents the PJM Industrial Customer Coalition, noted “a lot of discomfort” with the two-stage proposals because “once that gets imbedded into the market, there’s no going back.”
Gabel Associates’ Mike Borgatti said the extended MOPR creates a “pathway” that doesn’t currently exist for states to ensure their competitive renewable portfolio standard policies meet the Monitor’s standards without “running afoul” of the MOPR.
“There certainly [could be] programs that would not qualify under that pathway,” so MOPR rules may eventually need to be revised, but “I think this is an incremental first step,” he said. “It’s important to recognize that this gives state policymakers, PJM and market [participants] a level of regulatory clarity that does not exist today.”
Jason Barker of Exelon, which proposed a repricing variant, cautioned that the MOPR is “really stepping on a slippery slope … because all cost or revenue advantages conveyed by any level of government affect the market outcomes in exactly the same way” and would be “unduly discriminatory” if it allows “some subsidized competitors to participate unimpeded while mitigating others.
“One thing that needs to be balanced here is whether or not the mitigation that is being applied is being done so in an impartial fashion,” he said.
CAISO and Pacific Gas and Electric are opposing the terms of a reliability-must-run agreement for two California natural gas-fired plants that Calpine submitted with federal regulators early this month, complicating an arrangement set to take effect at the beginning of next year.
The ISO and PG&E filed separate protests with FERC over the terms of the RMR agreement for the Yuba City and Feather River plants, filed with the commission Nov. 2 by Calpine subsidiary Gilroy Energy Center. CAISO designated the units as RMR in March, but the ISO told FERC that Gilroy had not supported provisions related to scheduling coordinator charges, greenhouse gas emissions and gas prices.
Yuba City power plant | Calpine
CAISO is increasing its use of out-of-market RMR payments to keep units online, raising concerns that its market is not producing the price signals sufficient to support units needed to provide reliable electric service. The ISO’s Board of Governors early this month approved the third RMR of this year, for Calpine’s Metcalf Energy Center. (See Board Decisions Highlight CAISO Market Problems.) Costs are borne by utility ratepayers such as those of PG&E.
Map identifying the need for Yuba City and Feather River plants | CAISO
CAISO in its protest did not ask FERC to reject the application but to set it for settlement before the effective date of Jan. 1.
“There are also technical issues with the inputs to the other rate schedules as well, which the CAISO anticipates can be addressed through the exchange of information during settlement discussions and through further informal exchanges between the parties,” the ISO said.
PG&E said FERC should approve the RMR rates for Jan. 1, subject to refund, and launch a separate proceeding “under Section 206 of the Federal Power Act to examine whether the RMR program in the CAISO tariff is unjust and unreasonable.” The utility said “the RMR designations were premature” and will increase costs.
PG&E also noted the increased use of RMR units in recent years.
“After years of decreasing use, such that a minimal number of facilities were designated as RMR units, the CAISO has designated three new RMR units in PG&E’s service territory for 2018 alone,” PG&E said.
