Page 1220 – RTO Insider

January 19, 2018

FERC Backs NERC Supply Chain Standards

By Michael Brooks

WASHINGTON — FERC on Thursday proposed to adopt several reliability standards intended to mitigate cybersecurity risks posed by the global supply chain of grid operation tools.

Multiple entities around the world may participate in the development of software or technology used by utilities to manage their reliability duties, exposing them to potential corruption.

In a Notice of Proposed Rulemaking (RM17-13) FERC indicated its intention to approve a NERC critical infrastructure protection standard (CIP-013-1) that would require utilities to consider several cybersecurity issues when procuring these products for their medium- and high-impact systems. These issues include:

disclosure of known vulnerabilities in the products;
security event notifications;
coordination of vendor remote access;
notification when vendor employee remote or onsite access is terminated;
coordinated response to vendor-related cybersecurity incidents; and
verification of integrity and authenticity of all software and patches.

NERC noted that the standard does not “require that every contract with a vendor include provisions for each of the listed items.” Rather, utilities would need to “ensure that these security items are an integrated part of procurement activities, such as a request for proposal or in the contract negotiation process.”

The actual terms and conditions of utilities’ contracts with vendors are outside the scope of the standard, as are the activities of the vendors themselves. “A responsible entity should not be held responsible under the proposed reliability standard for actions (or inactions) of the vendor,” NERC said.

Reliability officials would evaluate and reapprove utilities’ procurement processes every 15 months under the standard.

FERC also proposed to adopt two additions to existing NERC standards, both to support the requirements in CIP-013-1. One (CIP-005-6) would require utilities to develop a method for identifying active remote access sessions by vendors. The other (CIP-10-3) would require utilities to verify the source of all software and patches before installing them.

Broader Scope, Tighter Deadline

NERC developed the standards in response to a FERC directive in July 2016, marking only the third time the commission has taken such initiative. (See FERC Orders NERC to Develop ‘Flexible’ Supply Chain Standard.) The organization submitted the proposed standards last September.

FERC found that NERC had generally satisfied the four objectives it had laid out in its order: software integrity and authenticity; vendor remote access; information system planning; and vendor risk management and procurement controls. The commission had also directed that the standard be flexible, leaving it to utilities to determine the best way to comply.

However, the commission directed NERC to include Electronic Access Control and Monitoring Systems (EACMS) — firewalls, authentication servers, security event monitoring systems and intrusion detection systems, for example — as part of the scope of the standard.

It also instructed NERC to evaluate the risks posed by Physical Access Control Systems (PACS) — such as motion sensors, badge readers and electronic locks — and Protected Cyber Assets (PCAs) — networked printers, file transfer servers and local area network switches — as part of a supply chain cybersecurity study the organization’s Board of Trustees ordered last August.

FERC also proposed to tighten the implementation deadline for the standards, shortening NERC’s proposed 18 months after commission approval to 12.

Commissioners: Good First Step

Commissioner Cheryl LaFleur, who had dissented from FERC’s earlier order, issued a lengthy concurrence to explain her vote. She had called the July 2016 directive too broad and lacking in guidance. She had also said the timeline for developing the standards was too short given the lack of stakeholder input.

At the commission’s open meeting Thursday, LaFleur said she still had some of those concerns, calling the standards “quite general.” But, she said, “I agree that they are an improvement over the status quo.

“I do not believe that remanding these standards or the larger supply chain issue to the NERC standards process would be a prudent step at this point,” she said. “Rather, I believe the better course of action at this time is to move forward with these standards and … improve them over time as needed.”

Her colleagues had similar sentiments.

“While the standard is not a panacea, it is an important step forward to tackle a tough problem,” Commissioner Neil Chatterjee said. “It will be particularly important to revisit the standard after several years of experience to see what is working and what aspects could be improved. But again, today’s order is a good step in the right direction.”

Commissioner Richard Glick also called the standards “an important first step,” but “I think more needs to be done.”

Comments on the proposal to adopt the standards are due 60 days after its publication in the Federal Register.

EOP Reliability Standards

FERC on Thursday also approved several updates to emergency preparedness and operations reliability standards proposed by NERC last March (RM17-12).

The revisions streamline existing standards and remove redundant language. The commission said they will ensure accurate reporting of events to NERC’s event analysis group; delineate the roles and responsibilities of entities involved in system restoration processes; and identify the elements required in plans for continuing operations when primary control functionality is lost.

FERC did not make any changes to the EOP standards since it proposed to adopt them last September, nor did stakeholders propose any. (See FERC OKs Rules on Balancing, Interconnection, Remedial Actions.) They will go into effect 60 days after their publication in the Federal Register.

January 19, 2018

FERC Denies FirstLight Hydro Capacity Change

By Michael Kuser

FERC on Thursday denied FirstLight Hydro Generating’s request to change reservoir levels this winter at a Massachusetts hydroelectric plant, citing inadequate time to assess the impact on the endangered shortnose sturgeon (P-2485-076).

FirstLight requested the temporary amendment to increase operational flexibility at its 1,167-MW Northfield Mountain Project in anticipation of potential reliability challenges in New England this winter. ISO-NE supported the request but did not say the extra capacity would be critical to reliability.

FERC sympathized with FirstLight’s intentions, but ultimately sided with the shortnose.

“While we are very sensitive to the need to take all feasible steps to ensure the reliability of the electric grid, and accordingly have approved previous amendment requests by FirstLight, the presence of an endangered species in the project reservoir that may be affected by the amendment is a significant new circumstance,” the commission said. “We could not lawfully approve the current amendment before completing consultation with the [National Marine Fisheries Service], a process that would require the gathering of information, followed by NMFS review and action.”

In comments filed with FERC last October, NMFS indicated the sturgeon had been found in Northfield Mountain’s lower reservoir, which was historically above the recognized upstream extent of the species’ range.

The commission ordered that “any future proposal of a similar nature should be filed a sufficient time before the winter season such that any necessary efforts with respect to [Endangered Species Act] consultation can be completed in a timely manner.”

Under federal regulations, NMFS has 135 days to complete a consultation. The commission said that “it did not appear possible” that the consultation process could be completed before March 31, the end of the period for which FirstLight requested the temporary amendment.

Technical Limits

FirstLight proposed reducing Northfield Mountain’s minimum reservoir elevation from 938 mean sea level (msl) feet to 920, and bumping up the maximum from 1,000.5 msl feet to 1,004.5, increasing the potential operating range from 62.5 feet to 84.5 and available storage from 12,318 acre-feet to 15,327. The company also sought unrestricted use of the extra capacity.

According to FirstLight, the additional 3,009 acre-feet of storage would increase the facility’s maximum daily generation by 2,050 MWh, or an additional 1.8 hours of generation at full load. Within current limits, it is capable of generating 8,729 MWh/day during peak load conditions.

But FERC signaled that it would seek limits on the flexibility offered by the adjustments. In its decision, the commission ordered that “any future proposal should be restricted to use during ISO-NE discretionary actions taken during emergency operations … unless FirstLight can provide sufficient evidence why a broader amendment is appropriate.”

The commission has previously granted six temporary amendments for the facility. The first three allowed FirstLight to modify operations only when ISO- NE declared an energy emergency, triggered by a forecast showing electric demand could exceed capacity reserves. The fourth and fifth did not restrict FirstLight’s use of the additional storage, but the sixth, most recent amendment also restricted the use of the additional storage to declared emergencies.

FERC Northfield Mountain FirstLight Hydro — Connecticut River at Turners Falls

Northfield Mountain includes an upper reservoir, an underground powerhouse containing four reversible pump-turbine generators and an intake/outlet structure in the Turners Falls reservoir. The 22-mile-long reservoir on the Connecticut River serves both Northfield Mountain and the Turners Falls Hydroelectric Project, for which FirstLight also holds the license.

Northfield Mountain, Turners Falls and three other hydroelectric facilities directly upstream are all currently undergoing relicensing. As part of that process, the licensees are required to conduct studies for the five facilities to analyze interrelationships in project operations and environmental effects.

January 19, 2018

‘Horse is out of the Barn’ for CAISO RC Effort

By Jason Fordney

CAISO said Wednesday there is no turning back on its departure from Peak Reliability in September 2019.

CAISO RC reliability coordinator — Schmitt | © *RTO Insider*

California’s grid operator has been studying its recent move to become a reliability coordinator (RC) since early last year, and ISO officials have extensively reviewed the proposal to offer RC services to others, CAISO Vice President of Operations Eric Schmitt said during a Jan. 17 conference call.

“We didn’t wake up on that morning” and decide to become a RC, Schmitt said, noting that the ISO on Jan. 2 gave Peak notice that it was departing.

“We were reluctant to do that, to be honest with you,” Schmitt said. “But it’s pretty evident that the marketplace is changing.” He added that the Western Interconnection is “is going to be even more complicated as we go forward.” Having notified Peak, CAISO must now become its own RC. “The horse is out of the barn,” he added.

The ISO hopes other Western balancing authorities will sign up for its RC services. Its timeline calls for comments on the plan by mid-May, a rate proposal to be submitted to its Board of Governors in late June, a FERC filing in August and final approval in October. The effort also requires approval from the Western Electricity Coordinating Council, the Regional Entity that develops the West’s reliability standards.

CAISO is asking that potential customers sign nonbinding letters of intent by March 1 that make them part of the implementation process and that in the future they will sign reliability service agreements.

Schmitt said CAISO will continue to work closely with Peak throughout the transition. “We have enjoyed a great relationship with Peak,” he said. “We expect that relationship will continue.”

When announcing its departure, CAISO cited its expectation that the Vancouver, Wash.-based Peak will be forced to increase its fees because of Mountain West Transmission Group’s likely departure from the RC, as well as Peak’s recent announcement that it has partnered with PJM to offer competitive market services in addition to reliability services in the West. (See Peak, PJM Detail Western Market Proposal.)

CAISO knows what it takes to obtain certification as an RC and has a transferable skill set for RC services, Schmitt said. The ISO is a registered balancing authority and already performs some reliability functions for its participating transmission owners, such as outage coordination, next-day planning analysis, and real-time grid monitoring and assessment.

New services in CAISO’s RC area would include system operating limit methodology, review of system-wide restoration plans, stakeholder processes and other services. It also plans to offer some non-RC services, such as hosting advanced applications and physical security risk assessment that will involve separate charges. CAISO will need to add personnel to support RC functions such as customer service, NERC/WECC compliance and technology positions. There would be an RC representative in each of the ISO’s two control centers located in Folsom and Lincoln.

The ISO had other public meetings on the RC proposal scheduled for Jan. 18 in Phoenix, Ariz., and Jan. 19 in Portland, Ore. Details of the initiative are provided on a new RC website.

January 18, 2018

NYISO Business Issues Committee Briefs: Jan. 17, 2018

NYISO power prices jumped sharply in December on the back of sharp gains for natural gas stemming from extreme cold weather at the end of the month.

Locational-based marginal prices (LBMPs) averaged $52.63/MWh for the month, up 58% from November and nearly 20% from the same period a year ago, Robert Pike, NYISO director of market design and product management, told the ISO’s Business Issues Committee (BIC) on Wednesday.

The ISO’s year-to-date monthly energy prices averaged $36.56/MWh in December, a 7% increase from a year earlier. The average daily sendout was 444 GWh/day, compared with 403 GWh/day in November and 433 GWh/day a year earlier.

New York natural gas prices surged 260% over the previous month, averaging $7.59/MMBtu at the Transco Z6 hub. Prices were up 73% from a year ago. Natural gas prices for the month peaked at $31.16/MMBtu on Dec. 29, five days into a severe cold snap.

Distillate prices gained 20.1% year on year, with Jet Kerosene Gulf Coast averaging $13.47/MMBtu, up from $13.04 in November. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $13.91, compared with $13.70 a month earlier.

The ISO’s local reliability share was 9 cents/MWh, down from 20 cents/MWh from the previous month, while the statewide share dropped 18 cents/MWh from the previous month to -78 cents/MWh. Total uplift costs were lower than in November.

Ongoing JOA Dispute with New Jersey

Reviewing the Broader Regional Markets report, Pike noted that the New Jersey Board of Public Utilities last month filed a complaint with FERC against PJM, NYISO, Consolidated Edison, Linden VFT, Hudson Transmission Partners and the New York Power Authority. The complaint challenges the implementation of the mutual benefits provisions of the Joint Operating Agreement between NYISO and PJM and requests amendments to it.

Pike said the ISO last month jointly filed with the other respondents to request an extension of the Jan. 11 answer deadline to Feb. 23. The commission granted the extension, which was unopposed by the BPU.

The report also noted the ISO is taking further steps to improve modeling consistency between real-time commitment (RTC) and real-time dispatch (RTD) and examine changes to look-ahead evaluations to improve scheduling and price convergence. The ISO published a white paper on the topic last month and will further explore RTC-RTD convergence this year.

BIC Recommends ICAP Manual Revisions

The BIC also recommended revisions to the Installed Capacity (ICAP) Manual covering deliverability requirements for capacity imports from PJM, effective May 1.

Zachary Smith, NYISO manager of capacity market design, told the committee that the ISO finished modifying the documentation requirements for capacity imports across the PJM AC ties. His report outlined changes that would require PJM-based ICAP suppliers to provide NYISO with evidence of firm transmission service for all capacity import obligations on the day Spot Market Auction results are posted.

Suppliers that fail to provide documentation by the deadline would be subject to penalties and deficiency charges. Monthly deadlines, which will be posted on the ICAP event calendar, would be the same for all imports.

The committee will continue evaluating deliverability requirements for other interfaces and imports.

New Price Correction Deadlines

The committee also approved modifying price-correction deadlines by using business days rather than calendar days in the period calculation. If approved by NYISO’s Management Committee and Board of Directors, the Tariff revision would reset deadlines to four business days after the market day for real-time prices, and two business days after the market day for day-ahead prices. The change is subject to FERC approval.

Michelle Gerry, the ISO’s price validation supervisor, told the BIC that ISO-NE allows five business days for real-time price corrections and three days for day-ahead, while PJM stipulates 10 calendar days for both categories.

NYISO would continue to provide notice as soon as any price correction is processed and post a detailed correction within 10 days of each correction, as well as the quarterly price correction report recapping all corrections for each quarter.

NYISO Applies Wind Forecast Fee to Solar

The BIC voted to recommend Tariff changes that would charge New York’s utility-scale solar facilities for acquiring solar forecasts, similar to how the ISO currently recovers the costs for wind forecasts.

The changes would be implemented in mid-2018 and would also apply to meteorological data requirements. The ISO will next year pursue Tariff modifications for the economic dispatch of solar.

In a report on solar integration, David Edelson, NYISO operations performance and analysis manager, explained that the grid operator procures a centralized solar forecast for each of its 11 load zones, for both behind-the-meter and individual utility-scale resources.

Edelson said the new cost recovery mechanism is modeled on the ISO’s wind forecasting fee, which is $500/month for each resource, plus $7.50/MW (nameplate) per month. The proposed Tariff changes would modify the forecasting fee rate to $6.20/MW (nameplate) per month for both wind and solar resources so that the fees remain in line with the costs NYISO incurs to develop the forecasts.

Applying these rules to front-of-the-meter solar resources will improve NYISO’s ability to reliably integrate higher levels of solar onto the grid, Edelson said.

— Michael Kuser

January 18, 2018

ERCOT, SPP Extend Winter Peak Records

Just as it projected a day earlier, ERCOT set a new winter peak of 65.73 GW Wednesday morning. The demand was almost 3 GW higher than the previous record of 62.86 GW on Jan. 3. (See SPP Resets Winter Peak Record, ERCOT Set to Follow.)

The ISO said historic low temperatures in Texas resulted in multiple new peaks before demand settled on the new record between 6 and 7 a.m. Single-digit temperatures extended from North Texas to the Gulf Coast overnight, stranding trucks on icy highways.

ERCOT said it has sufficient generation resources to meet forecasted demand, but it also issued a news release Wednesday offering conservation tips to consumers.

SPP also set yet another winter peak when it recorded demand of 43.58 GW at 7:23 a.m. Wednesday. That surpassed the Jan. 16 record of 42.71 GW.

MISO tweeted late Wednesday night that MISO South had also set a new winter peak but did not say the exact figure.

— Tom Kleckner

January 18, 2018

MISO Seeks Stakeholder Input as Queue Timeline Lengthens

By Amanda Durish Cook

CARMEL, Ind. — Amid growing complaints about the sluggishness of its redesigned interconnection queue, MISO is rolling out a new way for stakeholders to voice their concerns about the process.

RTO staff on Tuesday introduced a new feedback form designed specifically to capture stakeholder opinions on issues discussed during Interconnection Process Task Force (IPTF) meetings, in addition to other advice related to the queue.

MISO interconnection queue IPTF — | *MISO*

“If there are any areas of the process that you see need improvement, we want to make sure that we have a channel for stakeholder voices to be heard,” Arash Ghodsian, MISO manager of economic studies, said during a Jan. 16 IPTF meeting.

MISO will accept stakeholder submissions for about three weeks after IPTF meetings and post responses to the feedback on its public website, Ghodsian said.

Developer EDF Renewable Energy on Jan. 4 filed a FERC complaint against MISO’s year-old interconnection queue process, contending that the procedure is still too slow to ensure the company’s wind projects will beat the 2020 federal production tax credit deadline.

EDF argued that its projects can only meet the tax credit deadline if MISO completes interconnection studies by June 2019 to allow for the average 18-month construction of a wind farm. Otherwise, wind developers could risk forfeiting “tens of billions” of dollars, the company said. It urged FERC to consider a fast-tracked queue progression for vetted projects. (See Renewables Developer Escalates MISO Queue Design Dispute.)

“MISO will file a response to that complaint in the coming days or weeks,” Corporate Counsel Michael Blackwell said.

MISO FERC interconnection queue IPTF — MISO Queue as of Nov. 2017 | *MISO*

Meanwhile, the RTO has updated its timetable for when it expects projects that entered the queue’s definitive planning phase (DPP) during the past two years to execute generator interconnection agreements. The most recent predictions, divided by region, have projects clearing the DPP as late as July 3, 2019, in the wind-heavy MISO West region. In all other regions, the August 2017 cycle of projects are expected to wrap up in February or March 2019, except in the Upper Peninsula area of MISO East, where projects are slated to finish this December.

MISO’s queue reform was intended to reduce the number of days that interconnection customers spend in the DPP from an average of 589 days to 460. Customers that entered the August 2017 cycle of projects are currently predicted to spend an average of 579 days in the DPP before entering an interconnection agreement.

RTO staff and IPTF leadership will also assess the need for a February task force meeting based on stakeholder requests. Wind on the Wires consultant Rhonda Peters campaigned for the additional meeting, saying a conference call was needed between now and the next scheduled meeting on March 13, considering the queue’s tight timeline.

MISO will accept new generator interconnection requests until March 12 for the April 2018 DPP cycle of projects and until Jan. 22, 2019, for the March 2019 cycle.

January 17, 2018

FirstEnergy Lawyer Sought to Lobby Chatterjee on Plant Deal

By Rory D. Sweeney and Rich Heidorn Jr.

FERC Commissioner Neil Chatterjee says a former FERC general counsel attempted to privately lobby him last week in a proceeding for which he appeared to have prior knowledge of a pending order.

Chatterjee reported the ex parte communication by Gibson Dunn attorney William S. Scherman in a me m o filed in the docket Friday, shortly before the commission rejected FirstEnergy’s request to transfer ownership of a struggling coal-fired merchant generator to a regulated affiliate (EC17-88).

FERC Neil Chatterjee FirstEnergy — Scherman (left) and Chatterjee | *Gibson Dunn, FERC*

FirstEnergy merchant affiliate Allegheny Energy Supply had requested permission to transfer ownership of the 1,159-MW Pleasants Power Station to regulated affiliate Monongahela Power, with the latter assuming a $142 million obligation for pollution controls Allegheny installed at the plant. The commission’s unanimous Jan. 12 order concluded the deal was not in the public interest because it resulted from an “overly narrow” solicitation. (See FERC Blocks FirstEnergy Sale of Merchant Plant to Affiliate.)

Chatterjee reported that Scherman called him on Jan. 11, “indicating his concern that the commission would shortly issue an order adverse to the interests of Monongahela Power. Mr. Scherman also stated that he would prefer that the commission set the issue for hearing instead of issue an adverse order. As soon as I realized that Mr. Scherman’s communication concerned the merits of the contested proceeding, I terminated the communication and did not respond to Mr. Scherman’s statements. I then drafted this memorandum to memorialize the ex parte communication for the record.”

FirstEnergy spokesman Todd Myers declined to answer questions about the incident, referring a reporter to Scherman.

Scherman insisted Tuesday that he had done nothing wrong and said the commission should change its ex parte (on one side only) rules, which prohibit private communications with commissioners in contested case specific proceedings.

“Based upon my experience, I do not believe I engaged in any ex parte communications,” Scherman said in an email to RTO Insider. “But as I wrote about nearly three years ago [in a commentary published in The Energy Daily], and as this and other episodes over the years have shown, the ex parte rules are mostly gray, difficult to enforce, and serve to cut off federal and state commissioners from vital information. The time has come to revise the rules.”

Scherman also had kind words for Chatterjee.

“In the 30 years I have been involved with FERC, I have known almost every FERC commissioner,” he said. “Based upon his short time at FERC, it is apparent to me that Neal [sic] Chatterjee will be one of the finest members the commission will ever have. He is thoughtful and dedicated to doing what is right for the American people. He is a great American.”

Commissioners Cheryl LaFleur, Robert Powelson, and Richard Glick said they had not been contacted by Scherman. Chairman Kevin McIntyre did not immediately respond to a query about whether Scherman had attempted to contact him.

Scherman, who chairs Gibson Dunn’s Energy, Regulation, and Litigation practice group, served as FERC’s general counsel, chief of staff, and senior legal and policy advisor between 1987 and 1993. He joined Gibson Dunn in 2013 after 20 years as a partner at Skadden Arps.

Scherman and his firm were not listed as representing FirstEnergy in the Pleasants Power Station proceeding. However, Scherman submitted FirstEnergy’s comments in response to the Department of Energy’s proposed rulemaking to benefit coal and nuclear plants last October (RM18-1). He also has represented the utility in proceedings before the West Virginia Public Service Commission in 2012.

A pugnacious litigator, Scherman has been a vocal critic of FERC’s enforcement officials since leaving the agency, making his case in congressional testimony, a law review article, a Wall Street Journal op-ed, and a National Association of Regulatory Utility Commissioners conference. Senate Republicans quoted from his critique during the 2014 confirmation hearings for former FERC Commissioner and Enforcement Director Norman Bay. (See FERC Enforcement Process Under Fire in House Hearing.)

In his Energy Daily commentary, written with Gibson Dunn associate Jennifer C. Mansh, Scherman conceded the need for prohibiting ex parte communications in contested legal proceedings. “Prohibitions on ex parte communications are meant to protect litigants from secret discussions and perceptions of unfairness,” they wrote. “It isn’t fair, for example, for a plaintiff to communicate alone with the judge, without any record of what was said and without allowing the defendant to respond.”

However, they said the situation is different for FERC, which “is simultaneously acting in an adjudicatory and rulemaking capacity.”

“Topics in contested proceedings frequently overlap with major public policy issues before the commission. FERC’s ex parte rules thus often prohibit the people who have the best information available from sharing highly relevant information with decision-makers,” they said.

Although FERC bars ex parte communications in case-specific, contested proceedings (18 CFR 385.2201(a), (b), (c)(1)(i)) the rules do not apply in rulemakings (18 CFR 385.2201(a), (b), (c)(1)(ii)), according to the commission.

Scherman and Mansh also wrote that FERC’s ex parte rules “are unfair to investigation targets and hinder the settlement of FERC enforcement cases.”

January 17, 2018

PJM Going it Alone on Capacity Repricing Plan

By Rory D. Sweeney

PJM staff will recommend that the RTO’s Board of Managers approve its own capacity repricing proposal next month, ignoring an endorsement vote scheduled for Jan. 25 on an alternative proposal that had garnered more stakeholder support.

PJM FERC Capacity Repricing Proposal — Ott | © *RTO Insider*

PJM CEO Andy Ott announced the decision Tuesday in a let t er to stakeholders.

In addition to describing revisions to PJM’s proposal, Ott made the case for why the RTO’s proposal needs to be filed for FERC approval now and is superior to the proposal from PJM’s Independent Market Monitor.

“I do not make this recommendation lightly, recognizing valid concerns arise with any course of action PJM may take, including capacity repricing,” Ott wrote. “Despite all of our collective efforts in the stakeholder process, a workable consensus solution — or even a shared agreement on the nature and extent of the problem to be solved — appears unlikely.”

The filing would be the culmination of the Capacity Construct/Public Policy Senior Task Force (CCPPSTF) that dominated PJM stakeholder work in 2017. PJM said its plan would accommodate generator offers from state-subsidized plants by allowing them to bid into capacity auctions but ensure they don’t suppress competitive prices by removing those offers in a second “repricing” stage of the auction.

Several proposals like PJM’s arose to address perceived flaws in the concept, but the IMM’s proposal — fueled by concerns that PJM would unilaterally file its proposal without a clear stakeholder mandate — was the only one to receive endorsement to move forward, albeit slowly. The IMM’s “MOPR-Ex” proposal would extend the minimum offer price rule to all units indefinitely. (See MOPR-Ex Faces Uphill Battle as PJM Declines Recommendation.)

Ott’s Argument

Ott said PJM needed to seek approval quickly because of growing threats to PJM’s markets. He cited FERC’s rejection of the RTO’s 2012 MOPR compromise, the failure of a court challenge to Illinois’ zero-emissions credits program, and the “distinct potential” for additional state subsidies this year — likely a reference to New Jersey legislators’ consideration of a ZEC-style program. (See On Remand, FERC Rejects PJM MOPR Compromise and NJ Lawmakers Pass on Nuke Bailout in Lame Duck Session.)

Ott said he agrees with the Monitor that MOPR-Ex “offers the most economically sound response to the issue” and “the most direct and effective means to preserve price integrity” necessary for the capacity market to work. But he said PJM’s proposal is superior to MOPR-Ex because it is “substantially less punitive and less likely to frustrate the operation of state programs.”

“PJM believes it is vital for the regional market design to respect individual state interests while protecting consumers in other states from potential cost shifts,” Ott wrote. “While MOPR-Ex would not prevent state programs from providing support to individual generators, it would most likely exclude generators obtaining this support from clearing the PJM Capacity Market. PJM believes this approach is not sustainable and does not strike an appropriate balance between legitimate state interests and wholesale market integrity.”

IMM Response

In an emailed response, the Monitor said it agrees with PJM that there is a conflict between state subsidies and competitive wholesale power markets.

“But the IMM disagrees with PJM’s conclusion that PJM must reflect state interests even when state subsidies conflict with the operation of a competitive wholesale power market,” Monitor Joe Bowring said. “PJM’s capacity repricing proposal would permit state subsidized resources to push competitively offered resources out of the capacity market. That outcome is inconsistent with competition.”

Bowring took issue with Ott’s characterization of MOPR-Ex, saying that it’s not punitive to require competitive offers and “prevent subsidized, uneconomic resources from pushing competitive, economic resources out of the market.”

He reiterated his oft-repeated refrain that “subsidies are contagious.”

“If one subsidy program is permitted to undermine the PJM capacity market, others will follow,” Bowring wrote. “The MOPR-Ex approach would provide a disincentive for subsidies and would require individual states to bear the costs of state subsidies rather than spreading the costs across the other states in PJM.”

Next Steps

Ott said PJM would request FERC approve its proposal for an effective date after the 2021/22 Base Residual Auction in May. He promised that “PJM will actively listen, consider, and engage on alternative design suggestions that stakeholders might offer in the course of the FERC proceeding.”

January 17, 2018

LaFleur, Chatterjee Discuss NOPR Ruling, Resilience Proceeding

By Rich Heidorn Jr.

WASHINGTON — FERC Commissioner Neil Chatterjee acknowledged Tuesday he has suffered some growing pains in his transition from Capitol Hill partisan to FERC commissioner, saying he hadn’t fully appreciated the commission’s “fact-based, evidence-based approach.”

In a panel discussion, Chatterjee and Commissioner Cheryl LaFleur discussed the commission’s Jan. 9 ruling dismissing Energy Secretary Rick Perry’s Notice of Proposed Rulemaking (RM18-1) and previewed the docket the panel created to investigate RTOs’ resilience practices (AD18-7).

FERC NOPR Resilience Cheryl LaFleur Neil Chatterjee — The Bipartisan Policy Center’s panel discussion with FERC Commissioners Neil Chatterjee and Cheryl LaFleur attracted an audience that included the heads of groups representing the nuclear and coal industries, merchant generators and state regulators | © *RTO Insider*

The session, sponsored by the Bipartisan Policy Center, attracted an audience that included the heads of groups representing the nuclear and coal industries, merchant generators, and state regulators. (See DOE NOPR Rejected, ‘Resilience’ Deba t e Turns to RTOs, States.)

Chatterjee, a Kentuckian and former energy advisor to Senate Majority Leader Mitch McConnell (R-Ky.), had pushed for “interim” financial relief for struggling coal and nuclear generators pending further proceedings but ultimately joined LaFleur and their three colleagues in the unanimous ruling.

“During my time in the legislative branch I had spent time with lawmakers of all political stripes who stressed the importance of fuel diversity and the need for an all-of-the-above energy strategy,” Chatterjee, a Republican, said. “And so initially I did express some sympathy for what the secretary had laid out. … That said I was also very clear that if the commission were to take any action, it would have to be legally justified, and that it would not distort markets.”

“As we went through the process I came to really appreciate the fact-based, evidence-based approach that the commission takes. I was aware of it prior to my confirmation, but once you really get in there and start doing the work, you realize we do things in a cautious, steady, legally defensible manner. As we … went through the record and did the analysis, I came to the conclusion that my colleagues did, which is that while I feel Secretary Perry asked the right question, he proposed the wrong remedy.”

Chatterjee said he was pleased that all five commissioners also agreed “that resilience is something that needs to be explored further. The commission has looked at these kinds of issues throughout the last number of years, but we’ve never had a really hyper-focused analysis on resilience.”

LaFleur, a Democrat, said, “I disagree with Neil a little bit on how much we’ve done on this issue in the past.

“Since I’ve been on the commission for seven and a half years, a large percentage of our work has been driven by relentless changes in the nation’s resource mix. … And I would say that’s been driving our market work, our reliability work, and our transmission work for much of the last decade.”

LaFleur said although the resiliency proceeding is important, “I think we shouldn’t let this swallow everything the commission is doing. We have to continue on all fronts.”

LaFleur said she opposed interim subsidies for coal and nuclear plants because the commission lacked robust factual basis for the action. She likened it to the high burden of proof required of those seeking a preliminary injunction, who must show they have a likelihood of ultimately prevailing.

LaFleur also parted with Chatterjee on definitions, saying she believes resilience is part of reliability.

“I think resilience is distinct from reliability,” Chatterjee said “ … Perhaps the threats of a loss of resilience aren’t as dire as some generators are making them out to be. But they’re certainly not as insignificant as some proponents of new generating sources are making it out to be.”

BPC President Jason Grumet, who moderated the talk, praised the commission and Chairman Kevin McIntyre for their response to the NOPR. “I think for anyone who mistrusts government action, the rigor, the integrity and the independence, and the unanimity that FERC was able to show is really, I think, one of the brightest moments in basic public service that I’ve seen in a while,” Grumet said.

On McIntyre’s handling of the NOPR, Chatterjee and LaFleur were in agreement. “He threaded the needle very well,” Chatterjee said.

January 17, 2018

SPP Resets Winter Peak Record, ERCOT Set to Follow

With an Arctic cold front rolling through the southern part of its footprint Tuesday morning, SPP set a new winter demand peak of 42.71 GW. The previous mark of 41.01 GW — set Jan. 2 — lasted only two weeks.

The new record came at 7:24 a.m., and wind energy met just over 8 GW of the demand. Energy prices peaked at 11 a.m., with hubs averaging $496.67/MWh in the north and $478.49/MWh in the south.

ERCOT, which manages 90% of the Texas grid, expected to set its third demand record this winter during either the night of Jan. 16 or the morning of Jan. 17. The state has been hit with its second round of snow and ice this year, ranging from San Antonio to Houston.

ERCOT SPP winter peak demand — Ice in Houston Tuesday | © *RTO Insider*

The ISO’s current winter peak is 62.86 GW, set Jan. 3. That broke the short-lived record of 61.95 GW, set the day before.

Spokesperson Leslie Sopko said ERCOT has sufficient generation and transmission resources to keep up with forecasted demand.

“However, this is a fluid situation, and we will continue to monitor system conditions closely,” Sopko said.

The National Weather Service predicted Houston area overnight temperatures would fall into the teens to lower 20s F, with wind chill values possibly dipping into the single digits.

— Tom Kleckner