Page 1225 – RTO Insider

January 16, 2018

PJM Operating Committee Briefs: Jan. 9, 2018

VALLEY FORGE, Pa. — PJM’s Chris Pilong and Joe Ciabattoni told the Operating Committee last week that the RTO’s generation fleet passed muster during the recent cold snap despite several of the highest winter daily demand peaks it has ever seen.

PJM black start BAAL — Pilong | © *RTO Insider*

Pilong reviewed operational events from last month, which included four high system voltage alerts in November and 11 cold weather alerts in December that began on Christmas morning and persisted through to this year. He said it was “probably the longest cold stretch … I’ve seen,” but that “everything went very smoothly.”

“Our system operators were able to do a great job thanks to your operators,” he said.

The evening peak load of 138,465 MW on Jan. 5 came within 5,250 MW of PJM’s winter peak record set on Feb. 20, 2015. Throughout the first week of the year, coal generation accounted for nearly 40% of the output, with nuclear and gas each producing about a quarter of the supply, which Pilong called “a fairly consistent story for the fuel mix.”

He acknowledged there was “a higher volume of oil than would typically be seen” at between 9,000 and 14,000 MW for the week, caused by gas-fired units switching to alternative oil supplies.

“The higher gas prices [were] making coal and oil a little more economic,” he said.

Unplanned outages hovered around 8% until the wind picked up at the end of the week and unplanned outages increased to 22,906 MW, or 11.5%, on Jan. 6, Ciabattoni said. Of that, 9,220 MW (40%) were gas units with operating problems and 3,143 MW (14%) were gas units reporting supply issues. Except for Midwestern hubs around Chicago, gas prices throughout the RTO spiked to more than $80/MMBtu on Jan. 5, with some above $120/MMBtu. The data were preliminary and came from PJM’s eDART self-reporting system. RTO staff communicate with unit operators to confirm the details of reported issues, Ciabattoni said.

PJM’s Manual 13 anticipates that 8,000 to 10,000 MW of forced outages are expected during such conditions, Pilong said. There was a “similar uptick” during the 2014 situation often referred to as the “polar vortex,” he said, but the difference was that there was really “no advanced notice” in 2014. Staff had to call on 2 MW of generation for every 1 actually needed, he said, because “it was a 50/50 shot that we would get it.”

“So even two hours’ notice allows us to change our plans,” he said.

Ciabattoni noted that December outages — both generation and transmission — were down slightly year-over-year. The load forecasting error was higher than December 2016 — 2.54% on-peak and 2.18% off-peak compared to 2.09% and 2.14%, respectively — but the RTO average error of 2.36% was still within the 3% target. There was an outlier of nearly 5% on Dec. 22.

“Is 3% right [as the target]? I’m not sure that it is, but we’ve been using it for a while,” PJM’s Mike Bryson said in response to a stakeholder question, adding that “we’re very open to using another metric.”

Staff explained that the calculation is the compilation of the absolute value of the error between each day’s hourly peak and the forecast from eight hours previous. Forecast development begins up to seven days ahead of time with wind chill and other weather expectations and can be adjusted up to an hour ahead of delivery.

Balancing authority area control error limit (BAAL) performance remained at 99.8% from November through December. Both the number and total time of excursions outside the target limits were near yearly lows in December.

Black Start RFP Opens in February

PJM BAAL black start — Schweizer | © *RTO Insider*

PJM’s David Schweizer discussed the timeline for the RTO’s five-year black start request for proposals, which will open Feb. 1 with a pre-bid web conference scheduled for Feb. 6. Participants will have until March 8 to submit basic proposals, on which PJM will provide responses by March 30.

“We’re looking very heavily at fuel assurance as an evaluation component,” Schweizer said.

Final proposals will be due May 31, and Schweizer said applicants should expect to start seeing awards soon thereafter.

“We’re going to do a lot of this [analysis] in parallel, so we’re not going to get to the end and post the awards,” he said. “We will award the black start service as we run through the plans.”

Generation Transfer Seen as Overly Lengthy

Stakeholders endorsed changes to how generation ownership is transferred despite a concern about PJM’s requirement that owners submit initial information 45 days ahead of the transfer.

PJM’s Rebecca Stadelmeyer, who is overseeing the proposed changes, estimated that the initial information is about 65% of the amount needed for the RTO to ensure “what the member is seeking to do is reflected in our systems.” She said she wanted to avoid last-minute problems.

“That has occurred more than I want to count,” she said.

Chris O’Hara, PJM deputy general counsel, said 45 days is “a rational amount.”

“It’s not as simple as switching a toggle switch on an account,” he said.

Committee Changes

Ken Seiler, who chairs the OC, is switching jobs with Paul McGlynn, who chairs the Planning Committee. February will be Seiler’s last month chairing the OC. Dave Souder will then run the committee until McGlynn takes over.

— Rory D. Sweeney

January 14, 2018

MISO Seeks To-Do List for Resource Adequacy Panel

By Amanda Durish Cook

CARMEL, Ind. — MISO staff asked the Resource Adequacy Subcommittee on Wednesday for feedback on the group’s priorities for 2018.

The RTO is eyeing a few initiatives from 2017 that have not been completed, including:

How capacity accreditations should be granted to battery storage based on operating characteristics;
If units on an extended outage should still be allowed to offer into the capacity auction; and
If MISO should take steps to alleviate partial unit clearing, in which the RTO’s algorithm clears a marginal unit on a pro rata basis. This can result in resources clearing a fraction of their unforced capacity values, leading to higher costs than capacity revenues.

Michael Chiasson of Potomac Economics, the Independent Market Monitor, said he was concerned that if a resource decides not to offer into the Planning Resource Auction because of a lengthy planned outage, the Monitor could construe the move as physical withholding.

MISO staff also want the RASC to finalize Tariff changes to implement external resource zones for the 2019/20 PRA.

The committee also will discuss an upcoming whitepaper on resource availability and need, and whether to create minimum capacity procurement requirements to address the increase of intermittent renewable generation and an aging baseload fleet more susceptible to outages.

“We’re going to have a discussion on how PRA rules can support year-round operational adequacy,” said MISO Manager of Resource Adequacy John Harmon.

Ontario Contribution?

MISO RASC resource adequacy — Harmon | © *RTO Insider*

Harmon also said the RASC could decide how to import capacity from Ontario’s Independent Electricity System Operator (IESO).

“Ontario is interested in developing its export capacity to MISO via its interface with Michigan,” Harmon said.

Harmon said Ontario has never qualified as a balancing authority to export capacity into the RTO. The province would like to become a qualified external supplier in time for the 2019/20 capacity auction.

Customized Energy Solutions’ David Sapper said he understood that Ontario’s transmission service isn’t analogous to MISO because it does not offer firm point-to-point transmission rights.

“The sticking point is really that firm transmission piece,” Harmon said. Before the province can become an external supplier, MISO must also receive a commitment from Ontario to curtail non-firm exports during capacity emergency events, Harmon added.

Although Ontario has signaled a willingness to make some changes over the last year, Harmon said it’s too early to know if it will create firm transmission service. IESO currently sells transmission rights that entitle the owner to a payment if the price of energy in Ontario is different from the price in an intertie zone, allowing hedging of congestion risks and price volatility.

MISO is asking stakeholders to submit any additional 2018 improvement candidates and suggested prioritization by Jan. 26 to radequacy@misoenergy.org. MISO staff said they will review and prioritize the issues in February and finalize a plan to tackle them by the March RASC meeting.

January 14, 2018

FERC Upholds New York Denial of Constitution Pipeline

By Michael Kuser

FERC on Thursday refused Constitution Pipeline’s request to find that New York environmental regulators had failed to act in a timely manner on the company’s water permit application (CP18-5).

The New York Department of Environmental Conservation rejected Constitution’s application in April 2016, saying the company had not included sufficient information for the agency to determine whether its 124-mile natural gas pipeline met state water standards. The pipeline, originating in Susquehanna County, Penn., would deliver 650,000 dekatherms of gas per day.

FERC Constitution Pipeline water permit — Constitution Pipeline Route Map | *Constitution Pipeline*

Constitution asserted that the DEC had waived its authority under Section 401 of the Clean Water Act by failing to issue or deny a water quality certification for the project within the stipulated one-year “reasonable period of time,” contending that a cycle of withdrawal and resubmission of its application had not changed the effective start date for the agency to act.

Though the company first submitted its application in August 2013, it withdrew and resubmitted it several times at the request of the DEC. It submitted its final application on April 27, 2015, and the DEC ruled on April 22 the next year.

In its Jan. 11 order, the commission said that “that once an application is withdrawn, no matter how formulaic or perfunctory the process of withdrawal and resubmission is, the refiling of an application restarts the one-year waiver period under Section 401(a)(1).”

The commissioners said they “continue to be concerned, however, that states and project sponsors that engage in repeated withdrawal and refiling of applications for water quality certifications are acting, in many cases, contrary to the public interest and to the spirit of the Clean Water Act by failing to provide reasonably expeditious state decisions. Even so, we do not conclude that the practice violates the letter of the statute.”

FERC, however, also refused a formal hearing request by the Sierra Club and local environmental organizations Catskill Mountainkeeper and Riverkeeper, saying they raised “no material issue of fact that the commission cannot resolve on the basis of the written record.” The groups wanted the commission to reconsider its 2014 approval of the pipeline.

Gov. Andrew Cuomo on Thursday issued a statement commending the commission “for ruling in favor of New York’s efforts to prevent this project from moving forward,” saying that “the Constitution Pipeline represented a threat to our water quality and our environment.”

Last September, the commission ruled against the DEC on the same issue regarding the Millennium Pipeline, finding the agency had waived its authority by failing to act within the one-year time frame (CP16-17). (See Environmentalists Denounce FERC Millennium Pipeline Ruling.)

January 14, 2018January 17, 2024

Connecticut Regulators Hear Conflicting Advice on Millstone

By Michael Kuser

Connecticut regulators are getting mixed signals from power industry participants as they approach a Feb. 1 deadline for issuing a report on the economic viability of the Millstone nuclear power plant.

While some stakeholders say Millstone may be the most profitable nuclear plant in the country, others contend the plant must contract directly with the state in order to remain operational.

Gov. Dannel Malloy last July ordered the state Department of Energy and Environmental Protection (DEEP) and the Public Utilities Regulatory Authority to assess the current and future viability of the plant and determine whether the state should provide financial support (17-07-32). (See CT Gov Orders Financial Analysis of Millstone Plant.)

The governor’s move came a month after the state’s General Assembly failed to pass a bill that would have allowed the 2,111-MW nuclear plant in Waterford to bid into the state’s procurement process reserved for renewable energy resources such as large-scale hydropower, wind and solar (S.B. 106).

Plant owner Dominion Energy is seeking guaranteed state contracts for its nuclear units, claiming they operate under the same financial constraints from low natural gas prices that led New York and Illinois to provide state subsidies for some of their nukes.

The Electric Power Supply Association filed comments with the state this month, contending that Millstone’s profitability made any ratepayer subsidy unnecessary.

“EPSA believes — and the draft Levitan report confirms — that Millstone will remain economically viable through 2035,” said EPSA, referring to a Levitan & Associates report sent to the governor last month. (See Millstone Likely Profitable Through 2035, Conn. Consultant Says.)

EPSA also submitted a new study by Energyzt Advisors that said “numerous studies have shown that the plant is profitable — perhaps the most profitable nuclear plant in the United States.” The study also recommended regulators put a “price or cap on carbon for all sectors in the state and let market forces determine which carbon reduction investment provides the greatest payback.”

EPSA CEO John E. Shelk said Energyzt’s new analysis “identifies a wide range of strategies state policymakers can implement to protect and grow jobs, manage costs and reduce emissions for the long term.”

Dominion: Flawed Economics

Dominion’s Jan. 8 filing with DEEP and PURA accused the Levitan study of “mixing apples and oranges” in using the company’s regulated, Virginia-based nuclear plants as a proxy for Millstone’s cost projections.

“Millstone Unit 2 and Unit 3 are entirely different designs requiring separate control rooms, separate spare parts inventory, distinct operator training and separate teams of licensed operators,” Dominion said. “In addition, Millstone’s larger physical footprint requires a larger security staff and has higher site maintenance costs including utility costs, building maintenance and snow removal.”

Dominion also cited higher labor costs in Connecticut, saying its plants in Virginia are located in lower-cost rural areas.

In addition, Dominion said the Levitan report “understates the upcoming capital requirements of Millstone as critical station components reach their end-of-life cycle and need to be replaced to maintain the company’s core commitments of safety and operational efficiency. It is important in this regard not to confuse operating cash flow, much of which must be reinvested in the capital needs of the station, with profitability.”

The General Assembly submitted comments last week encouraging PURA and DEEP to “hedge against natural gas by opening a bidding process to receive bids from nuclear generating facilities, including Millstone, to purchase power directly by long-term contract.”

The legislators argued that “since Millstone’s power is currently purchased by hedge funds and financial institutions, these groups are receiving the benefit of price spikes today due to the current ‘cold snap.’”

Environment and Markets

Environmental organization Citizens Campaign for the Environment, which has more than 80,000 members in Connecticut and New York, said that it “strongly opposes any special deals for nuclear power under our state’s energy procurement markets. Allowing Millstone to compete with up-and-coming renewable technologies like wind and solar power would unfairly force Connecticut ratepayers to foot the bill for an antiquated, and yet highly profitable, power source.”

The Conservation Law Foundation submitted a draft proposal for a Dynamic Forward Clean Energy Market (DFCEM) that would allow Connecticut and other states in the region to procure clean and renewable electricity via a market administered by ISO-NE.

“The DFCEM market mechanism would allow Connecticut to procure the environmental attribute of new and existing zero-emission resources, including nuclear, on a least-cost basis through an auction mechanism that places all emissions-reducing resources on equal footing while allowing Connecticut to share emissions compliance costs with other states fairly and in proportion to each state’s climate and energy laws and regulations,” CLF said.

The group did not specifically address the issue of Millstone’s financial viability, but it referred to a November 2017 report by The Brattle Group that assumed “nuclear plants (with the exception of Pilgrim) retire after 60 years in service, or earlier if going-forward costs exceed market revenues.”

January 14, 2018

CAISO: Tx Constraints Hinder Out-of-State Wind

By Jason Fordney

California faces a “severe shortage” of transmission capacity needed to tap potential New Mexico and Wyoming wind resources that would help the state meet its 50% renewable portfolio standard, CAISO said in a new study.

The findings regarding interregional transmission projects are supplements to CAISO’s 2016-2017 transmission plan, which was approved by the ISO’s Board of Governors last year. A second study released Jan. 5 looked at the impact of gas generator retirements scenarios, finding flexible capacity shortfalls at certain times.

The ISO assessed the feasibility of accessing 4,000 MW of wind from New Mexico and Wyoming to meet the 50% renewables goal and reached out to other Western planning regions to assess out-of-state portfolios. It said it had received feedback that its production cost simulations and power flow analyses do not fully capture the challenges of accessing out-of-state resources.

wind resources transmission capacity caiso — California needs more transmission capacity to fully access New Mexico and Wyoming wind power

The study was “a preliminary examination of transmission implications of meeting part of California’s 50% RPS requirement by assuming California’s procurement of 2,000 MW of wind resources in Wyoming and 2,000 MW of wind resources in New Mexico,” it said.

CAISO did not say whether the lack of transmission capacity would make the RPS goal unattainable. But wind energy interests are urging the ISO to explore additional transmission capacity to access low-cost regional wind resources, and the transmission projects included in the study represent billions of dollars in investment to serve California’s RPS.

The study is informational, CAISO said, and the results are not intended to direct interregional transmission, renewable generation development or policy direction.

The study looked at four large proposed transmission projects — TransWest Express, Southwest Intertie Project – North, Cross-Tie Transmission Line and Renewable Energy Express. It used two case studies based on two assumptions regarding resources and transmission.

Major transmission projects outside California have a large impact on grid operations, CAISO said. It noted that transmission constraints on a 230-kV network in southern Wyoming would have to be mitigated for California to realize the full benefit of the Western transmission system.

CAISO Studies Gas Retirements

In a second study on the risks of early retirement of uneconomic gas plants, CAISO said in some scenarios capacity shortages would occur in early evening, the new period of peak net load.

“Capacity issues start to emerge between 4,000 to 6,000 [MW] of retirement, considering some uncertainties in forecasts,” the study said.

CAISO studied six retirement scenarios of between 4,000 and 7,900 MW for four types of gas-fired technology. It found “unlimited renewable curtailment” is masking the need for flexible ramping capacity to meet morning and afternoon demand ramps.

Large amounts of renewable generation on the grid “is also putting economic pressure on the existing gas-fired generation fleet, especially for those generators not obtaining resource adequacy contracts.”

CAISO produces its transmission plan each year to assess system limitations and needed reliability improvements. As part of the 2017-2018 plan, the ISO examined proposed system improvements in the Moorpark area, where it is increasingly unlikely that NRG Energy will build the Puente natural gas power plant. (See NRG Signals Pull-out on Proposed Puente Plant.) The review is needed because of the expected retirement of up to 2,000 MW of generation, CAISO said in a Jan. 11 presentation. Comments on the analysis are due Jan. 18.

January 14, 2018

CPUC Retires Diablo Canyon, Replaces Calpine RMRs

By Jason Fordney

SAN FRANCISCO — California regulators last week issued several decisions that will affect the state’s energy resource mix and markets, including approving the retirement of the Diablo Canyon nuclear plant and replacing three reliability-must-run contracts for gas-fired generators with energy storage.

CPUC Calpine RMRs Diablo Canyon — The CPUC met in San Francisco with President Michael Picker attending via teleconference from Sacramento | © *RTO Insider*

In its first meeting of 2018, the California Public Utilities Commission also approved exploring more uses for energy storage and pilot programs for new electric vehicle infrastructure. But staff delayed until Feb. 8 a vote on a proposal that would subject community choice aggregators (CCAs) to resource adequacy requirements, an idea that has drawn swift opposition from CCA supporters.

Fraction of Negotiated Cost Recovery

The CPUC unanimously approved the retirement of Pacific Gas and Electric’s 2,240-MW Diablo Canyon plant in San Luis Obispo County, the last remaining nuclear plant in the state. But the commission granted only a fraction of the $1.8 billion in cost recovery that was included in a joint proposal negotiated between PG&E and labor and environmental groups.

CPUC President Michael Picker said that with the decision, “We chart a new energy future by phasing out nuclear power here in California in 2024 and 2025.” Attending the meeting by teleconference, he called it “a very difficult and contentious case,” but “we agree the time has come.”

Diablo Canyon represents 6% of energy generated in California, but it is exacerbating overgeneration and curtailment of renewable resources. The plant is also aging and not needed for local reliability, Picker said. PG&E’s load is dropping with the growth of CCAs, direct access users (that buy directly from wholesale) and customer-based generation such as rooftop solar.

Picker said the order also directs PG&E to explore shutting the plant’s two units down earlier, in 2020 and 2022.

The CPUC rejected provisions in the joint proposal that would have paid for $1.3 billion in energy efficiency projects. An administrative law judge had proposed denying the efficiency cost recovery because the utility is already required to make that effort. (See PG&E Disputes ALJ’s Diablo Canyon Recommendation.)

The commission also rejected provisions in the joint proposal that allocated $85 million to mitigate the impact of the plant’s closure on the local community. Local officials say the plant is the hub of the local economy, but the CPUC said it would not authorize assistance without legislative direction.

The CPUC did approve recovery of $211 million to retain PG&E employees until the plant closes, $11 million for employee retraining of workers and $19 million for license renewal expenses already incurred. The commission said replacement capacity would be addressed in its integrated resource plan proceeding.

Parties to the joint proposal include PG&E, International Brotherhood of Electrical Workers Local 1245, Coalition of California Utility Employees, Friends of the Earth, Natural Resources Defense Council, Environment California, California Energy Efficiency Industry Council and Alliance for Nuclear Responsibility.

PG&E said it was “disappointed” the full proposal was not approved, but it noted the CPUC increased funding for employee retention above what was in the proposed decision.

“The joint proposal represents an array of interests from many parties who joined together to promote the best path forward for our state and PG&E’s customers,” the utility said in a news release. “Since the full proposal was not approved, in line with our agreement, PG&E will be meeting to confer with our labor, community and environmental group partners in the days ahead about the decision, our next steps and the path forward.”

Commissioners noted the significance of the plant and the new challenges involved with retiring a major energy resource. Commissioner Martha Guzman Aceves called it a “landmark decision” to get a safer source of energy that is also clean. Commissioner Clifford Rechtschaffen noted that the commission intends to ensure the replacement capacity does not increase greenhouse gas emissions.

Elizabeth Echols, director of California’s Office of Ratepayer Advocates (ORA), said, “PG&E customers benefit from this decision because it protects customers from paying $1.56 billion in unnecessary costs, while providing important funding for PG&E employee retention and retraining programs. Today’s decision is well-supported by the evidence ORA and other parties provided in this case.”

The two units at Diablo Canyon went online in 1985 and 1986.

RMR, Storage, EV Measures Passed

In its consent agenda, the CPUC passed a resolution to replace RMRs inked between CAISO and Calpine for the Metcalf, Yuba City and Feather River plants in PG&E’s service territory. The contracts have created tensions among ISO stakeholders and signal the state’s resource adequacy is not meeting reliability needs. The decision requires PG&E to hold solicitations to replace the RMRs with energy storage. (See CPUC Targets CAISO’s Calpine RMRs.)

Commissioner Carla Peterman also developed two decisions approved by the CPUC, including one adopting 11 rules governing multiple-use applications for energy storage. The decision creates a framework enabling energy storage companies to stack their offerings and provide more than one service to the wholesale market, distribution grid, transmission system and resource adequacy programs. The rule, developed in coordination with CAISO and other agencies, is supported by energy storage companies.

“This is the first time any commission has tried to do anything like this,” Peterman said.

Her other proposed decision supports new EV pilot projects, which she called “an important issue for the state of California.” It directs PG&E, Southern California Edison and San Diego Gas & Electric to invest $41 million in pilot projects for school buses, delivery trucks, airport/seaport equipment, truck stops and commuter locations. Other projects include the installation of fast charging for urban locations and car dealerships, the commission said.

The full list of the CPUC’s approved, withdrawn and held decisions from the Jan. 11 meeting is available here.

January 14, 2018

MISO Breaks down Recent Cold Snap

By Amanda Durish Cook

CARMEL, Ind. — History repeated itself during this month’s extreme cold snap — but only to a degree, MISO told stakeholders last week.

While the high load and generation outages during the arctic blast followed the pattern of 2014’s so-called “polar vortex,” this time the RTO managed to keep prices stable and maintain better reliability.

MISO polar vortex outages cold snap — Aliff | © *RTO Insider*

Tim Aliff, MISO director of system operations, said the RTO dubbed the weather event with a simple nickname.

“The best we could come up with was ‘cold snap,’” Aliff joked at Thursday’s Market Subcommittee meeting. “It doesn’t inspire the terror that ‘bombogenesis’ does, and ‘polar vortex’ was already taken.”

Aliff said that while there were major similarities between the polar vortex and last week’s artic conditions, MISO’s response to the demand and ensuing prices were very different, ensuring the RTO’s conservative operations declaration did not escalate to a maximum generation alert.

The recent low temperatures persisted longer and were on average lower than during the polar vortex, although the coldest day during 2014’s events was about 2 degrees Fahrenheit lower than this month’s. Demand peaked at 104.7 GW on Jan. 2, when low temperatures in the footprint averaged 0 F. During the polar vortex, MISO load hit an all-time winter peak of 109.3 GW on Jan. 6, 2014, when lows averaged minus 2 degrees.

Load topped 100 GW on five days during the recent cold snap, compared with two days during the polar vortex.

“We were on average about 10 degrees colder than in 2014,” Aliff said.

This year’s arctic blast was tempered in part by wind’s 13% contribution to the resource mix, supplying 13.4 GW during the Jan. 2 peak hour. In 2014, wind supplied 6.6 GW during the peak.

“The highest locational marginal price was significantly lower than in 2014,” Aliff said. Real-time LMPs hit $281.23/MWh during the peak, compared with the $1,780.70 record price seen in 2014. During the bitter cold on Jan. 1 and 2, gas prices held to $4.63/MMBtu, jumping to $9 a day later when temperatures increased by 13 degrees. In 2014, gas prices ranged between $5.88 and $7 during three straight days of punishing cold.

Outage levels on the most frigid day remained at levels typical for the month of January, Aliff said, accounting for about 36 GW of unavailable generation during the peak, including more than 19 GW of forced outages. Natural gas forced outages, mostly attributable to fuel transportation and supply issues, accounted for almost 7 GW of unavailable generation, while equipment failure in coal generation accounted for slightly more than 2 GW of forced outages.

“That is kind of expected at this time of year. The utility gas supply is competing with the residential gas supply,” Aliff explained. MISO was better prepared for outages this year and was equipped with a more accurate list of gas-fired generators most likely to be affected by a dwindling gas supply.

“We had a better picture of what the generation limitations would be,” he said.

Ameren’s Jeff Moore asked if greater wind production helped MISO fare better during the cold snap.

“I think that there’s a lot that went into the lower LMPs,” Aliff replied. Other improvements made since the polar vortex, especially gas-electric coordination, helped MISO’s performance, he added.

MISO staff at the meeting promised to provide more outage analysis and data collection on the event.

Stakeholders: More Real-Time Communication

Multiple stakeholders asked MISO to consider issuing more immediate updates to members as it navigates challenging conditions.

ITC Holdings’ Ray Kershaw led the charge, asking that MISO distribute more real-time electronic communication to its members when faced with near-emergency or emergency conditions.

Market Subcommittee Vice Chair Megan Wisersky said there was a marked difference between MISO’s sparse communication and PJM’s frequent email updates to its members on the state of its system during the cold snap. “It seemed like there was a little bit of an information gap between the two approaches,” she said.

“It’d be nice to know what the capacity breakdown is,” said Customized Energy Solutions’ David Sapper.

Indiana Utility Regulatory Commission staffer Dave Johnston pointed out that, sometimes, “no news is good news.” He noted that MISO does alert state regulators when reliability issues arise. “But, of course, I’m not a market participant, and I’m not watching prices,” Johnston said.

MISO Senior Director of Systemwide Operations Rob Benbow said the RTO would consider the request and determine what information it could release in real time. “We understand the importance of good communication,” he said.

“Good markets are run with better information,” Wiskersky said.

November Sees Boost in Load, Prices, Wind

MISO released a November market report showing that lower temperatures that month boosted average load to 71.6 GW, up 3.6 GW from a year earlier, while the monthly peak jumped by 2.5 GW to 84 GW. Real-time and day-ahead energy prices both averaged about $27.30/MWh, 10% higher than last November. MISO reported an all-time wind record of 14.6 GW on Nov. 21, only to be exceeded by a new high of 14.7 GW on Dec. 5.

January 14, 2018

MISO, PJM Ponder Interregional Study

By Amanda Durish Cook

MISO and PJM will decide this spring whether to take another shot at a two-year coordinated system plan, which could result in the RTOs’ first large-scale interregional project.

The grid operators’ Joint RTO Planning Committee will make a decision by May 18 after discussing the issue at a March 30 meeting of the Interregional Planning Stakeholder Advisory Committee.

MISO PJM coordinated system plan — | © *RTO Insider*

MISO and PJM staff last year already exchanged information on regional issues, market-to-market congestion, interconnection requests and newly approved projects near the RTOs’ seam. Those details should help the joint planning committee — comprising MISO and PJM planning staff — decide whether to pursue the study, MISO interregional adviser Adam Solomon said during a Jan. 12 IPSAC conference call.

The RTOs are calling on stakeholders to email a list of seams issues by Feb. 28 for the March IPSAC meeting. According to their joint operating agreement, the two grid operators then have 45 days to announce a decision on pursuing a plan.

The RTOs’ last coordinated system plan concluded in the fall without producing a viable interregional market efficiency project. One serious contender, a proposed 30-mile, 138-kV line near the Indiana-Illinois border, ultimately failed the joint 5% generation-to-load-distribution factor test, which requires each RTO to show that at least one of its generators has at least a 5% impact on the affected flowgate. (See MISO, PJM Reverse Support for Lone Interregional Tx Project.) Interregional market efficiency projects also must meet a 100-kV minimum voltage threshold and a 1.25-to-1 benefit-to-cost ratio based on each RTO’s expected share of the project’s total benefits.

Staff vowed to collaborate on ways to improve the coordinated system plan process after the study was concluded.

At EUCI’s Transmission Expansion in the Midwest conference in December, several stakeholders and panelists said that an effective wind transmission network in the Midwest will eventually require large-scale interregional projects. (See EUCI Panelists: Midwest Tx Plans Must Address Wind, Seams.)

Regardless of the outcome of the coordinated plan, the proposal window for interregional market efficiency projects — required under FERC Order 1000 — opens in November 2018. Stakeholders have until February 2019 to submit project suggestions.

January 12, 2018

ISO-NE Seeks Lower Cutoff for Market Power Reviews

By Michael Kuser

Bidders in ISO-NE’s capacity auctions would face a lower price threshold for triggering market power reviews under a Tariff revision filed by the RTO on Monday.

ISO-NE and the New England Power Pool Participants Committee filed with FERC to decrease the dynamic delist bid threshold (DDBT) in the RTO’s Forward Capacity Market from $5.50/kW-month (set in 2014) to $4.30/kW-month, starting with Forward Capacity Auction 13, slated for February 2019 (ER18-620). The DDBT is an administrative threshold established by the Internal Market Monitor for use in determining which capacity market bids from existing resources must be reviewed for the potential exercise of seller-side market power in the FCM.

ISO market power reviews FCM — | *ISO-NE*

The change reflects the Monitor’s estimation of the likely marginal bid in the auction. ISO-NE said changes in supply-and-demand dynamics since 2014 warrant the decrease in the DDBT. Four years ago, the Monitor projected a capacity shortage of more than 1,600 MW, but since then, existing capacity has increased each year while the installed capacity requirement has consistently declined. For next month’s FCA 12, the Monitor projects a capacity surplus of about 1,250 MW.

If the DDBT is set appropriately, bids below the threshold will be considered “infra-marginal” — that is, priced below the auction clearing price and therefore unable to exercise market power.

ISO-NE FCM market power reviews — | *ISO-NE*

The Monitor aims to set the DDBT slightly below the likely competitive price from the marginal resource in the FCA to minimize the likelihood of an uncompetitive bid setting the clearing price. If the DDBT is set too high and the auction clears below the threshold, all remaining delist bids enter the auction without having been reviewed for the potential exercise of market power.

In its testimony in the filing, the Monitor explained the adverse consequences of setting the DDBT too high.

“Since the ISO makes known … the amount of remaining supply at the start of each auction round, suppliers with market power within the dynamic range of the auction may be able to profitably increase the auction clearing price to benefit their supply portfolio,” the Monitor wrote. “Furthermore, the impact of an uncompetitive increase in the auction clearing price is not localized to the individual supplier that exercises market power; the clearing price is artificially inflated for the entire capacity zone or the entire system.”

But the Monitor said there are no corresponding adverse consequences for the auction if the DDBT is set well below the price of the marginal bid.

“While doing so may result in more suppliers carrying the administrative burden of submitting delist bids for IMM review prior to the auction … this burden is not unreasonable when compared with the significant risk to the competitiveness of the auction from setting the DDBT too high,” it said.

January 12, 2018

MISO RASC Briefs: Little Change to Capacity Forecasts

By Amanda Durish Cook

CARMEL, Ind. — MISO’s next capacity auction will likely rely on megawatt values and limits similar to those underpinning last year’s auction, the RTO said Wednesday.

For the 2018/19 Planning Resource Auction scheduled for early April, MISO is planning for a systemwide coincident peak load of nearly 122 GW ― a 42-MW decrease ― and a planning reserve margin requirement of 135 GW, which is 177 MW higher, Tim Bachus, MISO capacity market administration analyst, said during a Jan. 10 Resource Adequacy Subcommittee meeting.

The RTO also forecasts a zonal coincident peak of 126 GW and predicts that its 10 zones combined will need 152 GW to satisfy local resource requirements.

“These numbers aren’t final; we do accept updates to forecasts through January,” Bachus said.

2018/19 Transfer Limit

The RTO expects to make no changes to transfer flow limits between MISO South and Midwest for the 2018/19 planning year after FERC recently endorsed its methodology for calculating those constraints.

Manager of Resource Adequacy John Harmon said a feasibility analysis concluded that no adjustment is needed for this year’s regional directional transfer limits, leaving the preliminary South-to-Midwest limit at 1,500 MW (accounting for 1,000 MW of firm transmission reservation offsets) and the Midwest-to-South limit at 3,000 MW (with no firm reservations to reduce the limit).

In November, FERC denied a rehearing of the process for calculating subregional limits request by a coalition of MISO transmission customers that contended the limits were too conservative. (See FERC Upholds MISO Transfer Limit Policy.)

MISO calculates transfer limits between its Midwest and South regions by deducting firm reservations from 2,500 MW of available capacity flowing from South to Midwest and 3,000 MW estimated to be available in the opposite direction. The initial limits were determined in a settlement with SPP that became effective in early 2016.

Harmon said the RTO will release final megawatt values for the two-way limit in February.

2018 OMS-MISO Survey

MISO is also preparing its annual resource adequacy survey with the Organization of MISO States and moving ahead with a new calculation for estimating the volume of future new resources.

Ryan Westphal, MISO resource adequacy coordinator, said the new resource counting methods for the 2018 survey enjoy general stakeholder support.

In accounting for future resources, MISO will tally projects not yet in the three-part definitive planning phase (DPP) of its interconnection queue — and those that have entered the DPP’s first phase — at a 10% completion rate. Conventional and intermittent resources in phase two of the DPP will be counted at 50% and 25%, respectively, increasing to 75% and 50% in phase 3.

Projects still negotiating a generator interconnection agreement will be tallied at 90% completion, while those with signed agreements will be counted as new generation in the survey’s weighted averages. The percentages represent a further refinement of the likelihood values introduced by MISO in November. (See MISO Still Tweaking OMS Survey Assumptions.)

In response to stakeholder questions about the relatively lower completion figures for intermittent resources, Westphal said the RTO has observed that conventional resources have higher rates of completion, “so we’re reflecting that here in the numbers.”

MISO will also apply its capacity credit percentages to the projections, with wind receiving a 15.6% credit, solar receiving 50% and all other resources receiving full capacity credit.