Page 1123 – RTO Insider

October 3, 2018

UPDATED: Little Common Ground in PJM Capacity Revamp Filings

By Rory D. Sweeney, Amanda Durish Cook and Rich Heidorn Jr.

The first round of filings in FERC’s “paper hearing” on revisions to the PJM capacity market showed wide disagreement over the best way to address the impact of out-of-market subsidies on clearing prices.

Much of the debate in the dozens of filings focused on broadening the minimum offer price rule (MOPR) and modifying the fixed resource requirement (FRR), which were the basis of the hearing. But many stakeholders also proposed alternatives.

FERC ordered the hearing June 29 after concluding that increasing state subsidies for renewable and nuclear power were suppressing capacity prices. The commission’s 3-2 ruling required PJM to expand the MOPR to cover all new and existing capacity receiving out-of-market payments, including renewable energy credits (RECs) and zero-emission credits (ZECs) for nuclear plants. The MOPR currently covers only new gas-fired units.

The commission’s ruling rejected PJM’s April “jump ball” capacity filing (ER18-1314), granted in part a 2016 complaint led by Calpine (EL16-49) and initiated a Section 206 proceeding in a new docket (EL18-178). FERC also recommended creating an “FRR Alternative” allowing states to pull subsidized resources — and associated loads — from the capacity auction. (See FERC Orders PJM Capacity Market Revamp.)

PJM’s brief on Oct. 2 outlined its proposal for an “extended resource carve out” that builds on ideas it floated to stakeholders in August. (See PJM Unveils Capacity Proposal.)

The proposal would allow subsidized resources to obtain capacity commitments without clearing the capacity market, while creating a mechanism to restore prices to “the theoretically correct competitive level.”

The RTO said its proposal is intended to ensure both capacity offers and prices remain competitive and recognizes a bifurcated market will result in tradeoffs. “Making room, outside the auction, to accept subsidized generation as a PJM ‘capacity resource’ ineluctably will degrade auction prices. Unless the commission is prepared to accept a mechanism to adjust prices to their ‘correct’ level, this trade-off must be understood as an unavoidable consequence that comes once uneconomic resources are relieved from having to participate in the market.”

The Maryland Public Service Commission proposed what it called a “competitive carve-out approach” in which “a certain amount of load associated with the implementation of state policies is carved out of the existing capacity market and a separate competitive carve-out auction [is held] to meet the capacity needs associated with this amount of load.”

“This capacity would be provided by resources eligible to meet any state’s environmental policies,” the PSC wrote. “In effect, this proposed approach recognizes that, in the aggregate, resources eligible to meet states’ environmental policies and receive revenues for environmental attributes, may be capable of providing capacity to help meet the reliability requirements of all states and the region.”

It noted that the Organization of PJM States Inc. (OPSI) supported development of the idea.

‘Hokey Pokey’

The Electric Power Supply Association said the commission should prioritize protecting the capacity market from price suppression over accommodating state policies. It said the FRR Alternative would “effectively nullify” an expanded MOPR and could lead to the unraveling of the market.

“The FRR Alternative will actively push states towards the path of partial reregulation by letting them choose to be part in and part out of the [capacity] construct and, more importantly, away from reliance on competitive, organized markets,” EPSA said. It said the order would allow a state “to play the capacity market hokey pokey, putting its left foot into the [Reliability Pricing Model] market and pulling its right foot out.

“Even if the FRR Alternative provides greater transparency, that transparency does not make the resulting reregulation any more planned or any less damaging to what remains of the market,” EPSA said. “The only advantage of the transparency afforded by the FRR Alternative is that ‘investors, consumers and policymakers’ will have the opportunity to watch the collapse of the markets on the equivalent of a live-feed.”

Carbon Pricing

Eastern Generation, an EPSA member, filed a brief calling on the commission to treat the expanded MOPR as a “bridge” to PJM developing a mechanism for incorporating carbon pricing into its markets. “Carbon pricing is a more durable and sustainable long-term approach that will improve the efficiency of PJM’s capacity and energy markets while accommodating state and federal clean energy policies.”

A coalition of consumer advocates, environmentalists and industry stakeholders filed a joint brief arguing for prioritization of state interests.

“We frequently disagree on many issues before this commission, and some of us even disagree on certain aspects of this proceeding, such as the circumstances that should trigger a minimum offer price rule,” said the group, which includes consumer advocates from D.C. and Illinois, the Sierra Club, Natural Resources Defense Council, PSEG Energy Resources & Trade, Talen Energy, Exelon and the Nuclear Energy Institute.

“But as to the commission’s proposal regarding a resource-specific fixed resource requirement alternative (FRR-RS), the joint stakeholders strongly agree the commission’s decision should reflect certain basic principles: The commission should protect customers from paying for duplicate capacity and should preserve states’ ability to achieve clean energy policy goals without forcing states to withdraw altogether from the PJM market.” (See Zero-Emissions Backers Propose PJM Capacity Principles.)

In its standalone brief, Exelon called on the commission to “express its willingness to entertain a Section 205 filing from PJM incorporating carbon pricing.”

“Integrating a carbon price into PJM’s markets would reduce or eliminate the need for states to address carbon emissions from the power sector in other ways,” the company said.

PURPA Resources

Allco Renewable Energy said qualifying facilities under the Public Utility Regulatory Policies Act should have the option of choosing the FRR Alternative but should not be subject to the expanded MOPR, which it said would “unlawfully restrict, interfere and diminish the congressionally mandated right of a qualifying facility to sell energy and capacity.”

Columbia University’s Sabin Center for Climate Change Law insisted state environmental policies do not interfere with FERC-regulated markets. “Unless implemented with care, FERC’s proposed Tariff revisions could interfere with the operation of state clean energy policies, effectively preventing states from exercising their authority over generation,” it said. “There is no valid basis for concluding that REC, ZEC and other clean energy policies interfere with wholesale market operation.”

A Matter of State Jurisdiction

The Governors’ Wind and Solar Energy Coalition said FERC’s minimum bid requirement would intrude on states’ historical right to choose their own energy mix: “If the commission pre-empts or restricts the states’ ability to regulate environmental effects from energy power production, it would constitute a dangerous shift in the balance between state and federal authority.”

However, the Natural Gas Supply Association said it was “heartened” by what it called FERC’s “strong defense of the competitive markets it regulates.”

NGSA said PJM’s status quo would create an “untenable” environment where investment uncertainty erodes reliability and regulators pick winners and losers.

“It is no easy task to achieve a balance that allows states to make their own procurement decisions, while still ensuring those decisions do not harm the wholesale markets in your jurisdiction. Despite considerable pressure to disregard actions that erode the integrity of PJM’s capacity market, the commission had the courage to say, ‘no more,’” NGSA CEO Dena Wiggins wrote.

The American Coalition for Clean Coal Electricity and the National Mining Association also commended FERC on what they viewed as an effort to keep PJM’s market functioning through an expanded MOPR applied to all subsidies.

However, the groups asked for an exception to the MOPR: an exemption on a possible fuel security valuation in the PJM capacity market. They said a new MOPR shouldn’t “counteract federal efforts to ensure grid resilience and promote national security.” The groups urged FERC to require PJM to create a separate capacity auction for resources that can guarantee fuel security for a minimum number of days.

PJM’s “current market design is contributing to the loss of fuel-secure electricity resources, while encouraging reliance on pipeline-dependent and intermittent resources,” ACCCE and NMA said.

EPSA countered that any federal price supports for nuclear and coal units should subject them to the MOPR.

Other Out-of-Market Payments?

In arguing against an expanded MOPR, the Union of Concerned Scientists said PJM’s proposal “would arbitrarily provide an exemption for resources that have one kind of state-supported revenue, but not for other kinds of state-supported revenue.”

UCS argued PJM’s fleet of existing resources with state-sponsored out-of-market payments is “substantial” and greater in number than PJM has characterized.

“If the fundamental principles presented by both PJM and the commission are as important as suggested, and the commission has found that any price suppression due to out-of-market payments makes the PJM capacity auction results unjust and unreasonable, then there cannot be MOPR exemptions for investor-owned plants that have been receiving cost-recovery through state-administered rates,” UCS wrote. It also said PJM did not collect the list of states with out-of-market revenues for investor-owned generation through either a renewable portfolio standard, zero-emission credit program or regulated cost-of-service.

RPS National Map | *National Conference of State Legislatures*

“All of the states in PJM have one or more of these mechanisms that provide the means for generation to either enter or remain viable in PJM’s capacity market,” UCS said.

UCS said the fact that PJM’s Tariff allows zero-priced offers is evidence of state-supported cost recovery to keep resources viable in the capacity market.

APPA: Start Over

The American Public Power Association went for a scorched-earth approach, challenging PJM’s RPM itself.

The group argued PJM’s mandatory capacity market with a strict MOPR is “ill-suited” to achieving a diverse resource mix. It said PJM’s MOPR “now threatens to become an all-purpose restriction on any support for generation outside of revenues obtained through the PJM energy and capacity markets” and could “ultimately raise capacity prices without achieving any clear benefits.”

“The time is ripe to revisit the RPM construct in a comprehensive manner,” APPA said, rather than “doubling down” on a mandatory capacity construct with a “vastly expanded MOPR.”

APPA also argued self-supply resources used to meet the load of public power and cooperative utilities should not fall under an expanded MOPR, arguing vertical integration and tax-exempt financing do not constitute out-of-market support.

IMM’s ‘Sustainable Market Rule’

PJM’s Independent Market Monitor also suggested re-envisioning the RTO’s structure with what it calls a “sustainable market rule” that it argues is simple enough to be implemented in time for the next Base Residual Auction. While the Monitor attempted to differentiate its proposal from a MOPR, it would require all resources to offer into the BRA at their avoidable cost rate (ACR).

“A competitive offer in the capacity market is the marginal cost of capacity, or net ACR, regardless of whether the resource is planned or existing,” the Monitor wrote. “All capacity has a must-offer requirement and all capacity offers are included in the supply curve in the capacity market at competitive levels. All megawatts required for reliability are included in the capacity market demand curve (VRR curve).”

The Monitor acknowledged that load-side fears might be realized with this approach, but that “the possibility that customers may pay twice has been accepted by the courts” and FERC.

CASPR Appears

Vistra Energy and Dynegy Marketing and Trade proposed the Capacity Performance with Sponsored Supply (CaPSS), which it said is based on ISO-NE’s FERC-approved Competitive Auctions with Sponsored Policy Resources (CASPR) structure.

The two-stage auction would require all resources to offer in at their going-forward costs. PJM would create a table of resource-type ACRs, and any resource that believes its going-forward costs are below its applicable value in the RTO’s table would request a review to validate its argument. The second stage would be “purely voluntary” and allow existing resources that received a capacity obligation but are willing to permanently exit PJM’s markets to “give up” their obligations “in their entirety” to resources seeking subsidies that didn’t receive obligations in the first stage.

Next Steps

FERC faces a daunting task of threading the needle between at least eight proposed options for the MOPR and numerous modifications on both its FRR concept and PJM’s carve-out. Reply briefs in the docket will be due Nov. 6.

October 3, 2018

MISO Granted Longer Deadline for Offer Caps

By Amanda Durish Cook

FERC on Monday granted MISO a two-year lead time to implement a new offer cap into its fast-start pricing mechanism, while also directing the RTO to submit yet another compliance filing to meet Order 831 requirements.

The commission’s ruling set an Oct. 1, 2020, deadline for MISO to incorporate a $2,000/MWh hard cap for verified cost-based incremental energy offers into fast-start pricing (ER17-15 7 0-0 02).

miso offer caps fast start pricing — MISO’s Carmel, Ind. headquarters | © *RTO Insider*

In a March ruling on a previous compliance filing, FERC accepted much of MISO’s plan to permanently double its hard offer cap, but it also required the RTO to pledge to apply the new hard cap to adjusted energy offers from fast-start resources. (See FERC OKs MISO’s Doubled Offer Cap, Ord e rs Alterations.)

In the event FERC denied the extra time for implementation, MISO had also sought rehearing of the commission’s March order, warning it would otherwise need permission to “resort to manual processes” to enforce the caps. Citing the ongoing replacement of its market system platform, MISO contended it would likely need more time to “make appropriate adjustments to automate the requirements of Order No. 831” and “complete necessary system software changes.” The RTO also pointed out FERC granted ISO-NE a similar two-year lead time last November.

“We find that MISO has shown good cause for the granting of this requested effective date because it will allow MISO sufficient time for the development, testing and implementation of software needed to enable MISO’s existing market platform to apply the offer cap requirements to fast-start pricing,” FERC said.

One More Compliance Filing

Monday’s order also approved other revisions FERC had ordered in the March compliance filing, although it directed MISO to refine its proposed rules to address adders to the soft offer cap.

FERC accepted MISO’s fuller description of the data verification process for offers, how it would determine make-whole payments under the new offer cap and the process allowing market participants to dispute potential revenue sufficiency guarantee make-whole payments. The commission also accepted MISO’s clarification that its Independent Market Monitor will use data from its operating cost survey to determine facility reference levels. The IMM relies on the survey to collect operating cost data for market participants.

But in siding with the argument of a group of Midwestern transmission-dependent utilities (TDUs), FERC also directed MISO to submit another compliance filing to clarify that adders included in cost-based incremental energy offers above the soft cap of $1,000/MWh must be limited to a combined $100/MWh. MISO must also make clear those adders cannot be included in a resource’s after-the-fact make-whole payment, the commission said .

FERC also denied a request for a rehearing of its March order from the same group of TDUs, who argued the commission was too quick to accept MISO’s stance that outage risk is a verifiable component of energy cost rather than part of the $100/MWh adder above the soft offer cap. The TDUs argued it was arbitrary and capricious for FERC to find that outage risk is not an above-cost adder when it only used MISO’s rationale that outage risk is already included in a resource’s reference level in its current mitigation processes.

FERC didn’t bite at their argument.

“MISO explained that outage risk is a legitimate short-run marginal cost calculated separately for each resource based on validated data provided by market participants,” the commission wrote. “MISO also explained that incorporating this risk in a resource’s reference level continues MISO’s existing mitigation processes. As such, outage risk is a proper component of MISO’s reference level and is not an adder to verifiable costs pursuant to Order No. 831. Midwest TDUs have not proffered any arguments or evidence that contradicts MISO’s explanation of these risks.”

October 1, 2018

Overheard at NECA 2018 Fuels Conference

MARLBOROUGH, MASS. — Fuel security public policy and the role of traditional and non-traditional fuels in New England highlighted discussions at the Northeast Energy and Commerce Association’s 2018 Fuels Conference on Thursday.

“Natural gas is as pertinent and important as ever, particularly in New England,” Day Pitney attorney Joseph Fagan said.

“If it’s not easy — in this region especially — to site pipeline or gas infrastructure, it only makes sense that we’ll see virtual transportation become more important. It makes sense that LNG is going to become more of an issue,” Fagan said. “How is [ISO-NE] going to address fuel security and reliability when we have the reality that we have no new pipelines coming into this state … and we have a large plant [Mystic] that — unless things change — may be retired?”

NECA held their 2018 Fuels Conference on Sept. 27. | © *RTO Insider*

In July, FERC tentatively accepted a cost-of-service agreement between ISO-NE and Exelon for Mystic Generating Station Units 8 and 9, ordering an expedited hearing process on unresolved issues related to cost justification (ER18-1639). (See “Fuel Security,” Overheard at ISO-NE Consumer Liaison Group Meeting.)

The goal to reduce greenhouse gas emissions is driving policy in the region, said Brian Jones, senior vice president of energy consultancy M.J. Bradley & Associates.

“A lot of the resources that ISO New England manages today are a product of that and have to do with air quality and GHG,” Jones said. “Fuel supply is an obvious one, and pipeline constraints into the region are another. We face a lot of challenges, with six states that have pretty aggressive policies on energy and environmental issues, and I don’t think that’s going to change.”

Virtual Pipelines, LNG, RNG

A big chunk of heating demand met by gas cannot be substituted with renewables or energy storage, and Elon Musk has not yet invented a battery-powered heater, said Andrew Bradford, CEO of energy consultancy BTU Analytics.

“What the latent natural gas demand is in New England is a good question,” Bradford said. “We look at 0.75 Bcfd in winter, 1.5 Bcfd max, and 0.5 Bcfd on the peak price day and see there could be demand for around 2 Bcfd.”

Given the constraint on pipeline supplies, “for natural gas end-users in New England, there is no silver bullet,” he said.

There could be a large truck though. The lack of gas infrastructure has created a market for Xpress Natural Gas, a compressed natural gas distributor that now sends trailer trucks from its 40-Bcfd capacity terminal in Montrose, Pa., to inject into the Iroquois Pipeline at a terminal in New York.

Gary Ritter, XNG’s vice president of sales, said the company serves customers from Prince Edward Island to the Mid-Atlantic states, both companies lacking pipeline access and “to facilities on the pipeline grid, bringing incremental supplies to capacity-constrained areas.”

The Montrose terminal last winter loaded approximately 25 MMcfd filling some 60 trailers at an average capacity of 400 Mcf each.

Shaving of natural gas peak demand is the top use of LNG in New England, such as at National Grid’s waterfront facility in Salem, which holds 12 million gallons of LNG, the equivalent of 1 Bcf of natural gas, said Jonathan Carroll, director of U.S. business development for Energir, formerly Gaz Metro, the largest gas distributor in Quebec.

“This facility or facilities like it are very common in New England,” Carroll said. “As a matter of fact, there are close to 40 of these peak-shaving facilities in the region. Some actually have liquefaction and can produce their own fuel; others do not.”

In addition, he said there are currently three LNG projects under development in the region: Granite Bridge, Northeast Energy Center and REV LNG.

NECA Fuels Conference fuel security natural gas — Kenzie Schwartz | © *RTO Insider*

McKenzie Schwartz, a National Grid gas analyst, said the market for renewable natural gas (RNG) is taking off because of support from state and federal policies, such as EPA’s Renewable Fuel Standard.

RNG is derived from biomass and is fully interchangeable with natural gas.

“We believe this can help National Grid move our industry toward a lower-carbon future,” Schwartz said.

National Grid pioneered technology in 1982 as the first utility to allow an RNG project to interconnect. Its Staten Island Landfill project is still in operation, injecting 2,000 dekatherms/day into the distribution system.

Electrification: How Much?

Emily Lewis, senior policy analyst for Acadia Center, an environmental advocacy organization, said that if states push renewable energy policies, wind and solar energy could generate 45% of New England’s electricity in 2030, versus 24% under current trends.

Lewis and Richard Murphy, energy markets director at the American Gas Association, debated how much electric heat pumps can reduce GHG emissions.

Repeating findings she shared earlier in the month at the ISO-NE Consumer Liaison Group meeting in Connecticut, Lewis said electrification of space heating, under current trends, would reduce GHG by 3% by 2030 and by as much as 16% under an accelerated policy scenario. (See Overheard at ISO-NE Consumer Liaison Group Meeting.)

Murphy countered with an AGA study that contends aggressive residential electrification of heating and cooling would reduce national GHG emissions by only 1 to 1.5% in 2035. (See State Regulators Hear Challenges, Promise of Electrification.)

There are three common themes in efforts to achieve deep decarbonization of the energy sector, he said. One is to dramatically increase efforts around energy efficiency. The second is to advance policies that would require up to 100% of all the electricity generated in the U.S. to come from renewable resources. The third is to replace all end-use applications from natural gas or fuel oil to electric alternatives, he said.

“The region uses more than twice as much energy in peak winter months as in the summer, so what would the overall cost be of converting residences away from natural gas and to electrification?” Murphy said. “When we look at the data in the residential market, we really start to think about the impacts on consumers.”

Approximately 60 million homes in the U.S. would have to be converted from natural gas heating to electricity, he said, which is a “massive undertaking” for such a modest environmental gain.

Oil Still Relevant

Oil comprises only 1% of New England’s power generation on average. But the fuel remains relevant at times, such as a cold snap last winter when oil accounted for 37% of the region’s electricity generation, said Kevin Grant, an oil trader at Sprague Energy.

The ability of oil to fill the fuel gap in winter is compromised by the cost of maintaining inventory, delivery logistics and the changed nature of the market, he said.

“Power generators, while still important, no longer drive the commercial oil market,” Grant said. “A fuel supplier is going to gear their operations to the customer who comes in 300 times a year, not once a year. Logistics is also an issue, with a limited number of barges and trucks. Transportation companies have right-sized their assets in response to market demand the same as everyone else.”

Stephen Leahy, vice president of the Northeast Gas Association, said, “Natural gas is the last fossil fuel left standing for power generation, but oil is still the No. 1 fuel consumed overall in Massachusetts in terms of total Btus. It’s mostly in the form of gasoline, but it’s still oil.”

How are we going to balance energy needs with environmental goals? asked Nancy Seidman, senior adviser to the Regulatory Assistance Project.

“The first principle is to put energy efficiency first,” Seidman said. “What it’s done for New England has been huge. … To have demand actually dropping is fabulous.”

— Michael Kuser

October 1, 2018August 5, 2024

PJM Members Vote to End FTR Liquidations

VALLEY FORGE, Pa. — The PJM Markets and Reliability and Members committees on Thursday approved Operating Agreement revisions that would eliminate the requirement that the RTO liquidate a member’s financial transmission rights when it falls into default.

The proposed changes are in response to the June default of GreenHat Energy, which could cost other members more than $145 million. (See Doubling Down — with Other People’s Money.)

PJM presented stakeholders with four packages of revisions at the MRC. Two of those had received a majority sector-weighted vote out of 24 proposals at a special committee session Sept. 18. Option B, Thursday’s winner, received 3.8 out of 5 in support, while Option J1 — which would have liquidated all of a defaulting member’s long-term positions except those remaining in the 2018/19 planning year, allowing them to go to settlement — received 3.3.

After the special meeting, Macquarie Energy, with support from Apogee Energy Trading and Vitol, offered two more proposals: B’ and J1′ (read as “B prime” and “J1 prime”), identical to B and J1 except that they would only apply to GreenHat’s portfolio. Macquarie said these proposals would allow for continued discussion of PJM’s liquidation process after dealing with GreenHat.

All four proposals included two identical provisions. One would ensure that the maximum $10,000 default allocation assessment is charged only once for a default that spans multiple years, rather than each year.

The other would allow those who sold FTRs to the defaulting member in a bilateral trade to take them back if their most recent auction clearing prices were less than the purchase prices.

Brian Wilkie of Rockland Electric Co. moved for considering B without the bilateral provision, which Exelon’s Jason Barker seconded. This proposal was dubbed B” (“B double prime”).

Dean Bickerstaff of Hartree Partners moved, with CPower’s Bruce Campbell seconding, that the MRC also consider Option K1B, which had only received 1.99 in support at the special meeting. K1B would have also allowed the 2018/19 positions to go to settlement, but it would have canceled all defaulting long-term FTRs. It also would have forced counterparties to the defaulters’ bilateral trades to reassume those positions.

Only B received the 3.34 sector-weighted supermajority support necessary to move on to the MC, with 3.73 in favor. B” received 1.88, B’ and J1 each received 1.8, J1′ got 1.44 and K1B 0.44.

At the MC later Thursday, Bob O’Connell of Panda Power Funds moved that the committee vote to accept the MRC’s vote as its own, but he withdrew the motion when DC Energy’s Bruce Bleweis called for a sector-weighted vote on it. Committee Chair Michael Borgatti, of Gabel Associates, called for a sector-weighted vote on B anyway, and the proposal passed with 4.01 in favor.

CFO Suzanne Daugherty explained that PJM will submit B as three separate “prongs” to FERC, with the $10,000 maximum and bilateral provisions in their own filings. Daugherty said this was done so that if the commission ends up rejecting one provision, it would not be forced to reject the entire package.

Members also reaffirmed their opposition to the status quo, with only 0.5 in support. If FERC rejects the proposal to eliminate the liquidation requirement, the RTO will ask in an amendment to a pending filing that the commission allow all of GreenHat’s positions to go to settlement until the end of February to allow for additional stakeholder discussion of alternatives to the status quo. PJM has asked the commission to allow the positions to go to settlement through Nov. 30, but FERC has not acted on the filing, nor on the RTO’s waiver request seeking permission to only liquidate prompt month FTRs.

October 1, 2018

PJM MRC/MC Briefs: Sept. 27, 2018

PJM, Monitor Come to Agreement on Opportunity Cost Calculator

VALLEY FORGE, Pa. — Stu Bresler, PJM senior vice president of operations and markets, announced at the Members Committee that he and Independent Market Monitor Joe Bowring had signed an agreement regarding the use of the Monitor’s opportunity cost calculator.

pjm mrc mc vrr — Adam Keech, PJM executive director of market operations, addresses stakeholders. | © *RTO Insider*

Under the agreement, Monitoring Analytics will continue to use its calculator to calculate the opportunity costs for market participants and will explain its inputs and logic to PJM to demonstrate that the unit-specific opportunity costs are compliant with the OA.

In return, PJM acknowledged that the calculator is the Monitor’s intellectual property, that the agreement is not a license for PJM to use the calculator and that the RTO will not attempt to reverse engineer it.

In response to stakeholder questions, Bresler said he was not sure how long it would take for PJM to get the Monitor’s data, but he estimated it would take two weeks.

The agreement is the culmination of a yearlong dispute between PJM and the Monitor over opportunity cost calculations, which came to a head in August when the Markets and Reliability Committee approved Tariff revisions, proposed by Bob O’Connell of Panda Power Funds, allowing participants to use the Monitor’s calculator. The RTO said it would be willing to allow its use but needed to understand the details of how it worked, something at which the Monitor balked. (See PJM Monitor Holding Firm on Opportunity Cost Calculator.)

The Monitor has repeatedly criticized PJM’s calculator as inaccurate and the RTO’s process for verifying inputs as flawed.

Calpine’s David “Scarp” Scarpignato asked what would happen to a generator if the calculators gave different results, and the generator used the one that gave it a higher price. Bowring answered: “It is still our responsibility to calculate opportunity costs, and if you propose to use an opportunity cost that is too high, we will let you know and refer you to FERC as necessary.”

O’Connell, who had originally been scheduled to speak before Bresler on the topic and had deferred, moved to postpone the vote on his proposed revisions to the next meeting to give PJM and the Monitor time to put the new process in effect. The motion was approved by acclimation with no objections or abstentions.

Quadrennial Review

The MRC voted on four packages of revisions as part of PJM’s quadrennial review of the variable resource requirement (VRR) curve, but none of the proposals received majority support.

The committee’s sector-weighted votes were advisory to the Board of Managers, which has ultimate approval of what is filed with FERC.

The PJM MRC and MC meetings were held Thursday, Sept. 27. | © *RTO Insider*

The MRC voted on proposals by PJM, the Monitor, Calpine and the D.C. Office of the People’s Counsel. Several stakeholders noted that their support hinged on the reference unit used in the calculations. PJM and the Monitor have proposed changing it from General Electric’s 7FA combustion turbine to the new 7HA, while the OPC proposed using an F- and H-class combined cycle. Calpine’s proposal maintains use of the 7FA.

Exelon’s Jason Barker said his company was against the HA being used, noting that GE has had trouble with its newest turbine class.

Reports of problems with the H-class began coming in last year, and Exelon recently had to shut down two power plants in Texas after GE identified a flaw in the design.

PJM’s proposal came in first with 2.32 in favor, followed by Calpine’s with 2.14, the Monitor’s with 1.96 and the OPC’s with 1.42.

At the MC, Carl Johnson, representing the PJM Public Power Coalition, moved to adopt the MRC’s votes for the sake of efficiency. This was quickly approved by acclimation, with only one objection.

VOM Proposal Rejected by MC

A revised proposal by PJM to include certain variable operations and maintenance (VOM) costs in cost-based energy offers failed to win supermajority endorsement from the MC, garnering only 2.92 of a sector-weighted vote.

At last week’s MRC, PJM’s Melissa Pilong presented several revisions to an RTO proposal that had been rejected, along with four others, by the MRC in July. (See PJM Ponders Advancing VOM Effort over Objections.) The changes included removing the ability for resources that did not clear the capacity auction to recover their fixed costs in their energy offers.

Originally, the proposal included only changes in Manual 15, which would only require MC endorsement and approval by the Board of Managers. As part of the new proposal, PJM would also add clarifying language to the Tariff and OA, meaning it would have to be approved by FERC.

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said that while he appreciated the additional FERC provision, he was frustrated that the VOM proposal kept coming up with little change. In a sector-weighted vote motioned for by Poulos, the MRC advanced PJM’s new proposal, with 3.4 in favor.

Later at the MC, Poulos motioned to delay a vote on the proposal, which Chairman Borgatti set for a sector-weighted vote. Before members voted on whether to vote, however, Bresler noted that because of the Oct. 12 deadline for filing changes stemming from the quadrennial review, PJM had set both matters for that day. CEO Andy Ott also urged members to vote, saying “it would be helpful to the board if you resolved this today.”

PJM’s proposal would allow major maintenance costs to be included in the VOM costs in energy offers. That would mean that they would be not included in the cost of new entry, which is set as part of the quadrennial review. Without the vote, Deputy General Counsel Chris O’Hara said that it would be difficult for PJM to justify the quadrennial review. “We would have to tell FERC we lack sufficient information to ensure the quadrennial review is just and reasonable,” he said.

With only a simple majority needed, members resolved to vote that day, with 3.1 in favor, before the actual proposal failed in a subsequent vote. Bresler later told RTO Insider that PJM will discuss with the board whether it should file the proposal under Federal Power Act Section 206, which is done when a proposal lacks member support. The RTO would have to show that its existing OA language regarding VOM costs is unjust and unreasonable, rather than just show that its proposal is just and reasonable.

Liaison Committee Meeting to be Closed to Nonmembers

Near the end of the MC meeting, a motion by Poulos for a temporary waiver to the Liaison Committee’s charter to allow some nonmembers to attend its upcoming Oct. 3 meeting as listening-only participants failed in a sector-weighted vote, with only 2.43 in favor.

According to PJM’s Dave Anders, it has been accepted practice to allow nonmembers — such as state regulators and their staff, FERC staff, PJM management and staff, and the Monitor — to attend since an LC meeting in D.C. one year coincided with a meeting of the National Association of Utility Regulatory Commissioners several years ago. State regulators and FERC staff had asked to be allowed to attend the LC, and “how could we say ‘no’ to that?” Anders said.

In an email to RTO Insider after the meeting, Poulos said his motion was prompted by a member’s request to enforce the charter during a “prep call” for the upcoming meeting. Poulos declined to name the individual who made the request.

“It was not the first time I’ve heard this request, but this time the request was gathering support from the others on the call,” he said. “I thought the decision was important enough to be heard by the entire stakeholder body.”

At Thursday’s meeting, Barker said he was disappointed that PJM had been lax in its enforcement of the charter. “This is our private discussion with the board,” he said. “This is our one opportunity.”

Alex Stern of Public Service Electric and Gas, who participated in the formation of the Liaison Committee and its charter several years ago, echoed the statements of other stakeholders. He said the charter should be respected and that it had been thoroughly developed to allow members direct and unfettered access to the board.

Before voting on Poulos’ motion, O’Connell moved to keep individual members’ votes private, only allowing the board to view them. This passed with 3.42 in favor.

Ott said PJM would notify members of the charter’s stricter enforcement going forward.

“Member actions at PJM’s September Members Committee reduced transparency in PJM governance,” said Illinois Commerce Commissioner John Rosales, president of the Organization of PJM States Inc., in a statement provided to RTO Insider. “This is an issue which needs examination going forward.”

PJM Debuts Web-based Governing Documents

PJM has converted its OA, Tariff and Reliability Assurance Agreement into user-friendly webpages.

On the left side of each page is a sidebar with links to each section in a document, and each page contains hyperlinks to referenced sections and attachments. Every term on a page has a clickable pop-up containing its definition.

There’s even a search bar.

The web versions are technically unofficial versions, as PJM changed the formatting and removed redundancies from the official, FERC-approved PDFs to make them more readable.

PJM staff presenting the new pages at the MRC were enthusiastic, and stakeholders expressed gratitude.

The Tariff PDF is a 3,554-page, 58-MB file. Its Table of Contents alone runs for 29 pages.

The PDFs for the OA and RAA are a bit more manageable at 630 and 251 pages, respectively.

— Michael Brooks

October 1, 2018

NYISO Management Committee Briefs: Sept. 26, 2018

RENSSELAER, N.Y. — NYISO experienced six days with peak loads of more than 31,000 MW this summer, compared with last summer’s actual peak of 29,677 MW, the ISO’s Management Committee learned last week.

New York ambient temperatures were above the 20-year average in May, July and August, and near average in June. Albany registered 19 days over 90 degrees Fahrenheit this summer, which has occurred only 10 times since 1874, Wes Yeomans, vice president of operations, said as he delivered the Summer 2018 Hot Weather Operations report.

“Fuel supplies for electric generation worked very well this summer,” he said. (See “Adequate Summer Capacity Forecast,” NYISO Management Committee Briefs: June 12, 2018.)

nyiso peak loads tcc — Total load (GWh) was above 50/50 projections this summer, while peak load was below the 50/50 projection for the 5th consecutive summer. | *NYISO*

Total New York Control Area load was above 50/50 projections this summer, while peak load was below the 50/50 projection for the fifth consecutive summer. The summer 2018 50/50 forecast was 32,904 MW, while actual peak load hit 31,861 MW on Aug. 29. The all-time peak of 33,956 MW occurred on July 19, 2013.

NYISO on Aug. 29 activated 481 MW of demand response for Zone J to support New York City transmission security from noon to 6 p.m., while utilities in the state also activated their DR programs. The ISO will report scarcity pricing outcomes at the Market Issues Working Group meeting in October.

Pallas LeeVanSchaick of Potomac Economics, the ISO’s Market Monitoring Unit, said the ISO called DR in Zone J for the two largest contingencies, not just the single largest.

“So, these DR resources are needed to meet the reserve requirements for Zone J — which is a real reliability requirement, but it’s not reflected in the market,” LeeVanSchaick said. “It’s really a failure of the market to procure reserves for this requirement, not an operational issue of activating excessive demand response.”

Yeomans replied that the ISO is engaged in a project to review reliability criteria.

Significant summer transmission outages were the 345-kV Hudson-Farragut B and C Lines, the 230-kV St Lawrence-Moses L33P and the 345-kV Dunwoodie-Mott Haven 71, which was forced out on July 1 in New York City near the beginning of a six-day heatwave and remains out of service.

Many more outages occurred, but the ISO only reports those that were out for a long time and impacted power availability during a heatwave, Yeomans said.

NYISO’s behind-the-meter solar installations have increased six-fold since 2013, with total registered nameplate capacity around 1,200 MW, Yeomans said. “But you’d need all of the panels aimed south and working in full sun to achieve that.”

Yeomans said pop-up showers on a hot day can reduce load by around 500 MW, prompting Mark Younger of Hudson Energy Economics to suggest that the weather normalization program at the ISO should try to account for this effect on net load.

Weather normalization refers to smoothing chaotic weather data from several years in order to provide a useful model for load forecasting.

AC Transmission Project on Hold

NYISO CEO Brad Jones informed the MC about why the ISO’s Board of Directors had not yet voted on the AC Public Policy Transmission Project approved by the committee in June.

“The board has looked at this and asked for additional data,” Jones said. “We hope to get as much as we can to them for the October board meeting but are not sure we’ll have all of it.” (See NYISO MC Supports AC Transmission Projects.)

The MC in June approved joint proposals by North America Transmission and the New York Power Authority to build two 345-kV transmission projects that could cost $900 million to $1.1 billion.

NYISO Proposes 8.5% Budget Increase

The ISO’s draft 2019 budget totals $168.2 million, including an 8.03% increase in revenue requirement from this year’s budget and a 0.45% decrease in projected megawatt-hours, for an overall Rate Schedule 1 increase of 8.51%.

Alan Ackerman of Customized Energy Solutions, chair of the Budget and Priorities Working Group, presented the review of a budget allocated across a forecast of 157.1 million MWh, for a Rate Schedule 1 charge/MWh of $1.071, compared to $155.7 million allocated across 157.81 million MWh for a Rate Schedule 1 charge/MWh of 98.7 cents this year.

The ISO has held the budget to an approximately 1% average increase in revenue requirement for the past four years, “but this trend is not sustainable for the 2019 budget,” Ackerman said.

One big factor driving up spending is repayment of a $30 million loan to finance an Energy Management System/Business Management System upgrade project, Ackerman said. Other factors include debt service, new software needs, professional consultant fees, and salaries and benefits. The ISO plans to add 15 new positions over the coming year.

The board will review the draft budget Oct. 15, the MC will vote on a new budget Oct. 31, and the board will consider the final proposal on Nov. 13, 2018.

MC Approves 2018 Reliability Needs Assessment

The committee approved the ISO’s 2018 Reliability Needs Assessment (RNA), which identified no reliability needs on the state’s bulk power system over the coming decade. The board will consider the RNA in October.

Resource Planning Manager Laura Popa reported that the 2018 RNA is based on information from the 2018 Gold Book (the annual transmission planning and evaluation report filed with FERC), historical data and market participant data.

For transmission security, planners evaluated Year 1 (2019), Year 5 (2023) and Year 10 (2028) for summer peak baseline power flow cases, and found no reliability needs for Years 1 and 5. However, for Year 10 they identified one preliminary reliability need: a 3-MW deficiency in Eastern Long Island.

The deficiency would stem from a 1% overload on the 138-kV Brookhaven-Edwards Avenue line (Line 864), the contingency being the loss of the 138-kV Wildwood-Riverhead line (Line 890) and returning the system to normal criteria. PSEG Long Island presented an updated and firm long-range transmission plan at the June 28 Electric System Planning Working Group/Transmission Planning Advisory Subcommittee that involved scheduling terminal upgrades at the Brookhaven 138-kV substation to be in service in June 2019. With these upgrades the overload is resolved, according to NYISO.

LeeVanSchaick elaborated on MMU comments filed with the ISO that markets are generally well designed, noting an inconsistency between the assumed value of certain resources needed for reliability transmission planning purposes and how NYISO’s capacity market compensates those resources.

The MMU recommends the ISO periodically reassess the assumed relief from land-based wind generators and special case resources (SCRs) in transmission security planning assessments to ensure levels are commensurate with their expected performance and availability. It also asked the ISO consider using different assumptions for offshore wind generators than for land-based wind units, and possibly further discount the capacity ascribed to wind generators and SCRs, which represent load capable of being interrupted upon demand or a distributed generator rated 100 kW or higher.

Failure to maintain consistency between planning reliability criteria and capacity market requirements may increase the need for regulated transmission solutions and reliability-must-run contracts to satisfy reliability needs, which becomes particularly important as more wind generation is built in import-constrained areas over the coming decade, the MMU said.

“It’s important to think about this as the resource mix is turning over,” LeeVanSchaick said.

ISO Customers Mostly Satisfied with Query Response

Customers and market participants continue to be pleased with how NYISO interacts with them and are nearly 100% satisfied with how the ISO answers their questions, according to a biannual customer satisfaction survey conducted by the Siena College Research Institute (SRI).

SRI Director Don Levy told the MC his group recorded a 98% “customer inquiry satisfaction” score on the survey, which combined a market participant satisfaction score (89.9%) with assessment of performance (76.8%) for an overall approval rating of 84.7%.

Levy said the surveys identified several areas for improvement, including tariff, legal and regulatory webpages; ISO manuals, technical bulletins and user’s guides; market mitigation and analysis interactions; transparency of operations; and increasing the consideration of stakeholder input.

MC Approves Revisions to OATT Attachment L

The MC approved revisions to Attachment L of NYISO’s Open Access Transmission Tariff updating terms regarding transmission congestion contracts (TCCs).

Gregory R. Williams, manager of TCC market operations, said the updates to Section 18.1.1 (Table 1A) of Attachment L followed an annual review. Among the changes were revising contract expiration dates from Dec. 31, 2017, to Dec. 31, 2027, for two specified agreements.

If authorized by the board at its meeting in October, the ISO will file the revisions with FERC.

MC Approves Change to Unsecured Credit Scoring Model

The MC approved changes to the ISO’s unsecured credit scoring model following its first review of the methodology since 2009.

John Jucha, senior credit analyst for corporate credit, said that under the new model, the 12.7% weighting for revenue/market capitalization in predicting a default will be replaced with a measure of total assets. The review found that asset size variables were not represented in the model despite their “strong predictive power.”

Rating all market participants — including corporations, financial institutions and government entities — on the same scorecard may mask differences between them, the analysis found.

If authorized by the board in October, the ISO will file the revisions to Attachment K of the Market Administration and Control Area Services Tariff with FERC.

— Michael Kuser

October 1, 2018

FERC OKs Discounted Tx for Maine Biomass Plants

FERC on Thursday approved Emera Maine’s proposal to provide discounted transmission service to two ReEnergy biomass plants in northern Maine (ER18-2123, ER18-2124).

The commission’s Sept. 27 order also found that a protest from Maine Gov. Paul LePage lay outside its jurisdiction. LePage alleged that Emera would recover the cost of the discounts from the state’s retail customers, but FERC said retail rates are regulated by the Maine Public Utilities Commission. “Our findings here are limited to whether Emera Maine’s proposed commission-jurisdictional wholesale rates are just and reasonable,” FERC said.

ReEnergy employee leads tour of Fort Fairfield biomass generator. | *Biomass Power Association*

ReEnergy owns a 39-MW biomass-fueled power plant in Ashland and a 37-MW biomass plant in Fort Fairfield. Both facilities have market-based rates and are allowed to sell their output into ISO-NE’s energy, capacity and ancillary services markets.

Under the agreements, Emera will provide non-firm transmission service from the two ReEnergy facilities to ISO-NE for $0/MW-month for Oct. 1, 2018, through Dec. 31, 2019, and $1,132/MW-month for Jan. 1, 2020, through Dec. 31, 2020.

ReEnergy said the discounts were needed to remain in business because of the pancaked transmission charges they pay to move energy to the ISO-NE market.

Emera would provide service to the plants through the Maine Public District transmission system, which is not directly interconnected with any portion of the U.S. transmission grid. Entities interconnected with it can only access the New England grid over transmission facilities in New Brunswick, Canada, which NB Power owns and operates.

Emera said it agreed to the discounts because ReEnergy provides jobs in northern Maine.

— Michael Kuser

October 1, 2018November 13, 2023

PUCT Urges 2nd Look at Freeport Project Costs

By Tom Kleckner

Texas regulators last week signaled their discomfort with the rising costs of CenterPoint Energy’s planned 345-kV transmission line to serve load in the industrial Freeport area south of Houston.

The Public Utility Commission has asked ERCOT to provide further input on CenterPoint’s project, which is part of the “Freeport Master Plan Project” addressing load growth around the Gulf Coast seaport.

“I’m not going to trust these huge shifts in costs without having ERCOT weigh in,” Chair DeAnn Walker said during the commission’s Sept. 27 open meeting.

CenterPoint’s application for a certificate of convenience and necessity presented 30 alternative routes, ranging in length from 54 to 84 miles, and in estimated costs from $481.7 million to $695.2 million. The costs at the lower end are almost double ERCOT’s estimate of $246.7 million when it approved the Freeport project in December. (See “Board Approves $246.7M Freeport Transmission Project,” ERCOT Board of Directors/Annual Meeting Briefs.)

“Some of these numbers are approaching those of a nuclear plant,” Commissioner Arthur D’Andrea said.

Warren Lasher, ERCOT’s senior director of system planning, didn’t argue that point. He explained that the grid operator made its recommendation based on “specific electrical reasons,” but it has taken a second look after CenterPoint notified it of the cost increase.

“From our very preliminary analysis, neither the need nor the timing for the need for the project has changed,” Lasher said. “When we looked at this project electrically, there were just not that many options to get to that part of the state and serve the increasing customer demand. I’m not sure we couldn’t have found another option, but it’s unlikely.”

ERCOT has projected a 92% increase in the Freeport area’s load to 1,979 MW by 2019, with a large chemical plant accounting for much of the growth. The region is expected to see an additional 300 MW of load by the end of 2022.

PUC staff agreed to prepare a preliminary order for the commission’s Oct. 12 open meeting. The order would incorporate ERCOT’s input on whether there are other alternatives for meeting the area’s demand.

“I am going to need that,” Walker said.

Rio Grande Electric, AEP Texas Reach Agreement

The commission canceled an Oct. 31 procedural hearing in the dispute between Rio Grande Electric Cooperative and AEP Texas over which utility will serve certain customers in a Uvalde subdivision after the companies said they had reached a settlement (Docket 47186). (See “Hearings Set for AEP Texas Legal Cases,” PUCT Reduces Rates for AEP, Others on Income Tax Cut.)

Rio Grande and AEP Texas told the commission they will resolve the dispute through requests for service area changes. They said they are finalizing maps and preparing the necessary documents to reflect “definitive boundary changes.”

The PUC gave the parties until Oct. 22 to file an agreement or a status update.

Commission Accepts IOU Earnings Review; OKs Interventions

The commissioners accepted staff’s review of the state’s 14 investor-owned utilities’ earnings reports. Staff said none of the IOUs “warrant[ed] a more detailed analysis” (Project 48158).

Following a closed session, the PUC agreed to allow Walker, who represents the PUC on SPP’s Regional State Committee, to work with outside counsel on FERC dockets involving SPP. The PUC also said it would intervene in two FERC dockets:

- The Louisiana Public Service Commission’s complaint against Entergy Services and the corporation’s five operating companies alleging they failed to include 100% of the costs of Entergy’s transmission control centers in MISO’s Attachment O formula rate (EL18-201). The PSC said Entergy’s failure to bill MISO for all of the costs would force “native load customers to cross-subsidize the use of the Entergy transmission system by third party wholesale customers.”
- East Texas Electric Cooperative’s complaint against American Electric Power subsidiaries Public Service Company of Oklahoma, Southwestern Electric Power Co., AEP Oklahoma Transmission and AEP Southwestern Transmission. The co-op alleges the 10.7% base return on common equity in the AEP West companies’ formula transmission rates is unjust and should be reduced (EL18-199).

October 1, 2018

FERC Approves New Hampshire Capacity Settlement

By Michael Kuser

A 4.5-MW biomass power generator in Claremont, N.H., will refund ISO-NE capacity payments it wrongly accepted for nine months following the plant’s closure in September 2013 and pay a $250,000 civil penalty under a settlement approved by FERC on Friday (IN18-10).

The commission accepted a stipulation and consent agreement between its Office of Enforcement and Wheelabrator Technologies under which the company will disgorge $107,231.34 in capacity payments and interest.

Claremont energy-from-waste facility | *Stuart B. Millner & Associates (SBMA)*

Enforcement began its investigation in March 2015 following a referral from the RTO. “Claremont subsequently responded to data requests and requests for investigative testimony, and demonstrated cooperation during the investigation,” the commission said.

Following the Claremont facility’s closure, ISO-NE continued to issue monthly capacity payments for a year in exchange for Claremont’s continuing obligation to supply capacity while the facility was inoperable. The RTO later clawed back the July to October 2014 payments through its Tariff-based reconciliation process.

Public Service New Hampshire (now part of Eversource Energy) previously purchased Claremont’s generation and operated as its lead market participant and asset owner, managing Claremont’s participation in the Forward Capacity Auctions (FCAs) and receiving the payments issued by ISO-NE. On Dec. 1, 2013, PSNH transferred Claremont’s market participant status to Wheelabrator North Andover, which operates a generation facility in North Andover, Mass., and, as of that date, began receiving capacity payments on Claremont’s behalf.

At the time, Wheelabrator management did not fully understand its obligation to shed its capacity supply obligations for FCA 4 (June 2013 to May 2014) and FCA 5 (June 2014 to May 2015) and continued to collect capacity payments for the closed Claremont facility, the commission said.

“Accordingly, Claremont did not successfully shed those obligations. Claremont did shed its obligation for FCA 9 through a non-price retirement request. Claremont’s obligations in FCA 8 were eventually unwound by ISO-NE after it discovered Claremont’s permanent closure,” the commission said.

Wheelabrator’s compliance measures were insufficient to identify the violation, the commission said. The company also agreed to submit annual reports for two years on the progress of its recently implemented compliance measures and any new incidents of noncompliance.

October 1, 2018

New NERC Chief Not ‘Smartest Guy in the Room’

By Rich Heidorn Jr.

nerc jim robb e isac — Jim Robb, NERC CEO | *© RTO Insider*

WASHINGTON — NERC CEO Jim Robb is a chemical engineer who learned the electric industry as a McKinsey consultant in California in the 1990s.

“So I learned the industry much more from a business and strategic angle than coming up through technology, operations and planning,” he said Thursday during an hourlong press conference scheduled to mark six months on the job for Robb, who was previously CEO of the Western Electric Coordinating Council. (See NERC Names WECC Chief to Top Post.)

“I’m … not an electrical engineer. … I’m never going to present myself as the smartest guy in the room on any technical topic,” he said. “I think the reason the NERC trustees chose me for this job was my ability to put the right set of people together to work on the right set of issues at the right time.”

Robb, who was tapped to replace long-time CEO Gerry Cauley, met with the press at NERC’s D.C. office, which houses about 30% of the organization’s employees, including its legal, enforcement and communications staffs and the Electricity Information Sharing and Analysis Center (E-ISAC). Robb said he spends most of his time at NERC’s Atlanta headquarters but visits D.C. about three or four times a month. (See related story, NERC Chief Sees Need for Inverter, Fuel Assurance Standards.)

Robb said NERC has a good foundation, citing the long-term strategic plan developed over the last 18 months and its four-year effort to transition to a risk-based approach, the Reliability Assurance Initiative (RAI).

The RAI initiative moved NERC away from the “one size fits all, check the box” approach of the past, Robb said.

Instead of auditing all registered entities on a three-year cycle, NERC and its Regional Entities are focusing on the most critical standards. NERC also has identified about 20% of its requirements as candidates for retirement.

NERC is also narrowing its focus on the entities that present the biggest risks to the system, based on their scale, location and the neighbors with whom they are connected. The organization’s staff now has power to change their audit scope on site if they encounter unexpected issues.

“It’s much more tailored to the individual company, its risk posture and its historical performance,” Robb said. “I think when we first rolled this out, industry thought, ‘This is great. This is going to be much less [regulation].’ And in fact, the experience has been all over the board. There’s some entities that would say, ‘Boy, we’re seeing a lot more of you than we’d like.’ And there are a few that we have had a much lighter touch on.

“We have to maintain rigor at all times. While we’ll disproportionally focus our time on and attention on the key risks and issues of the moment, we can’t lose sight of all the other stuff that goes on,” he added, mentioning criticism the Federal Aviation Administration received over its inspection practices in April following a fatal Southwest Airlines engine failure caused by cracked fan blades. “I don’t want to go through that,” he said.

Among Robb’s priorities are improving the consistency in how standards are implemented across regions, long a source of industry complaints, and improving the work of the ISAC.

The ISAC effort is being led by Bill Lawrence, a NERC veteran who led the GridEx IV exercise in 2017. Lawrence was appointed in August as chief security officer, replacing Marcus Sachs, who resigned last December. RTO Insider reported that Sachs was forced out because of concerns by industry officials on the Electricity Subsector Coordinating Council (ESCC) that he lacked the background to lead the ISAC’s planned expansion. (See NERC Parts Ways with Chief Security Officer.)

“The ISAC really has not performed up to expectations,” Robb said. “Over the last couple years we, and the Electricity Subsector Coordinating Council’s Member Executive Committee, worked with Bill and others to put real rigor around the strategic role of the ISAC. … The ISAC is really designed to [provide] a service function for the industry. It’s not meant to be an idea lab.”

Robb said the ISAC faced challenges in “sanitizing” confidential information it receives and converting it to actionable intelligence.

The ISAC will double its staffing to “build [a] very strong analytical capability” and create a 24/7 watch operation, Robb said. The ISAC is now staffed only during normal business hours, although there is a NERC officer on duty around the clock.

The Cybersecurity Risk Information Sharing Program (CRISP), which is funded by industry and the Department of Energy and managed by the ISAC, is now monitoring utilities representing about 75% of electric meters to identify hackers seeking to penetrate the companies.

“The risk of a major outage as a result of one of these [attacks] is very low — but not zero,” Robb said. “And given the havoc that would result, we need to always be vigilant and staying way ahead of the curve, and I think we are. I think our system is designed with so much security built in, through the standards, through the isolation of operating systems from enterprise systems, that it would be very, very unlikely that a foreign entity or a malicious actor of any type would be able to create a catastrophic kind of cascading issue on the grid. Not zero, but very unlikely.”