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November 4, 2024

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PJM Markets and Reliability Committee Briefs: Aug. 24, 2022

Discussions Continue on Market Seller Offer Cap

VALLEY FORGE, Pa. — Load interests continued to oppose PJM’s proposal to change the market seller offer cap (MSOC), a month after it failed to meet the two-thirds endorsement threshold at the July 27 Markets and Reliability Committee meeting.

The proposal, which would ensure sellers are always able to represent the cost of their Capacity Performance (CP) risk when offering into the Base Residual Auction, had won only 60.4% support, as load sector stakeholders expressed concern over its impact on capacity prices. (See Change to PJM Market Seller Offer Cap Falls Short.)

The rule change would set the MSOC at the greater of the CP quantifiable risk (CPQR) or net avoidable-cost rate (ACR) inclusive of CPQR. PJM said it would address circumstances in which a unit with a positive CPQR value has that cost offset by an otherwise negative net ACR, which could result in a $0 offer cap. PJM had hoped to win stakeholder and FERC approval for the change effective with the 2024/25 capacity auction in December.

Load interests remained cool to the idea at the MRC on Wednesday.

Gregory Carmean, executive director of the Organization of PJM States Inc. (OPSI), asked PJM’s Pat Bruno why it was in buyers’ interests to “pay upfront the default costs of a supplier.”

“We think it’s in consumers’ interests to achieve competitive outcomes in the auction results,” Bruno responded. That result, he said, is “clearing the cheapest set of resources including the risk of nonperformance.”

Susan Bruce, representing the PJM Industrial Customers Coalition, suggested more work was needed before considering the proposal. “Are we ready for prime time with this vote?” she asked.

Independent Market Monitor Joe Bowring said PJM’s proposal would displace the Monitor’s role in setting the offer cap and fails to adequately define CPQR.

“We do not agree that what’s being proposed is a competitive outcome, or that it’s a narrow change,” he said. “You simply can’t have an unlimited adder that’s not defined in the tariff.”

Bowring said not using net energy revenues as an offset to CPQR breaks the “essential link” between the energy market and the capacity market, which generally means lower capacity prices when energy market prices are high. Because PJM has not defined how it would calculate the CPQR or the asserted opportunity cost, the RTO cannot say that the impact would be small, Bowring said.

Carl Johnson, representing the PJM Public Power Coalition, said his members agree with Bruce’s and Bowring’s concerns.

“I’ve become convinced we cannot have this discussion separate from the holistic” discussions at the Resource Adequacy Senior Task Force, he said. The proposal “is such an open door to market power that I don’t see how PJM could effectively mitigate it.”

However, Johnson said his members “do want to represent CPQR in their offers, so they wouldn’t go as far as [Bowring] recommended.”

Jason Barker of Constellation Energy said PJM’s proposal is “consistent with real-world economic decisions” that generation owners are making.

“PJM’s proposal is welcome; it’s ready; and it solves a very distinct problem that sellers encounter time and again,” he said. “A compulsory capacity commitment is not risk-free.”

Manuel Esquivel of Enel North America also expressed support, saying the status quo is not just and reasonable.

Tom Hoatson of LS Power also called for change to the offer cap, saying current rules result in “over-mitigating.” He said his company supports the PJM proposal with several revisions, including that the CPQR should be based on the market seller’s view of the risk of taking on a capacity obligation.

“This risk is viewed differently by different market sellers, and the market seller’s view of this risk is commercially sensitive,” he said. “One size doesn’t fit all, and the process needs to reflect that.”

LS Power also would change the deadline for requesting an exception to the must-offer requirement, making it at least five days after receipt of the final unit-specific MSOC value from PJM and the IMM. The current deadline is the same day as when the final MSOC is issued.

Hoatson also said all models, data and methodologies that the Monitor and PJM use to make their determinations should be made available to the market seller before their decisions are made.

Under the current rules, “it’s a black box,” Hoatson said. “We don’t know how the numbers were arrived at, so we can’t debate them with the IMM and PJM. Perhaps we’re wrong. Perhaps the other side is wrong. We don’t know.”

GreenHat Payments Expected by January

PJM Assistant General Counsel Mark Stanisz told members that the RTO should receive $1.375 million in disgorgements from the principals of the defunct GreenHat Energy by the end of January.

Under settlements approved by FERC on Aug. 19, two of GreenHat’s founders and the estate of the third agreed to pay the disgorgements. The principals also consented to the entry of a $179.6 million judgment against the company, reflecting the losses suffered by PJM market participants when GreenHat defaulted on its obligations in the financial transmission rights market in 2018. (See FERC OKs GreenHat Settlements.)

But PJM has no hope of recovering any of the nearly $180 million, Stanisz said. GreenHat “has no funds and no assets,” he said.

FERC ordered PJM to distribute the disgorged monies “in a reasonable manner” approved by the commission’s Office of Enforcement. The RTO said it will likely do so in a single distribution.

In response to a request from Constellation, PJM said it would advise market participants where they will see the disbursements in their billing statements.

Revised Bankruptcy Rules

PJM proposed changes to its credit policies to provide greater protections against bankruptcies by market participants, the RTO’s latest response to the GreenHat default.

The revisions would clarify that PJM has a first priority security interest in market participants’ cash deposits.

PJM would also require that a party filing for bankruptcy immediately address the RTO’s rights with a “first day” motion ensuring the full repayment of pre-petition obligations and the continuation of post-petition obligations.

The new language aims to demonstrate to bankruptcy courts that PJM has interests that are set apart from “garden variety” creditors, Assistant General Counsel Eric Scherling told the MRC. Though there are limitations on PJM’s ability to compel action from parties that have filed for bankruptcy, the revisions are aimed at making the proceedings go more smoothly to mitigate potential losses from delays.

“PJM is different, and we want to basically do whatever we can … to lay the groundwork as to why PJM is different,” Scherling said.

Tariff language would be changed to clarify that FTR transactions “are entitled to the special protections given to ‘forward contracts,’ ‘swap agreements’ and ‘master netting agreements’” under the U.S. Bankruptcy Code, including exceptions from automatic stays and allowing for immediate termination or liquidation.

The revisions were endorsed by the Risk Management Committee in July after meeting to discuss the issue six times. The proposal is expected to go before the MRC for approval next month.

FERC already approved revisions to PJM’s credit policy for FTR transactions in September 2018, setting a minimum credit requirement for FTRs equal to 10 cents/MWh (ER18-2090).

FTR Manual Changes Endorsed

The MRC endorsed revisions to Manual 6: Financial Transmission Rights as part of a periodic review and changes to conform with tariff revisions intended to increase the transparency and efficiency of the RTO’s auction revenue rights and FTR markets. The changes were approved by FERC in March (ER22-797). (See FERC Accepts PJM ARR/FTR Market Changes.)

Variable Environmental Costs and Credits Rules OK’d

Members approved an update to rules governing variable environmental charges and credits and their inclusion in cost-based energy offers. Generation units receiving production tax credits or renewable energy credits must reflect them in their fuel-cost policies when submitting non-zero cost-based offers into the energy market. The changes will include revisions to Manual 15: Cost Development Guidelines and Operating Agreement Schedule 2. (See “Variable Environmental Costs and Credits,” PJM MIC Briefs: May 11, 2022.)

Johnson thanked PJM for addressing Old Dominion Electric Cooperative’s concerns regarding differentiating fuel costs from emissions costs.

The update will be brought to a Members Committee vote in September.

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No Consensus on PJM Capacity Parameters

VALLEY FORGE, Pa. — PJM members failed to find consensus on any of four proposed sets of capacity auction parameters Wednesday, with the RTO’s proposal winning support from slightly more than half of members but falling below the necessary two-thirds threshold.

Proposals by the Independent Market Monitor, Calpine and GT Power Group in the 2022 Quadrennial Review all received less than 50% support in the sector-weighted votes. (See “2022 Quadrennial Review,” PJM MRC/MC Briefs: July 27, 2022.)

The parameters include the shape of the variable resource requirement (VRR) curve, the cost of new entry (CONE) for each locational deliverability area, and the methodology for determining the net energy and ancillary services (E&AS) revenue offset.

PJM’s proposal received a sector-weighted vote of 52%, with support of most Transmission Owners, Electric Distributors and End-Use Customers, but little support from Other Suppliers or Generation Owners. GT Power’s proposal on behalf of Cogentrix was the second favorite, winning 41%, with most support from the GO and OS sectors. The Monitor and Calpine packages trailed with 22% support each. Only 16% favored retaining the status quo parameters without changes.

Immediately after the meeting, the Members Committee approved a motion to forward the results of the MRC vote to the Board of Managers. The board is expected to file changes with FERC by Oct. 1; the changes would be effective with the July 2023 capacity auction.

Packages Explained

While PJM’s proposal includes major maintenance in variable operations and maintenance for recovery in the energy market, the Monitor’s would provide for recovery through the capacity market.

Both Calpine’s and GT Power’s proposals would continue to use historic net E&AS offsets, rather than switching to forward-looking as proposed by PJM and the Monitor.

GT Power’s would also continue to use a combustion turbine rather than a combined cycle plant as the reference unit because of the latter’s greater dependence on volatile E&AS revenues. All other packages would switch to the combined cycle plant.

CEJA Impact

Before the vote, economist Paul Sotkiewicz, representing generator J-Power USA, said the rules for the ComEd zone should reflect the shortened lifespan for new fossil-fired generation as a result of the Illinois Climate and Equitable Jobs Act (CEJA), which requires the state to move to a 100% carbon-free power sector by 2045.

Melissa Pilong 2022-08-24 (RTO Insider LLC) FI.jpgMelissa Pilong, PJM | © RTO Insider LLC

Sotkiewicz said the gross CONE will need to be updated to reflect the shortened economic life of new fossil units, noting a gas plant that went into service in 2026 would have only a 19-year lifespan rather than the 20-year assumption. “You can look at the [Illinois] legislation,” he said. “It’s clear as day.”

PJM’s Melissa Pilong said RTO staff had determined that no change in the lifespan was currently required.

Although PJM’s tariff mandates consideration of the parameters every four years, “nothing prevents us from changing parameters between Quadrennial Reviews,” MRC Chair Stu Bresler said.

DC Circuit Ruling

Sotkiewicz said PJM’s position ignored the D.C. Circuit Court of Appeals’ Aug. 9 ruling setting aside FERC’s order in April that rejected NYISO’s use of a 17-year assumed lifespan for a peaking plant in its capacity parameters (21-1166).

NYISO had cited the New York Climate Leadership and Community Protection Act (CLCPA), which mandates that by 2040, “the statewide electrical demand system will be zero emissions.” The ISO concluded that a gas-fired plant built between 2021 and 2025 would have an average lifespan of 17 years because the CLCPA “requires electricity demand in New York to be served by 100% zero-emission resources” by 2040.

FERC rejected NYISO’s proposed amortization period and required it to return to 20 years, noting that the CLCPA allowed the state’s Public Service Commission to relax the emissions rules if needed to maintain reliability (ER21-502-001). FERC said the ISO’s proposal was “premised on the speculative assumption that all fossil-fueled resources will cease operation in 2040.”

The D.C. Circuit granted the appeal of the Independent Power Producers of New York’s (IPPNY), noting that FERC’s review of Federal Power Act Section 205 filings is limited to whether the proposed rates are reasonable and not whether the proposal is more or less reasonable than alternative designs. The court said FERC’s decision to reject NYISO’s filing based on the possibility that the PSC might alter the CLCPA’s requirements was “squarely inconsistent with its precedents.”

FERC can abandon its precedents as long as it provides reasoned explanation for its action and acknowledges that it is changing its position, the court said. “FERC’s order neither recognized nor explained its departure from precedent,” it said. “That was arbitrary.”

The Sierra Club’s Casey Roberts said the D.C. Circuit ruling was unpublished and lacked much detail. “I don’t think it requires upending the Quadrennial Review,” she said.

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said the review “has been a great process,” although he said “most advocates still have a concern about over-procurement. It’s something that costs consumers billions.” He said most advocates would support the Monitor’s proposal.   

Susan Bruce, of the PJM Industrial Customer Coalition, said the ICC supported both the PJM and IMM proposals. The loss-of-load expectation (LOLE) was “much higher” for the other proposals, she said. The others also produce results far beyond the one-day-in-10-years LOLE reliability standard, increasing customers costs.

Roberts said the most recent capacity auction procured 13 GW in excess of the RTO’s reliability requirement.

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California PUC Postpones NEM Decision Amid Pressure

The California Public Utilities Commission on Thursday approved a one-year postponement of a decision in its net energy metering rulemaking, as parties on both sides of the issue argued that the Inflation Reduction Act, signed by President Biden last week, supports their views on rooftop solar credits.

The CPUC passed the order extending the deadline for its decision in a unanimous vote on its 35-item consent agenda. Commissioners did not discuss the move, despite its significance and the controversy that has engulfed the CPUC ever since it issued a proposed decision in December to slash solar credits and charge owners for grid participation in a new net energy metering (NEM) tariff. (See California PUC Proposes New Net Metering Plan.)

“An extension of the statutory deadline until August 27, 2023, is necessary to allow adequate time to complete this proceeding,” the order said, citing the need to digest a flood of comments and consider alternative approaches.

The proposed decision was released on Aug. 15. (See CPUC to Delay Net Metering Decision for a Year.)

As in many of its voting meetings this year, the bulk of the CPUC’s session Thursday consisted of public comments on the NEM proceeding, mainly from homeowners upset about the proposed changes.

Their latest target was a filing by the state’s three large investor-owned utilities contending that the extension of federal credits for rooftop solar in the IRA made the state’s generous credits unnecessary.

“The Inflation Reduction Act, and more specifically the extension of the 30% tax credit for both non-residential and residential solar projects, is directly relevant to the modeling of a successor net energy metering tariff in this proceeding,” Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric said in their Aug. 19 joint filing, which asked the CPUC to take official notice of the new law.

The federal credit “reduces the cost of solar adoption, thereby reducing the payback period for customers benefitting from the tax credit,” the IOUs said.

The utilities have pushed to reduce the longtime state credits that reimburse residential and non-residential solar owners for energy exported to the grid. Customers receive credits at full retail rates, which are now much higher than utility solar costs.

The utilities argued the scheme shifts $4 billion in costs from those who cannot afford rooftop solar to those who can.

In her December proposed decision, Administrative Law Judge Kelly Hymes agreed with the argument, saying the cost shift “disproportionately harms low-income ratepayers.”

Opponents of that proposal, however, contend that more than 1.3 million rooftops in California now have solar arrays, thanks in large part to the generous NEM credits. On Thursday, commenters took issue with the IOUs’ suggestion that the IRA made California’s incentives less necessary.

The state wants to reduce incentives just when Congress clearly indicated the importance of rooftop solar to the nation and when incentives are needed more than ever, they said.

“Your mindset of allowing new solar taxes to be charged and lowering the solar production credits is just wrong,” David Delphos of Orange County told the CPUC. “There is nothing in the new Inflation Reduction Act of 2022 that can justify any new California solar taxes or justify lowering the solar credits for solar system owners.”

Yvette DiCarlo of San Francisco said that “PG&E is now using the Inflation Reduction Act to further justify penalizing rooftop solar.

“Meanwhile PG&E’s website boasts how they own and operate 13 solar large farms in the Central Valley, far from their main customers, and how they also continue to add solar to the grid through contracts with third-party developers. They also boast adding 3,300 MW of new storage by 2024, so it’s clear that PG&E treats rooftop solar as a competitive threat to be squashed.”

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MISO Flags Capacity Gap Risks in Fleet Transition Assessment

CARMEL, Ind. — MISO this week said its future holds exponential renewable growth, free-falling carbon emissions and a stubbornly persistent capacity risk, requiring a slew of new capacity.

The pronouncements come from the initial findings of MISO’s annual Regional Resource Assessment (RRA). The grid operator said that by using publicly available utility plans and its own assumptions, it expects the system will draw 30% of its annual energy from renewables by 2027 and approach 60% by 2041.

Also by 2041, the footprint will collectively decarbonize 80% from peak 2005 levels, MISO predicted. Renewables currently make up about 13% of the RTO’s resource portfolio.

“That is significant because this study is basically bringing together our members’ plans … and showing what the footprint will look like,” MISO engineer Aditya Jayam Prabhakar said during a Resource Adequacy Subcommittee meeting Wednesday.

Jayam Prabhakar said the risk of a capacity shortfall will persist throughout the fleet transition, “highlighting the immediate importance of coordinated resource planning.”

The grid operator said it found a need for members to expand nameplate capacity by 100 GW by 2030 to meet their combined carbon-reduction plans and stay within safe reserve margins. By 2041, MISO may need a 200-GW expansion in nameplate capacity.

The RTO also said it expects average capacity factors for operational natural gas and coal units to decline between 10 and 30% over the next 20 years. It said that even if current company resource planning is implemented on time, a systemwide shortfall is possible beginning in 2027.

Jayam Prabhakar added that the assessment relies on “highly evolving” information and characterized MISO’s analysis as a “guided tour,” as opposed to a deep exploration of future possibilities.

MISO did not include generation retirements beyond what is already publicly announced. Michelle Bloodworth, of coal lobby group America’s Power, said she thought the RTO was underestimating thermal generation retirements.

“Like all studies, the results of the RRA are sensitive to inputs and assumptions. This is but one possible scenario in a quickly evolving landscape,” Policy Studies Engineer Hilary Brown said.

MISO future capacity need projections (MISO) Content.jpgMISO future capacity need projections | MISO

 

She said MISO is notably missing some intermediate resource planning information from members around their 2030 greenhouse gas emissions goals. “Many companies have defined carbon-reduction milestones around 2030, leading to a possible large, single-year buildout.”

Responding to stakeholders’ questions, Brown said MISO has not yet included the torrent of renewable energy development that will possibly take place under the recently signed Inflation Reduction Act. She said the impacts under the law will be contemplated in next year’s assessment.

“We’re going to see some pretty crazy changes next year in how companies react to the Inflation Reduction Act,” Southern Renewable Energy Association Executive Director Simon Mahan said.

Brown said a “one-for-one capacity replacement” is not sufficient when replacing thermal generation with intermittents. She said that while MISO foresees a deepening capacity shortfall, members’ plans could change in reaction to MISO’s Planning Resource Auctions (PRAs).

“This isn’t new. We’ve seen it in last year’s PRA,” Brown said of declining and inadequate margins. (See OMS RA Summit Confronts Midwestern Supply Squeeze.)

Months after MISO’s capacity auction shortfall, several utilities unveiled deferrals on coal retirements.

WEC Energy Group and Alliant Energy have announced they are postponing retirement plans for multiple coal plants because of concerns over grid reliability. Likewise, Ameren Missouri is expected to defer the planned Sept. 1 retirement of its 1.2-GW Rush Island power plant until 2025. Two Montana Public Service Commissioners recently called on state lawmakers to do everything in their power to keep the Colstrip generating facility operating to prevent freezing deaths this winter. Colstrip is owned by Talen Montana, Puget Sound Energy, Portland General Electric, Avista, PacifiCorp and NorthWestern Energy.

On the other end of the spectrum, Clean Grid Alliance in mid-August saluted Illinois, Iowa and Indiana in particular as jurisdictions in the MISO footprint where renewable energy development is blossoming.

The alliance said Indiana’s 6.3 GW of solar projects in development currently ranks third in the nation; Illinois’ nearly 8 GW of operating wind, solar and storage capacity currently ranks sixth; and Iowa leads with 207 MW of land-based wind power coming online in the second quarter of 2022.

CGA said the nine states in MISO’s Midwestern region combined have 12 GW of clean power capacity in advanced stages of development.

Multiple stakeholders said MISO did not reveal enough about its modeling methods and data sources for others to fact-check its resource analysis.

The RTO plans to publish the full 2022 RRA in November.

Stakeholders Ask MISO for Midyear Capacity Accreditation

Disappearing reserves in its capacity auction has sparked a new stakeholder proposal at MISO.

MidAmerican Energy’s Dennis Kimm asked that MISO accredit new planning resources that enter the picture after the planning year is underway.

MISO doesn’t currently permit new generation to convert its output into accredited capacity in the middle of a planning year. New generators currently must wait until preparation for next year’s capacity auction begins before they become eligible to receive zonal resource credits.

Several stakeholders said they supported the proposal and requested MISO create new tariff language immediately.

Alliant’s James Niccolls said that, “frankly, it’s hard to explain” MISO’s current practice to his company’s leadership and customers.

“There’s obviously widespread stakeholder support on this,” RASC Chair Kari Hassler said.

Meanwhile, stakeholders again requested that MISO publish more data ahead of its PRAs on generator suspensions and granted participation exclusions. Some have said MISO should publish a line item on generation that’s likely to be unavailable in the auction and give members a better idea of the footprint’s expected margins before the auction window opens.

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California Adopts Rule Banning Gas-powered Car Sales in 2035

The California Air Resources Board on Thursday adopted regulations that will require all new cars sold in the state to be zero-emission or plug-in hybrid by 2035 — a move the agency described as historic and trailblazing.

The CARB board voted unanimously to approve the regulations, called Advanced Clean Cars II (ACC II).

“This is the most important and most transformative action that CARB has ever taken,” board member Daniel Sperling said. Sperling, who is a founding director of the Institute of Transportation Studies at the University of California, Davis, cast his vote by saying “super aye.”

“We can solve this climate crisis if we focus on the big, bold steps necessary to cut pollution. California now has a groundbreaking, world-leading plan to achieve 100 percent zero-emission vehicle sales by 2035,” Gov. Gavin Newsom said in a statement.

ACC II will require car manufacturers to provide for sale in California an increasing percentage of zero-emission vehicles each year. The new regulation starts with a 35% zero-emission vehicle (ZEV) sales requirement for model year 2026, increasing to 68% in 2030 and reaching 100% in 2035.

The rules build on the state’s Advanced Clean Cars regulation, which was first adopted in 2012 and is still in effect. The current regulation’s ZEV sales requirement tops off at 22% for model year 2025.

In addition to ZEV requirements, the ACC II regulation includes a low-emission vehicle (LEV) component aimed at reducing tailpipe emissions of gasoline-powered cars.

Seventeen states have adopted California’s Advanced Clean Car standards as allowed under Section 177 of the Clean Air Act. Many of those states are now expected to consider adoption of ACC II.

CARB must apply for and receive a waiver from the EPA to enforce the regulations.

Reducing GHG

Transportation is California’s single largest source of greenhouse gas emissions and air pollution, according to CARB. ACC II is expected to reduce passenger vehicle GHG emissions by 50% or more by 2040.

Environmental groups commended CARB for adopting ACC II.

“The standards passed today move California to the head of the pack in the race for clean transportation,” Fred Krupp, president of Environmental Defense Fund, said in a statement. “Thanks to the state’s leadership, California — and our entire country — are now speeding toward a safer and healthier future with no tailpipe pollution.”

But some people who commented during the board meeting were concerned about the impact of the ZEV requirements on small businesses and farmers. One farmer asked CARB staff how she is supposed to install a Tesla charging station in the middle of her cornfield.

ACC II applies to new vehicle sales and will not impact vehicles already on the road.

One speaker at the board meeting predicted that as a result of the regulation, drivers will hang on to their internal-combustion engine vehicles longer, bringing in more business for mechanics.

Infrastructure Is Key

CARB board member Barbara Riordan cautioned that building sufficient EV charging infrastructure will be key to the success of the program.

While substantial funding has been earmarked for EV infrastructure, “it has to be implemented,” Riordan said.

“A lot of people won’t invest in an electric vehicle unless they can be assured that the infrastructure is there to keep it charged, to keep it going,” she said.

The ZEV sales requirements of ACC II apply to cars, pickup trucks and SUVs. Plug-in hybrid (PHEVs), full battery-electric and hydrogen fuel cell vehicles count toward an automaker’s requirement. PHEVs must have an all-electric range of at least 50 miles under real-world driving conditions. Automakers will be able to meet up to 20% of their ZEV requirement with PHEVs.

Battery-electric and fuel cell vehicles will need a minimum range of 150 miles to qualify under the program. In addition, they must include fast-charging ability, come with a charging cord and meet new warranty and durability requirements.

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Western Power Pool Board Approves WRAP Tariff

The Western Power Pool’s board on Tuesday approved a tariff to implement its Western Resource Adequacy Program, an initiative intended to ensure that participants across much of the Western Interconnection have sufficient capacity amid a changing resource mix.

WPP said it is planning to file the WRAP tariff with FERC by Aug. 31, followed by a 30-day comment period.

The program, which already has 26 participants in an area reaching from British Columbia to Arizona and east to South Dakota, is the “first region-wide reliability planning and compliance program in the history of the West,” WPP said in a news release Wednesday.

The tariff approval “is another major milestone leading us closer to making this first-of-its-kind program a reality,” WPP CEO Sarah Edmonds said in the news release. “Resource adequacy is an urgent and immediate challenge, especially in the West, and requires this type of regionwide approach to address it.”

Last week the WRAP’s Resource Adequacy Participant Committee (RAPC), consisting of a representative from each participant, also approved the draft tariff. The 74-page document lays out the program’s governance structure, including the roles of the RAPC, a Committee of State Representatives (COSR) and a Program Review Committee.

It describes in detail the program’s two main “time horizons,” a forward-showing program requiring participants to show they have sufficient capacity months in advance of summer and winter peaks, and an operational program, focused on the allocation of resources in real-time and day-ahead time frames.

And it addresses issues such as participation rates, financial penalties for resource deficiencies and failures to deliver, and dispute resolution.

Since 2020, WPP has been developing the WRAP, an initiative conceived to address concerns that Northwest utilities have been increasingly and unknowingly drawing on the same shrinking pool of reliability resources. But interest in the effort spread quickly to other areas of the West. In a move that signified its expanding reach across the Western Interconnection, the Northwest Power Pool rebranded itself as the Western Power Pool earlier this year.

The WPP is slated to launch a “nonbinding” iteration of the WRAP in the third quarter of this year and a binding phase with penalties sometime in 2024. Initially, the absence of enforcement and penalties will shield the program from FERC oversight, giving members additional time to iron out wrinkles and finalize its design.

WPP last year selected SPP to develop and operate the technical aspects of the WRAP, providing the market’s forward-showing functions, modeling and system analytics, and real-time operations.

Some in the West have speculated the WRAP could serve as a springboard for the eventual development of an RTO, one that would compete with CAISO’s stalled regionalization efforts and the ISO’s well-established Western Energy Imbalance Market. SPP has been using its new foothold in the West through the WRAP to build interest in its Markets+ program, a collection of services that stops short of a full RTO but could eventually develop into one. (See SPP Continues to Build on Markets+ Offering.)

Anticipating possible future requirements, WPP has already moved to restructure its governance and prepare to adopt some elements of an RTO, such as the appointment of an independent board of directors. WPP also established the COSR to ensure that utility regulators have a voice in discussions related to the WRAP.

The tariff appears to address the eventuality, saying: “Subject to the limitations and prohibitions imposed under Section 3.4 of this tariff, if the Board of Directors votes to file at FERC to expand the WRAP to include market optimization or transmission planning services, WPP will initiate a formal process with COSR and other stakeholders to conduct a full review of governance structures and procedures, including the role of states.”

‘Collaboration and Transparency’

The WPP published the WRAP draft tariff last month, inviting stakeholders to comment during a public webinar on July 25. Feedback from that session was incorporated into the updated draft that the board approved.

“Throughout this process we have remained committed to collaboration and transparency,” Edmonds said. “For three years, we have worked with regulators, participants and stakeholders to shape the program. We’ve listened to stakeholder voices, embraced their comments, and refined the program design and the tariff itself to get to a solution supported by all participants.”

FERC’s approval of the tariff would allow WPP to set rates and terms of participation and to make governance changes.

“WPP is hoping for a final order from FERC giving approval by the end of this year,” the group said in the news release. “The WRAP team also intends to confirm commitments from potential participants for the next phase of their participation by mid-December.”

WRAP Stage 1 participants include Arizona Public Service, Avangrid, Avista, Black Hills Energy, Basin Electric Power Cooperative, Bonneville Power Administration, Calpine, Chelan PUD, Clatskanie PUD, Douglas PUD, Eugene Water and Electric Board, Grant PUD, Idaho Power, NorthWestern Energy, NV Energy, PacifiCorp, Portland General Electric, Powerex, Puget Sound Energy, Seattle City Light, Snohomish PUD, Shell Energy, Salt River Project, Tacoma Power, Turlock Irrigation District and The Energy Authority, which is representing seven Washington and Oregon publicly owned utilities.

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Oregon Looks to Accelerate GHG Reduction Goals

With its 2035 greenhouse gas reduction goal in sight, the state of Oregon is looking for ways to reach that same target in 2030 instead.

The state is analyzing two pathways. One would rely on electrification to hit the goal of reducing GHG emissions 45% below 1990 levels by 2030.

The second pathway would maximize the use of alternative fuels — RNG and hydrogen in particular — with some electrification actions included. This so-called hybrid scenario was developed because relying on RNG and hydrogen alone would not be enough to reach the GHG reduction target, according to projections.

The alternatives were discussed last week during a meeting of the Oregon Global Warming Commission. The OGWC is working with the Oregon Department of Energy (ODOE) and consultants on a plan called the Transformational Integrated Greenhouse Gas Emissions Reduction, or TIGHGER. (See Oregon Effort Seeks to ‘Close the Gap’ on GHG Goals.)

The commission plans to complete a Roadmap to 2035 report by the end of the year, in time to submit to the state’s 2023 legislature. The report could recommend implementing the electric or hybrid alternative, or some combination of the two.

Accelerated Goal

TIGHGER initially set 2035 as the target date for reducing GHG emissions 45% relative to 1990 levels. The target is an interim step toward the state’s long-term GHG reduction goal of 80% by 2050.

But an analysis found that the state would hit the 2035 target through programs and regulations already adopted and under development.

“That was great to see,” said OGWC Chair Catherine Macdonald. “Because we found out that we are on track to meet our goal for 2035 by 2035, we are looking at an accelerated goal.”

Efforts that will contribute to meeting the target in 2035 include last year’s HB 2021, which aims to reduce GHG emissions from electricity generation 80% by 2030, 90% by 2035 and 100% by 2040. There’s also the Climate Protection Program from the Oregon Department of Environmental Quality, which sets a declining cap on GHG emissions from fossil fuels used in transportation, residential, commercial and industrial settings. (See Oregon Adopts GHG Cap-and-invest Program.)

With those two major programs being implemented, remaining steps to reduce GHG emissions will be relatively small in scope, said Alan Zelenka, assistant director for planning and innovation at ODOE.

Additional steps to reduce GHGs might include heat pump installation in new and existing buildings, all new electric vehicle sales by 2035, a shift of drivers to car-sharing and public transit, and a reduction in food waste.

“It’s a combination of all these little projects that make up the ability to … meet the goal,” Zelenka said.

Rating Cost Effectiveness

The scenario analysis included development of marginal abatement cost curves, which rank GHG-reduction actions by their cost effectiveness.

For both the electrification and hybrid scenarios, new commercial building codes, followed by a transition in medium- and heavy-duty vehicles, were found to be the most cost-effective measures. Residential and commercial building retrofits were the least cost-effective actions.

Zelenka said that under a least-cost planning approach, the most cost-effective measures would be implemented first. By the time the least cost-effective actions are implemented, their costs may have come down, he added.

But when developing a final ranking of GHG reduction actions, officials may consider co-benefits, such as job creation or healthcare cost reductions. OGWC will further discuss co-benefits next month.

IRA Impact

Some meeting participants said the Inflation Reduction Act that President Biden signed into law this month could improve the cost-effectiveness of certain GHG reduction actions. The new law will provide incentives for energy-efficient home retrofits and electric home appliances.

“That’s definitely very relevant to how we’re framing costs,” said commission member Nora Apter.

Zelenka said the impact of the IRA could be included in updates to the analysis.

During a public comment period, Karen Harrington with The Climate Reality Project’s Portland chapter said she was thrilled that OGWC was looking at an accelerated 2030 target. But Harrington questioned the commission’s consideration of the alternative fuels-focused hybrid scenario.

“To get us there, we have to look at all-electric,” Harrington said. “The hybrid system isn’t going to get us there.”

Commission member Tom Potiowsky responded by saying it’s “more robust” to keep the hybrid scenario in the analysis. And technology may change as time goes on, he said.

“As we go down the road, these things may become more … economically viable alternatives for us to use to reduce emissions,” Potiowsky said.

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NSTAC Warns of IT/OT Convergence Risks

Serious cybersecurity vulnerabilities continue to plague U.S. critical infrastructure — including the power grid — despite their owners’ commitment to protecting their assets, according to a report released this week by the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA).

The report was prepared by the President’s National Security Telecommunications Advisory Committee (NSTAC), a body of leaders from the telecommunications, information technology, finance and aerospace industries that advises the federal government on maintaining secure and reliable communications. It is part of a broader federal response to the Colonial Pipeline hack and other cybersecurity incidents ordered last year by President Biden. (See Biden Directs Federal Cybersecurity Overhaul.)

Biden’s order directed NSTAC to study three key cybersecurity topics:

      • software assurance in the commercial information and communications technology supply chain;
      • zero trust and trusted identity management; and
      • the convergence of IT and operational technology systems.

Tuesday’s report, a working draft, focused on the third issue; a later, comprehensive report is planned that will cover all three areas.

Common Risks in OT Systems

In the document, NSTAC identified three common deficiencies that enable potential attackers to cross over from businesses’ IT networks — which are used for data-centric computing and communications — into their OT systems, which monitor and control events, processes, and devices in enterprise and industrial operations. Cybersecurity researchers have warned that cybercrime groups around the world are actively developing such crossover capability. (See Dragos Warns Malware Developers Building Skills Fast.)

The first security issue cited by the report’s authors is the lack of an effective “air gap”: an isolation of a business’s OT and IT assets that prevents any communication, either physically or wirelessly. Air gapping is essential to OT security because attackers can use any contact with an IT system to gain access to and control over the OT system. But the report said that even this basic level of security seems to be a major challenge for many businesses.

“While there are many OT engineers that may rely on the idea of an air gap to protect their environments, asset operators should recognize that in most environments, the air gap is a myth,” the NSTAC said, adding that many of its members “have 25 years-plus experience and have never seen a true ‘air-gapped’ OT system.”

What prevents an effective air gap, the report said, is usually the sheer convenience of connecting OT networks to the internet. Putting systems online rather than limiting access to those who are physically present allows a wider range of employees to monitor and step in if anything goes wrong.

However, it also means that an organization’s security staff lose some control and visibility into who has access to the OT systems. The NSTAC calls this phenomenon “accidental convergence,” and it comprises the second major theme of the report, defined as when “the system owner does not even realize or have visibility into which devices reside where on their networks.” This is especially the case in systems where OT assets have been connected to cloud services, which is increasingly common in the U.S.

While the authors acknowledged efforts are underway to mitigate the security risks of connecting to the open internet, they cautioned that even these advanced security controls cannot entirely remove the “fundamental availability risks of services delivered over the internet.”

The final vulnerability is the existence of “shadow IT,” in which OT systems are “added and modified without official IT change management control and approval.” While the report noted that OT systems usually are designed to “limit the ability to effect changes to assets in the environment,” as with air gapping, such precautions often lapse without highly disciplined change management processes. This can create problems when, for instance, employees use workarounds during urgent troubleshooting that are never removed from the environment afterward, or engineers use off-the-shelf components with unauthorized connectivity capabilities instead of following proper procurement protocol.

NSTAC provided several recommendations for the president and other government agencies, including CISA, to help “further reduce risk and secure the nation’s critical infrastructure.” While these mainly concern government OT networks, they also include measures on communication and information sharing. The report’s authors called on CISA, the National Security Council and the Office of the National Cybersecurity Director to develop “interoperable, technology-neutral, vendor-agnostic information-sharing mechanisms” to allow the sharing of real-time data “between authorized stakeholders involved with securing U.S. critical infrastructure.”

“NSTAC also recognizes that the federal government alone cannot uniquely resolve all the challenges surrounding OT cybersecurity, and readers from all stakeholder groups will benefit from the additional findings, best practices and general guidance contained in the appendices,” the report said.

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Maine, RI Join Multistate Hydrogen Agreement

Maine and Rhode Island will join New York, Connecticut, Massachusetts and New Jersey to create a consortium that will apply for federal funding this fall to develop a regional hydrogen hub, New York Gov. Kathy Hochul announced Thursday.

The coalition — which includes 14 private sector industry leaders, 12 utilities, 20 hydrogen technology original equipment manufacturers (OEMs), 10 universities and two transportation companies — will compete for $2 billion matching grants from the U.S. Department of Energy early next year.

It has agreed to work with the New York State Energy Research and Development Authority, the New York Power Authority and Empire State Development on a proposal to advance clean hydrogen projects in the Northeast, according to Hochul’s office. The proposal will center climate and environmental justice while also looking to boost the economies and quality of life in each state involved, it said.

Kathy-Hochul-(Darren-McGee-Office-of-Governor)-FI.jpgNew York Gov. Kathy Hochul | Darren McGee, Office of Governor

“Building a robust and connected clean hydrogen market across the Northeast will provide a game-changing clean energy alternative that will transform our ability to meet our shared climate goals while advancing 21st century innovation and stimulating strong economic growth throughout the region,” Hochul said in a statement.

The hydrogen hub grants were authorized in the $1.2 trillion Infrastructure Investment and Jobs Act signed into law in November 2021, providing $8 billion for four regional hydrogen hubs, $1 billion for research to bring down the cost of hydrogen electrolysis and $500 million to support equipment manufacturing.

DOE said it will issue a request for proposals in September or October, with final applications due in the first quarter of 2023. The department issued an initial request for information earlier this year.

The Battelle Institute, which administers nine National Laboratories, said earlier this summer that multistate applications would have a better chance of winning funding. The independent research lab is working with Ohio, Pennsylvania and West Virginia in an effort to plan a regional hub creating and using hydrogen made from natural gas, which is plentiful in the region.

There are also efforts to create hydrogen hub groups in Oregon and Washington state, and a Gulf Coast hub from Louisiana to Texas, centered in Houston. Four Western states — New Mexico, Colorado, Utah and Wyoming — announced intentions in February to create a hub. And New Mexico is considering switching a power plant to hydrogen. Southern California Gas unveiled a plan in February to build a pipeline to transport hydrogen from Mojave Desert to customers in the Los Angeles Basin.

“I am proud to have Rhode Island join the New York-led Regional Clean Hydrogen Hub as we explore the amazing potential that hydrogen offers, not only as an additional clean energy resource, with broad applications across our transportation and industrial sectors, but also by adding new jobs to our economy,” Gov. Dan McKee said in a statement.

Dan Burgess, director of the Maine Governor’s Energy Office, said clean hydrogen is “an exciting technology with potential for economic growth that can reduce greenhouse gas emissions from fossil fuels.”

The Northeast Clean Energy Council, a major policy player in the region, is another of the coalition’s new partners. So are Rensselaer Polytechnic Institute, Siena College and the University of Connecticut. And energy companies including EDP Renewables North America, Equinor and Edgewise Energy have joined as well.

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Company Looks to Build Hydrogen Projects in Eastern Oregon, Washington

An Oregon renewables company wants to construct two hydrogen manufacturing plants and a network of hydrogen pipelines in eastern Oregon and Washington later this decade.

Obsidian Renewables of Lake Oswego, Ore., plans to build hydrogen production plants at existing industrial parks in Hermiston, Ore., and Moses Lake, Wash. The plants would use electrolyzers to separate hydrogen from water and wastewater.

These would supply a proposed pipeline system that would terminate at points in The Dalles, Pendleton and Prineville in Oregon, and in Wenatchee and Spokane in Washington. Another pipeline would extend to Lewiston, Idaho. One connecting pipeline would go through the Tri-Cities, which is the second-most populated area in eastern Washington behind Spokane.

The network would be powered by electricity from new wind and solar farms, with each type of renewable resource expected to supply 800 MW.

The company believes the project will cost roughly $3 billion, Obsidian President David Brown said in an interview.

Obsidian is still putting together the pieces of the project, with Brown declining to name potential partners. He said different partners will likely tackle different aspects of the project. For example, one might build the plants, while another constructs the pipeline. Other partners would build the wind and solar farms.

Obsidian hopes to tap into the $8 billion fund that the U.S. Department of Energy has set aside to create four to eight regional hydrogen hubs across the nation. Each hub would get $1 billion to $2 billion. Washington is aggressively pursuing that money to create a Northwest hydrogen hub, including passage of legislation this year to help organize the effort. (See Wash. Looks to Boost Prospects for Winning Hydrogen Hub.)

In Washington, one hydrogen manufacturing plant owned by the Douglas County Public Utility District is scheduled to go online in East Wenatchee in mid-2023. The Port of Seattle is studying whether it wants to get into hydrogen manufacturing and distribution. Refueling stations for hydrogen-powered vehicles are in the works for East Wenatchee and the transit authority in Chehalis and Centralia

DOE expects to receive roughly 100 proposals by September, after which it will begin winnowing through them. No timetable is set for DOE’s decisions on how to allocate the $8 billion.

Brown said the earliest that the hydrogen plants might be built is 2025 but added that completion could be later this decade. The pipelines could likely take three years to build after Obsidian obtains all the needed permits, he said.

Potential customers would be fertilizer plants, hydrogen-powered vehicles and other agricultural uses. Also, Eastern Washington is home to several data farms, which could use hydrogen as fuel for their backup generators.

Brown did not rule out trying to connect with any potential western Oregon and Washington hydrogen customers that might want to build pipelines across the Cascade Mountains.