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.
FOLSOM, Calif. — Energy storage and distributed energy resources stand to play a bigger role in markets as CAISO moves forward with its latest proposal to integrate and compensate the emerging technologies, ISO staff said last week.
The scope of the Energy Storage and Distributed Energy Resources Phase 3 (ESDER 3) initiative is still taking shape, CAISO Infrastructure and Regulatory Policy Specialist Eric Kim said as he led a March 29 working group in analyzing the design elements.
“Nothing is set in stone,” said Kim, adding that interested parties should file comments with the ISO by April 9.
“What are some things we are not considering?” he asked.
The all-day session provided a view into the extremely technical process of integrating resources that behave in different ways, with new engineering, regulatory and market rule challenges.
CAISO is still gathering stakeholder input on its ESDER 3 straw proposal, issued in February. The ISO said the purpose of the proposal “is to present the scope and solutions of issues related to the integration, modeling and participation of energy storage and DERs in the CAISO market.” The rules will apply across the Western Energy Imbalance Market (EIM) but will not include EIM-specific items. At a session last fall, stakeholders pushed the ISO to expand the scope of the effort. (See CAISO Urged to Broaden ESDER Phase 3.)
The ISO has organized the proposal under the broad themes of demand response, multiple-use applications (MUAs) that allow storage to provide services and receive revenue from more than one entity at a time, and non-generator resources (NGRs). MUAs are getting more attention, with the California Public Utilities Commission in January passing a suite of 11 rules governing their use for storage.
The initiative includes exploration of new bidding and real-time dispatch options for DR and removal of a requirement that DR be aggregated under a single load-serving entity. It will also explore a process for facilitating market participation for NGRs, including identifying commitment costs. Also under development is a load-shift product for behind-the-meter storage, and a methodology to measure load curtailment from electric vehicle supply equipment, which is seen as a way to absorb excess output from renewables. (See CAISO Load-Shifting Product to Target Energy Storage.)
Currently, a DR resource that includes EV supply equipment is measured without considering the equipment’s effect on load dynamics. One of many complex tasks confronting the ISO is determining how to meter the data to measure the performance of EV infrastructure, according to a CAISO presentation.
The initiative’s previous phase, ESDER 2, is being prepared for submission to FERC after being approved by the CAISO Board of Governors last July. (See New CAISO Rules Spell Increased DER Role.) ESDER 2 included a set of alternative energy usage baselines to assess the performance of proxy demand resources, which are DER aggregations of retail customers. It also set out new rules that distinguish between charging energy and station power for storage resources, and established a net benefits test for DR resources that participate in the EIM.
Kim said the ISO will host more ESDER 3 working groups. Thursday’s participants included EV charging station company eMotorWerks, California Energy Storage Alliance, DER and DR companies, utilities and others.
CAISO, Pacific Gas and Electric, and Calpine have settled their differences over the terms of the reliability-must-run agreements keeping three Calpine gas-fired plants operating instead of retiring.
FERC is likely to issue a decision on the agreements by April 30, Administrative Law Judge H. Peter Young said Tuesday after certifying the uncontested settlements that would reduce the annual revenue the plants receive. The controversial out-of-market RMR payments are opposed by the California Public Utilities Commission and were reluctantly approved by the CAISO Board of Governors in November. (See Board Decisions Highlight CAISO Market Problems.)
The new settlements filed March 21 cover two different FERC dockets, one Calpine’s Metcalf plant (ER18-240), and another for the company’s Feather River and Yuba City plants in Northern California (ER18-230).
Calpine’s Metcalf Energy Center | Calpine
“In general, the offer of settlement would substantially reduce Metcalf’s RMR service rates and would change the MEC facility’s operating status,” Young said of the Metcalf settlement. (See FERC Orders Hearing, Settlement Talks for Calpine RMRs.)
The Metcalf settlement would reduce the plant’s annual fixed revenue requirement to $43 million from about $72 million through 2020 if it retains its RMR status, and make the plant operator responsible for routine repairs and capital expenses. It would set recovery for planned 2018 capital items to $8 million, to be recovered in 12 installments of $675,000 beginning on Jan. 1, 2018.
If the RMR agreement is extended, capital recovery would remain at about $8 million per year. The settlement would also grant the plant $8 million in 2019 and 2020 if the revised agreement is not renewed and the unit shuts down.
The settlements would also take all three plants from Condition 2 (eligible for full cost-of-service payments) to Condition 1 (eligible for only a portion of their revenue requirement) status, and impose a must-offer requirement, which the ISO’s Department of Market Monitoring has recommended for all RMR units. CAISO is working to revise its RMR program to establish a must-offer requirement for resources. (See CAISO, Stakeholders Debate RMR Revisions.)
The Feather River and Yuba City settlements would reduce each plants’ 2018 revenue to about $3.5 million from the previous $4.4 million, with a 2% hike for 2019 and 2020 if the RMRs are renewed. They would also impose a must-offer requirement on the plants.
After CAISO approved the RMRs last November, the CPUC issued an order directing PG&E to use energy storage to meet the needs currently served by the plants. (See CPUC Targets CAISO’s Calpine RMRs.) The storage resources must be online before 2019.
CARMEL, Ind. — FERC on Wednesday approved MISO’s plan to permanently double its hard offer cap but told the RTO to clarify some details about the proposal in a compliance filing within 60 days (ER17-1570-001).
The proposal marked MISO’s second attempt to comply with FERC Order 831, which required RTOs and ISOs to raise their hard caps for verified cost-based incremental energy offers to $2,000/MWh. The commission issued the order in response to the 2014 polar vortex, which sent natural gas prices soaring and left some generators unable to cover fuel costs.
MISO control room | MISO
FERC late last year rejected MISO’s first attempt at complying with the rule, saying the RTO wrongly proposed a provision that prohibited resources from submitting cost-based offers above the required $2,000/MWh hard cap. (See MISO’s Plan for Wintertime Offer Caps Stalled by FERC.)
The commission had also ruled that MISO:
failed to describe what factors it would consider when verifying cost-based offers or distributing uplift;
was silent on its treatment of external supply offers in excess of the cap;
neglected to specify a verification process for demand response; and
failed to limit the cap on all adders above cost to $100.
On Wednesday, FERC determined that MISO’s second filing had cleared up the offer validation process, which gives the Independent Market Monitor discretion to validate market participants’ data. The RTO additionally complied with a requirement that external energy transactions not exceed the hard cap but also not be subject to validation.
However, FERC said MISO still must pledge to apply the new hard cap to adjusted energy offers from fast-start resources.
The commission acknowledged that its previous ruling mistakenly understood “proxy offers” to include fast-start resources’ adjusted offers, but it said it now recognizes the term applies to resources deployed during emergency operating procedures.
“The commission did not intend to change the definition of ‘proxy offers,’” FERC said.
MISO had proposed to apply the $2,000/MWh hard cap to most proxy offers used during emergency conditions for price-setting purposes, but it said emergency demand response proxy offers would not be included. The RTO has long allowed emergency DR resources to exceed the hard price cap up to the value of lost load, which is currently $3,500/MWh.
FERC said it viewed MISO’s value of lost load as an “administratively determined pricing mechanism beyond the scope of the offer cap reforms in Order No. 831.”
The commission also accepted the RTO’s plan to have its Monitor verify offers from DR resources above the $1,000/MWh soft offer cap before market clearing in order to allow them to set the LMP. FERC also approved edited Tariff language that allows resources to submit cost-based incremental energy offers above $2,000/MWh and recover verified costs through make-whole payments, although such offers are barred from setting LMPs.
But the commission is requiring MISO to provide more detail on the Monitor’s verification process for resources that submit incremental energy offers above $1,000/MWh that cannot be verified prior to the market clearing. FERC said MISO must also describe when the Monitor will verify the prices and revise reference levels, and when a market participant can dispute revenue sufficiency guarantee make-whole payments.
“Additionally, we direct MISO to propose Tariff language describing how the amount of the make-whole payment will be determined,” FERC added.
FERC also ordered MISO to update its Tariff to include references to its Operating Cost Survey, which is used to determine reference levels by collecting more than 200 “pieces of data for a single plant,” according to the RTO.
FERC additionally said MISO must clarify the use of its adder for “outage risk,” a term the RTO used in its amended offer cap filing but is not found in Tariff provisions that define reference levels, which instead employs the term “legitimate risk.”
FERC also said MISO appeared to violate a rule that limits to $100/MWh the sum of any adders for cost-based incremental energy offers above $1,000/MWh by allowing two types of adders within its offer cap: the legitimate risk adder and a fuel cost uncertainty adder. The commission gave the RTO 60 days to explain the differences, if any, between the two terms and describe how it will stay within the $100/MWh adder limit.
