LaFleur Recounts Turbulent Tenure at FERC

‘Every President’s Second Choice’

By Michael Brooks

WASHINGTON — FERC Commissioner Cheryl LaFleur last week provided a clip show of anecdotes from her tenure at the commission, giving attendees at the Energy Bar Association’s annual meeting an insider’s view of the nearly constant change of the past several years.

The May 7 speech was a farewell address to the bar from LaFleur, whose term ends June 30. Although she was not nominated for another term, LaFleur told the audience she intends to stay on past June; she’s allowed to stay until the end of the year or a replacement is appointed. (See LaFleur Announces Departure from FERC.)

LaFleur’s luncheon speech was a reminder of just how much turnover the commission has seen in less than a decade. During her time, LaFleur has served as acting chairman twice, the official chair for nine months and the lone commissioner for a month.

In contrast to Commissioner Bernard McNamee — who the day before gave the EBA the same colorless keynote that he’s delivered at other conferences — LaFleur was loose, sipping a glass of wine and cracking jokes, often at her own or the commission’s expense.

She began her tenure in July 2010 after serving as executive vice president and acting CEO of National Grid. “I knew what FERC did; I knew its jurisdiction of course. I had read plenty of FERC orders; I knew enough to read them from the back.”

She arrived without any agenda, personal or political, she said. “I didn’t really have any clearly developed policy agenda I was there to do, other than a vague sense that I could add value on reliability because I had run a company. So, when people said, ‘What are you going to focus on?’ The very first week I would say, ‘Oh, uh, a lot of reliability.’”

LaFleur was also candid about her reactions to some of the commission’s most tense and uncertain moments, lamenting how the country’s partisan divide slowly began to affect the commission’s work. Nevertheless, she said, the commission’s staff remained diligent and dedicated.

She recalled an article listing the top five candidates to replace Chair Jon Wellinghoff in 2013. “And I was not mentioned as a top-five candidate, even though I was one of two sitting Democrats at the commission. Hello, Rodney Dangerfield.” Then, after President Barack Obama nominated Ron Binz for the chair, “[Commissioner] John Norris went postal because he wasn’t nominated.”

When Binz’s nomination was withdrawn in the face of opposition from the coal industry, “it seemed like it was getting more political — at least what we thought was political at the time,” LaFleur said. (See “Echoes of Binz,” Senate Confirms McNamee to FERC.)

In November 2013, 45 minutes before the start of the commission’s monthly open meeting, LaFleur received a call from the White House telling her that Obama had named her acting chair. At the end of the meeting, Wellinghoff announced his departure and LaFleur’s promotion. “And the looks on the people in the room: ‘Oh my God, something actually happened at a FERC meeting!’”

She “had zero transition with Jon,” who left that day. Fortunately, she said, senior commission staff helped familiarize her with her new duties.

Months later began what LaFleur called a “very tumultuous” period. Obama nominated Norman Bay, then director of the commission’s Office of Enforcement, to be chair; a memo detailing a FERC analysis of the most critical 30 substations in the country was leaked to The Wall Street Journal; and the end of LaFleur’s term was coming up, leaving her to run the commission while she wondered whether she would be reappointed.

“There were some really awkward moments,” she said. “I remember the open meeting when I congratulated Norman on his nomination. You could just hear a pin drop in the commission meeting room.”

Obama did nominate her for a second term, but Bay’s nomination, like Binz’s, was controversial. Bay and LaFleur appeared before the Senate Energy and Natural Resources Committee together in a joint confirmation hearing, where several senators said LaFleur should have been named chair.

“We had to field questions about each other,” LaFleur said. “And I thought that was the height of the craziness, but then it got crazier.” (See Analysis: LaFleur Cruises, Bay Bruises in Confirmation Hearing.)

In a deal between the White House and the Senate, LaFleur was named the official chair for nine months while Bay served as a commissioner.

Trump’s Arrival

Bay took the gavel in April 2015. “For about a year and half after that, life seemed pretty settled,” LaFleur said. “Whether I was chairman or Norman was chairman, the work kept going.” With the addition of Commissioner Colette Honorable in December 2014, the commission was fully staffed.

However, the commission’s ranks began to dwindle with the departures of Phil Moeller in fall 2015 and Tony Clark 11 months later. “It really didn’t seem like a big deal at the time, but obviously it was in retrospect. As we went into the [2016 presidential] election, a lot of the press talk and industry gossip was about who Hillary Clinton would make chairman. …

“Of course, I was never mentioned. I knew I would never be mentioned.

“So then came the election,” she said, taking another sip of wine. The commission had scheduled a technical conference on energy storage for the day after the election. “So, we’re sitting in the commission meeting room trying to focus on some pithy storage issues, thinking, ‘What is going to happen? What’s going to happen?’”

After President Trump’s inauguration, LaFleur said a messenger from the White House dropped off a letter at the front desk of FERC making her the acting chair once again. “I am truly every president’s second choice. … It was just bizarre.”

Bay announced his resignation the next day, and the commission had nine days before he left to vote on as many as orders as possible before it lost its three-member quorum. Trump nominated Robert Powelson and Neil Chatterjee in May, and they were swiftly advanced to the Senate floor by the ENR Committee. LaFleur said she and Honorable were thrilled, but the nominations languished for almost two more months, during which Honorable departed at the end of her term, leaving LaFleur as the only commissioner.

“In early August, I finally gave up [waiting for the Senate to vote] and took a vacation.” While she was away, Powelson and Chatterjee were confirmed. After Chatterjee was sworn in, she received another call from the White House informing her that he would be the new chair. “So, I stayed on vacation,” she said.

In comparison to Wellinghoff’s departure, the transition from LaFleur to Chatterjee was well coordinated, aside from “one unusual change which was more administration involvement in selecting senior staff,” she said. “But we took it in stride; we were excited to be back in the saddle.”

The new chief of staff, Anthony Pugliese, came to FERC after a stint at the U.S. Department of Transportation as a member of President Trump’s so-called “shadow cabinet.” (See “Mum on White House Input on Staff,” FERC Chair Praises Perry’s ‘Bold Leadership’ on NOPR.)

‘Rifts Started to Appear’

The quips dissolved and the room became silent as LaFleur spoke about the Department of Energy’s 2017 Notice of Proposed Rulemaking calling for RTOs and ISOs to compensate generators with 90 days’ worth of on-site fuel their full operating costs. The NOPR “hit [FERC headquarters at] 888 First St. like a thunderclap,” LaFleur said. “We were already working as hard as we could to catch up, but we had to spend most of the fall grappling with the NOPR.

“It was very divisive. And it soaked up a lot of time and energy that we could have directed at the backlog of policy dockets that we had lined up. … I was really happy when FERC unanimously rejected the NOPR in January 2018. That was what the record required, but it also protected FERC’s independence.” She praised Powelson “for holding his ground on his pro-market views” and then-Chair Kevin McIntyre “for bringing us together.”

In May 2018, however, “rifts started to appear on the commission, and I fully acknowledge that I was a part of those rifts.” The three Republican commissioners voted to narrow the circumstances under which FERC would estimate greenhouse gas emissions from natural gas pipeline projects. The decision was part of its rejection of a request for rehearing of its approval of Dominion Energy Transmission’s New Market Project pipeline. (See FERC Narrows GHG Review for Gas Pipelines.)

The new policy reversed the commission’s practice since late 2016 of including more information on upstream and downstream GHG emissions in its pipeline orders.

“I’ve thought a lot about what happened, and in part, I think the polarization of Washington, D.C., and societal rifts on big issues have sort of spread to 888 First St., especially the profound societal disagreement about climate change,” she said.

“Throughout this period … I tried to keep my same regulatory philosophy. I’m still trying to decide case by case, still trying to get things partly my way and still trying to find a middle where I can, if there is a middle. … I’m trying to keep our disagreements about the way we conduct our environmental reviews from forcing me to dissent every single time, even if I have to supplement the climate analysis myself.

“I expect that the courts will ultimately require the commission to do more climate analysis,” she added.

Another Reset

The most consequential event of 2018 came when McIntyre — who had been absent from the commission’s open meetings since July as he battled brain cancer — relinquished the chair back to Chatterjee, LaFleur said. McIntyre succumbed to his illness and died Jan. 2.

“The loss of Kevin was a major blow to the agency on both a personal and professional level,” LaFleur said. Coupled with Powelson’s departure last summer, “we had to reset again, and the reconstituted FERC that started in December 2017 never really fully had a chance to get its bearings.”

“In retrospect, it’s hard to deny the collective impact of all these events, particularly the continued changes in commission membership and leadership, and our underlying policy disagreements,” she said. “It’s hard to deny that that hasn’t had a significant impact on our work as a commission.”

LaFleur acknowledged that since the loss of McIntyre and the arrival of McNamee, the commission has seen more dissents, separate statements and partisan splits. She said she has written separately 36 times in 2018 and 10 times in 2019.

She also revealed that “even some less prominent orders that have nothing apparently to do with climate have gotten stalled because individual commissioners are too dug in on something to agree on language. And this has happened far more frequently than in the past.”

But she said that the splits along party lines only “give the appearance that people are voting by party philosophy and not individual views.” She also lamented the lack of certainty caused by the splits. “If you keep changing your positions by who’s in the seats, it doesn’t promote regulatory continuity and regulatory certainty for the regulated community.”

May 14, 2019

FERC Orders Indemnification Provision for PJM Tariff

By Amanda Durish Cook

FERC last week ordered PJM to revise its Tariff to comply with interconnection procedures that the commission established more than 15 years ago.

The May 10 order was a partial victory for American Electric Power Service Corp. (AEPSC), which in November filed a complaint against PJM on behalf of its transmission owners, arguing the RTO had failed to include an option-to-build indemnification provision in its Tariff, counter to long-established FERC policy (EL19-18).

AEPSC’s argument rested on FERC Order 2003, which established procedures and agreements for interconnection of new and expanded large generators, including a pro forma large generator interconnection agreement (LGIA) with transmission providers.

The order also set out an option-to-build provision that allowed interconnection customers to build interconnection facilities and standalone network upgrades “if the transmission provider notified the interconnection customer that it could not meet the in-service dates established by the interconnection customer.” After multiple TOs raised concern about possible reliability issues that could arise from customers upgrades, FERC added an indemnification provision to the wording of the pro forma.

In Order 845 issued last year, FERC determined that interconnection customers could build interconnection facilities “regardless of whether the transmission provider can meet the interconnection customer’s proposed in-service dates.” The commission this year clarified that the change doesn’t affect an LGIA’s indemnification and consequential damages provisions. (See ‘Boring Good’ Rulemaking Seeks to Clean up Order 845.)

In its complaint, AEPSC argued that PJM’s pro forma interconnection service agreement (ISA) and interconnection construction service agreement (ICSA) are unjust and unreasonable because neither included an indemnification provision “established in Order No. 2003 and clarified in Order No. 845.”

The RTO crafted the ISA and ICSA in 2002, after FERC’s Notice of Proposed Rulemaking on Order 2003, but before the commission issued the final rule that included the indemnification provision.

“In 2004, when PJM submitted its Order No. 2003 compliance filing, PJM failed to amend any option-to-build provisions, leaving the indemnification provision out of the PJM Tariff,” AEPSC explained to FERC.

The company contended that the indemnification provision is “one of the safeguards the commission included in the pro forma LGIA to address concerns that interconnection customers’ exercising the option to build could adversely affect transmission system safety and reliability.”

No Delay in Relief

In its response to the complaint, PJM contended that it already plans to add an “indemnification paragraph” to its pro forma ICSA as part of its upcoming Order 845 compliance filing.

Ordering modifications to the pro forma ISA and ICSA would be premature, PJM said, and would serve to undermine its stakeholder process.

“Because Order No. 845 addresses some of the same issues as the complaint, action on the complaint while PJM’s Order No. 845 compliance filing is pending is an inefficient use of regulatory resources,” the RTO said.

Guernsey Power Station agreed with PJM, saying the complaint is an attempt to “unilaterally rewrite the PJM Tariff without following the stakeholder process, imposing revisions that erect barriers to generator interconnection.”

PJM also argued that any deviations from Order 2003 in the pro forma ISA and ICSA “reflect an independent entity variation, vetted through stakeholder processes and accepted by the commission.” The RTO also argued that its current rules give TOs “sufficient protection.”

However, East Kentucky Power Cooperative, Duke Energy, FirstEnergy and PPL intervened in support of the complaint, arguing that TOs should expect equal treatment both inside and outside of PJM with respect to the indemnification protections.

FERC agreed.

“We find that PJM’s lack of an indemnification provision in the pro forma ICSA for facilities constructed under the option to build is inconsistent with the policy established in Order No. 2003 and creates an unjust and unreasonable result for transmission owners that must take title to customer-built facilities,” FERC said.

The commission also said relief couldn’t wait for PJM’s upcoming Order 845 compliance filing.

“Because we find PJM’s Tariff unjust and unreasonable, we direct PJM to file revised Tariff records that include an indemnity provision in the pro forma ICSA that complies with Order No. 2003 within 30 days of the date of this order rather than waiting for compliance with Order No. 845.”

But FERC declined to order all of AEPSC’s proposed revisions, including one that would have granted TOs indemnity on design, engineering and installation in addition to construction of the interconnection facilities constructed under the option-to-build provision. FERC also rejected AEPSC’s proposal to remove the limitation on damages of interconnection customer’s liability in both the pro forma ISA and ICSA.

However, FERC ordered PJM to add language to the pro forma ICSA giving TOs the right to review and approve a customer’s engineering design of an interconnection facility.

May 14, 2019February 1, 2024

RTO Board Members Share Views on Oversight Role

By Rich Heidorn Jr.

WASHINGTON — Day Pitney attorney David Doot had a list of questions to ask the present and former RTO board members on a panel he moderated at the Energy Bar Association’s annual meeting May 6. But the alpha dog board members quickly seized control, asking each other questions rather than wait for prompting.

Former PJM Chair Howard Schneider started, asking his fellow panelists, “Are boards policymakers?”

Barney Rush, a member of ISO-NE’s board, said he saw the board’s role as akin to the “town crier” in identifying problems.

“We’re listeners,” said MISO Director Barbara J. Krumsiek, former CEO of Calvert Investments. “We have to be very careful and diligent listeners.”

Former MISO Chair Michael Curran, now on the ISO-NE board, jumped in with his own question, asking whether boards serve as “thought leaders.”

“More often than not, we’re reactive to stakeholder problems,” responded Rush. He recounted the discussions the board, the New England Power Pool, the New England Conference of Public Utilities Commissioners and New England States Committee on Electricity had in 2017 on whether to implement a carbon tax in the region. (See ISO-NE Effort to Accommodate States Leaves them Alienated.)

“Once it became a nonstarter to the states, we dropped it,” he said.

Krumsiek, a mathematician and former Pepco Holdings Inc. director, said the board has an important role in strategy development. “The energy sector as we all know is undergoing the most significant disruption and innovation in its history and arguably the most significant disruption and innovation of among all industries,” she said.

As a result, MISO’s board meets twice annually. “I’ve never been on a board that’s met twice a year for strategy,” she said. “But our industry demands it.”

MISO also has created a standing technology committee to address cybersecurity and ensure its market systems evolve to handle new products, she said. “The urgency of this is clear. All the disruption we’re talking about is often technology-solved and technology-driven.”

Doot, who serves as secretary to NEPOOL, ISO-NE’s stakeholder body, eventually got to ask more of his questions, querying the panel on board turnover and other matters.

Providing Oversight Without Being Overbearing

Discussing the need for board members to provide active oversight without meddling in day-to-day operations, Krumsiek said she follows the advice she received from Curran when he was on the MISO board: “Noses in, fingers out.”

Rush said the ISO-NE board asks two questions when management comes to it with a proposal. “One question is, ‘What is the actual substance of the issue you’re asking us to think about and what are you asking us to respond to?’ The other that’s always in our minds is, ‘Are we comfortable with the process that you undertook to come to that recommendation to us?’ Do we feel that you have undertaken the appropriate review, ventilation, thoughtfulness, consultation with everybody?”

Licensing for FTR Traders?

When Doot opened questions to the audience, Direct Energy’s Marji Philips cited the GreenHat Energy default in PJM’s financial transmission rights market, asking when boards should “push back” on their executives. (See Report: ‘Naive’ PJM Underestimated GreenHat Risks.)

Schneider responded first but said he could not comment on the default, noting “I was out of [PJM] by the time it blew up.”

Curran, who also serves on the NASDAQ board of directors, said the incident highlighted the need for licensing of traders to “take these bad players out of the market.” GreenHat’s two principals had come to FERC’s attention earlier for their roles in J.P. Morgan Ventures Energy Corp.’s scheme to manipulate the CAISO and MISO markets between 2010 and 2012.

“You misbehave, we’ll pull your license,” Curran said. “It’s being performed at other organizations. Why wouldn’t we consider it?”

Krumsiek said she also favored licensing of traders in RTO markets. GreenHat “would not happen in most financial markets,” she said, adding, “To have expected RTO markets to have reached maturity in 20 years is probably [unrealistic].”

Board Independence and the Role of the States

Schneider, who was part of PJM’s first Board of Managers in 1997, recalled that when the board was formed, one sector, which he did not name, sought veto power on issues the board could consider. The board refused to sit unless the veto power was eliminated, he said. “And that spark of independence has remained throughout,” said Schneider, a senior consultant at Charles River Associates.

Schneider called the states “key policy players in the RTO paradigm.”

“And while an RTO is quasi-governmental in a sense, the states — for whatever reason — initially chose not to become members of PJM. In retrospect, I think that was a mistake,” he said.

Acknowledging there are pros and cons to state participation, Schneider continued, “The pros to me are they get in on an issue earlier. They think about the issue, and they have some [clout] as a member that they don’t have as a non-member.

“The states that we represent are not a monolith. The states have different views and they need to come across with their views in the context of a stakeholder meeting.”

“I think [on] that last point, you may have some disagreements up here and in the audience,” Doot said.

“It wouldn’t be an Energy Bar Association [meeting] if there weren’t disagreement,” joked Schneider, the only lawyer among the panelists.

“Fair point,” responded Doot.

May 14, 2019

Texas PUC Briefs: May 9, 2019

The Public Utility Commission of Texas last week gave its final blessing to a $1.37 billion transaction involving Oncor, Sharyland Utilities and Sempra Energy (Docket 48929).

The commission signed off on the order during its Thursday open meeting, after first requesting clarification to language on certificates of convenience and necessity (CCNs) that it found confusing.

PUC Chair DeAnn Walker filed a memo before the meeting that said “having multiple CCNs can be confusing” and asked the parties to ensure the final order would not lead to unintended consequences before approving a transaction that has spent months before the commission.

“We have no concern with the brilliant memo you wrote,” Oncor General Counsel Matt Henry said.

Not to be one-upped, Lino Mendiola, legal counsel for Sharyland Utilities, said, “Matt stole my words.”

PUCT — Sharyland Utilities’ Lino Mendiola (center) explains the intricacies of the deal as Oncor’s Matt Henry (left) listens.

The series of transactions will result in Sempra, which acquired Oncor last year, gaining a 50% stake in Sharyland Distribution & Transmission Services and Oncor taking ownership of Sharyland’s transmission-owning InfraREIT. The asset exchange will extend Oncor’s footprint in West Texas and “de-REIT” the Sharyland utility in South Texas. (See Oncor-Sharyland-Sempra Deals Inch Toward Approval.)

The parties agreed to regulatory commitments that include a promise to provide $17 million in merger-savings rate credits and to implement a ringfence at Sharyland Utilities. Oncor and Sharyland also agreed not to seek recovery of nearly $39 million of outstanding regulatory assets.

PUC Amends Resource Adequacy Rules

The commission amended a portion of its agency rules related to resource adequacy in ERCOT and also repealed outdated language that referred to a high systemwide offer cap of $4,500/MWh (now $9,000/MWh).

The amended language will update reporting requirements “consistent with current practices” and ERCOT protocols and clarifies that the gird operator will still be able to administer pricing mechanisms, such as the operating reserve demand curve, after the peaker net margin threshold is reached and the low systemwide offer cap is applied (Project 48721). (See “Reduction in Peaker Net Margin Threshold Tabled,” ERCOT Technical Advisory Committee Briefs: March 27, 2019.)

Commission Assesses $136K in Penalties

The commission also approved three settlement agreements representing more than $136,205 in administrative penalties.

Real estate investment firm The Connor Group was fined $96,205 and ordered to provide refunds totaling $88,794 to current and former tenants related to billing of common-area electric charges (Docket 48925).

Oncor agreed to pay $25,000 for inaccurate disconnect switch telemetry that may have contributed to higher-than-normal market prices (Docket 48926).

Ector County Energy Center was docked $15,000 for a non-spinning reserve service failure (Docket 48927).

— Tom Kleckner

May 14, 2019

NERC Standards News Briefs: May 8-9, 2019

ST. LOUIS — The NERC Board of Trustees voted Thursday to approve a supply chain report and a new standard on third-party transient electronic devices while retiring 84 reliability requirements. Below is a summary of the actions on, and discussions of, standards at the May 8-9 meetings of the Trustees and the Member Representatives Committee (MRC).

Standards Efficiency Review Retirements OK’d

Completing Phase 1 of the Standards Efficiency Review (SER) project begun in 2017, the trustees approved the complete retirement of 10 standards and the elimination of some requirements for seven standards.

NERC also approved the withdrawal of MOD-001-2, which has been awaiting FERC approval since February 2014 (RM14-7). It was intended to ensure that calculations of available transmission system capability support reliability and that the methodology and data behind the calculations are disclosed to applicable registered entities. The standards authorization request (SAR) said the standard was no longer needed because other standards, including subsequent improvements to transmission operator rules, ensure that real-time operations observe system operation limits.

Each of the changes received 87 to 97% approval on balloting that closed May 2, said Howard Gugel, vice president of engineering and standards. (See NERC Standards Retirements Go to Final Ballot.)

In total, 77 requirements and part of one requirement are being retired in addition to the six MOD requirements being withdrawn.

The seven standards for which only some of the requirements were eliminated were given updated version numbers reflecting the revisions:

FAC-008-4 – Facility Ratings
INT-006-5 – Evaluation of Interchange Transactions
INT-009-3 – Implementation of Interchange
IRO-002-7 – Reliability Coordination – Monitoring and Analysis (reflecting the retirement of Requirement R1 and a variance for reliability coordinators in WECC; see below.)
PRC-004-6 – Protection System Misoperation Identification and Correction
TOP-001-5 – Transmission Operations
VAR-001-6 – Voltage and Reactive Control

Gugel said FERC staff have expressed concerns over a few of the retirements but that NERC staff agree with the rationale provided by the standards development team and are confident that the retirements will not cause any vulnerabilities. “When we file this with FERC, we will provide additional supporting arguments and lay out how all these standards requirements hold together to bridge any potential gap,” he said in response to a question from Chair Roy Thilly.

Team Reviewing Feedback on SER Phase 2

Phase 2 of the Standards Efficiency Review is considering changes in six areas of the organization’s operations and planning (O&P) and critical infrastructure protection (CIP) standards.

John Allen, chair of SER Phase 2, briefed the MRC on the results of the industry survey that ended March 22 with submissions from 75 participants. (See “Chair Urges Comments on Standards Efficiency Review,” NERC Standards Committee Briefs: March 20, 2019.)

Participants were asked to indicate via a 1-10 scale how much they supported each of six concepts.

Changes to the evidence-retention rules, which vary by standard, ranked highest at 8.12, said Allen, manager of reliability compliance for the City Utilities of Springfield (Mo.). It was closely followed by consolidating information/data exchange requirements (8.11); moving requirements to guidance (7.85; and developing a risk-based standards template (7.78).

Less popular were relocating competency-based requirements to the certification program/controls review process (6.85) and consolidating and simplifying training requirements (6.19).

The Phase 2 team will use the feedback to evaluate and prioritize the concepts for potential action.

Trustees OK WECC Variance; Questions on Gen-only RC, Calif.-Ariz. Seam

The trustees approved reliability standard IRO-002-6 (Reliability Coordination – Monitoring and Analysis), which adds a variance for the WECC region to address its transition to multiple reliability coordinators (RCs) with the demise of Peak Reliability. (It was immediately supplanted by IRO-002-7, reflecting the retirement of Requirement 1 from SER Phase 1.)

The variance requires each RC to develop a “common interconnection-wide modeling and monitoring methodology” for use in operational planning analysis and real-time assessments, including facility ratings, thermal limits and steady state voltage limits.

“Actions that happen up in the Northwest can impact the Southwest, so for us it’s important to have that coordination across the entire model,” David Godfrey, WECC’s vice president of reliability and security oversight, told the board in an update on the RC transition.

The Eastern Interconnection, which has 16 RCs, has not asked for the standardization requirement WECC sought, Gugel said.

“In the Eastern Interconnection, there’s a lot of coordination that occurs there, but the geographic spread and regional diversity there sometimes doesn’t lend itself to requiring a common model,” he said. “Something going on in Florida for an operation situation may not be necessary for the folks up in Manitoba. It does seem to be necessary out in the Western Interconnection, but we’re continuing to evaluate whether it would be necessary in the East.”

Godfrey’s presentation included a map showing most of the West has chosen CAISO’s or SPP’s RC services but that several generation-only balancing areas — wind, solar and gas units — have selected Gridforce Energy Management.

“This will fit within our certification criteria?” Thilly asked.

“We’re early in that part of the process,” responded NERC General Counsel Charlie Berardesco. “I would ask a little patience as we consider the application and the actual technical details. … We haven’t made a determination on anybody yet.”

CEO Jim Robb said the transmission operators and balancing authorities are accountable for ensuring they have an accredited RC.

“We’ve made it very clear when this whole regime change started to occur a year-and-a-half ago that if — by the time Peak winds down — there aren’t certified reliability coordinators in place, we pull out heavy-duty enforcement actions,” Robb said.

He also said he was concerned about the seam between Arizona and California, noting “that’s been a corridor where bad things have happened in the past.”

“Are we pretty confident that seams agreements that are being developed will provide for fairly seamless operations on those paths?” he asked Godfrey.

Godfrey said he was, adding, “We will continue to monitor that to make sure that [the agreements are] enforced.”

NERC Task Force to Build on EPRI EMP Study

Mark Lauby, NERC senior vice president and chief reliability officer, told the MRC that the organization is launching a task force in response to the Electric Power Research Institute’s April report on the threat of electromagnetic pulses.

The EPRI report concluded a high-altitude nuclear explosion could cause a multistate electric outage but not the nationwide, months-long blackout some observers have warned of. (See EPRI Report Downplays Worst-Case EMP Scenario.)

Lauby said the task force will review the EPRI report to identify additional research needs and best practices and potential reliability standards for mitigating the impacts. He noted that the report did not look at the impacts on generation.

The group is expected to begin work this month and present any SARs to the Standards Committee, if needed, in the fourth quarter.

“This is not to relitigate the research results,” Lauby said. “But rather, now with what we’ve learned from those results … we are better informed to understand exactly what makes sense from a guideline perspective or standard perspective.”

Robb told the Board of Trustees on Thursday that Lauby has laid out an “aggressive” timeline.

“We now understand the science,” he said. “So we can galvanize our resources, and industry’s, to start to think through, ‘OK, what sort of response is required here?’”

Supply Chain Report Recommends Expanding Standards

The trustees accepted staff’s Supply Chain report, which recommends revising the supply chain standards to address electronic access control or monitoring systems (EACMS) and physical access control systems (PACS) to high and medium impact bulk electric system cyber systems. Monitoring, alarming and logging systems would be excluded.

FERC ordered NERC to expand protections to EACMS last October, when it approved the organization’s supply chain standards: CIP-013-1 and modifications in CIP-005-6 and CIP-010-3 (RM17-13, Order 850). (See FERC Finalizes Supply Chain Standards.)

Among the best practices cited in the report are use of “well-known, trusted and established vendors” and those with third-party accreditations or self-certification of their supply chain practices.

“We stand ready to facilitate; we don’t intend to be the accreditor but do want to be a part of the process,” Gugel told the MRC on Wednesday.

The report did not recommend including all low-impact BES cyber systems in the standards but called for additional study on whether low-impact systems with external routable connectivity should be covered. Staff are working on a data request under Section 1600 of the NERC Rules of Procedure to obtain additional information on the subject. It also will continue monitoring the issue through questionnaires and surveys.

To address potential risks to such systems in the interim, staff will work with the Critical Infrastructure Protection Committee (CIPC) Supply Chain Working Group to develop guidelines to help entities evaluate their protected cyber assets on a case-by-case basis. The report also recommends that entities refer to best practices of the North American Transmission Forum, North American Generation Forum, National Rural Electric Cooperative Association and the American Public Power Association.

CIP Standard Approved

The trustees approved CIP-003-8 (Cyber Security – Security Management Controls) in response to FERC’s April 2018 order approving CIP-003-7 and directing NERC to modify it to “mitigate the risk of malicious code that could result from third-party transient electronic devices.”

Section 5.2.1 in Attachment 1 of CIP-003-7 requires the use of at least one safeguard before connecting a transient cyber asset to a low-impact BES cyber system, including reviews of antivirus updates and application whitelisting.

The revision adds a new section 5.2.2 to ensure that the entity acts to mitigate any risks identified in the reviews from Section 5.2.1. It requires entities to “determine whether any additional mitigation actions are necessary and implement such actions prior to connecting the transient cyber asset” (Project 2016-02).

The evidence that entities can provide of compliance include documentation from change management systems, email and contracts that identify a review.

FERC Briefing

Andy Dodge, director of FERC’s Office of Electric Reliability, provided the MRC an update on two reliability standards pending before the commission:

Comments are due June 24 on FERC’s April 18 Notice of Proposed Rulemaking proposing to adopt CIP-012-1 (Cyber Security – Communications between Control Centers), which would require protections for communication links and data communicated between BES control centers and clarify the types of data that must be protected (RM18-2 0). (See FERC Proposes Revisions to NERC CIP Standard.)

Also pending is CIP-008-6 (Cyber Security Incident Reporting), which NERC filed on March 7 in response to a July 2018 FERC order (RM18-2). The commission called for expanded reporting of cybersecurity incidents, saying attempts not currently reported could lead to bigger, more successful attacks. The standard would expand mandatory reporting to include actual or attempted compromises of an entity’s electronic security perimeter (ESP) or associated EACMS. (See FERC Orders Expanded Cybersecurity Reporting.)

Post-technical conference comments are due May 24 on FERC’s March 28 joint technical conference with the Department of Energy on security investments (AD19-12). (See TSA Defends Pipeline Security Practices Before FERC.)

Dodge also mentioned FERC staff’s March 29 report on lessons learned from commission-led CIP audits in fiscal 2018. The second in what is intended as an annual report, it includes the results of the audits by the Office of Electric Reliability and input from the Office of Enforcement and Office of Energy Infrastructure Security.

The report makes 13 recommendations, including implementing valid security certificates within BES cyber systems; using strong encryption for interactive remote access; and replacing or upgrading “end-of-life” system components of cyber assets.

— Rich Heidorn Jr.

May 14, 2019

NERC Technology Security Committee Briefs: May 8, 2019

ST. LOUIS — Below is a summary of the NERC Board of Directors Technology & Security Committee meeting Wednesday.

Australia and New Zealand to Join in GridEx V

GridEx V will see increased international participation, including the possible use of “active injects” from Australia and New Zealand to simulate a “worldwide assault … on Western civilization,” Chief Security Officer Bill Lawrence said.

The exercise, scheduled for Nov. 13-14, also will see increased participation by the natural gas industry, he said.

The “executive tabletop” portion of the exercise, formerly constructed as a continent-wide attack, will this time affect a “specific region with severe electric and natural gas impacts,” Lawrence said. The targets will no longer be CEOs but the “operational level: the COO, CSOs, etc.”

They will discuss what they learned from “a bad, bad day on the grid in hopes, and active preparations, that it wouldn’t happen for real,” he explained.

“GridEx is a lot about information sharing and some analysis, but really it’s the engagement opportunity. It’s building those trade routes [to industry and government] that will be of particular value,” he said.

Lawrence said he was encouraged to have the participation of Australia and New Zealand, who are members of U.S.’ Five Eyes intelligence alliance, along with the U.K. and Canada. He recalled the worldwide preparations for Y2K, when it was feared that legacy computer systems that represented four-digit years with only the final two digits would be flummoxed by the change from 1999 to 2000. “We were able to see New Zealand and Australia stay lit up [on Jan. 1, 2000,] and have a much higher confidence that North America was going to be good to go as well,” he said.

E-ISAC Continues Growth

Lawrence gave the committee an update on growth plans for the Electricity Information Sharing and Analysis Center (E-ISAC), which is expected to triple in size by the end of 2022 from the 20 staffers it had at the end of 2017.

The 2020 organization chart shows a staff of 47, an increase of seven full-time equivalents for analytics, watch operations and engagement, and three for corporate support. 2020 will be the third year of a five-year strategic plan that has already seen NERC add 19 FTEs.

The ISAC plans another 14 hires for 2021 and 2022 to enable 24/7 watch operations and support investments in technology and collaboration with strategic partners.

Lawrence said the E-ISAC is using consultants to help develop policies, such as information sharing protocols, that are “repeatable and scalable as we grow our team.”

“The E-ISAC is not as mature as we should be for a 20-year-old organization,” he said.

Lawrence said the move to a 24/7 watch operation was prompted by stakeholder input. “They want somebody who is awake at the phone. Right now, we do have 24/7 coverage but it’s with duty officers with a phone by the nightstand.”

The ISAC will initiate 24/5 operations this year with 24/7 staffing in 2020.

Lawrence praised the infrastructure support NERC is providing the ISAC. “It means that I don’t need to build my own IT, HR, legal [and] external affairs [capabilities], and I can focus on the analysts that are going to provide … value.”

Lawrence Downplays Denial of Service Incident

Lawrence decried media reports characterizing a denial of service incident involving a WECC member in March as a cyberattack, saying there has been no evidence of malicious involvement.

“It was a denial of service. So, something happened to — in this case — a piece of … communications technology — [firewalls] — that for about five minutes acted like a deer in the headlights. They went offline, causing a brief breach of communications” between the control center and generation.

The unnamed company disclosed the March 5 incident to the Department of Energy in an electric emergency and disturbance report (OE-417) that said it affected Kern and Los Angeles counties in California; Salt Lake County, Utah; and Converse County, Wyo. although no customers were impacted.

Lawrence said the incident led to a “leap to conclusions” that it was caused by hackers.

“But in this case, it might have been that or something as simple as a scan that detected this certain vulnerability that’s known about these [firewalls]. So, you update them with a patch and they’re good to go against that vulnerability,” he explained. “It’s not a distributed denial of service where somebody is just slamming against the firewall and keeping the communication systems down. It’s a hiccup, and they come back on and we gain visibility.

“There was no generation loss; no customers lost service,” he said, adding that a root-cause analysis is being conducted. “Calling it a cyberattack stretches the definition of cyberattack.”

The following day, however, FERC Commissioner Bernard McNamee described the incident as an “attack” during remarks to the Board of Trustees. McNamee said afterward he was speaking based on media accounts and not information shared with FERC.

— Rich Heidorn Jr.

May 14, 2019

Stakeholder Soapbox: PJM Slowing Change to Clean Grid

By Jennifer Chen

PJM is seeking to procure more reserves at higher prices by augmenting its o perating r eserve d emand c urve.

PJM’s current and proposed ORDCs | *PJM*

Because the reserve and energy markets interact, energy prices will increase too. Consumer costs could grow by $512 million to $1.7 billion per year, and about 95% of this revenue would flow to fossil and nuclear resources.

CO₂ emissions could increase by up to 537,000 short tons (or decrease by about 116,000 short tons if higher prices bring down energy consumption). On the high end, CO₂ emissions would roughly equal driving another 100,000 cars around for a year.

Comments on PJM’s proposal are due May 15 at FERC.

What is the problem PJM is trying to solve?

Operating reserves provide insurance against uncertainty in future supply and demand, which a grid operator must balance. A power plant might fail, demand might spike, or there may be less wind and solar power available than forecasted.

PJM believes that its market is not procuring enough or sufficiently paying reserves that can start up within 10 to 30 minutes. To be clear, PJM is not claiming that there are insufficient reserves on its system or that reliability is at stake in the near term. With 40,000 MW of excess capacity, PJM has a surplus accessible to its control room operators. However, PJM would rather procure a consistently higher level of reserves through its market and rely less on its operators committing and compensating reserves as needed.

PJM also asserts that a higher penetration of renewables will require more accurate market price signals and improved grid flexibility.

What kinds of reserves, how much and are there substitutes?

Less reserves are needed as future uncertainty decreases. Improving forecasts reduces uncertainty, as does shortening the forecast’s look-ahead horizon. For example, the wind forecast 10 minutes from now is dramatically more accurate compared to the forecast for 30 minutes or an hour from now.

PJM — Wind forecast average absolute percent error quickly diminishes with forecast horizons shorter than an hour. | *National Renewable Energy Laboratory*

PJM’s proposal focuses on 10-minute start-up reserves to address the uncertainty in a 30-minute look-ahead forecast and 30-minute start-up reserves for a 60-minute look-ahead. But modeling shows that shortening the look-ahead from 30 minutes to 15 minutes in PJM’s proposal reduces the amount of reserves needed and cuts the proposal’s estimated costs by about $183 million per year, or about 36%.

Newer, faster resources can help address uncertainties on shorter time frames, but older, less flexible resources need longer advance notice. Current market and operational rules are tailored to conventional resources, but market rules that enable operating the grid closer to real time can incentivize more flexibility from resources.

Ensuring that the grid can cost-effectively integrate renewables is important, but PJM singles out a particular kind of reserve instead of prioritizing reforms based on a comprehensive assessment. For example, PJM’s 2014 Renewable Integration Study found that it can operate its system with up to 30% of its energy generated by wind and solar without significant reliability issues by investing in transmission and adding regulation reserves. PJM’s variable renewable penetration is low, so it has time to pursue these reforms.

PJM — VRE here includes wind, solar photovoltaics and concentrating solar power. | *National Renewable Energy Laboratory*

Regulation reserves can respond within milliseconds to minutes and correct for inaccurate forecasts in real time, much faster than the reserves PJM is seeking to increase. CAISO, ERCOT and SPP — grid operators with more renewables than PJM — provide separate regulation up and down services. This helps when wind generation is high at night, demand is at its lowest and inflexible power plants operating at their minimum levels cannot further reduce output. Regulation down would be more valuable than regulation up in this case and could be provided by energy storage or responsive demand from customers. Regulation reserves decrease the need for reserves with slower response times, such as those PJM is seeking to beef up.

Load-following reserves operate on the minutes to hours time frame (similar to the reserves in PJM’s proposal) and can offset net demand after accounting for daily variation in renewable generation. However, there are substitutes for this type of reserve that also provide other services and thus may be more cost effective. Today, the energy market itself provides a load-following service. Accurate wholesale energy prices can attract resources capable of responding within five minutes. They can also encourage customers to reduce or shift demand to save and earn money through demand response. Transmission and newer technologies also reduce the need for load-following reserves by relieving congestion and evening out the variations in renewable generation.

Thus, before deciding to procure more 10- to 30-minute start-up reserves, PJM could improve its forecasts; shorten its look-ahead; consider increasing regulation reserves and separating them into up and down services; invest in needed transmission (particularly newer technologies implementable today); and improve energy price signals.

Which resources benefit from PJM’s proposal?

PJM’s proposal would procure more reserves from coal and gas plants that can ramp up, fast-start diesel generators and energy storage resources. Some flexible technologies will get a boost from reserve revenues, but the largest share of reserve revenue would accrue to gas plants that are already experiencing explosive growth from PJM’s capacity market and to coal plants that could receive a six-fold increase in payments per year to provide synchronized (or spinning) reserves. Some of this revenue would be from plants staying online overnight at minimum output when demand is low.

Wind, solar and nuclear resources are ineligible to provide reserves unless they demonstrate their capability. DR could qualify to provide reserves up to a limit under PJM’s proposal, but the 8,000 MW of DR committed through the RTO’s capacity market is emergency-only and not economically dispatched in its energy and reserves markets.

Separate from higher reserve payments, more than 70% of the revenue increase from PJM’s proposal comes from higher energy market prices. Energy prices increase with higher reserve requirements because resources deployed to generate energy cannot provide reserves, so there is a lost-opportunity-cost payment folded into energy market prices.

Energy price increases make sense when there is a shortage of energy resources. But the modeling of PJM’s proposal shows that it consistently raises energy market prices when there is no shortage because additional reserves are being procured most hours of the year, even during off-peak times and seasons.

Graph produced from PJM’s data. Energy prices for nearly all hours, including off-peak hours, are bumped up even during shoulder months. | *PJM*

So under PJM’s proposal, inflexible generation that is always running benefits from consistently inflated energy prices. For example, coal plants could earn another $120 million to $420 million per year in higher energy revenues on top of higher reserve revenues. Solar, which only produces energy during daylight hours, gets a smaller boost than around-the-clock resources.

Many of the power plants benefiting from the reserve payments and inflated energy prices also receive capacity market payments to be available at all times. The capacity market is intended to supply the revenues needed to maintain a certain level of capacity in PJM that are not available through the RTO’s other markets. Thus, higher energy and reserve revenues should translate to lower capacity revenues. However, any capacity revenue reduction to offset higher energy and reserve costs would not be timely nor commensurate without significant rule changes.

Does PJM’s proposal improve price incentives during times of grid stress?

PJM’s proposal would over-procure reserves (similar to how its capacity “demand curve” over-procures capacity). PJM’s modeling shows that consistently keeping more reserves on the system actually depresses energy prices when the grid is stressed while maintaining higher prices during off-peak times. For example, keeping large power plants running at their minimum output levels would enable them to ramp up and provide energy during peak. Over the peak period, this could be cheaper than deploying reserves that can quickly start without being online, but customers would pay more overall to consistently maintain a higher level of reserves.

PJM — Current status of demand response. “Capacity” here includes market products like reserves that guarantee supply. | *International Energy Agency*

Lower prices at peak mute the incentive for flexible resources such as energy storage and DR to participate, while inflated prices overall would inefficiently subsidize inflexible baseload to stay on. This cost would be socialized among all customers, shifting costs to customers who value reserves the least and would rather manage their energy consumption to save money.

Higher prices during times of grid stress with lower prices overall can offer more distinct and accurate price signals to flexible resources while enabling consumers to save. The potential for DR is still largely untapped (estimated to be about 15% of electricity demand), and a key barrier is a lack of price signals.

An alternative to boosting reserves to ensure future reliability

The ultimate goal is not to procure a certain amount of reserves at a sufficiently high price, nor is it to automate through the market potentially inefficient actions that operators take when they conservatively commit extra reserves. The goal is to design markets to produce efficient outcomes and, in doing so, maintain reliability standards and improve grid flexibility cost-effectively.

A market solution that avoids the market distortions introduced by PJM’s proposal is to allow real-time energy prices to reflect the marginal cost of resources delivering that energy. Today, energy offers are capped below what many would consider the willingness of customers to pay for energy (known as the value of lost load).

With such a cap in place, operators are likely to procure additional reserves the market does not commit, without knowing whether consumers want the extra reserves. But if the market accurately values energy, the operators will know that the market is procuring the efficient level of resources and no additional reserves are required.

PJM could propose to lift energy market offer caps beyond the $2,000/MWh permitted for the purposes of setting energy market prices, while verifying that offers above a threshold are based on costs to safeguard against market power. As noted by former FERC Commissioner Norman Bay, the commission, market operators and market monitors are better equipped today to ensure that nothing like the Western Energy Crisis happens again.

Energy, not reserves, is the most fundamental product in the electricity markets today, and ensuring it is accurately valued through market dynamics should precede efforts to administratively set the value for other market products. Enabling true scarcity pricing by allowing real-time energy prices to reflect marginal costs will result in more accurate prices compared to raising energy prices through an adder reflecting a PJM-determined reserve value. Properly valuing energy will enable us to better evaluate how much reserves we truly need.

Jennifer Chen, senior counsel of federal energy policy at Duke University’s Nicholas Institute.

May 14, 2019

MISO Tames Flows on North-South Transfer Limit

By Amanda Durish Cook

CARMEL, Ind. — MISO says a new process to better contain flows on its North-South settlement transmission path is working as intended.

The new practice was prompted by a MISO South maximum generation event in January 2018, where the RTO exceeded the limit on the transmission linking its Midwest and South regions over multiple dispatch intervals. (See Louisiana Regulators Question MISO South Max Gen Event.)

MISO staff spent several months reassessing the RTO’s control of transfer flows after the violation, Director of System Operations Tim Aliff said during a Market Subcommittee meeting Thursday.

Now, MISO has switched from using its Unit Dispatch Systems (UDS) to “real-time and raw measurements” to reduce instances where the limits are exceeded, Aliff said. As of August 2018, the RTO also reduced the effective transfer limit in its system to 90% of contractual values.

Aliff said the two dispatch methods — using UDS and real-time operator monitoring — can result in different megawatt predictions on the settlement path.

MISO said its strategy so far “has resulted in greatly reducing number and duration of exceedances.” Aliff said using a 90% threshold of the settlement limit dramatically cuts — but doesn’t eliminate — limit overruns. From January to August 2018, MISO exceeded transfer limits on 2,073 occasions. Since August 2018, MISO has exceeded the limits 522 times.

Customized Energy Solutions’ Ted Kuhn said the changes make MISO “a good citizen.”

WPPI Energy economist Valy Goepfrich asked whether the RTO intentionally violated settlement limits using the UDS in January 2018 to dispatch the North in order to serve the South.

“We didn’t plan to exceed the limits,” Aliff answered, saying a variety of factors, including a dearth of generation in MISO South, caused the RTO’s raw flows to exceed the settlement limits.

During the past winter, Independent Market Monitor David Patton observed that the settlement path bound frequently in the south-to-north transfer direction because of cold weather in the northern part of the footprint. He said MISO had been derating regional transfers from what was originally scheduled so it didn’t exceed the megawatt limits laid out in its settlement agreement with SPP. Patton said such derates caused the contract path to bind almost 300 MW below the megawatt limit on average this winter.

“I think it’s worth in the future thinking about how to calibrate these scheduling limits so we’re making full use of the” regional directional transfer, Patton said at an April 11 Market Subcommittee meeting, adding that both the South and Midwest regions benefit in different seasons with full use of the megawatt limit.

While MISO came close to violating the 2,500-MW limit on the south-to-north constraint during the Jan. 30-31 maximum generation emergency, it did not ultimately exceed the limit. The settlement agreement stipulates that MISO has an obligation to reduce internal transfers within 30 minutes once the limit is exceeded. The two RTOs also agreed that transfer limits can be temporarily increased or decreased to avoid a system emergency, provided there is adequate communication and the actions don’t cause an emergency in a neighboring balancing authority. MISO and SPP maintain a six-member operating committee composed of their staffs and joint party representatives to oversee compliance with the settlement agreement.

MISO is also currently accepting proposals for projects designed to relieve the North-South transmission constraint, predicting the settlement path flows will become increasingly expensive. (See MISO Seeking Proposals to Relieve North-South Constraint.)

The RTO said it will continue to monitor and calibrate flow control to determine whether additional changes are needed.

May 14, 2019

Ex-Coal Plant Site Chosen for Mass. OSW Hub

By Rich Heidorn Jr.

In an announcement rich with symbolism, transmission developer Anbaric said it will spend $650 million to build a delivery hub for offshore wind at Brayton Point, the former site of New England’s largest coal-fired plant.

Anbaric said it will spend $250 million on a 1,200-MW HVDC converter to receive offshore wind power and another $400 million on 400 MW of battery storage at what it is calling the Anbaric Renewable Energy Center. The May 13 announcement by Anbaric and Commercial Development Co., the owner of the 307-acre site in Somerset, Mass., came just days after the former coal plant’s 500-foot cooling towers were imploded.

Terms of the lease between the two companies were not released, but CDC Executive Vice President Stephen Collins said the lease is “very long.”

Anbaric CEO Edward Krapels said the project is part of his company’s plan for its Massachusetts OceanGrid to bring wind power from projects off southeastern Massachusetts, Cape Cod, Nantucket and Martha’s Vineyard to ISO-NE.

Stephen Conant, an Anbaric partner and project manager for the Brayton Point project, said construction could begin as early as 2021, depending on how soon Anbaric signs up generation to use the facilities.

Anbaric is counting in part on Massachusetts’ 2016 directive ordering Eversource, National Grid and Unitil to procure 1,600 MW of offshore wind.

Conant said his company will partner with an unnamed generator to bid for an 800-MW OSW solicitation the utilities are expected to issue later this month. But he said Anbaric is “open to working with any and all” OSW generators, including those off of Rhode Island and Connecticut.

“It’s a very attractive site,” he said, noting the 1,600-MW interconnection from the old coal plant. “It’s the best interconnection facility on the south coast” of Massachusetts.

Anbaric file d a 1,200-MW interconnection request with ISO-NE in March, and Conant said the company could seek to increase that to 2,400 MW with upgrades.

The company received FERC approval in February 2018 to conduct an “open season” bidding process for OSW developers to use its Massachusetts OceanGrid to deliver OSW power to ISO-NE (ER18 –435).

Anbaric said it expects its project to create 300-400 construction jobs over a two-year period, with five to 10 full-time employees running the center once completed.

“It’s certainly not going to replace the number of jobs lost at the coal plant,” which employed about 250, Conant acknowledged. But he said the “real jobs are going to come from the growth of offshore wind … and well-developed infrastructure will make that happen.”

Conn. Adding 2,000 MW?

Connecticut and Rhode Island have agreed to purchase 700 MW of OSW from Eversource’s and Ørsted’s Revolution Wind project between Martha’s Vineyard and Block Island.

In addition, the Connecticut House of Representatives on Tuesday approved legi s lation that would authorize Eversource and Avangrid subsidiary United Illuminating to procure an additional 2,000 MW of offshore wind. The bill, which is headed to the state Senate, calls for the issuance of a solicitation within two weeks of passage to take advantage of expiring federal tax credits, Conant said.

But Connecticut officials have their own plans for capitalizing on their procurements, earlier this month anno u ncing agreement on a $93 million public-private partnership to make State Pier in New London an OSW hub.

Other Tenants?

Anbaric’s project will take only 20 acres of the former power plant’s 300-acre site, which CDC has renamed Bray t on Point Commerce Center.

Collins said the company is “actively engaged” with about a half-dozen additional potential tenants interested in the site and its 34-foot deep port, some of them also in offshore wind or energy. “There’s an enormous amount of interest at this site,” he said. “I’ve had five meetings in the last two days.”

Bay State Wind announce d a year ago it would build turbine foundations at the site if it won Massachusetts’ first 800-MW OSW solicitation, but that contract was snagged by Vineyard Wind. Collins said Vineyard Wind has talked about bringing work on the “transition piece” between the turbines’ monopole and nacelle to Brayton Point.

Anbaric has partnered with Vineyard on the Liberty Wind project in New York but was not part of its initial Massachusetts bid.

CDC purchased Brayton Point from Dynegy in early 2018 after the 1,600-MW plant, Massachusetts’ last coal generator, shut down in May 2017 after more than 50 years of operation.

Before imploding the cooling towers last month, CDC had sold much of the plant’s equipment and machinery, begun demolishing fuel oil tanks and power plant buildings and conducted asbestos abatement and other environmental remediation.

[Editor’s Note: An earlier version of this story incorrectly stated the Connecticut House passed a bill regarding offshore wind procurement on Wednesday (May 15). The bill was passed Tuesday, May 14.]

May 14, 2019

NYISO Business Issues Committee Briefs: May 13, 2019

NYISO’s Business Issues Committee on Monday approved a proposed Tariff revision that redefines acceptable collateral for foreign market participants, largely to head off cumbersome bankruptcy proceedings in foreign jurisdictions.

Sheri Prevratil, the ISO’s manager of corporate credit, presented analysis on the proposal to allow only entities formed or incorporated in the U.S. or Canada to post cash collateral.

The changes modify Section 26.6.1 of the Services Tariff and affect only four market participants, she said.

NYISO currently allows market participants to post either unsecured or secured credit, with participants not meeting unsecured credit standards required to provide secured credit.

The ISO is seeking the change to avoid the potential costs required to secure and use collateral in the case of a foreign bankruptcy. Given the potential number of jurisdictions at issue worldwide, it is not feasible for the ISO to evaluate laws in all jurisdictions to ensure its interest in cash collateral would be adequately protected, Prevratil said.

State of the Market: Peak Load Up 7%

Rising natural gas costs and increased load levels were the two key factors that drove up NYISO electricity prices by 23% to 36% in 2018, Pallas LeeVanSchaick of the Market Monitor told the BIC while presenting a summ a ry of the 2018 Sta t e of the Market Report.

The report showed peak load up 7% last year — “quite a large increase,” LeeVanSchaick said.

Average gas prices rose 21% to 47% across the state, with much of the increase caused by a cold spell in early January, while gas price spreads between western and eastern New York fell, leading to less west-to-east transmission congestion, LeeVanSchaick said.

The state’s electricity consumption rose from low levels seen in 2017, with average load up 3% and higher congestion occurring within New York City and Long Island.

“These factors also increased day-ahead congestion revenues, which we saw go up by 21% to just over $500 million in 2018,” LeeVanSchaick said.

Declining gas price spreads helped to reduce NYISO’s west-to-east transmission congestion in 2018, the Monitor found. | *Potomac Economics*

LeeVanSchaick said the current capacity market produces prices for only the four modeled capacity regions and may produce incentives for excessive investment in some export-constrained areas and insufficient price signals for investment in import-constrained load pockets or in areas that improve reliability elsewhere, such as Long Island.

The four-zone model may not allow prices to change efficiently as units retire and enter, or transmission is built, and incentive issues become more acute with anticipated policy-induced retirements and new resource additions, as well as resource retention necessary to support local reliability in NYC load pockets, he said.

Based on those considerations, the Monitor recommends implementing a more granular locational capacity pricing mechanism, LeeVanSchaick said.

Included among the multiple policies aimed at removing capacity sources are the Indian Point nuclear plant retirement, coal plant retirements and the state’s Department of Environmental Conservation proposal to curb emissions from peaker plants. (See NY DEC Kicks off Peaker Emis s ions Limits Hearings.)

LeeVanSchaick said retirement of inflexible generation is needed to make room for state-sponsored resources and flexible resources that help integrate them, and that requires efficient market incentives.

“Even if those [public policy] resources are not justified based on economics and competitive entry, there is still an opportunity to get an exemption through a Part A test … which in New York City essentially allows for 6% excess capacity,” LeeVanSchaick said. The Monitor’s Part A test is intended to exempt from mitigation any resource deemed to be economic compared with a NYISO forecast, allowing that resource to bid into the capacity market on the same basis as other resources.

Updates to Economic Planning Process Manual

The BIC approved limited updates to the Economic Planning Process (EPP) Manual, the first since February 2016, modifying the description of historic congestion data reporting.

Timothy Duffy, the ISO’s manager of economic planning, delivered a summ a r y of the changes, providing a brief overview of the separate generation deactivation process outlined in the overview section of the Comprehensive System Planning Process (CSPP).

The changes correct NYISO web links and make ministerial revisions for user readability, standardization of tariff references, inappropriate capitalizations and use of Tariff-defined terms, Duffy said.

NYISO-PJM JOA Revisions

The BIC approved NYISO-P J M joint operating agreement revis i ons, which the Management Committee will consider on May 20, and if approved, will go to the Board of Directors in June, ahead of a joint NYISO-PJM FERC filing.

Total redispatch settlement last year was “very small,” said Cameron McPherson, NYISO operations analysis and services analyst.

NYISO and PJM last September filed with FERC a joint request for waiver of their joint operating agreement to permit them to add the East Towanda-Hillside tie line as a market-to-market (M2M) flowgate. (See “NYISO, PJM Revising JOA for Tie Line Issues” in NYISO Business Issues Committee Briefs: March 13, 2 0 19.)

Robert Pike, NYISO director for market design and product management, presented the monthly Broader Regional Markets re p ort and highlighted the ongoing work to revise the JOA to address coordination on flowgates similar to the East Towanda-Hillside Tie Line.

Pike also highlighted continued stakeholder discussions regarding deliverability requirements for external capacity suppliers, including new rules such as those approved at the April BIC. (See “New External SRE Penalty” in NYISO Business Issues C o mmittee Briefs: April 17, 2019.)

The requirements relate to New York capacity market eligibility, and the objective of the effort is to better understand any obstacles preventing external resources from delivering capacity-backed energy to the New York Control Area border.

Under the new proposal, any external resource that fails to meet the criteria will be subject to the penalty, which is equal to 1.5 times the applicable spot price multiplied by the number of megawatts of shortfall and the percentage of the SRE call hours to which a supplier fails to respond.

In a separate matter, the ISO is reviving its Metering Working Group, with meetings starting in July on technical issues around metering infrastructure for distributed energy resources and storage.

LBMPs Drop 25% in April

NYISO locational-based marginal prices averaged $28.01/MWh in April, down about 25% from March and the same month a year ago, Pike said in delivering the monthly operations rep o rt. Year-to-date monthly energy prices averaged $40.12/MWh, a 27% decrease from a year ago.

Day-ahead and real-time load-weighted LBMPs came in lower compared to March. Average daily sendout was 371 GWh/day in April, lower than 411 GWh/day in March and 390 GWh/day in the same month a year ago.

Transco Z6 hub natural gas prices averaged $2.37/MMBtu for the month, down 24% from March and 15.1% from a year ago.

Distillate prices were down 1.5% year over year and up slightly from the previous month, with Jet Kerosene Gulf Coast averaging $14.63/MMBtu, compared to $14.18/MMBtu in March, while Ultra-low Sulfur No. 2 Diesel NY Harbor rose to $14.72/MMBtu from $14.18/MMBtu in March.

April uplift increased to -$0.15/MWh from -$0.33/MWh in March, while total uplift costs, excluding the ISO’s cost of operations, came in higher than those of the previous month.

The ISO’s $0.20/MWh local reliability share in April was down from $0.31/MWh the previous month, while the statewide share climbed to -$0.35/MWh from -$0.64/MWh in March.

The Thunderstorm Alert cost was $0.01/MWh, unchanged from March.

— Michael Kuser