Page 1161 – RTO Insider

December 8, 2019

Cold, Security Lead MRO Risk Assessment

By Holden Mann

ST. PAUL, Minn. — Increasing incidents of extreme winter weather, along with threats to physical and cybersecurity, are the most pressing items identified in Midwest Reliability Organization’s draft Regional Risk Assessment, presented at the organization’s Annual Member and Board of Directors Meeting last week.

The report follows NERC’s 2019 ERO Reliability Risk Priorities Report, which analyzed the risks facing electric utilities on a national scale and grouped them into four major categories: grid transformation; extreme natural events, including both weather and geomagnetic disturbances (GMD); security risks; and critical infrastructure interdependencies. (See NERC Board of Trustees Briefs: Nov. 5, 2019.) MRO aimed to determine which areas had a higher or lower potential burden for operators in the region.

Resource Mix Heightens Weather Impact

Given MRO’s footprint, which extends from Oklahoma to as far north as Saskatchewan and Manitoba, it is not surprising that winter weather, along with GMD events, are a higher priority than for regions in warmer regions. However, officials said winter challenges have become more pronounced over the last 10 years, with extreme events such as the 2011 polar vortex straining grid capacity even in the southern areas of the region.

MRO Risk Assessment — John Seidel, MRO | © *ERO Insider*

“Winter peak demand is approaching or exceeding summer peak during severe cold spells. For example, on [the] Jan. 17, 2018, [cold-weather] event in the southern portion of the Midwest, all five entities involved exceeded their winter forecast by about 5 to 13%,” said John Seidel, MRO’s principal technical adviser. “It’s pretty interesting what winter … can cause, mainly due to the electric heating that occurs during the severe cold.” The 2018 event led Gen Operators Cool to Winter Preparedness Standard.)

MRO’s changing resource mix can also complicate the cold-weather issues, as conventional synchronous generation is replaced by renewable options such as wind, with output that is harder to predict. Seidel cited the gap between MISO’s predicted and actual wind energy production during the Jan. 30, 2019, cold-weather event as an example of this concern, adding that the problem was exacerbated when the extreme cold led turbines to hit their cutoff temperatures just as the need for their energy was most acute. (See Extreme Weather Tops NERC Winter Outlook.)

Evolving Threats, Lagging Response

Rapid change is also a hallmark of the technology landscape, and the need to determine how to integrate new technology tools while maintaining the reliability of the grid continues to be a source of headaches for security professionals.

Steen Fjalstad, security and mitigation principal at MRO, observed that 2019 saw no reported cyber or physical security incidents in the bulk power system that caused a loss of load, according to NERC’s Electricity Information Sharing and Analysis Center (E-ISAC). Along with this good news, however, there is also no shortage of reminders about the dangers that can arise from deploying new technology without adequate preparation.

“There have been recent breaches, not necessarily in our sector … due to cloud storage, and … identifying if we have the same risks and liabilities is very important,” Fjalstad said. “It’s kind of a gray area still in terms of components: A lot of the controls that might be in the cloud area [are] under contract, and the legalese … of what’s going into these contracts … is really a very valuable opportunity for us to delve further and reduce this risk.”

Risks highlighted in the cyber and physical security section of the report include a lack of adequately trained security staff and internal cultures focused on compliance rather than proactive threat detection. This feeds into other common problems such as incomplete asset inventory, with Fjalstad observing that “if you don’t know what you have to secure, then it is very hard to make sure that you’re mitigating all the risks.” Third-party equipment suppliers must also be considered a potential security backdoor, with vendors held to as high a standard as a utility’s own staff.

Unmanned aerial vehicles pose a unique challenge, as the intersection between physical and cybersecurity that is not well addressed by current law. (See Feds Late to Act on Drone Threat, DHS Official Says.) Utilities that believe drones are monitoring their facilities have no recourse to law enforcement unless their airspace is violated, and even then, tracking down the operator of the vehicle is easier said than done. Fjalstad said operators must find other ways to protect their assets from unwanted surveillance.

Infrastructure Intersections

While environmental and security concerns dominated the presentation, other topics were suggested for future monitoring. One example is the risk that the growth of electric vehicles and charging stations could exacerbate the weather and resource mix issues. Operators also identified copper theft and vandalism as ongoing dangers — not just to their own equipment, but also among the telecommunication companies on which they rely for remote monitoring.

December 6, 2019

ERCOT’s Reserve Margin Climbs to 10.6% in 2020

By Tom Kleckner

ERCOT will likely welcome back double-digit reserve margins next year and well into the decade, according to the grid operator’s latest capacity, demand and reserves (CDR) report.

While they won’t provide relief from Texas’ blistering summers, the additional reserves will give ERCOT a little more room to work with than it did in surviving 2019’s record demand with a 8.6% margin — up from an initial historic low of 7.4%.

Released Thursday, ERCOT’s newest CDR indicates its planning reserve margin will hit 10.6% in 2020 and 18.2% in 2021. The margin will shrink again after that, reaching a projected 12.9% in 2024. The grid operator has a target planning reserve margin of 13.75%.

“Yes, the reserve margin’s improving, and the [later] years seem to be significantly better,” said Dan Woodfin, ERCOT’s senior director of system operations. “While the reserve margin seems higher in 2020, we could still see some operating days with tight conditions. We’re prepared for that, just like we were last year.”

ERCOT shattered its all-time system peak in August, hitting 74.8 GW and breaking the mark set in 2018 by more than 1 GW. While its resources met peak demand, the grid operator ran into tight conditions during the early afternoon when West Texas wind energy dropped off. It was twice forced to call energy emergency alerts to ease the scarcity. (See “ERCOT CEO Briefs Commission on Summer Performance,” Texas PUC Briefs: Aug. 29, 2019.)

Staff are projecting a peak of more than 76.7 GW in 2020, but they also expect an additional 7.6 GW in new capacity for summer 2020, based on preliminary data from generation owners. Most of those resources are renewable or smaller gas-fired peakers.

ERCOT has approved 1,058 MW of installed capacity for commercial operations since the last CDR was released in May. More than 4,650 MW of installed capacity has become eligible for inclusion in the CDR after completing necessary agreements and permits.

Two canceled gas plants with 1,227 MW of capacity were removed from the CDR, and eight solar projects with a 1,056-MW capacity contribution were delayed until 2021, accounting for the reserve margin’s leap to 18.2% that year.

Wind and solar energy will continue to increase their shares of ERCOT’s fuel mix. Solar’s summer capacity is forecast to account for 9.7% of the fuel mix by 2022, while coal will drop to 15.6%. Wind energy is projected to reach 10.2% of the summer mix in 2024.

ERCOT has changed the way it calculates wind and solar capacity for the CDR, switching to a capacity-weighted average instead of a simple average of historical contributions. Staff also split its non-coastal wind region into “Panhandle” and “other” wind regions.

December 6, 2019

MISO RASC Briefs: Dec. 3, 2019

CARMEL, Ind. — MISO says it will look to make improvements to the capacity testing process after sifting through results from its generators and discovering errors.

The RTO received more than 1,800 submittals from approximately 140 generation operators by the Oct. 31 deadline for its generation verification test capacity (GVTC) process. It requires generation owners to test the capability of their units annually to determine maximum capacity to help calculate MISO’s resource adequacy.

At the Resource Adequacy Subcommittee’s meeting Tuesday, MISO Manager of Capacity Market Administration Eric Thoms said the RTO would reach out to about 40 generation owners this month to discuss correcting possible errors in the submittals in time for the 2020/21 Planning Resource Auction.

Some stakeholders asked how MISO had determined errors had been made in the first place.

“It wouldn’t be obvious to me that we’ve even made errors,” MidAmerican Energy’s Greg Schaefer said.

Thoms said MISO performed a quality and validation review at the behest of its Independent Market Monitor. He said the likely errors are centered on temperature corrections for cooling water and air temperature, generator polarity data, and “misinterpretations” of some of the fields on the survey.

RASC liaison Patrick Brown said that over the next year, the RTO will investigate potential GVTC process improvements to “increase the quality of data being submitted and lesson the burden of MISO’s review.”

“We’re not trying to eat the elephant all at once,” Brown said of working in improvements.

Stakeholders Remain Critical of Capacity Deliverability Remedy

MISO remains committed to tightening capacity deliverability requirements using the same method it proposed in October, but some stakeholders are voicing concerns over reduced capacity credits issued to wind resources.

The RTO has said it will use an intermittent resource’s transmission service request value to set its maximum historical output for the average capacity factor, which will likely reduce a resource’s unforced capacity values and stands to reduce capacity credits. It would only apply the solution to its intermittent resources, citing increasing wind curtailments in the footprint. (See “MISO Pushes Back Deliverability Requirements,” MISO RASC Briefs: Oct. 9, 2019.)

MISO’s Darrin Landstrom said the move will “improve the expectation of generators required to deliver capacity to load.”

“Under the current process, an intermittent resource that is not fully deliverable could acquire capacity credit with the same equality as an intermittent resource that is fully deliverable. Revising capacity accreditation calculations to factor in studied levels of deliverability may incentivize intermittent resources to obtain more deliverability if necessary and/or improve the confidence that capacity is being accredited in a method that more closely aligns with deliverability levels,” MISO said.

The Monitor has argued for more than a year that the RTO doesn’t properly account for capacity deliverability because its loss-of-load expectation (LOLE) study assumes that all capacity resources are fully deliverable on an installed capacity (ICAP) basis. However, it also allows resources to demonstrate deliverability only up to the unforced capacity (UCAP) levels, which tend to be about 5 to 10% below full ICAP levels. The Monitor thinks it should assess deliverability for all capacity resources based on full ICAP.

Madison Gas and Electric’s Megan Wisersky said MISO’s proposal may be expensive in that more capacity resources or more transmission capacity will be required to meet peak loads.

“Are we merely trying to jack up the transmission we’re building, increasing costs to our customers?” she asked.

Landstrom said the proposal might leave some of the wind fleet’s effective load carrying capability (ELCC) unassigned. He said the unassigned ELCC might be applied to resources that have secured full deliverability through transmission service. However, MISO may run into problems if it gives a resource more capacity credit than the reliability, including the issue of “how to slice and divide the ELCC pie.” MISO annually calculates a system-level ELCC, which is currently 15.7% of the MISO wind fleet’s registered maximum capacity.

IMM Michael Chiasson also pointed out that there are few benefits to purchasing transmission service for 100% deliverability. He said it’s possible to achieve zonal resource credit requirements “well under” full deliverability.

“We have some homework to do,” Brown said before closing the discussion. He said MISO may need to delay release of its design concept until February and promised another presentation in January. “In my mind, we have a lot of open questions, and I’ll take that, on behalf of MISO staff.”

— Amanda Durish Cook

December 5, 2019February 19, 2025

DC Circuit to Reconsider FERC Tolling Orders

By Rich Heidorn Jr.

The D.C. Circuit Court of Appeals indicated Thursday it will reconsider its precedent that allows FERC to issue “tolling” orders to indefinitely delay action on requests for rehearing.

The court vacated an August 2019 ruling by a three-judge D.C. Circuit panel that rejected challenges to FERC’s approval of Williams’ Atlantic Sunrise natural gas pipeline project, scheduling an en banc oral argument for March 31 (17-1098).

The project, an expansion of the existing Transco pipeline between northern Pennsylvania and South Carolina, began service late last year after winning FERC approval in February 2017 (CP15-138). (See FERC OKs Pipelines, Delegation Order Before Losing Quorum.)

The three-judge panel unanimously rejected the challenges by environmental groups and landowners, but Judge Patricia Millett wrote a concurring opinion sharply critical of FERC, saying it had “transformed this court’s decisions upholding its tolling orders into a bureaucratic purgatory that only Dante could love.”

Millett’s concurrence took no issue with her colleagues’ rejection of complaints that FERC failed to consider the pipeline’s downstream greenhouse gas emissions or to substantiate market need for the project.

President Barack Obama nominated Judge Patricia Millett (right) to the D.C. Circuit Court of Appeals in 2013, along with (from left) Robert L. Wilkins and Cornelia “Nina” Pillard. | The White House

But she expressed sympathy for pipeline opponents’ complaint that FERC denied them due process by allowing construction to begin before the certificate of public convenience and necessity could be challenged in court.

Parties seeking judicial review of such a certificate must first seek rehearing from the commission. Because the Natural Gas Act says rehearing requests are deemed denied if the commission fails to act within 30 days, FERC regularly issues tolling orders granting rehearing “for the limited purpose of further consideration.” It also uses tolling orders to circumvent the 30-day deadline on rehearings under the Federal Power Act.

The commission issued a tolling order in response to a request for rehearing and stay of the Atlantic Sunrise certificate order, then took no action on the stay motions for more than five months before denying them.

Pipeline opponents also sought rehearing of the commission’s Sept. 15, 2017, order granting Williams permission to begin construction. The company began construction that day.

In December 2017, more than nine months after the first rehearing request and three months after construction began, FERC rejected the appeals, making its decisions finally subject to court review.

Pennsylvania portion of Williams’ Atlantic Sunrise natural gas pipeline project, which began service late last year after winning FERC approval in February 2017 | Williams

Millett acknowledged that the D.C. Circuit has previously ruled that the commission’s tolling orders qualify under the NGA as an action upon the rehearing request, effectively stopping the 30-day clock.

“But the commission has twisted our precedent into a Kafkaesque regime,” she wrote. “Under it, the commission can keep homeowners in seemingly endless administrative limbo while energy companies plow ahead, seizing land and constructing the very pipeline that the procedurally handcuffed homeowners seek to stop. The commission does so by casting aside the time limit on rehearing that Congress ordered — treating its decision as final-enough for the pipeline companies to go forward with their construction plans, but not final for the injured landowners to obtain judicial review. This case starkly illustrates why that is not right.”

She noted that the court’s acceptance of tolling orders started in a case that involved disputes over money, not property. “Because disputes over monetary payments can be fixed later, the consequences of commission delay were temporary and remediable,” she said. “But allowing the commission to take its time while private property is being destroyed is another thing altogether.”

Millett said the court could require more timely action by the commission on rehearing requests, or FERC could decline to issue construction orders until it resolves certificate rehearing requests on the merits.

“If that is too administratively burdensome, then the commission could try the easiest path of all: take absolutely no action on the rehearing application. That would have the effect of denying the request as a matter of law. And that approach would have opened the courthouse doors to the homeowners … five months before construction started.”

FERC declined to respond to the ruling, saying it doesn’t comment on court proceedings.

ClearView Energy Partners analyst Christi Tezak said FERC’s tolling orders “may be vulnerable to prospective change” but that the court is unlikely to reject the commission’s use of precedent agreements as evidence of the need for new pipelines, although it was part of the homeowners’ appeal.

“Regardless of how this case plays out, we see little risk to the operation of the Atlantic Sunrise project at this time,” Tezak said in a note to clients. “We also would note that neither the FERC’s [National Environmental Policy Act] review nor its contentious policies on downstream greenhouse gas (GHG) emissions appear to be at issue in this en banc review.”

December 5, 2019

West’s RC Transition Earns Plaudits

By Robert Mullin

SALT LAKE CITY — The Western Interconnection’s transition to multiple reliability coordinators ended on a high note Tuesday when SPP took over the remaining portions of Peak Reliability’s territory in the Mountain States region.

Western Electricity Coordinating Council CEO Melanie Frye took note of the happy conclusion to the 18-month process the next day with a touch of regret, even as others noted that the challenges were not all in the past. “Going into this, there was a lot of concern and a lot of angst as to how this would all turn out, but once again the industry has come together and proven what we can do,” Frye said during a WECC Board of Directors meeting Wednesday. “I’m really proud to acknowledge that — and a little saddened with Peak being dissolved. They’ve really been great for the interconnection.”

Under mounting financial pressure as more of its customers signaled their intentions to defect to CAISO’s lower-cost RC service (now called RC West), Peak announced in July 2018 that it would shut its doors by the end of this year.

The announcement — coming about a month after Frye assumed the helm at WECC — set off alarm bells for a region accustomed to being served by one major RC, initiating a scramble by WECC and NERC to ensure a smooth transfer of RC responsibility to CAISO, SPP and BC Hydro. But by September, WECC officials were assuring their board members that they and other industry participants had the situation in hand. (See No ‘Hiccups’ for West’s RC Transition.)

Frye lauded the “tremendous amount of work” done by the new RCs, Alberta Electric System Operator’s existing RC and the “engaged and focused” industry participants who ensured “all of the tools were developed.”

She also “selfishly” called out the key contribution by WECC senior engineer Tim Reynolds, team lead for each RC’s certification.

“It’s been a tremendous lift this year, [and] Tim has performed admirably. I know [he worked] lots of weekends and nights — and I’ve seen the texts and the emails, so I think we really should be proud of what has been accomplished in the interconnection,” Frye said.

She also pointed to Peak’s own role in the transition: “My hat’s off to Peak Reliability, [CEO] Marie Jordan and her entire team. They performed until the very last moment that their services were required.”

Tightening the Seams

Branden Sudduth, WECC vice president of reliability planning and performance analysis, said he had been reflecting on where the organization was a year ago, “anticipating the amount of work that was going to be needed in 2019 to make this a successful transition.”

“Between the utilities, the RC transition coordination group, WECC, NERC and other entities — the new RCs [and] Peak — it really was a herculean effort that they were able to accomplish this this year. They did run into several bumps along the way, but the industry really kind of [grabbed] the bull by the horns and they overcame,” he said.

Sudduth cautioned that WECC’s work with the RCs wasn’t done, but instead entering a new phase.

“This isn’t it. We can’t just say, ‘Alright, perfect, we’re done. The transition’s complete.’ We need to make sure that these RCs are performing effectively,” he said.

Sudduth outlined WECC’s “next steps,” which include ramping up reliability and security oversight activities — the auditing that will verify the new RCs are following NERC standards. He also emphasized WECC’s role in ensuring that the new RCs reach across newly formed boundaries to work with each other.

“We recognize the importance of ensuring that any seams issues between the RCs are addressed, and this coordination and continued communication between the RCs needs to happen,” he said.

Sudduth noted that while WECC will hold its final RC transition webinar next week, “that doesn’t mean we’re not going to receive regular updates on the new RCs. It just means that that will now continue to happen at [WECC’s] Operating Committee meetings,” held quarterly.

The ‘Fragile’ West

WECC Member Advisory Committee member Fred Heutte, of the Northwest Energy Coalition, added his praise during the board meeting’s public comment period.

“I want to thank and commend WECC for stepping up and doing what really needed to happen to make sure that things did not get sideways, did not fall behind,” Heutte said. “The really strong willingness by all of the new RC coordination organizations to make this work was not going to be enough by itself. There needed to be a cohesive approach and enough pushing to make sure that things got done, and WECC has really succeeded in my view.”

But Heutte expressed reservations about the outcome of fractured RC services in the West, questioning whether the new arrangement will stand the “test of time.”

“I wish everybody the best of luck going forward. As I’ve said before, in the future, we may want to reconsider having multiple RCs in the West. There are some distinctive differences in topology here that make the situation more … fragile, perhaps, than [in] the East, but I know that we’ll pursue this current arrangement as best we can.”

December 5, 2019January 21, 2024

MISO OK’d to Require Site Control in Queue

By Amanda Durish Cook

MISO received FERC approval this week to require its generation developers to secure land for projects earlier in the interconnection queue over some protests from renewable developers.

The RTO will now require interconnection customers to demonstrate 100% site control 90 days before the proposed projects enter the first phase of the three-phase definitive planning phase (DPP) of the interconnection queue for study. It also scrapped the previous practice of accepting a $100,000 cash deposit in lieu of demonstrating site control.

FERC said the stricter process was a reasonable way for MISO to better manage its brimming interconnection queue. It also accepted MISO’s transition plan to grandfather interconnection requests submitted in prior DPP cycles from the changes.

“More stringent site control requirements, as proposed by MISO, may help to reduce the number of speculative, duplicative, and non-ready projects entering DPP Phase I,” the commission said Tuesday (ER20-41).

As of last month, MISO’s queue totaled 569 projects at nearly 89 GW of generating capacity. The RTO reported that more than 730 projects totaling almost 120 GW have entered the queue in the last three DPP cycles.

“Much of this capacity will not come to fruition and is the result of certain interconnection customers submitting multiple interconnection requests into DPP Phase I to find the most advantageous point of interconnection, a strategy that has resulted in numerous withdrawals,” FERC said. “We find persuasive MISO’s argument that the ability of interconnection customers to enter the queue without financial risk contributes to the submission of speculative projects, which negatively impacts the entire queue by causing delays, skewing study results, shifting costs to other customers and inflating milestone payments when these projects are withdrawn.”

The filing FERC accepted was MISO’s second attempt at more rigorous obligations on project owners. The RTO first proposed higher milestone fees in addition to the firmer site control requirements. However, it dropped its plan to change the first, $4,000/MW milestone payment to a variable cost representing 10% of the average network upgrade cost from the last three DPP cycles. FERC said the change would have resulted in accounting uncertainty and averages applied unfairly across the entire footprint. (See MISO Zeroes in on Queue Overhaul Filing.)

MISO will now allow different fuel types and multiple generation projects to share the same site, abandoning the first proposal’s requirement that project owners show exclusive use of land. As it proposed in the first filing, the new rules add a provision that 50% of milestone fees are considered at risk of not being refunded if they’re needed to help defray network upgrade costs should a project withdraw.

A group of renewable generation developers, Invenergy and the Solar Energy Industries Association had disputed MISO’s 50% milestone forfeiture, arguing that it didn’t show that the current practice of fully refunding the first milestone fee caused delay in queue studies. They also argued that withdrawing after paying the first milestone fee is natural, as MISO delivers the estimated costs of necessary network upgrades only after the milestone payment deadline has passed. Withdrawal after the queue’s first decision point is usually a “reasonable response” to expensive upgrade estimates, they said, and not the hallmark of a speculative project.

But FERC pointed out that MISO will now require a screening study more than two weeks before the DPP begins, thereby informing customers of potential thermal and voltage constraints. The new study “should provide interconnection customers with an awareness of what network upgrades may be necessary to accommodate the interconnection of their projects,” the commission said.

FERC also denied EDF Renewables’ request that it compel MISO to annually detail in reports how the 50% milestone forfeiture has a “meaningful impact on keeping speculative projects from entering the queue.”

EDF had also sought a defined endpoint for MISO’s harm tests on withdrawing projects and a deadline for it to return milestone payments to interconnection customers if no impact is found on other projects. The commission said it wouldn’t hold the RTO to deadlines on either, noting that project withdrawals can create ripple effects that impact other projects, even as they advance to later stages of the queue.

FERC urged MISO to be more transparent with customers over how it “will calculate harms caused by withdrawing interconnection customers and how it will distribute forfeited milestone payments to offset those harms,” but it did not direct the RTO to make an additional compliance filing.

December 5, 2019

MISO Market Subcommittee Briefs: Dec. 3, 2019

CARMEL, Ind. — MISO is moving ahead with a proposal to bring solar generation into market dispatch, reusing many of the rules from its 2011 change that brought dispatchable wind generation into the markets.

At the Market Subcommittee meeting Tuesday, Executive Director of Market Operations Shawn McFarlane said MISO will file the Tariff changes later this month.

The proposal would require solar plants to register under the dispatchable intermittent resources category, the same category MISO requires of its wind generation. Officials said the change is driven by the rapid increase of solar installation in the RTO’s footprint. (See Anticipating Boom, MISO Extending Dispatch to Solar.)

Some stakeholders last month asked for grandfathered provisions from the change for existing solar generation, but MISO Manager of Resource Retirement Kun Zhu said no grandfather provisions were laid out in the RTO’s wind dispatch rules, nor SPP’s similar rules for solar dispatch.

Restoration Energy Design Nears Completion

MISO said its stakeholders are supportive of its plan to price energy that reactivates islanded areas of the grid following a blackout.

The RTO plans to make a Tariff a filing to incorporate the new pricing structure in either March or April.

MISO’s proposal dictates that compensation for restoration energy would rely on last-submitted offers before the blackout as a starting point for pricing, resulting in unique costs based on resource. The RTO would allow for the recovery of start-up costs, emergency purchases and resource-specific energy costs. It would also include recovery for any unusual costs incurred during operation, provided they can be verified by the Independent Market Monitor. It would also accept after-the-fact updates of offers. (See “Restoration Energy Pricing in the Works,” MISO Market Subcommittee Briefs: Oct. 10, 2019.)

Costs of restoration energy — including both resource costs and emergency energy purchases — would be allocated on an hourly load-ratio share to re-energized load in an islanded area. The restoration events would be considered finished when MISO’s day-ahead market again takes over economic dispatch.

Michael Chiasson, vice president of Potomac Economics, MISO’s Monitor, said the cost determination might not be neat and orderly, as islanded areas might shrink, grow or meld into one another as the restoration develops.

Chris Delk, MISO manager of market settlements, said the RTO would limit non-typical start-up costs, with a cap proposed at 50% of a unit’s cold start-up costs, the most expensive category. He said MISO and the Monitor were concerned about how high supplementary start-up costs could go absent a cap. The atypical costs might include the costs of renting hotel rooms for employees, travel or transportation, he said. Recovery of anything beyond the 50% cap on additional start-up costs would require a filing with FERC.

“We want it to go before FERC to get it on the record and get them defending it publicly,” Delk explained to stakeholders.

New MISO Market Protections Inevitable

MISO will seek FERC approval next month for authority to increase collateral requirements and suspend trading when a market participant exhibits undue risk to its markets.

The RTO will request an effective date before April for the changes to its credit policy.

MISO’s proposed Tariff language would allow it to act when it perceives evidence of default, manipulation or unreasonable risk to the markets. The new rules would also allow it to reject applications from new market participants and former market participants that have an uncured financial default and attempt to rejoin the RTO under a different name. Finally, MISO would ask prospective and current market participants for more specifics on its annual certification form. It would inquire about any past defaults, bankruptcies, dissolutions, mergers or acquisitions, and any investigations.

The broader market protections edits are an expansion on stepped-up requirements in MISO’s financial transmission rights market. The RTO on Nov. 22 received FERC permission to apply higher collateral requirements (ER20-73). (See MISO Looks Beyond FTRs for Market Protections.)

Customized Energy Solutions’ David Sapper asked if MISO will rely only on publicly available information to make decisions about risk to the market.

“Probably not,” said Brian Brown, principal credit analyst for the RTO. “If there’s risk to the market, we don’t want to put our head in the sand and ignore it.”

Brown also pointed out that the Tariff already requires market participants to notify the RTO of confidential investigations, so it should already be privy to certain nonpublic information.

— Amanda Durish Cook

December 5, 2019

ISO-NE Projects Adequate Resources for Winter

ISO-NE reported Wednesday that the region has sufficient power generation resources to meet the forecasted peak demand this winter but warned that during periods of extreme cold weather, “natural gas pipeline constraints can limit the availability of fuel for natural gas-fired power plants.”

Based on regular surveys on generators’ fuel supplies, the RTO estimates that more than 4,500 MW of natural gas-fired generating capacity is at risk of not being able to get fuel when needed.

Storms and extreme cold can also impact oil and LNG availability and deliveries, the RTO said.

This is the first winter season since the 2,028-MW Pilgrim nuclear plant retired in May. The plant’s capacity is being replaced by several new resources, including three dual-fuel plants, as well as solar and wind resources.

By the Numbers

The RTO forecasts a peak demand of 20,476 MW, assuming normal winter lows (7 degrees Fahrenheit), and 21,173 MW under extreme winter weather (2 F).

Resources with a Forward Capacity Market capacity supply obligation represent 32,747 MW (94%) of the region’s total resources.

Last winter’s peak demand of 20,773 MW occurred Jan. 21, 2019, during the hour ending 6 p.m. The all-time winter peak in New England was 22,818 MW on Jan. 15, 2004.

ISO-NE is developing an Energy Security Improvements proposal, with stakeholder discussions on LNG supplies, market mitigation and a second demand curve. (See NEPOOL Markets Committee Briefs: Nov. 12-13, 2019.) The RTO has until April 15, 2020, to file a long-term fuel security mechanism under FERC’s second extension since its original order last July (EL18-182).

– Michael Kuser

December 5, 2019

Dominion Cancels RFP for New Peaker Plant

Dominion Energy called off its solicitation for a 1,500-MW peaking plant Wednesday, just days after LS Power asked Virginia officials to intervene in the process.

The request for proposals, issued last month, was meant to help close a projected 4,044-MW capacity gap identified in the company’s integrated resource plan. But LS Power argued that such generation already existed in Dominion’s footprint and questioned the competitive process described in the RFP. (See Dominion Challenged on RFP for New Peaker Plant.)

Jeremy Slayton, a Dominion spokesperson, did not give a reason for the reversal in an email sent to RTO Insider Wednesday afternoon.

“The company will continue to monitor market conditions to determine if an RFP for peaking generation will be reissued in the future,” he said.

Nathan Hanson, senior vice president at LS Power, had urged William F. Stephens, the State Corporation Commission’s director of public utility regulation, and state Attorney General Mark Herring “to suspend the solicitation as it is currently structured, review the requirements and implement changes that will make the process competitive, for the benefit of Virginia consumers.”

Hanson sent the letter on behalf an LS Power limited partnership, which began operation of two 170-MW natural gas peaking plants at the Doswell Energy Center in Hanover County, Va., in May 2018.

Marji Philips, LS Power’s vice president of wholesale market policy, said late Wednesday via email that the company “was pleased by Dominion’s recognition that the RFP was ill conceived at this time.”

— Christen Smith

December 5, 2019

PG&E Judge Weighs Insurers’ Settlement

By Rich Heidorn Jr.

Attorneys for Pacific Gas and Electric urged U.S. Bankruptcy Judge Dennis Montali on Wednesday to quickly approve the utility’s proposed $11 billion settlement with insurance companies and hedge funds, warning that claims could rise much higher if it is rejected.

Opponents countered that the settlement would require wildfire victims to sign “one-sided” releases that could leave them far from whole for their losses.

PG&E Bondholders Settlement — Stephen Karotkin | *Weil, Gotshal & Manges*

“No one can challenge the reasonableness of the settlement,” PG&E attorney Stephen Karotkin told Montali during a nearly two-hour hearing, saying it represented a 45% “discount” from more than $20 billion in claims.

Karotkin asked Montali to rule by Friday, calling it a “serious drop-dead date” for the subrogation claimants seeking reimbursement for insurance claim payouts. Swift approval of the deal is essential to the utility’s ability to meet the June 30 deadline for eligibility to participate in an insurance fund for future wildfire claims under Assembly Bill 1054, he said.

“From the debtor’s perspective, we don’t want to take the risk that this [settlement] blows up,” he said.

But Robert Julian, representing the Official Committee of Tort Claimants, said the case could be settled within days if the “one-sided” release was eliminated.

Wildfire victims facing hospital bills or damaged homes will be forced to sign the release to obtain cash “because they’re so desperate. That’s not choice,” he said.

“You’re asking me to violate the ‘bird in hand rule’ and let this $11 billion bird fly away,” Montali responded, saying that if he rejects the deal, “maybe there will be a $20 billion or $25 billion set of claims. … That’s not a good thing for anybody.”

With the proposed release, “this case is not resolving,” Julian responded. “I can’t get lawyers to agree to any plan in this case or mediation … or anything because they can’t [endorse] something they can’t recommend under the law. … You’re forcing this release down our throats.”

Rebecca J. Winthrop, attorney for Adventist Health, whose Feather River Hospital was among 18,700 structures damaged or destroyed by the Camp Fire in November 2018, agreed that the release “is not symmetrical.”

“So, if I want to go against those tree trimmers or against my insurers, I can’t. … That is well beyond what is necessary to protect the insurance carriers,” she said.

Nancy Mitchell, representing Gov. Gavin Newsom, said the governor is concerned that the settlement will leave the utility without enough cash to meet the requirements of AB 1054. She echoed claims the governor’s office made in court filings last month that holders of subrogation claims, some of which also hold equity in PG&E, are using the settlement to improve their holdings. (See Fight Escalates over PG&E Settlement with Insurers.)

“This settlement is about leverage. It is not about a debtor who … is trying to do the right thing,” she said. “This plan is making it impossible for us to evaluate other plans because the debtor is only pursuing one plan.”

Gregory Bray, representing the official Committee of Unsecured Creditors, said the $11 billion settlement is “in the ballpark” but that it should apply also to competing reorganization plans.

In his closing remarks, Karotkin denied that the company was acting in bad faith or taking advantage of wildfire victims, insisting the release provisions challenged by the opponents “are customary and typical.”

“The debtors are not hell-bent on an equity-sponsored plan. What they are hell-bent on is having the best plan, a financeable plan, that is fair to all of the debtors’ economic stakeholders and will get these debtors out of Chapter 11 in a timely basis so they can participate in the wildfire fund.”

Montali ended the hearing with a pledge to make a ruling, “not to defer a ruling,” as some in the case had urged.

“I can’t promise you how soon it will be,” he said. “I’m trying to keep the decisions coming out. I’ll do my best.”

Bloomberg reported Wednesday that PG&E is close to finalizing a $13.5 billion settlement to wildfire victims, half in cash and the rest in stock in the reorganized company. PG&E stock rose 7% on news of the potential deal, closing at $9.47/share after trading as high as $10.75.