NEW ORLEANS — MISO’s dedicated market platform replacement team will work this year to ensure the RTO’s existing system can stay afloat during the time it will take to build the new one, staff told stakeholders last week.
While MISO is slated to begin naming specific requirements and assembling the new platform next year, this year’s efforts will focus on “standing up” the existing platform for day-to-day operations with software patches, Executive Director of Market Development Jeff Bladen told the Technology Committee of the Board of Directors on March 27.
The RTO has so far filled 18 of the 30 positions it has planned for this year, including market engineers and a software architect, Bladen said.
In 2017, MISO completed an assessment on the capability of its existing market platform and began early design of the new, more adaptable modular system. The RTO is poised to spend $130 million by 2024 to replace the aging system. It expects to begin migrating to the new system in 2020, keeping the current one in operation at least until 2021. (See MISO Makes Case for $130M Market Platform Upgrade.)
“This will be one of the largest undertakings in our history,” Bladen said.
“We’re making sure we build the right kind of system, not just an enhanced version of the current system,” MISO Director of Forward Operations Planning Kevin Sherd told stakeholders at a March Market Subcommittee meeting.
‘No BS’
With such a complex project, MISO’s directors urged that executives deliver clearer reports that do not minimize any future hitches or budget overflows.
“What I want to hear from you is clear, candid communication. No BS. No flowery language. … That’s the kind of stuff that I need to hear,” Director Thomas Rainwater told MISO executives.
“That’s what we need: full transparency and candor. We’re not going to rip your heads off,” Director Baljit Dail added.
Earlier in March, Bladen said the RTO’s new platform will be equipped to handle expanded energy storage participation under FERC’s Order 841, but the legacy system may struggle to accommodate the directives.
Meanwhile, MISO’s separate, settlements platform replacement is ready for the launch of five-minute settlements, officials said, although the RTO is continuing to test the new system while it waits for generation owners to adapt their own software and reporting systems to a five-minute schedule. MISO has twice obtained FERC approval to defer the five-minute settlements roll-out until July. (See MISO Wins Delay on 5-Minute Settlement Roll-Out.)
FirstEnergy Solutions filed for bankruptcy Saturday, two days after asking Energy Secretary Rick Perry to issue an emergency order directing PJM to compensate coal-fired and nuclear power plants that have 25 days of onsite fuel.
The request from FirstEnergy’s competitive power business came a day after the company announced that it will close its three nuclear plants — Davis-Besse and Perry in Ohio, and Beaver Valley in Pennsylvania — by 2021.
Davis Besse Plant NRC
Late Saturday night, the subsidiary filed for Chapter 11 protection in U.S. Bankruptcy Court in Akron, Ohio. The move has been expected since at least February, when FirstEnergy CEO Charles Jones predicted it in a company earnings call. (See FirstEnergy CEO Predicts Death of FES, Coal, Nuclear.)
In a statement, FirstEnergy made clear that the bankruptcy proceedings only applied to FES and its subsidiaries, including FirstEnergy Nuclear Operating Co. Jones touted the move as part of the company’s strategy to get out of the competitive power industry.
“Becoming a fully regulated utility company should give FirstEnergy a stronger balance sheet, solid cash flows and more predictable earnings. Simply put, we will be better positioned to deliver on the tremendous opportunities for customer-focused growth,” he said.
According to Bloomberg, FES is about $3.6 billion in debt, of which 60% is in municipal bonds. It had faced an April 2 deadline to pay bond holders $100 million.
‘Immediate Action’ Requested
In its 44-page letter to Secretary Perry, FES said the premature retirements of its three plants, along with other coal and nuclear plants in PJM, constitute an emergency threat to the reliability of the RTO’s grid. It cited as evidence a report released just two days earlier by the Department of Energy’s National Energy Technology Laboratory that said coal “provided the most resilient form of generation in PJM” during the January cold snap known as the “bomb cyclone.”
“PJM continues to claim that all is well with its system, but at the same time shows it does not have a clear view of what resilience is, how to measure it or how to ensure it,” FES told Perry. “PJM has demonstrated little urgency to remedy this problem any time soon — so immediate action by the secretary is needed to alleviate the present emergency.”
Beaver Valley Plant
PJM rejected FES’ allegation. “This is not an issue of reliability,” PJM said in an emailed statement. “There is no immediate emergency.”
FES also criticized FERC for rejecting DOE’s Notice of Proposed Rulemaking that would have directed all RTOs and ISOs to compensate the full operating costs of any generating facility with 90 days of onsite fuel. The commission instead opened a new docket to receive input on the resilience issue. (See RTO Resilience Filings Seek Time, More Gas Coordination.)
“Despite the fact that the time for such remedial action has come, FERC terminated your rulemaking proceeding and chose instead merely to study the issue further,” the company wrote. “FERC’s response was disappointing. FERC’s reliance on comments by RTOs/ISOs — the very entities that preside over the flawed markets — is misplaced. More fundamentally, FERC’s decision to study the issue further is too little, too late.”
FERC recently extended the deadline to May 9 for intervenors to submit comments in response to the grid operators’ filings (AD18-7).
FPA Section 202c
FES’ requested order, which would be invoked under Section 202c of the Federal Power Act, would apply to “nuclear and coal-fired generators located within the PJM footprint that have a supply of fuel on site sufficient to allow 25 days of operation at full output; that are substantially compliant with all applicable federal, state and local environmental laws and regulations; and that do not recover any of their capital or operating costs through rates regulated by a duly authorized state regulatory authority, municipal government or energy cooperative.”
Those plants would “be compensated with just and reasonable rates that provide for full recovery of its fully allocated costs and a fair return on equity.”
FES also requested that in cases when PJM and a qualifying plant are unable to reach an agreement on rates, “the secretary step in and determine the just and reasonable compensation and conditions.” It also asked that the order remain in effect for at least four years or “until the secretary determines that the emergency has ceased to exist because the PJM markets have been fixed to properly compensate these units for the resiliency and reliability benefits that they provide.”
The Energy Department has used its authority to declare emergencies eight times since 1977 — when the Department of Energy Organization Act transferred this power from FERC to the secretary of energy — beginning with the Western Energy Crisis of 2000. Perry has invoked it twice: last April for the Oklahoma-owned Grand River Dam Authority’s Grand River Energy Center Unit 1, and in June for Dominion Energy’s Yorktown plant. (See DOE Approves Emergency Dispatch of Yorktown Units.)
In both cases, the plants were coal-fired. And in both, Perry issued the orders less than five days after receiving the requests from the plants’ owners. In Yorktown’s case, PJM had also filed a request.
Section 202c limits any emergency action to 90 days if it conflicts with any other law, although it allows the secretary to extend the emergency for another 90 days after a review. Perry has renewed the Yorktown request twice, as PJM had requested that it stay in effect until the construction of a needed transmission line in the Historic Triangle region of Virginia.
However, FES said that “because the eligible nuclear and coal-fired generators must continue to substantially comply with all applicable federal, state and local environmental laws and regulations, the provision in Section 202c limiting the duration to a 90-day period is not applicable.”
Robert Murray, CEO of coal producer Murray Energy, has been lobbying the Trump administration to issue an emergency order for FirstEnergy’s Ohio coal plants, his company’s biggest customer, since at least last July. Perry had reportedly rejected the use of such an order in August, opting instead to issue the resilience NOPR. (See Photos Show Murray’s Role in Perry Coal NOPR.)
Bloomberg, citing anonymous sources, reported in February that DOE officials were still considering the use of 202c for FirstEnergy’s coal plants, but the department countered that the sources were “misinformed.” Nevertheless, Undersecretary Mark Menezes told Bloomberg that “we have authorities that we can use when the need arises. They’re well known. And we’ll use them if we need to.”
PJM, Stakeholders React
PJM acknowledged fuel supply diversity is important. “But the PJM system has adequate power supplies and healthy reserves in operation today, and resources are more diverse than they have ever been. Nothing we have seen to date indicates that an emergency would result from the generator retirements,” the RTO said. “The potential for the retirements has been discussed publicly for some time. In anticipation, PJM took a preliminary look at the effect of the retirements on the system. We found that the system would remain reliable. We have adequate amounts of generation available.”
In February, PJM issued a report showing that its grid performed reliably during the cold snap but that price formation changes were needed, echoing comments that CEO Andy Ott made in January before the Senate Energy and Natural Resources Committee. (See PJM: Cold Snap Uplift Shows Need for Pricing Changes.)
Condemnation of FES’ request was widespread across stakeholder sectors and interests.
“FirstEnergy does not speak for its own customers, as strong opposition from their customers to past FirstEnergy bailout attempts clearly shows, much less their attempt to speak for all 65 million customers who depend on PJM,” the Electric Power Supply Association said. “Similarly, FirstEnergy does not speak for all other coal and nuclear asset owners.”
On Friday, EPSA joined with 10 other trade associations — the American Council on Renewable Energy, American Forest & Paper Association, American Petroleum Institute, American Wind Energy Association, Electricity Consumers Resource Council, Independent Petroleum Association of America, Interstate Natural Gas Association of America, Natural Gas Supply Association, Solar Energy Industries Association and Advanced Energy Economy — to request that Perry allow comment on FES’ filing, citing the company’s failure to seek rehearing of FERC’s decision on the resilience NOPR.
“It would be manifestly unreasonable and unfair to both other interested parties and the secretary for FE Solutions to demand that the secretary act without hearing from interested parties, including PJM, after having failed to exercise its right to request rehearing before FERC and waited nearly three months before challenging FERC’s order through the March 29 request to the secretary,” the groups said.
The Sierra Club said a 202c order would be illegal and promised to sue the department if Perry granted FES’ request. “If the Trump administration bows to FirstEnergy and moves forward with this bailout attempt, Sierra Club fully intends to challenge and defeat the administration in court,” said Mary Anne Hitt, director of the group’s Beyond Coal campaign.
NRG Energy spokesman David Gaier called FES’ request “a solution in search of a problem.”
“The only crisis here is one affecting FirstEnergy’s shareholders, and Ohio ratepayers should not be asked to bail out FE for its inability to profitably operate its power plants,” Gaier said.
John Moore, director of the Natural Resources Defense Council’s Sustainable FERC Project, said, “FirstEnergy is desperate to pad its bottom line at the expense of its customers. The region is awash in cleaner and cheaper resources, and FirstEnergy can’t compete in the market. This move is stunning given that the Federal Energy Regulatory Commission, the Department of Energy and the state of Ohio have all rejected these bailouts.”
“PJM has twice the reserve margin it needs so this fuel supply crisis is completely manufactured,” said Rob Gramlich, president of Grid Strategies, a renewable energy consultancy. “PJM has been quite accommodating in my opinion, asking FERC for a nationwide ruling and to be directed to make market design changes if they deem necessary. They’re punishing some pretty good deeds.”
While the Nuclear Energy Institute lamented the plant closures, it did not express direct support for FES’ request.
“The announcement from FirstEnergy to retire more than 4,000 MW of nuclear power generation demonstrates the urgency for policymakers to act before it is too late,” said John Kotek, NEI vice president of policy development and public affairs. “All options to prevent the closure of nuclear plants should be explored.”
Nuke Closures
In Wednesday’s announcement of the nuclear plant closures, FES Generation President Don Moul repeated its call for “elected officials in Ohio and Pennsylvania to consider policy solutions that would recognize the importance of these facilities to the employees and local economies in which they operate, and the unique role they play in providing reliable, zero-emission electric power for consumers in both states.”
Zero-emission credit legislation similar to that passed in Illinois and New York has stalled in Ohio, however.
Perry Nuclear Plant | Wainstead
The plants have a combined capacity of slightly more than 4 GW, representing about 65% of the electricity FES generated in 2017, according to the company.
“PJM has an established 90-day process to review generator retirement requests. We will conduct the full analysis required to determine if there would be any local effects on the grid,” the RTO said in its statement. “However, given the unusually long advance notice, there would be sufficient time to complete any transmission upgrades required.”
It also noted there are about 10 GW of generation in Ohio under construction or in the interconnection queue.
FERC on Thursday accepted the recommendations of SPP’s Market Monitoring Unit to eliminate the Woodward frequently constrained area (FCA) in Northwest Oklahoma and replace the Texas Panhandle FCA with a smaller one for the Lubbock area. The changes are effective April 1 (ER18-736).
FCAs are areas with high levels of congestion that are also subject to one or more pivotal suppliers.
The Monitor’s December 2017 FCA report recommended removing the two historically congested areas that appeared on the 2016 report, while designating one new FCA. The MMU annually reviews and designates SPP’s congested areas.
| SPP
The MMU recommended removing the Woodward FCA — added in January 2016 because of the growth in wind resources in western SPP — because of a decrease in congestion following the Woodward phase shifting transformer upgrade in May 2017.
It said the Texas Panhandle FCA should be removed because it no longer met the threshold of binding for at least 500 hours with a $25/MWh impact during a given 12-month period.
However, the Monitor suggested the Lubbock, Texas, area be added as SPP’s lone FCA for this year. The area first appeared as an FCA candidate in the 2015 study and has seen increased congestion since, indicating a shift in congestion south of the Texas Panhandle, the MMU said.
SPP’s FCA Candidate Areas | SPP
Congestion in this area was part of the southern section of the Texas Panhandle FCA but upgrades north of the Lubbock area and the Woodward-Border-Tuco 345-kV line shifted the congestion to the southwestern edge of the RTO’s grid.
“The Texas Panhandle still sees congestion, but the addition of the Lubbock area better represents where the concern of exercise of market power exists,” the MMU said. The Lubbock area saw 686 hours of congestion in 2017.
FERC ruled that the Monitor’s suggestion that it simply post the FCA list on SPP’s website without the Board of Directors’ approval was outside the proceeding’s scope. The MMU said that following the Tariff requirement for board approval can take six months, a lag that can lead to outdated FCA lists and that “does not allow SPP or the Market Monitor to efficiently and appropriately address market power concerns.”
The commission urged the RTO and its stakeholders to consider the MMU’s suggested improvements to the FCA re-evaluation and designation process through the stakeholder process.
FERC last week approved SPP’s proposed Tariff revisions reducing network service charges for customers in Southwestern Power Administration’s (SWPA) pricing zone, effective April 1 (ER18-769).
The commission agreed with SPP that the proposed revisions, filed in January, will ensure SWPA customers are not charged twice for the same deliveries. FERC noted it had previously accepted similar mechanisms to eliminate double charging for deliveries of statutory hydropower obligations to federal preference customers.
SWPA is one of several Department of Energy power marketing administrations selling hydroelectric power produced at Army Corps of Engineers dams “with preference to public bodies such as rural electric cooperatives and municipal utilities.” The agency participates in SPP as a limited transmission owner under the RTO’s Tariff, selling excess transmission capacity on its system as non-federal transmission service under grandfathered agreements with individual customers or through its Tariff.
SPP uses SWPA’s transmission facilities, located in pricing Zone 10, to provide transmission service, scheduling services, operating reserve sharing, reliability coordination and other services. Attachment AD of the RTO’s Tariff “contemplates” the migration of all non-federal transmission service customers to network service or point-to-point transmission service, FERC said.
SWPA recovery crew pauses during 2009 restoration work | Southwestern Power Administration
SPP explained to the commission that network service customers in SWPA’s pricing zone are assessed monthly demand charges on a coincidental peak basis under Schedule 9 of the Tariff, based on the customer’s total metered load. Because SWPA charges a bundled rate for deliveries of its federal power, federal preference customers could pay twice if they take SPP network service in the zone and do not use any other TOs’ intervening facilities, the RTO said.
SPP said the revisions would eliminate the double charging by reducing the eligible network customers’ network load by the amount of federal power they receive from SWPA, scheduled at the time of the coincident peak used in calculating Schedule 9 demand charges.
The commission noted SWPA recognized the double charging issue and sponsored the Tariff revision through SPP’s stakeholder process. The SPP Board of Directors approved the change in July 2017.
NEW ORLEANS — MISO’s Steering Committee last week said it needs more time to decide whether the stakeholder-led Energy Storage Task Force can deliberate on how the RTO can comply with FERC’s sweeping storage order issued in March.
Established last year, the task force was charged with exploring expanded storage participation in MISO, including generator-and-storage interconnection combinations and competitive bidding on storage projects that solve transmission issues. However, the task force has not assumed it could begin considering expanded storage rules as they specifically relate to last month’s Order 841. (See MISO Storage Task Force Talks Order 841.)
MISO’s task forces do not determine stakeholder policy; instead, they submit recommendations to other committees with decision-making authority, such as the Advisory Committee. The Energy Storage Task Force has already sent several discussion topics — including storage capacity accreditation, must-offer requirements, state-of-charge management, possible aggregation and new modeling needs — to MISO’s Resource Adequacy Subcommittee, Reliability Subcommittee, Planning Advisory Committee and Market Subcommittee.
“My initial response is that this task force was created prior to Order 841,” Steering Committee Chair Tia Elliott said during a March 28 meeting.
Task force Chair John Fernandes said his group will have plenty of issues to discuss even if the committee decides against assigning it Order 841. The group can hold dialogue on operational functions, customer-owned storage assets and modeling issues — including whether storage should be modeled in MISO’s yearly Transmission Expansion Plan process or the interconnection queue, he said.
“I don’t necessarily have it in my mind that the task force will go away,” Fernandes said.
As an interim measure, FERC last week approved a second MISO storage definition, allowing storage to participate in front of the meter to supply energy, capacity, spinning reserve, supplemental reserve and regulating reserve. (See FERC OKs MISO Plan to Expand Storage.) However, the commission also determined that MISO had to address other storage participation rules, namely creating unique bidding parameters for storage resources, a path for storage to receive make-whole payments and an outline detailing how storage could provide voltage support and black start services. It ordered the RTO to devise those rules in a compliance filing.
NEW ORLEANS — MISO Board of Directors Chairman Michael Curran paid tribute to Eugene Zeltmann, a former board member who passed away in late February after a battle with leukemia.
Zeltmann was a former CEO of the New York Power Authority and served on several boards after his retirement from that position in 2006. He served a nine-year tenure on MISO’s board, exiting in 2015.
Zeltmann | Beloit College
“He served with considerable distinction and was a moral compass to us all,” Curran said during a March 29 board meeting.
After struggling to compose himself, Curran disclosed that he visited Zeltmann two weeks before he died and found the same man he served with on MISO’s board.
“‘Tell me about MISO, Michael. Tell me how everyone is doing,’ he said. He was Gene until the end,” Curran said.
RTO Adds 8 New Members
MISO can add eight new non-transmission-owning entities to its membership in 2018, board members decided Thursday.
Senior Vice President of Compliance Services Stephen Kozey said five of the eight applicants will join the RTO’s Competitive Transmission Developers stakeholder group: Avangrid Networks, Cardinal Point Electric, Eastex Transco, Ferrovial Transco International UK and LS Power Midcontinent.
MISO is also adding the city of Benton, Ark.’s Benton Utilities as a participant in the Municipal, Cooperative Electric Utilities and Transmission-Dependent Utilities sector, and Ranger Power and Tradewind Energy to the Independent Power Producers sector.
Election Year for MISO
MISO will also hold board elections later this year to fill three board seats.
Directors Phyllis Currie’s and Mark Johnson’s first terms are ending, and both are seeking re-election. Curran will reach the RTO’s limit of three three-year terms at the end of this year and will not be eligible for re-election.
MISO will use an outside search firm to produce a slate of outside candidates to be vetted by the RTO’s Nominating Committee (composed of stakeholders), board members and staff through summer.
NEW ORLEANS — A new rule change will prevent MISO participants from simultaneously running for chair and vice chair of a stakeholder group, a move that multiple stakeholders said was needed to simplify the nominating process.
MISO Advisory Committee sector representatives voted 19-5 in favor of the change during a March 28 meeting.
The RTO’s Stakeholder Governance Guide was previously silent on whether stakeholders could submit their names as nominees for the chair and vice chair positions of a single stakeholder group.
“I think we assumed that stakeholders would not try for both,” Advisory Committee Vice Chair Tia Elliott said.
However, two candidates running last year for chair of MISO’s new Energy Storage Task Force expressed interest in running for vice chair if they weren’t picked for the top position. The situation led to one candidate submitting a late vice chair nomination, ultimately forcing a rerun of the election. (See Nomination Redux for MISO Energy Storage Task Force.)
NEW ORLEANS — MISO Advisory Committee members last week criticized the RTO’s plan to revamp load forecasting using projections from load-serving entities, saying the amount of data needed is nearly impossible to provide.
Speaking at a March 28 Advisory Committee meeting, Planning Advisory Committee Chair Cynthia Crane said that while MISO must revise its independent load forecast to accommodate growth of distributed resources and changing load shapes, the RTO’s 140-plus LSEs have concerns over how to provide four 20-year forward forecasts using four sets of future assumptions from the Transmission Expansion Plan.
“If you do the math, you’re talking 98 million data points, and there’s the question of how MISO is going to organize all of that,” Crane said, using a calculation of 8,760 hours per year for 20 years across the four MTEP futures.
Wisconsin Public Service’s Chris Plante said he wasn’t convinced that MISO needs that level of detail for transmission planning.
“I started my utility life out as a load forecaster. … If I could forecast 8,760 hours for 20 years over four futures, I wouldn’t be in this room,” joked Madison Gas and Electric’s Megan Wisersky. “When I’m told this will improve the planning process, I just laugh,” adding that she doubted that current third-party load forecaster Purdue University provides the same level of detail.
“We’re not going to add staff for such a meaningless exercise,” Wisersky said of her fellow LSEs.
MISO has said it might replace its current independent load forecast prepared by Purdue’s State Utility Forecasting Group with data compiled by LSEs to produce the forecast that informs transmission planning, an effort that will require LSEs to annually assemble four different 20-year load forecasts to fit with each MTEP future. The approach is one of two MISO is vetting to improve its load forecasts. If LSEs decide they cannot collect that level of information, the RTO will continue its practice of hiring a contractor to put together a load forecast. (See Members Skeptical as MISO Explores LSE Load Forecasting.)
Plante said it’s difficult for members to make an informed decision until stakeholders know how much MISO pays Purdue for its independent load forecast. He wondered if the alternative plan would save the RTO any money.
“We see this as an opportunity to try to offset some of these increases we see in the [operations and maintenance] budget year to year,” he said.
Crane pointed out that all other RTOs use an independent load forecast to guide transmission planning.
“I’ll sound like my mother here: Just because someone else is doing it, doesn’t mean you should,” Wisersky said.
MISO staff did not provide comment at the meeting, although Executive Director of System Planning Aubrey Johnson took notes on the members’ reactions and promised to deliver a report to RTO planners.
The Public Utility Commission of Texas last week conditionally approved Vistra Energy’s $1.7 billion acquisition of Dynegy, allowing the combined company to avert a requirement that it divest generation over market power concerns (Docket No. 47801).
The commission amended staff’s proposed order by excluding 820 MW of DC tie import capacity from the Eastern Interconnection as “not being appropriate” in determining the combined entity’s market share. Combined with a previous ruling that excluded a 915-MW gas plant from market power calculations, Vistra’s generation arm, Luminant, would no longer be required to divest itself of at least 1,281 MW of capacity.
The Texas PUC had an open meeting on March 29 | AdminMonitor
PUC staff in February had recommended the divestiture to keep post-merger Vistra below the statutory cap of 20% of ERCOT installed capacity. (See Vistra Balks at Divesting 1,281 MW in Dynegy Merger.) Staff’s proposed order excluded Luminant’s Lake Hubbard power plant from the calculations based on its grandfathered exemption in a previous docket (No. 45429).
PUCT Chair DeAnn Walker | AdminMonitor
PUC Chair DeAnn Walker and Commissioner Arthur D’Andrea both filed memos in the proceeding, with Walker agreeing to D’Andrea’s more substantive changes during the March 28 open meeting.
PUCT Commissioner Arthur D’Andrea | AdminMonitor
With the modifications, the order now says Vistra and Dynegy have met the requirements for approval “by demonstrating that the proposed transaction will not result in the combined ownership and control of more than 20% of the installed generation capacity located in or capable of delivering electricity to ERCOT.”
Staff had said that Dynegy owns 820 MW of generation in the Eastern Interconnection “capable of delivering electricity to ERCOT” and recommended that capacity should be included in the calculation. D’Andrea countered by saying the DC ties should be treated as an exception, “not as a natural extension of the ERCOT market.”
“I like the idea of saying that doesn’t count as our market,” he said.
With the changes, Luminant would no longer have to go through with the prospective sale of up to three gas plants, whose suitors include a trading firm.
“If you look at those three plants, I think I trust Vistra with them,” D’Andrea said. “Would you rather Vistra, who you know and with a ton of skin in the game, run those three plants this summer, or would you rather a trader run those three plants this summer?”
Luminant assuaged the commission by committing that they would not import power over the DC ties. “That commitment is legally binding and enforceable through the coercive power of the state,” D’Andrea wrote in his memo. “To my eyes, that makes the applicants ‘incapable’ of importing power.”
The commission added language requiring the combined entity to annually file an affidavit, “under penalty of perjury, attesting to compliance” with the commitment not to import.
Walker said she was concerned other applicants could make the same commitment in future cases. “If we’re expecting ERCOT to police this, I’m worried about the workload on [the ISO].”
“We’re mostly dealing with really big players with a lot of skin in the game,” D’Andrea said, noting ERCOT’s Independent Market Monitor “can go after them.”
“If [the IMM] finds something, they’ll violate their agreement, and that’s a pretty serious thing. That’s something we don’t take lightly,” he said.
The Texas PUC’s commissioners share a laugh before the meeting | AdminMonitor
Vistra announced its intention to acquire Dynegy in October. The all-stock deal will create a generation and retail company owning 40 GW of capacity and serving nearly 3 million customers, mainly in ERCOT, PJM and ISO-NE. (See Vistra Energy Swallowing Dynegy in $1.7B Deal.)
Vistra said the transaction remains on track to close by July. It is only waiting on FERC approval, having obtained all other necessary regulatory approvals, including that of the New York Public Service Commission. Vistra’s shareholders approved the merger in an early-March vote.
ERCOT Directors’ Elections Approved
The commission’s consent agenda included the approval of Terry J. Bulger’s election (Docket No. 47916) and Peter Cramton’s re-election (Docket No. 47915) as unaffiliated directors on ERCOT’s board.
Bulger, a 35-year banking professional with ABN AMRO and Bank of Montreal, fills the vacancy created by Jorge Bermudez’s resignation in 2016. His term will begin in April’s board meeting.
Cramton, an economics professor at the University of Maryland College Park and the University of Cologne, will begin a second three-year term on Aug. 17.
Both directors were elected during ERCOT’s annual membership meeting in December.
Exelon on Thursday filed with ISO-NE to retire its 1,998-MW Mystic Generating Station in 2022, but the company said it “may reconsider” the decision if the grid operator can reform its markets to properly value the plant’s contributions to reliability and regional fuel security.
The Everett, Mass., facility includes a 576-MW dual-fuel unit (Unit 7); two gas-fired units capable of producing a combined 1,414 MW (Units 8 and 9); and Mystic Jet, an 8.6-MW oil-fired peaker.
Mystic Generating Station, on the Mystic River in Everett, Massachusetts. A wind turbine owned by the local water authority to power a pumping station is on the right.
“Changes to market rules are necessary because critical units to the region, like Mystic 8 and 9, cannot recover future operating costs, including the cost of securing fuel,” Exelon said in a statement.
Absent regulatory reforms, “these units will not participate in the Forward Capacity Auction scheduled for February 2019,” Exelon said in a statement.
ISO-NE spokeswoman Marcia Blomberg told RTO Insider that Mystic is “one of the two largest generating stations on the regional power system. The ISO will conduct a study to ascertain how these retirements could affect power system reliability and will release the results as soon as possible.”
Exelon Power President Ron DeGregorio said it was “a difficult day not only for the talented men and women who have dedicated themselves to operating Mystic safely and reliably every day, but also for their families, their communities and all of their colleagues here at Exelon.”
Cost Recovery
Exelon’s announcement referred to a recent statement by the RTO that it “may propose interim and long-term market rule changes to address system resiliency in light of significant reliability risks” identified in its January 2018 fuel security report. (See Report: Fuel Security Key Risk for New England Grid.)
“To the extent that changes are timely filed and approved by the Federal Energy Regulatory Commission, Exelon Generation may reconsider the retirement of the Mystic units,” the company said.
FERC in September 2017 approved Exelon’s request for recovery of more than $1.5 million in fuel costs for the plant (ER17-933). The commission granted Exelon more than $1.5 million for Unit 8 and 9 fuel costs that were not recovered because of market power mitigation measures applied in October and November 2016. (See FERC Approves Cost Recovery for Exelon’s Mystic Plant.)
Fuel Security and LNG
Oil supplies at plants in New England declined rapidly during a cold snap earlier this winter as gas prices spiked and dual-fuel plants switched to oil, but the RTO avoided serious reliability issues thanks to LNG shipments.
Contributions from other types of generators were crucial during the cold snap, according to the RTO’s analysis.
“For instance, electricity produced by the Millstone nuclear station during the cold spell is equivalent to what could be produced by about 880,000 barrels of oil, and the power from the Mystic 8 and 9 units in Boston, which are fueled by LNG from the nearby Distrigas import facility, was the equivalent of more than 360,000 barrels of oil,” ISO-NE CEO Gordon van Welie said in February. (See Van Welie: ISO-NE in ‘Race’ to Replace Retirements.)
Exelon also announced Thursday it will purchase the Everett Marine Terminal, an LNG import facility, from ENGIE North America “to ensure the continued reliable supply of fuel to Mystic Units 8 and 9 while they remain operating.” No contract terms were disclosed.
The facility is the oldest such LNG facility in the U.S. and has connections with two interstate pipeline systems, the Tennessee and Algonquin pipelines, as well as with the local distribution system owned by National Grid.
