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December 24, 2024

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FERC Approves Pause of PJM Transmission Constraint Penalty Factor in Virginia

FERC on Friday accepted revisions to PJM’s tariff and Operating Agreement that temporarily remove transmission constraint penalty factor (TCPF) rules in Virginia’s Northern Neck peninsula (EL22-26, ER22-957).

The peninsula, which encompasses Lancaster, Northumberland, Richmond and Westmoreland counties, is normally served by three transmission lines: a 230-kV line from Fredericksburg, a 230-kV from Lanexa-Dunnsville and a 115-kV line Harmony Village. But as part of a transmission upgrade project approved in 2020, PJM placed the Lanexa-Dunnsville line on outage at the beginning of the year.

That immediately created price fluctuations of the TCPF to its default rate of $2,000/MWh in the real-time energy market. PJM on Jan. 31 told FERC that the TCPF rules were creating “unjust and unreasonable energy market rates” for consumers on the peninsula.

The RTO also said the price fluctuations contributed to the default in January of Hill Energy Resource & Services, which had portfolio positions in the financial transmission rights market in the congested Dominion zone. (See PJM Weighs Options on Hill Energy FTR Default.)

TCPFs provide price signals to incent more supply or demand response. But the Northern Neck has a “few relatively small” combustion turbines, PJM told FERC, and load has not “responded significantly enough.” The line outage has resulted in “repeated instances” when no actions can relieve the transmission constraint on the other two lines, causing real-time energy market prices to oscillate between the offers of the CT plants and the TCPF of $2,000/MWh, even in the early morning hours, when behind-the-meter solar resources located on the peninsula are usually enough.

“PJM has shown that under the specific circumstances in the record, the transmission constraint penalty factor is not achieving its intended purpose in the Northern Neck peninsula and is resulting in an inappropriate price signal that establishes high prices without a commensurate benefit,” the commission said. “We therefore agree that it is just and reasonable to stop applying the transmission constraint penalty factor in the Northern Neck peninsula for a limited time.”

The RTO said the situation is expected to continue throughout the life of the project until its completion in December 2023, resulting in “significant increases in costs to load,” without an “amendment to the existing transmission constraint penalty factor rules.”

To solve the pricing issue, PJM proposed setting the transmission line limit “at a level that ensures the offers of the resources being used to control the constraint are reflected in the congestion price in lieu of applying a transmission constraint penalty factor.”

The RTO also proposed providing “regular informational filings” to the commission regarding congestion on the peninsula and to work with stakeholders on reforms to the TCPF rules if a similar situation happens in the future.

PJM requested an effective date of Feb. 1, 2022, one day after the date of its filings, because “recalculating energy market settlements is labor intensive, especially over an extended period of time.”

Protests

Several stakeholders protested PJM’s proposed changes.

Chicago-based hedge fund Citadel argued that PJM failed to demonstrate the existing TCPF rules were unjust and unreasonable. The company said PJM recorded recent scarcity pricing on the same path in August and December of 2020 and August 2021 and did not demonstrate how customers were harmed during those events and did not raise concerns at the time of those events. Citadel said there were 784 real-time intervals of prices reaching $2,000/MWh during the previous outages on the line, which “did not prompt PJM to make an emergency filing.”

DC Energy also said the outages in 2020 and 2021 created “substantially similar conditions on the remaining facilities serving Virginia’s Northern Neck” and argued that “emergency measures to eliminate the scarcity pricing signal were not justified in those circumstances and they are not justified now.”

Citadel also argued that “PJM should focus on ways to accelerate new generation development in this location as opposed to creating uncertainty around existing, market-based price signals.” The company said more than 700 MW of new solar, battery, and solar-battery facilities are planned to come online in the peninsula during or shortly after the period of the transmission outage.

Appian Way said that, because this case involves the Hill Energy default, PJM “may have responded with an excessive and unwarranted level of political sensitivity due to the historical context of the GreenHat” Energy default of 2018.

The commission said that while PJM has an existing process to temporarily relax the TCPF, the existing provisions “do not contemplate the unique scenario presented here.”

“Based on the evidence in the record, we find that PJM’s continued application of the transmission constraint penalty factor to congestion in the Northern Neck region resulting from the Lanexa-Dunnsville-Northern Neck line outage will not produce the intended short-term or long-term responses and, instead, will only result in higher costs to ratepayers without a commensurate benefit,” FERC said.

The commission said it agreed with PJM that new generation resources sufficient to relieve the constraint “could not reasonably be expected to be sited, constructed and complete the PJM interconnection process before December 2023.”

FERC also disagreed with Citadel’s argument that PJM failed to provide enough evidence for its proposal. The commission said PJM provided LMP data for the Northern Neck on Jan. 14, as well as for the period Feb. 1-14. The data were “sufficient to demonstrate the link between high prices and the transmission constraint penalty factor.”

The commission also disagreed with DC Energy’s and Citadel’s assertions that past incidences of high prices in the same area of the Dominion zone “demonstrate that PJM’s current tariff is not unjust and unreasonable.” It said the findings were “grounded in the unique circumstances” in the proceeding.

It directed PJM to submit an informational filing updating the commission on congestion patterns within 90 days of the date of the order and every 90 days after until the Lanexa-Dunnsville line upgrade is complete. The RTO was also encouraged to “consider modifications to its analyses of and planning for transmission outages to prevent such occurrences in the future.”

Danly Dissent

FERC Commissioner James Danly provided the lone dissent on the order, saying he disagreed that PJM met its Section 206 burden to demonstrate the existing transmission constraint penalty factor tariff rate is unjust and unreasonable

“As best I can make out, the high prices required by the tariff in the face of an unresolvable constraint are both too high for PJM’s liking but are simultaneously an insufficient incentive for anyone to do anything about it,” Danly said. “I am suspicious that this is a case of scarcity pricing being allowed in a market tariff only until it actually occurs, and then it must be eradicated. Markets cannot work when high prices that occur by design are disallowed in practice.”

Danly said it “does appear” that there may not be a short-term solution to the pricing issue, but he said he was “skeptical” that three weeks was a sufficient amount of time to make the determination. He said he was also concerned by the “regulatory uncertainty” making the change could cause.

“I cannot imagine how an existing generation resource in PJM can remain in business given the frequency of changes the commission repeatedly imposes on these markets, all tending to reduce prices for existing generation,” Danly said. “Today, we reduce price again, demonstrating to everyone that the mechanisms we put in place to harness market forces will be abandoned when they work as planned.”

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Vt. Maps Fast-charger Buildout for Federal NEVI Funds

With some National Electric Vehicle Infrastructure (NEVI) program guidance in hand, Vermont is already mapping out where it expects to begin building electric vehicle fast-charger stations in the coming year.

The state will receive a $3.1 million NEVI apportionment for federal FY2022, followed by four additional $4.5 million annual installments, said Patrick Murphy, sustainability and innovations project manager at the Vermont Agency of Transportation. The total $21.1 million in funding is Vermont’s part of the $5 billion allocated for NEVI over five years under the Infrastructure Investment and Jobs Act.

After reviewing the federal government’s NEVI guidelines released Feb. 10, VTrans has a preliminary plan to install or upgrade 15 fast-charger stations along federally approved alternative fuel highway corridors.

“Priority must be given to [alternative fuel corridors] … until they are deemed by the Federal Highway Administration (FHWA) to be fully built out,” Murphy said Friday in testimony to the Vermont Senate Transportation Committee.

Each station must have at least four, 150-kW ports and cannot be located more than 50 miles from another qualifying fast-charger station on a corridor. In addition, stations cannot be located more than one mile from a highway exit.

By pairing first-year NEVI funding with American Rescue Plan Act funding, Murphy said, Vermont could “come close within the next fiscal year to building out what’s required under the federal guidelines,” before it can use remaining funding for the state’s existing EV infrastructure goals. The installation cost for four 150-kW ports would be an estimated $413,000.

Vermont has an existing plan to put fast chargers along highways based on prior federal guidance for placement every 50 miles and within five miles of highway exits or interchanges and allowing for lower charging output.

Given Vermont’s rural nature, many highway exits do not have the electric infrastructure to support high output fast chargers within one mile.

“The move from the five- to one-mile distance may result in a number of requests for exceptions,” Murphy said, adding that it might also require other solutions, such as renewable energy and battery storage at some locations.

Fast-charger stations that the state has funded and built already along FHWA-approved corridors mostly have two 50-kW plugs.

“No locations on any of the corridors that we’ve had designated meet the new higher standard,” Murphy said.

NEVI guidelines call for states to complete station installations within six months of securing equipment and installation providers. That timeline, Murphy said, is “faster than any of the projects that we’ve completed to date” and could present certain challenges.

Demand for charging equipment will increase with the amount of NEVI funding that states will receive, he said. And there may be ongoing supply chain issues from the pandemic that could be compounded by Buy America requirements that the federal government has yet to clarify.

Current equipment costs also could increase as demand grows across states, Murphy said.

VTrans foresees additional difficulties arising from requirements of President Biden’s Justice40 initiative, which calls for 40% of investments to benefit disadvantaged areas. The initial guidance for locating fast-charger stations along highway corridors is “pretty prescribed,” Murphy said.

“The one-mile guidance from a highway intersection or exit clearly serves the traveling public for longer trip making, but it won’t always be compatible with a dual concern about making sure that these investments support local communities,” he said.

Murphy expects VTrans will have a draft plan for NEVI funds ready by March for stakeholder feedback, and final state plans are due for submission to FHWA by Aug. 1.

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Study Casts Doubts on Corporate Green Goals

Of five studied, large U.S.-based companies, only Apple has a fair chance of hitting its carbon reduction goals, a recent report said.

The study by the Next Climate Institute and Carbon Market Watch gives Seattle-based Amazon, California-based Google and Arkansas-based Walmart a low chance of meeting their goals, while suggesting Rhode Island-based CVS Health Corp. has only a faint chance.

Of the 25 companies examined in the report, all of which have pledged to reduce carbon emissions, Danish shipping giant Maersk stands the greatest chance of meeting its carbon goals.

The study authors admit many gaps in its structure. Each nation was limited to five companies among the 25 samples, which defined their goals differently and exhibited varying levels of transparency about their current carbon emissions and reductions plans.

The study gives only Maersk a good chance of reaching its goals. It concludes that Apple, Sony and Vodaphone have fair chances. Amazon, Google and Wal-Mart are among 10 companies with poor chances.  Eleven corporations, including CVS, have faint chances, the study said.

A breakdown of the study’s five U.S.-based companies finds that:

      • Apple’s (NASDAQ:APPL) claims to be currently carbon neutral are misleading, addressing only its administration office, business travel and employee commuting, which represents just 1.5% of its carbon footprint, the study said. The overwhelming majority of its carbon footprint comes from buying, manufacturing and transporting components. Apple’s 2030 targets call for reducing massive amounts of carbon from manufacturing. The company does not have any published interim carbon reduction targets, but it has shown steady year-by-year carbon reductions.
      • The study dinged Amazon (NASDAQ:AMZN) for a lack of details in its data, and the absence of interim reduction targets on emissions plus haziness on how emissions are defined leaves the study’s authors leery about Amazon becoming a net-zero emitter by 2040, which is the company’s goal. However, the study noted more detailed targets are expected to be published this year. Also, the study voiced concern about Amazon achieving part of its goals by investing in carbon credits related to forestry improvements.
      • Google (NASDAQ:GOOG) currently claims to be carbon neutral and plans to be carbon-free by 2030, but the study says carbon neutrality is achieved with carbon credits and that only some specific emissions are tracked. Google has a great number of anti-carbon measures in motion. The study also contends more detailed data are needed to gauge their effectiveness.
      • Walmart (NYSE:WMT) has credible interim targets and a strategy to eliminate its operational emissions by 2040, but that accounts for only 9% of its carbon footprint. Meanwhile, the retailer relies on its suppliers voluntarily reducing their emissions with no interim targets. The report recommends that Walmart make suppliers’ participation mandatory or create better incentives to participate. The company should also set specific emissions targets for its suppliers.
      • The study criticized CVS (NYSE:CVS) for “insufficient identification of emission reduction measures” to achieve a 2050 net-zero target: “We could not identify measures that CVS Health wants to implement to realize deep emissions reductions.”

Meanwhile, Maersk is decarbonizing its ship fuel, which accounts for 63% of its total emissions. However, the study contends the shipper does not have clear plans to decarbonize emissions from its supply chains and electricity use, which will likely grow as the ships switch to alternative fuels. Maersk is aiming for net-zero emissions by 2040.

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SPP Briefs: Week of Feb. 14, 2022

SPP Reaches out to Public Interest Organizations

Faced with a rapidly evolving grid’s continued focus on decarbonization and a resource mix to match, SPP is working to strengthen its relationship with public interest organizations (PIOs) and the interests they represent.

Staff told the Corporate Governance Committee (CGC) on Thursday that they have held two meetings this year with PIOs and stakeholders to discussion the grid operator’s governance structure and their straw proposals.

The subjects have included expanding qualifications to sit on the Board of Directors and the Nominating Committee’s search criteria; eliminating membership withdrawal deposits for PIOs; adding even more transparency to SPP meetings; and providing a role for Western regulators before their utilities become RTO members.

“I’m encouraged by the nature of the conversations that are taking place,” board Chair Larry Altenbaumer said.

Staff said they find PIOs offer value to SPP because they have “an unbiased perspective” in reviewing policy and market design proposals that serve the larger interests and because they tend to be actively engaged in state, regional and interconnection-wide generation, and regional market and transmission planning forums, particularly in the Western Interconnection.

Their participation is motivated by the end state of evolving market design and rules to support future technology. SPP says a decarbonized grid is essential and the evolving grid’s economics warrant change, including regional coordination of energy needs.

“We’re very, very encouraged with the past few months and very, very encouraged by the items under consideration,” said Kylah McNabb, an energy consultant representing the Sustainable FERC Project. “We do understand it’s a process. Taking a look at these items is the start of a larger conversation that will take place in coming weeks.”

McNabb indicated to the CGC that her organization is all but certain to soon submit its membership application to SPP. The organization, based in Oklahoma City, is a partnership of state, regional and national environmental and other PIOs working to expand clean energy’s deployment and to reduce and eventually eliminate carbon pollution from the power sector.

SPP currently has only one PIO member in the Lignite Energy Council. However, that sector could grow should the RTO reclassify alternative power members Advanced Power Alliance (APA) and American Clean Power Association, the grid operator’s newest and 110th member, as PIOs.

Western Resource Advocates, which spoke for consumers during SPP’s failed bid to integrate the Mountain West Transmission Group, is also considering membership in the RTO. (See Xcel Leaving Mountain West; SPP Integration at Risk.)

APA’s Steve Gaw, who helped facilitate the discussions with the PIOs, said, “There’s still more conversation ahead on this. When I look at the issues that are there, I feel like the attempts to find paths forward have been very positive and help educate and understanding on both sides has been worthwhile.”

SPP said it is pursuing “something more appropriate” for PIOs related to their membership withdrawal deposits. Staff have proposed three categories: $150,000 for load-serving entities, $50,000 for non-LSEs, and $12,000 for PIOs, consumer advocates and other similar groups.

CGC OKs Future Grid Group

The CGC approved the 17-person roster for the Future Grid Strategy Advisory Group, which will be responsible for providing periodic assessments of the RTO grid’s future state.

“We’re very pleased. … We really hit a home run with what we’ve got here,” COO Lanny Nickell said in presenting the group’s nominations, a reference to the group’s wide range of expertise. Its members represent investor-owned utilities, public power and governmental agencies, and independent transmission companies, while bringing expertise in transmission and generation planning and regulatory backgrounds.

Noting 11 of the members are in upper management, Nickell said, “I think we hit the mark there, as well.”

The group was approved in December and will identify gaps between future state projections and current trajectories, and increase organizational awareness of opportunities to shape the grid.

The team is chaired by Mark Ahlstrom, vice president of renewable energy policy for NextEra Energy Resources, with SPP’s chief information security officer, Sam Ellis, serving as staff secretary. The advisory group’s full roster can be found here.

The CGC also recommended:

      • that Google’s Will Conkling replace Jeff Riles, who recently left the company to be director of energy markets at Microsoft, as the large retail sector’s representative on the Members Committee; and
      • EDF Renewables’ Arash Ghodsian to be chair of the Generation Interconnection User Forum.

Committee members met in executive session to discuss the board vacancy created by Graham Edwards’ departure at the end of last year. The search process for his replacement didn’t begin in time to be included with the selection of SPP’s two newest board members, cyber expert Ben Trowbridge and utility veteran John Cupparo. (See “Members Elect 2 New Directors,” SPP Board of Directors/Members Committee Briefs: Jan. 25, 2022.)

M2M Settlements Reach $243M

SPP accrued $29.39 million in market-to-market (M2M) settlements from MISO during November in what staff termed “a very exciting month” during Friday’s Seams Advisory Group meeting.

The total was the second highest since the RTOs began the M2M process in March 2015, exceeded only by the massive $51.49 million settlement in MISO’s favor last February, in large part because of that month’s severe winter storm.

Staff said the M2M process also settled in SPP’s favor in December at $10.25 million. It was the 10th straight month the process settlements have been in the green for SPP and the 25th time in the last 27 months. Settlements in SPP’s favor now total $243.31 million.

Permanent and temporary flowgates were binding for more than 5,700 hours in November and December, compared to 1,875 hours in October. The grid operators exchange settlements for redispatch based on the non-monitoring RTO’s market flow in relation to firm-flow entitlements.

Staff’s Neil Robertson told SAG members that SPP and MISO are planning a series of stakeholder meetings through midyear to discuss cost allocation for their joint targeted interconnection queue (JTIQ) study, which last month identified a $1.755 billion portfolio of suggested projects. (See MISO, SPP Roll out $1.755B Joint Tx Portfolio.)

The grid operators will also raise the subject during Tuesday’s meeting of their state commissions’ staffs as they look to involve the regulatory community.

“We’re better off trying to get onto the front end versus waiting for a baby to be dropped on the doorstep,” said Adam McKinnie, an economist with the Missouri Public Service Commission.

Robertson also said the Joint Planning Committee, comprising single representatives from MISO and SPP, will soon meet to consider suggested projects submitted during the grid operators’ Feb. 15 Interregional Planning Stakeholder Advisory Committee meeting. The grid operators plan to conduct a targeted market efficiency project (TMEP) study this year, focusing on smaller projects Robertson referred to as “TMEP-like”. (See MISO, SPP Take on 2nd Interregional Planning Effort.)

The RTOs expect to complete the study’s report and recommendations in August.

In reviewing their 2022 SAG work plan, members added a placeholder for Western services expansion to account for SPP’s many initiatives in the Western Interconnection. The group’s work plan also includes support for the TMEP development and JTIQ cost allocation work, and supporting SPP with seams-related activities in executing the RTO’s strategic plan.

MOPC, Board Meetings Moved to Dallas

SPP has moved its April governance meetings, originally scheduled for Little Rock, Ark., and Kansas City, Mo., to Dallas because of “challenges and uncertainty” its stakeholders have faced in making travel arrangements.

The Markets and Operations Policy Committee will be held April 11-12 and the Strategic Planning Committee on April 13. The Regional State Committee and quarterly joint stakeholder update is scheduled for April 25, with the board and Members Committee meeting April 26.

SPP encouraged stakeholders who are sick or who have been in close contact with someone infected with COVID to participate online. Unvaccinated attendees are “encouraged” to wear masks, but social distancing will not be enforced because of space limitations.

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FERC Reverses Itself on NYISO BSM Exemptions

FERC on Thursday voted 4-1 to accept revisions to NYISO’s buyer-side market power mitigation (BSM) measures designed to prioritize evaluating New York state-subsidized resources, reversing its decision in September 2020 to reject the ISO’s proposal (ER20-1718-002).

The BSM measures are designed to prevent uneconomic resources from entering NYISO’s capacity market. Under Part A of the mitigation exemption test, the ISO exempts a new entrant from the offer floor if the forecast of capacity prices in the first year of a new entrant’s operation is higher than the default offer floor. Its proposed revisions, submitted to FERC in April 2020, would to place “public policy” resources (i.e., renewable resources, battery storage and other zero-emission resources) ahead of nonpublic policy resources in its evaluations.

NYISO argued that in light of New York state legislation, including enactment of the Climate Leadership and Community Protection Act (CLCPA), subsidized resources were more likely to be completed. Unlike in 2020, under a Republican majority, the commission this time agreed.

Capacity requirements overview (NYISO) Content.jpgNYISO

 

“We are persuaded by evidence in the record indicating that NYISO’s proposed resequencing of resources is just and reasonable because it will minimize artificial capacity surpluses, which, as NYISO’s Market Monitoring Unit [Potomac Economics] explains, would otherwise occur ‘because the current Part A test can provide inefficient incentives for investment in new resources that are not needed,’” the commission said.

In addition to the CLCPA’s binding targets, the commission said that the Accelerated Renewable Energy Growth and Community Benefit Act provides for fast-track environmental review and permitting for major renewable energy facilities, and a number of nonpublic policy resources are expected to exit the market as a result of the state’s new “peaker rule” limiting NOx emissions.

FERC directed the ISO to submit a compliance filing within 30 days proposing a new effective date for the revisions no later than Aug. 1, the start of the next class year.

Reversal

FERC had approved several other of NYISO’s proposed revisions to the BSM measures in September 2020, including a formula that limited the amount of renewables that could be exempted. But its rejection of the Part A changes prompted a dissent from then-Commissioner Richard Glick and rehearing requests by the ISO, Equinor, New York Transmission Owners, the New York State Energy Research and Development Authority and the New York Public Service Commission. (See FERC Rejects NYISO Bid to Aid Public Policy Resources.)

The Republican majority at the time said NYISO’s plan was “unduly discriminatory because it does not provide sufficient justification for prioritizing the evaluation of public policy resources before nonpublic policy resources, independent of cost.”

Commissioner James Danly, now in the minority, said in a dissent that “the justifications offered in this order are simply unconvincing.”

“Our duty is to ensure just and reasonable rates pursuant to the [Federal Power Act], and not to determine whether NYISO’s proposal is consistent with federal, state, or municipal renewable energy policies,” Danly said.

Fellow Republican Commissioner Mark Christie concurred in a separate statement, taking exception to the majority’s reasoning.

“New York’s state law is discriminatory in its expressed preference for certain types of resources,” Christie said, while noting that the FPA does not pre-empt the state from doing so. “Does this make the NYISO’s tariff revisions — through which NYISO is acting necessarily to accommodate the reality of New York’s laws — produce rates that are ‘unjust, unreasonable and/or unduly discriminatory’ under the FPA? Under an ‘as-applied’ analysis of this specific, single-state ISO filing by NYISO — and under a practical approach — I do not find it so.”

Christie also said that there is no evidence that NYISO’s proposal would harm consumers in other states, and “if the people and businesses of New York do not like the impacts of their new state laws, their recourse is to the ballot box,” Christie said.

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Maryland Lawmakers Vow to up Climate Goals

ANNAPOLIS, Md. — State lawmakers last week expressed confidence that they will adopt more ambitious climate goals in 2022, saying they have resolved most of the differences between House of Delegates and Senate measures that stalled action last year.

“We are going to pass a climate bill this year,” Senate President Bill Ferguson (D) promised attendees at the Maryland Clean Energy Center’s (MCEC) legislative reception Thursday, during the sixth week of the General Assembly’s 90-day session. “A piece of legislation will be moving forward this year that will be robust and substantial.”

Last year, negotiations to increase the state’s emissions-reduction target collapsed after the Senate rejected House revisions that would have set the state’s 2030 goal at 50% of 2006 levels from the 60% target the Senate favored. (See Md. Climate Bill Dies in House-Senate Standoff.)

Del. Kumar Barve (D), chair of the House Environment and Transportation Committee, said earlier in the week that the two chambers were “working hand in glove” and that only small differences remain between the two versions of the climate package, Maryland Matters reported.

The wide-ranging Climate Solutions Now Act of 2022 (SB0528), sponsored by Sen. Paul Pinsky (D) and more than two dozen other Democrats, would mandate a 60% emissions cut by 2030, while the House legislation would set the deadline in 2032. The current 40% reduction has not been updated since 2016.

Pinsky told a crowd of more than 65 at the MCEC reception that much of the emissions reductions to date have resulted from low-cost natural gas, which has displaced coal-fired generation. “But we’re past low-hanging fruit. It’s time to change the paradigm,” he said, calling for “urgency and boldness.”

In addition to replacing the current GHG goal, Pinsky’s bill would advance the electrification of cars and school buses; ban the use of fossil fuels in newly constructed buildings beginning in 2023; and require commercial and residential buildings larger than 25,000 square feet to reach net-zero emissions by 2040. It also would create a $5 million/year green bank.

The House is considering separate bills on the elements in Pinsky’s legislation.

Pinsky’s bill and several other climate measures were aired during a nearly five-hour hearing of the Senate Education, Health and Environmental Affairs Committee on Feb. 15. Representatives of Exelon’s (NASDAQ:EXC) Baltimore Gas and Electric and Pepco opposed Pinsky’s proposed phase out of natural gas use as too quick and too expensive.

What Future for Gas?

The debate over gas’s future also played out at the MCEC event.

Josh Greene, vice president of government and industry affairs for A. O. Smith, the largest manufacturer of water heating equipment in North America, said his company supports “building decarbonization policies that are pragmatically formulated and executed.”

He said electric heat pump technology for water heaters remains “nascent,” noting that only 100,000 of the 8 million water heaters sold in the U.S. in 2020 were heat pumps.

“Multifuel approaches, from our perspective, are going to be important for us to achieve decarbonization goals,” he said. “It’s very hard for us to see a pathway that’s just one size fits all. So, we need to have flexibility as we move forward.”

But Maryland People’s Counsel David Lapp said the state needs to address the “death spiral” that will result as fewer people are left to pay for gas infrastructure.

He noted that the state is only a quarter of the way through its STRIDE program to replace existing gas infrastructure, with $4.8 billion in spending proposed for future years. BG&E’s cost recovery would extend until the year 2100, he said.

“We need to think about abandonment of parts of the gas system. It sounds significant and radical, but if we don’t start thinking about it, we are going to be facing huge cost consequences down the road for customers, perhaps taxpayers or shareholders,” Lapp said. “The people that can afford to electrify are the ones that are going to move off first. And people on budgets are going to be left on the system and are going to be stuck with higher rates.”

Lapp also called for limiting the role of utilities in electric distribution planning. “If we defer in our electric distribution planning too much to the utilities, we are going to end up spending more money than we need to, and we may not get the products and services that we want,” he said.

Grid planning is the subject of a bill (HB88) sponsored by Del. Lorig Charkoudian (D), who said it would ensure that distribution system planning is consistent with state goals and will allow the state to maximize federal infrastructure funding. “It’s technical; it’s wonky; people in this room love it,” she joked of the bill. “I love you for that.”

Ferguson, Pinsky and Charkoudian were among a parade of legislators and cabinet officials who asked for support of their legislative proposals.

Sen. Benjamin F. Kramer (D) made a pitch for SB 135, which would impose fees on fossil fuels, and SB 126, which would charge purchasers of high-polluting vehicles as much as $450 to fund electric transit and school buses and electric vehicle infrastructure.

‘Not that Far Apart’

Two members of Gov. Larry Hogan’s (R) cabinet also made appearances. Commerce Secretary Mike Gill expressed excitement over the economic development potential of offshore wind. “If we can only achieve 50% of [the jobs] they project … it’s like life sciences 30 years ago,” he said. “I think within the next 10 years, it is probably going to be … easily one of the top eight industries, seven industries, in Maryland.”

Environment Secretary Ben Grumbles dismissed what he said was a “false narrative” that the Hogan administration opposes climate action. “The key message that I want to convey is [that] throughout Maryland and throughout the legislative and executive branches, we are not that far apart,” he said. He noted that Hogan’s top priorities for the current legislative session — his last before his term expires — includes three environmental measures, including financing for Chesapeake Bay restoration.

Grumbles sought to distinguish Hogan from Virginia’s new Republican governor, Glenn Youngkin, who has called for pulling the state from the Regional Greenhouse Gas Initiative. Although he did not mention Youngkin by name. Grumbles said pointedly that Maryland “continues to be a leader” of RGGI. (See Youngkin Takes 1st Steps Toward Va. RGGI Withdrawal.)

State Comptroller Peter Franchot, who is seeking the Democratic gubernatorial nomination, also made a call for bipartisanship in brief remarks. “You know, we’ve got ideologues on the left; we’ve got ideologues on the right, 5% each side. Ninety percent of us are all in this together in the middle.”

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Just Transition: More than ‘Checking the Box’

WASHINGTON — Nicole Horseherder, a member of the Navajo Nation, began working to ensure a just transition for her tribe about five years ago, after learning that the 2.5-GW Navajo Generating Station would close more than two decades earlier than planned.

Nicole Horseherder 2022-02-17 (RTO Insider LLC) FI.jpgNicole Horseherder, To Nizhoni Ani | © RTO Insider LLC

“When we started, it was an uphill battle. I don’t think anyone really knew what a just and equitable transition was. And the utilities opposed our proposals, as did consumer groups and the [Arizona Corporation Commission] staff,” she said. But after learning how to intervene in the ACC’s proceedings and winning funding from Arizona Public Service (NYSE:PNW), “it looks like the road to just and equitable transition is possible,” Horseherder told the National Association of Regulatory Utility Commissioners’ Winter Policy Summit on Feb. 14.

Cara Goldenberg, a manager at RMI (formerly Rocky Mountain Institute), also has seen progress. Last year, she said, at least five states — Colorado, Illinois, Maine, Massachusetts and Oregon — passed “legislation to require, or explicitly authorize,” public utility commissions or other agencies to consider equity in decision-making.

“But even without legislation, regulators are already taking action,” said Goldenberg, who joined Horseherder and others on a panel discussion moderated by Wyoming Public Service Commissioner Mary Throne and Ohio Public Utilities Commissioner Beth Trombold.

“We’ve seen commissions create new staff positions or teams to focus on equity explicitly. We’ve seen states use performance-based regulation and planning processes to encourage utility efforts to evaluate distributional impacts of their investments, improve program design and targeting [to] benefit low- to moderate-income customers; and increased visibility and utility accountability on important equity metrics. We are also seeing commissions explore new ways to reach beyond intervener compensation and encourage effective collaboration and effective stakeholder participation from groups that haven’t traditionally been part of the regulatory process before.”

3,000 Jobs

Horseherder, executive director of Tó Nizhóní Ání (“Sacred Water Speaks”), a Navajo environmental organization, became engaged with Arizona regulators in 2017, with her group intervening in two proceedings. “Our goal is to ensure that utilities that own the plants are not allowed to just walk away. Instead they need to provide some kind of support to the communities that they profited from for half a century,” she said.

The Navajo Generating Station, the largest coal plant in the western U.S., closed in November 2019, and three other coal plants on or adjacent to Navajo land are scheduled to shut down within nine years. The plants had a combined capacity of more than 5,000 MW and employed about 3,000, most of them Native American workers.

“They are easily the highest paying [jobs] in the region, and for about 50 years, the power plant and the [Kayenta coal] mine were the economic foundations in northern Arizona,” Horseherder said. “The decision to shut them down so abruptly wiped away about $50 million of the Navajo Nation’s annual revenues and about 85% of the Hopi Nation’s tribal budget.”

APS, part owners of the Navajo plant and two of the other coal plants, reached an agreement to provide the Navajo Nation, Hopi Tribe and Navajo County $144 million to ease the post-coal transition. But the ACC last year reduced the funding to $10 million for the Navajo Nation alone, expressing concern that the deal would have been funded by ratepayers rather than APS shareholders.

Horseherder said the Arizona commissioners — who are elected statewide and serve four-year terms — see their stakeholders as only ratepayers and utilities.

The residents of communities where coal-fired generators are located may not be ratepayers, she said, and “are far removed from the cities in which the Corporation Commission is situated [Phoenix and Tucson]. And I think that’s the disconnect: that there’s people out there that they’re impacting that never even get to the radar.”

‘Learning Curve’ for Welfare Rights Org

Also joining Horseherder on the panel was Briana Parker, an organizer for the Detroit-based Michigan Welfare Rights Organization, who said the group has found it a challenge to engage with the Michigan Public Service Commission.

Briana Parker 2022-02-17 (RTO Insider LLC) FI.jpgBriana Parker, Elevate and Michigan Welfare Rights Organization | © RTO Insider LLC

“There’s lots of barriers, because we don’t understand [regulatory rules],” she said. “So while we’re there, it’s not meaningful, because, you know, the outcomes aren’t there; we’re just having conversations. … Having the utilities and commissions and nonprofit organizations that are already at the table all work together is how we can get to meaningful involvement, because there’s a learning curve.”

Wade Buchanan, director of the Colorado Office of Just Transition, who participated remotely, said community groups can find themselves outgunned in what is “a regulatory, legalistic process.”

“My observation is if you’ve got a good lawyer, you’ll get heard. And if you don’t have a good lawyer, you aren’t necessarily going to be heard,” he said.

Goldenberg said environmental justice and equity issues are beyond the traditional purview of state consumer advocates. “As these new proceedings get initiated, [they] are focusing on really difficult issues — issues that we haven’t necessarily had to deal with in the past — and a lot of issues that have a very real people element to it,” she said. “I want to be sure that commissioners don’t think that just because the consumer advocate is participating, that they can sort of just check that box. I think it’s necessary to have those community-based organizations as well.”

Goldenberg suggested that commissions document stakeholder comments, and how they were addressed, in writing. “Just that simple documentation gives assurance to groups that they’re being heard,” she said.

After the legislative action last year, Goldenberg said she is excited for 2022.

“I think there’s a lot of precedent now to build upon,” she said. “Legislation might not be necessary for commissions to act on it. So, I would encourage commissioners to also think about what they can do … with their current authority to advance the issue. … I feel like [we have] only scratched the surface in terms of what is possible for making equity a true tenet of utility regulation.”

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NARUC Transmission Panel: Leave No Megawatt Behind

WASHINGTON — With hundreds of gigawatts of solar, wind and storage sitting in interconnection queues across the country, state regulators are increasingly being faced with the conundrum of how to get more clean energy on already congested power lines.

At least part of the answer lies in a range of new technologies and strategies for optimizing existing distribution and transmission lines and rights of way, according to speakers on a Feb. 13 panel at the National Association of Regulatory Utility Commissioners’ (NARUC) Winter Policy Summit in D.C.

For example, David Townley, director of public policy for CTC Global, pitched for advanced conductors — like the ones his company produces — as “the fastest, lowest-cost way to add substantial capacity to an existing system.”

These conductors — wires that allow more electricity to flow on a system — use a “core made of carbon composites [that are] much lighter than the steel core of the conventional technology,” Townley said. “You can literally change wire for wire … but now you can upgrade the capacity on that line and increase the efficiency [and] lower the line losses immediately as soon as you energize that line.”

Allie Kelly, executive director of The Ray, an Atlanta-based nonprofit, believes that “the highway right of way is the solution that has been hiding in plain sight. The next-generation highway seeks to leverage that public asset — the public land and right of way — to enable and clear the way for new transmission development and construction,” she said.

Looking toward the electrification of commercial fleets, Kelly said, charging hubs for those vehicles are likely to be located adjacent to highways. “So, this is actually a very practical solution because you’re utilizing the right of way of the highway to provide the energy that will be required by these heavy-duty fleets.”

The Ray also promotes siting solar in highway rights of way, with an online mapping tool aimed at locating interstate interchanges that could be used for solar.

“We really need to have a dialogue and a conversation with the states, with the utility commissions, with developers, looking at existing infrastructure,” said Patricia Hoffman, principal deputy assistant secretary of the Department of Energy’s Office of Electricity. “Where can we maximize existing capacity? Where do we need to have additional capacity transfers across the United States so that we can develop the renewable energy but also get [it] into the markets in the most efficient and effective way possible?”

Building a Better Grid

Hoffman provided an overview of DOE’s thinking on transmission and the funding and financing opportunities made available under the Infrastructure Investment and Jobs Act (IIJA).

The department’s recently announced Building a Better Grid initiative includes integrating existing rights of way into national transmission planning, and Hoffman said collaboration will be key for achieving the “early wins” that optimizing existing transmission with grid-enhancing technologies (GETs) can produce. (See DOE to Tackle Tx Siting, Financing, Permitting in Better Grid Initiative.)

Looking at how GETS may change systems operation is yet another opportunity, Hoffman said. “How do we look at the operation of the system so that we get those most out of the topology we have?”

On the funding side, the IIJA includes $5 billion for system hardening and upgrades and another $5 billion for “innovative demonstration projects” that improve grid resilience, Hoffman said. It also authorizes DOE to become an “anchor tenant,” purchasing capacity on transmission projects, and to directly finance projects to get them “across the finish line.”

While not talking directly about the complex issues surrounding the permitting of new transmission, Hoffman suggested that system upgrades could provide momentum for new projects. “If we can utilize existing rights of way, existing capacity on the system, hopefully we can accelerate some of those opportunities for getting transmission built,” she said.

Bottom-line Benefits

Beyond upgrading lines with advanced conductors, utilities and transmission operators are also now looking at other GETs, such as dynamic line ratings (DLRs) and topology optimization, said Rob Gramlich, president of Grid Strategies.

DLRs vary the capacity of transmission lines based on multiple real-time conditions, Gramlich said. “When the wind is blowing, particularly perpendicular to the lines … or if the temperature is cold, you can deliver more megawatts over the same line without running into safety [or] reliability concerns,” Gramlich said. If that wind is also turning a wind turbine, “there’s great alignment with renewable energy.”

DLRs can also be used to redirect power to reduce congestion and increase financial savings, he said. Topology optimization software allows utilities or grid operators to track which circuits on their systems are open or closed on any given day; for example, if maintenance is being done. Power can then be rerouted, or different circuits opened or closed, to optimize efficiency and lower costs on a system, he said.

The challenge, Gramlich said, is that GETs may not provide bottom-line benefits to grid operators at this time. To fill the gap, state and federal regulators might consider incentives and, if necessary, requirements for including them in transmission planning, he said.

FERC on Thursday opened a docket on DLRs as a first step toward possibly requiring them for interstate transmission lines. (See related story, FERC Opens Inquiry on Dynamic Line Ratings.)

Townley argued that the economic case for reconductoring is more straightforward. Advanced conductors can be installed quickly — in some cases without shutting down the system — and without extra permitting or assessments under the National Environmental Protection Act, he said.

Putting more capacity on a line can allow more renewable energy to be interconnected on a system, reducing carbon emissions and, possibly, creating carbon credits or renewable energy credits that can be sold or traded on regional markets, he said.

A ‘Bright, Shiny Object’?

The Ray’s Kelly also pointed to the streamlined permitting that is possible if new transmission is sited in existing highway rights of way. It can cut permitting times in half — from 10 years to five years, she said — which can pencil out to $1 billion in savings.

Federal policy and funding are now encouraging transmission siting in highway rights of way, she said, calling for collaboration between state transportation and energy agencies to “establish priority corridors for new construction projects. … How many of you have talked with your state” department of transportation? she asked the NARUC audience. “The answer is never or not recently. Let’s start doing that today.”

She also cautioned that next-gen highways should not be seen as the next “bright, shiny object” in industry discussions about transmission — a quick solution to complex problems. “The right of way, whether it’s highways and interstates or the rail right of way, is an opportunity to design projects while reducing public impact,” she said. “So, it’s worth the effort to take the opportunity seriously.”

“Let’s not leave an ounce of capacity that is available online when taking a hard look at the existing system,” Hoffman agreed. “Look at your rights of way; look at your ability to reconductor; partner with your environmental offices as well as your transportation offices [and] the ISOs and RTOs. Those are the partnerships that we need to think about so we can capitalize on every megawatt that’s available.”

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Overheard at NARUC Winter Policy Summit 2022

WASHINGTON — More than 1,000 people traveled to D.C. for the National Association of Regulatory Utility Commissioners’ Winter Policy Summit last week, a hybrid affair that also offered video feeds for many sessions. Much of the talk was about the $62.5 billion in funding the Department of Energy received under the Infrastructure Investment and Jobs Act (IIJA).

Granholm: DOE Learning to Use ‘New Muscles’

The infrastructure bill is not only the biggest influx of funding in DOE’s history. It also marks a change in the department’s role regarding new technology, Energy Secretary Jennifer Granholm told the conference Feb. 15.

Jennifer Granholm (NARUC) Content.jpgEnergy Secretary Jennifer Granholm | NARUC

“It expands our department’s mandate to get clean energy technologies out into the world through demonstration and deployment. It’s a new muscle for us,” Granholm said, speaking to NARUC members via a video feed. “We’ve been really historically a research and development [agency] … with our National Labs. And now we are exercising a whole new muscle.”

Although the bill’s $615 million in funding for electric vehicle charging infrastructure is being awarded under Department of Transportation formula allocations, most of DOE’s funding from the IIJA will be awarded competitively, Granholm said. (See States to Get $615 Million for EV Charging from IIJA Funds.)

“Many of these are new programs,” she said. “So, we’re asking folks to send us their best, most innovative ideas. We want to solicit proposals that invest in rural and underserved communities. We want to bring in smaller utilities. We want to have maximum impact for climate and job creation and justice. So we are very excited about what this law means for DOE, and obviously everyone in [the NARUC conference] room, and for the country and the planners. We just can’t wait to work with you to get this done.”

DOE’s Energy Earthshots

Earlier Tuesday, the conference received a briefing on DOE’s three “Energy Earthshots,” initiatives to accelerate new technologies in order to meet President Biden’s targets of complete grid decarbonization by 2035 and net-zero emissions by 2050. 

Each initiative has its own cost-reduction target to achieve wide-scale deployment. The department received IIJA funding dedicated to research and development of each of the technologies: $9.5 billion for clean hydrogen; more than $10 billion for carbon capture and removal; and more than $7 billion in the supply chain for batteries.

Three DOE officials gave NARUC attendees an overview of each Earthshot, laying out just how ambitious the targets are and how necessary they will be in the future.

The goal of the Hydrogen Shot is to cut the cost of “green” hydrogen — produced with renewable power — to $1/kg by 2030. Because it can be used in so many different ways and in so many different sectors, producing it at scale will require unprecedented collaboration, said Kelly Speakes-Backman, of the Office of Energy Efficiency and Renewable Energy.

“Hydrogen is going to involve a greater integration of our Renewable, Fossil and Nuclear offices,” Kelly Speakes-Backman said. “It’s going to take an integrated approach across all sectors to realize the full benefits of hydrogen.”

Michael Pesin, of the Office of Electricity, discussed the Long Duration Storage Shot, which aims to cut the cost of utility-scale storage that can last more than 10 hours by 90% by 2035.

He presented a graph showing the staggering amount of short-duration (up to four hours) storage that would be needed to achieve the president’s 2035 target: up to 800 GW under a “high” scenario to be detailed in a future DOE report.

But the longer resources can last, the less capacity is needed. And by 2050, the U.S. will need storage that can last more than 100 hours and can be cycled seasonally or even weekly, Pesin said, because of equally staggering amount of renewables that are expected to be on the grid by then.

“This is a very aggressive goal; we realize that,” he said. “But we’re going to [use] all the resources of the department and work with industry and all of you to make sure we can achieve this.”

Finally, and perhaps most importantly, is the Carbon Negative Shot. Announced in November, it aims to reduce the cost of carbon dioxide removal (CDR) technologies to less than $100/net metric ton of CO2e.

The initiative is not about point-source emissions capture, said Emily Grubert, of the Office of Fossil Energy and Carbon Management. Nor is it about carbon avoidance and mitigation practices, though all are important to achieving net-zero emissions. It’s about directly removing carbon that is already in the atmosphere and oceans.

The goal is to enable gigaton-scale carbon removal. “To put this into perspective, 1 GT of CO2 is equivalent to the annual emissions from the U.S. light-duty vehicle fleet, according to a DOE factsheet on the initiative. “This is equal to approximately 250 million vehicles driven in one year.”

“Net zero can not happen without gigaton-scale CDR, based on a lot of the modeling we’ve globally and domestically,” Grubert said.

The department expects to establish at least three more Earthshots in the future. Grubert noted that the Carbon Negative Shot is the “youngest” of the current three, “but hopefully not for long.”

ACP Chief Cool to FERC ‘Backstop’ Authority

Speaking after Granholm, Heather Zichal, CEO of the American Clean Power Association, noted that most of the infrastructure funding will be spent over five to 10 years, unlike the spending in the pandemic recovery legislation, where the priority was to “get the money out the door as quickly as possible.”

“So we have a little bit more time to get the projects right, and get the processes right,” she said.

Zichal said she sees the infrastructure’s transmission funding as helping to accomplish three goals: preventing outages from natural disasters; relieving congestion that increases consumers’ costs and limits the connection of new renewable generation and deploying new technology, including offshore wind, microgrids and hybrid projects incorporating storage.

Like FERC Chairman Richard Glick, Zichal sought to lower expectations for the “backstop” authority the bill gave the commission to site transmission lines over state objections or delays. Glick told National Association of State Energy Officials conference attendees Feb. 9 that he doesn’t expect many utilities to ask FERC to overrule their state regulators. (See Glick Aiming for Final Transmission Rule by End of Year.)

North Dakota Public Service Commissioner Julie Fedorchak asked Zichal whether FERC’s exercise of that authority would result in better outcomes.

“That’s quite the question,” Zichal joked in response. “I might not have any friends [among state regulators] after answering it.

“When you have new authority, using it for the first time is scary and often a lot more difficult than you probably anticipated,” Zichal said. “Most major infrastructure projects are successful when they have strong buy-in at the state, local and regional level. And so I think that’s going to be … the key to success for any of these major transmission projects. …

“Without the local and regional support, you’re just not going to see those projects come to fruition,” she continued. “I think there are major questions around whether and how, the new authority in the bipartisan infrastructure bill would even be utilized.”

“I agree with you,” responded Fedorchak. “I think the states will get it done. Right, guys? We can do this.”

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WECC Workshop Assesses Western Risks

WECC continued its focus on reliability threats to the Western grid last week with a workshop on risk priorities and the first meeting of its new Reliability Risk Committee (RRC).

In the online Risk Priorities Workshop, stakeholders were split into a dozen small groups that each discussed four broad categories of reliability and security dangers for the bulk power system in the Western Interconnection. Two categories focused on the grid’s transition to renewable resources and its potential to undermine resource adequacy and transmission. Another dealt with security threats, and the fourth addressed extreme weather events.

“Our goal today is to narrow this universe of risks down to a preliminary list of, let’s say, around a dozen,” Victoria Ravenscroft, WECC’s senior policy and external affairs manager, told attendees Feb. 15. “To do this, we put the risks down into four categories to allow for manageable conversations. Each breakout group will discuss one of these risks, and everyone in this webinar today will discuss all four of these risks.”

Participants later prioritized what they believed to be the major threats in each category by voting on a mobile app. WECC compiled the top five results from all categories, generating a ranking with three top contenders: cyberattacks; human performance and skilled workforce; and extreme heat and drought.

Conversations in the breakout groups included talk of cyberattacks, including May’s Colonial Pipeline ransomware attack, and the perils of inexpensive drones to grid infrastructure.

The hazards of heat waves, like the one that caused rolling blackouts in California in August 2020, and deep freezes, like the one that nearly collapsed ERCOT’s grid last winter, featured prominently.

Workforce shortages caused by the retirement of skilled employees was another top conversation topic.

The workforce concerns were a new addition to the top-risks list, surprising some participants.

“I really appreciate the ‘crowdsource/wisdom of the crowds’ approach to collecting input, because I’ve been doing kind of remote regulatory support for long enough that human performance wouldn’t have been on my radar screen,” Brian Theaker, vice president of Western regulatory and market affairs at Middle River Power, said during a meeting of the Member Advisory Committee (MAC) held the next day. “But clearly, it’s an issue for a lot of … utility folks.”

Another MAC member, Grace Anderson, an adviser with the California Energy Commission, said, “I was surprised it rated that high on this list, but it did come up repeatedly in the sessions for my group.”

Anderson said her group lamented the loss of system knowledge that comes with retirements but also voiced concerns about the practice of younger employees departing utilities for more lucrative jobs in consulting.

“The attitudes and experience of the younger workers they do bring on are just from a different generation and a different set of experiences so that the twain doesn’t necessarily meet the way it has in the past,” she said.

WECC will use the rankings in the development of its biennial Reliability Risk Priorities report that identifies the Western Interconnection’s top hazards and guides WECC workplans.

The ERO’s first report in 2020 focused on resource adequacy, a changing resource mix, “extreme natural events” and the impacts to the grid of distributed energy resources and behind-the-meter storage. (See WECC Board Adopts Reliability Risk List.)

As for that report, this year’s workshop list will go to a WECC Board of Directors workshop in April and be subject to a board vote in June. WECC technical committees will then develop three-year workplans around the risk priorities, to be shared with stakeholders at the regional entity’s annual meeting in September.

Workshop participants praised WECC’s online orchestration of the workshop and expressed optimism about how its findings will contribute to future industry discussions on reliability in the Western Interconnection.

Speaking at the inaugural meeting of the RRC just after the workshop, Anderson offered a “shout out” to WECC staff for hitting a “grand slam” with the event.

“It was implemented, I think, flawlessly, because there was an enormous amount of work done behind the scenes in advance — a very difficult, complex set of arrangements,” Anderson said. She said the success was an “auspicious sign” for the launch of the newly formed RRC, which will take up many of the subjects unearthed at the event.

“You could clearly see how much effort went into it because it was seamless; so, yeah, major kudos to WECC and their staff,” MAC Chair Brenda Ambrosi, market policy and operations manager at BC Hydro, said at Wednesday’s MAC meeting.

Question of ‘Engagement’ on the RRC

It’s not often that a power industry meeting invokes the thinking of a storied president or a member of the Supreme Court in one sitting, but the launch of the RRC was just such an occasion.

The product of a yearlong — and at times contentious — effort to recast WECC’s stakeholder committee structure to closely align with its risk-oriented mission, the RRC is not so much a new body as it is a melding of the longstanding Operating (OC) and Market Implementation (MIC) committees. (See WECC Board Approves Stakeholder Committee Shakeup.)

And with that blending comes redefined roles. According to its charter, the RRC is tasked with identifying and addressing “known and emerging risks to the reliability and security of the Western Interconnection.” Its responsibilities will include:

  • evaluating “the reliability and security risks associated with relevant commercial, operational and other industry practices”;
  • working with WECC staff and the Reliability Assessment Committee “to develop and maintain an ongoing, prioritized list of known and emerging reliability and security risks facing the Western Interconnection; and
  • initiating actions “to address priority risks through the appropriate expertise and mechanism.”

RRC Chair Jon Aust, vice president of operations at the Western Area Power Administration, said the Stakeholder Engagement Task Force (SETF) that birthed the committee identified “the merger between commercial and reliability operations, and how those interplay with one another.” The group recognized a need to bring the two disciplines together into a shared forum.

“And that’s really at the core of why the MIC and the OC really have become the RRC,” Aust said.

RRC member Chifong Thomas, a transmission planning engineer with GridBright, said she was happy the RRC would include participants from both planning and operations.

“From participating in [WECC’s] Path Task Force, I understand that we have a different language; we’re separated by different language,” Thomas said. “So, the more we interact with each other, the better off we will be for the reliability of the system.”

Aust said he envisions a “dynamic” membership for the RRC, which should include real subject matter experts and people with the authority to make decisions on behalf of their organizations. He then posed the question of what other RRC members think should constitute true “stakeholder engagement” on the committee.

“It’s important that the organization send the right member, and it needs to be somebody who’s interested in what WECC’s doing and somebody that’s knowledgeable about WECC and NERC missions, goals and responsibilities,” said Ken Silver, vice president of storage operations and reliability at 8minutenergy Renewables.

Silver advised companies against sending staff to just “fill a chair” on the committee and instead select those equipped to share knowledge about relevant reliability matters.

“The sharing of ideas is paramount to engagement, and grid reliability is a concern for all of us, because we sink or swim together when it comes to reliability. And WECC and committees play a key role in our collective wellbeing,” Silver said.

“I always like to paraphrase President [John F.] Kennedy: Ask not what WECC can do for you; ask what you can do for WECC.”

Bryce Freeman, administrator of the Wyoming Office of Consumer Advocate, was demur about his ability to answer such “philosophical questions,” but he channeled the late Supreme Court Justice Potter Stewart in his attempt to do so.

“What does stakeholder engagement look like? I don’t know. Kind of like pornography. I recognize it when I see it, right?”

Freeman would instead “turn that question on its head” and ask how the committee could make its work engaging for the people volunteering their time join to it.

“WECC has always been good at not only identifying risks, but being able to see over the horizon to identify risks, and I think that is what is going to be critically important in the next five to 10 years as the resource mix changes, as there becomes multiple voices and multiple purposes about transmission.”

The RRC is expected to meet again in June.