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November 18, 2024

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NY Creates Coordinated Grid Planning Process

The New York Public Service Commission approved the state’s first-ever Coordinated Grid Planning Process (CGPP) on Thursday, 39 months after it ordered the state’s utilities to begin the process (20-E-0197).

The move is designed to increase transmission and distribution capacity — while controlling costs and speeding up the process — as New York ramps up its production and consumption of electricity to meet its emission-reduction goals.

The utilities in November 2020 submitted their initial response, which the PSC deemed inadequate in September 2021. The utilities submitted a proposal in December 2021, then held nine technical conferences before submitting their final proposal in December 2022.

Stakeholder response this year was lukewarm at best and loaded with suggestions for changes. (See NY Utilities’ Proposed Grid Planning Process Gets Tepid Reaction.) The version of the CGPP approved in Thursday’s order incorporates numerous modifications based on stakeholder comments and Department of Public Service staff suggestions. More modifications are expected, informed by experience gained once the first CGPP cycle begins next month.

It is the first time the PSC has initiated a long-term, coordinated, statewide planning process. Its focus is supporting the state’s landmark Climate Leadership and Community Protection Act (CLCPA) of 2019, which calls for 70% renewable energy by 2030 and a zero-emission grid by 2040.

The plan lays out a two-year, six-stage process to be conducted by the investor-owned utilities and the Long Island Power Authority, culminating in a report and system investment recommendations for PSC consideration. After the PSC responds, another study cycle will begin.

The two-year timeframe is one of the modifications; as proposed, the CGPP would have operated on three-year cycles. That would have been too slow to support the CLCPA, the PSC said. NYISO also generally does its planning on a two-year cycle.

A stakeholder group called the Energy Policy Planning Advisory Council (EPPAC) will inform but not control the process. Thursday’s order specifies that DPS staff will choose the EPPAC’s members, have a significant role in managing it and make decisions necessary to advance the process if the EPPAC cannot reach a consensus on giving direction to planning entities.

The Advanced Technology Working Group — which is focused on dynamic line ratings, power flow control and energy storage — will support the CGPP by scouting for solutions to constraints as they are identified.

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NERC Board of Trustees/MRC Meeting Briefs: Aug. 16-17, 2023

OTTAWA, Ontario — As NERC’s Board of Trustees and Member Representatives Committee gathered in Ottawa this week, attendees took the opportunity to remark on the recent anniversary of a major milestone in the ERO’s history.

“Twenty years ago this past Monday, an obscure tree fell on a power line in Ohio, triggering a disastrous chain of events culminating in 55 million people without electricity, and almost 100 people dead,” said David Morton, chair of Canada’s Energy and Utility Regulators (CAMPUT). “As you all know, this event gave birth to NERC as we know it today, a corporation [that’s] probably unique in the world … However, unlike Sergeant Pepper’s band, which kept coming in and out of style, NERC’s mission not only doesn’t go out of style, but grows ever more important.”

Morton’s address on Thursday wasn’t the only reference to the August 2003 blackout, nor was he the only speaker to slip a Beatles reference into his remarks. Manny Cancel, NERC senior vice president and CEO of the Electricity Information Sharing and Analysis Center, shared his memory of “not going home and staying in my office for those two days,” and NERC staff shared a video they made with ReliabilityFirst and NPCC reminiscing on the event and the lessons learned since.

NERC CEO Jim Robb — who was unable to fly to Ottawa but listened via web conference — told ERO Insider before the meeting that he considered the legacy of the 2003 blackout to be the ERO Enterprise’s collaborative model of seeking input from all stakeholders in the electric grid.

“The thing that I always tell utilities is that, when we put in place a standard, it’s never about you — it’s about your neighbor. Because you want to make sure that your neighbor is operating their system the same way you are,” Robb said. “That’s really critical, given the interconnected nature of the grid. … We learned that in [the blackout of] 1965, and we relearned it in 2003.”

From left: NERC Trustee George Hawkins; Chair Ken DeFontes; General Counsel Sonia Rocha | © RTO Insider LLC

2024 Budget Approved

NERC’s final 2024 business plan and budget passed its penultimate hurdle at Thursday’s board meeting, with trustees agreeing to the document after members of the Finance and Audit Committee approved it at their meeting the day before. The budget will now be submitted to FERC for final approval.

Speaking at the FAC meeting, NERC CFO Andy Sharp reviewed revisions to the budget since the drafts were submitted for public comment in May. (See Personnel, Meeting Costs Drive 2024 ERO Budget Hikes.) NERC’s final budget has been set at $113.6 million, $3 million higher than the draft budget.

The biggest driver of the increase is a $3 million charge associated with the Interregional Transfer Capability Study (ITCS), an 18-month effort ordered by Congress earlier this year in the Fiscal Responsibility Act. NERC was able to account for $400,000 of the ITCS cost by repurposing funds intended for contractors and consultants. The rest will be split between the organization’s Assessment Stabilization Reserve and Operating Contingency Reserve, meaning that assessments will be unchanged from the $97 million in the draft budget.

Another added cost is a $400,000 charge for constructing a new database platform for NERC’s system operator certification and continuing education program. This too is expected to have no impact on the ERO’s assessment because it will be funded entirely from the System Operator Certification Reserve.

Standards Process Changes Accepted

Introducing a set of proposed changes to NERC’s reliability standards development process, Soo Jin Kim, NERC vice president of engineering and standards, thanked stakeholders for supporting the ERO in the “concerted effort” to streamline its internal procedures.

“I do believe this is a long process, and it has been a very fruitful process, but I’m very pleased today because the work product that we are delivering is going to allow for the ERO Enterprise to fulfill its statutory obligations and to provide for more agile and efficient processes,” Kim said.

Soo Jin Kim, NERC’s vice president of engineering and standards | © RTO Insider LLC

The revisions, which trustees approved for filing with FERC, will affect NERC’s Rules of Procedure, particularly Section 300, which governs standards development, and Appendix 3A — NERC’s Standard Processes Manual.

Among the most significant changes is a new Section 322, which gives NERC’s board “the authority to direct the development of a reliability standard in extraordinary circumstances … to address an urgent reliability issue.” Under the Section 322 process, the board will issue a preliminary written notice of its intent to issue a directive, along with its reasoning.

Stakeholders will have the opportunity to weigh in during a public comment period of at least 45 days, after which the board will issue a final determination in writing, along with a consideration of comments received. Upon final determination, any impacted party will have the opportunity to request rehearing or clarification.

Kim emphasized that Section 322 was meant to be considered only “a failsafe [that] will not replace our stakeholder model that we’re all very connected to.” She said the changes were necessary to meet the ERO’s “statutory obligations under Section 215” of the Federal Power Act.

Trustees also agreed to adopt reliability standards TOP-003-6 (Transmission operator and balancing authority data and information specification and collection) and IRO-010-5 (Reliability coordinator data specification and collection), along with their implementation plan. The standards were developed under Project 2021-06, which was started to address potential administrative burdens identified in previous versions of the standards by NERC’s Standards Efficiency Review.

Compliance Committee Renamed

NERC’s Compliance Committee held its last meeting on Wednesday — at least the last under that name. The committee approved a set of amendments to its charter that the board approved the following day, changing its name to the Regulatory Oversight Committee.

The name change is intended to reflect the committee’s evolving scope, after members determined that because of the “current volume and complexity of standards-related projects and issues,” NERC requires “increased focus and oversight” in the standards development process. The committee’s new responsibilities include:

    • Ensuring that the standards program addresses appropriate strategic priorities;
    • Monitoring the overall results of the standards development process;
    • Assessing the efficiency of standards and their effectiveness at addressing targeted reliability risks;
    • Monitoring progress in addressing regulatory mandates and standards-related directives; and
    • Responding to the board’s requests for advice and recommendations on standards-related matters.

Future Meetings

The Ottawa meeting was the second and final in-person gathering of the year for the board and MRC, after the February meetings in Tucson, Ariz. Members and trustees will hold their final meetings virtually. However, unlike previous virtual gatherings in which the MRC and board met within a day of each other, these events will be separated by almost two months: the MRC will meet on Oct. 25, and the board will hold its final meeting on Dec. 12.

Next year’s meeting schedule will look similar to that of 2023, with face-to-face gatherings in Houston on Feb. 14-15 and Vancouver on Aug. 14-15. May’s meetings will follow a hybrid format, with members and trustees gathering at NERC’s D.C. office and all other participants attending virtually, and the final meetings (Dec. 13 for the board and an undetermined time in October for the MRC) will again be held entirely online.

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NJ Opens Community Solar and Nuclear Support Programs

The New Jersey Board of Public Utilities (BPU) on Wednesday enacted a permanent community solar program that will approve projects totaling more than 150 MW a year, replacing the state’s temporary pilot program after two heavily oversubscribed solicitations.

The Community Solar Energy Program (CSEP) will be open to community solar projects that are smaller than 5 MW and are on rooftops, carports, canopies over impervious surfaces, contaminated sites, landfills or bodies of water.

Registration for the new program will begin Nov. 15. Projects will be awarded on a first-come, first-served basis, with incentives allocated under the Administratively Determined Incentive section of the state’s new solar subsidy program, the Successor Solar Incentive Program.

“This new program will greatly expand the burgeoning market for solar in New Jersey. Adding hundreds of megawatts of new solar in coming years will bring all the benefits of clean energy and hundreds of new jobs to the state,” said Morgan Sawyer, a BPU research scientist who outlined the new program for the board.

Community solar projects in the program will be eligible for an incentive of $90/MWh, and program rules say it should approve projects totaling at least 225 MW in each of the first two years and at least 750 MW in the first five years.

The program passed on a 4-0 vote, with one abstention due to a conflict of interest. Joseph L. Fiordaliso, BPU’s president, called the approval of a permanent program a “big day” that will provide clean energy to residents who previously couldn’t access it because they don’t own a house or their property is not suitable for solar panels.

“They now have the ability to be a part of the clean energy revolution that New Jersey is currently involved in,” he said. “All of us have to be a part of the clean energy movement if we are going to continue to mitigate the effects of climate change.”

Progress, but Also A Missed Opportunity

Community solar projects target users who either cannot or do not want to have solar on their roofs but seek to support a clean energy initiative. To make the projects work, the developer must sign up subscribers, who commit to using the clean energy and in turn receive a credit on their utility bill, reducing the electricity cost by a set percentage.

New Jersey’s program targets low- and moderate-income (LMI) residents, requiring that they constitute 51% of a project’s subscribers. The new program requires that community solar providers discount subscribers’ utility rates at least 15%.

The BPU approved the proposal after releasing the straw proposal for public comment March 30 (QO22030153) and holding a public hearing April 24.

The state enacted its first community solar pilot program in 2019, and a second pilot in 2021. The first program, which attracted 252 applicants, approved 45 projects totaling 75 MW. The second pilot, which attracted 412 applications, awarded 105 projects totaling 165 MW.

In February, the BPU launched a website to help ratepayers find the closest community solar project to them.

Lyle Rawlings, CEO of Advanced Solar Products and president of the Mid-Atlantic Solar and Storage Industries Association, said the program is a good one and his association, which includes community solar developers, expects it to be oversubscribed in the future.

The permanent program “is an important advancement to the community solar program,” Rawlings said. But he also called it a “missed opportunity” because the program rules don’t do enough to focus on getting LMI residents into the program.

He said his organization pushed unsuccessfully to get projects ranked by the size of the discount they would give to LMI subscribers, and by the percentage of project subscribers from the LMI communities. If the annual capacity block were to be oversubscribed, the rankings ― and their ability to identify the projects that favored LMI residents ― would be used to help determine which projects should be approved, he said.

“We’re disappointed that those recommendations were not followed,” he said.

Ease of Access

The launch of the program follows a contentious history, in which solar developers at one point complained that the agency was taking too long to announce the winners of the second pilot and to outline when the agency would transition to a permanent program. (See Slow Progress of NJ Community Solar Pilot Draws Fire.)

The success of the pilot programs prompted two lawmakers to introduce a bill (S3123) that would have more than tripled the size of the planned permanent community solar program to 500 MW a year. BPU officials argued that the agency could not handle such a rapid increase. (See NJ Proposes Modest Community Solar Capacity Hike.)

Members of VoteSolar, a national advocacy group, welcomed the BPU’s move, saying it would give greater access to solar energy for LMI residents. The program’s adoption of consolidated billing ― so that details of subscribers’ clean energy use and the size of the credit discount are part of their utility bill, rather than a separate bill ― is a new element that will make it more accessible for residents, the group said in a release.

“We can’t leave anyone behind in the transition to 100% clean energy, and community solar is key to expanding equitable access for all New Jersey residents,” said Elowyn Corby, Mid-Atlantic regional director for Vote Solar.

Nuclear Subsidies

The BPU also voted to start the process for awarding a new round of subsidies under the Zero Emission Certificates (ZEC) program and determining which nuclear plants in the state are eligible for the subsidies.

With a 5-0 vote, the board opened the process in which utilities that own nuclear plants can apply for ZECs to be used between June 1, 2025, and May 31, 2028. The board also set the ZEC price at $9.88/MWh and agreed to hire a consultant to help evaluate the applicants and other ZEC issues that arise.

The ZEC program provides subsidies to nuclear power plants at risk of closure so they can remain open to generate carbon-free power. New Jersey will rely heavily on nuclear power in seeking to reach its clean energy goals. In 2021, nuclear plants generated 44% of the state’s electricity, slightly less than was generated by gas-powered plants, according to the U.S. Energy Information Administration. Renewable energy accounted for about 8% of the electricity in that year.

The New Jersey Legislature created the program in 2018, and in 2019, the board awarded ZECs totaling $300 million to New Jersey’s three nuclear plants: Hope Creek Nuclear Generating Station, which is owned and operated by Public Service Enterprise Group (PSEG), and Salem One and Salem Two nuclear power plant, which are owned and operated by PSEG with Exelon.

The state awarded the same certificate rate — $10/MWh — in 2021, to cover the 2022-to-2025 period. (See NJ Nukes Awarded $300 Million in ZECs.)

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Illinois Governor Vetoes Downstate ROFR for MISO Regional Transmission Projects

Illinois Gov. J.B. Pritzker (D) on Wednesday vetoed a measure that would have allowed incumbent downstate utilities — particularly Ameren Illinois — exclusive rights to build regional MISO transmission lines.

The governor issued an amendatory veto to HB 3445, striking out the right of first refusal (ROFR) piece of the legislation and letting other portions stand, including an adjustment making on-site solar grants more available to schools, an amendment requiring the Illinois Power Agency to conduct more comprehensive policy studies and a requirement that renewable energy developers be more responsible for drainage system issues stemming from their projects.

State lawmakers have the option to let the governor’s decision stand through either acceptance or nonaction or override the veto to pass the bill in its entirety.

Pritzker’s office said the ROFR “will raise costs for rate payers by giving incumbent utility providers in the MISO region a monopoly over new transmission lines.”

“Eliminating competition will cause rates to increase in the MISO region, where there is currently over $3.6 billion in planned transmission construction in the Ameren service territory. Without competition, Ameren ratepayers will pay for these transmission projects at a much higher cost, putting corporate profits over consumers,” Pritzker said.

MISO executives have said they were monitoring developments around the measure and how it could affect competitively bid projects in its first, $10.3 billion long-range transmission plan (LRTP) portfolio. (See “ROFR Developments May Complicate LRTP Planning,” MISO Modeling Line Options for 2nd LRTP Portfolio.)

MISO has seen a flurry of ROFR law activity in its footprint since it approved the first LRTP portfolio last year. The grid operator has a goal to approve another multibillion-dollar LRTP aimed again at its Midwest region next year.

The Electricity Transmission Competition Coalition (ETCC) welcomed news of the veto, saying the ROFR would have squelched competition and stymied innovation.

“By vetoing the ROFR provision, Gov. Pritzker has powerfully stood up against utility monopoly interests and shown that he is on the side of consumers and backs lower electricity prices,” ETCC Chair Paul Cicio said in a statement. “The ROFR was anti-competitive, anti-consumer, inflationary and Illinois families and businesses would have paid higher electricity prices for decades to come.”

The ETCC said data from the U.S. Energy Information Administration ranks Illinois the 13th highest in the nation for electricity rates.

Bill sponsor Rep. Larry Walsh Jr. (D-Elwood) has vowed to file for an override and pass the bill over the governor’s opposition during the legislature’s veto session beginning in October. Walsh told Capitol News Illinois that he believes a ROFR will ensure Illinois labor unions are employed for the projects under Illinois’ worker protections. He said the bill will give the state more oversight over transmission line construction, rather than dealing with out-of-state developers.

Ameren Transmission Co. of Illinois similarly characterized the ROFR as a “labor proposal” that would “enable much-needed electric transmission capacity to be quickly and cost effectively placed into service.”

“Unfortunately, [the] veto will result in unnecessary delays in construction that increase costs for downstate energy customers and put the benefits of the clean energy transition at risk,” Shawn Schukar, president of Ameren Transmission Co. of Illinois, said in an email to RTO Insider. “To do it fast and do it right, with accountability for results, these projects should be managed by trusted local energy companies with a proven track record of success, who already competitively bid the projects with local contractors and union workers.”

Pritzker Takes New Nuclear Off the Table

Last week, Pritzker also vetoed SB76, which would have lifted Illinois’ moratorium on new nuclear reactors. The state in 1987 prohibited construction of new nuclear facilities in the absence of a permanent solution for storing nuclear waste. The bill would have allowed the development of the first small modular reactors in the state.

Pritzker said he vetoed the bill because it contained a vague and “overly broad definition of advanced reactors,” which might “open the door to the proliferation of large-scale nuclear reactors that are so costly to build that they will cause exorbitant ratepayer-funded bailouts.”

The governor also said the bill didn’t provide regulatory protections for Illinois residents who would reside and work near new reactors.

Walsh, a sponsor of that bill, again criticized the governor’s veto, saying that nuclear energy must factor into the clean energy transition. He said Illinois lost an “opportunity to allow new, safe and efficient reactors to be a tool in our energy toolbox.”

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MISO Members Approach Revised NIETCs with Hope, Caution

MISO members were both apprehensive and hopeful over the Department of Energy’s new plan to designate National Interest Electric Transmission Corridors (NIETCs) to spur transmission expansion.

MISO Advisory Committee members discussed the topic at their Aug. 16 teleconference.

The DOE in May issued a notice of intent that it might unroll a new process to designate NIETCs, which would fast-track permitting and financing for transmission projects under development. (See States, RTOs Caution DOE on Transmission Corridors.)

The Union of Concerned Scientists’ Sam Gomberg said MISO’s Environmental Sector believes the rule will “expand and accelerate” the building of a system that is prepared for future needs. He also said the rule seems “responsive to past failures” of the federal government to involve itself in transmission siting.

Wisconsin Public Service Commissioner Tyler Huebner said MISO state regulators are split over the proposed rule, with some enthusiastic over how it could spur lines that span multiple planning regions but others saying such a process would be administratively burdensome and a means to subvert existing state routing authority.

During an Aug. 14 Organization of MISO States meeting, Texas Public Utility Commissioner Lori Cobos said Texas is “concerned, very concerned” over the DOE potentially nominating corridor projects that ratepayers will finance.

“What we don’t want this to become is an adversarial process,” Gomberg said, adding that the DOE should recognize states’ primacy in permitting and siting.

MISO Transmission Owner representative Stacy Herbert said the DOE should make sure its designation process “does not interfere with, but rather complements” regional and interregional transmission planning.

Huebner said some MISO state regulators believe NIETCs will be key to getting interregional lines built.

“We think this might be the best value add of the process,” he said.

Huebner said the DOE could invite states to propose NIETCs locations. He said if multiple states propose adjacent locations, that could build toward larger, national designations.

Gomberg said he worried the federal government would use its new permitting authority too little.

“I’m going to be blunt here. I’m not convinced that FERC has the guts to move forward with anything but the most egregious needs on the system,” he said.

Gomberg also said while members of the MISO Environmental Sector aren’t expecting the federal government to be the architects of a “grand national grid” through its authority, there are going to be clear opportunities for corridors.

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FERC Rules on Four Issues from Tri-State Rate Filing

FERC on Tuesday affirmed, in part, and reversed, in part, four disputes arising from Tri-State Generation and Transmission Association’s first jurisdictional rate filing before the commission in 2019 (ER20-676).

The issues were set aside from a settlement approved by the commission in August 2021. (See FERC Approves Tri-State’s 1st Major Rate Case.)

Before the year was up, FERC directed further hearing procedures on the four reserved issues related to wholesale power service rates for Tri-State’s 43 members. The presiding judge issued an initial decision in May 2022.

The commission agreed with the judge’s decision on the first reserved issue that Tri-State is subject to FERC Order 888’s functional unbundling requirements.

It also affirmed in part and reversed in part the initial decision on the third reserved issue, which determined whether Tri-State can apply a transmission demand charge to member United Power’s storage resources. FERC agreed that United Power must pay the charge based on gross load and that Tri-State must reimburse the cooperative for overcharges.

However, it reversed some of the determinations describing how Tri-State must calculate the appropriate reimbursements and refunds and the judge’s finding that United Power doesn’t need to pay a late charge for not meeting the payment’s deadline.

FERC reversed in part and affirmed in part initial decisions in the other two reserved issues: Tri-State’s cost-allocation standards applicable to certain costs, and whether the G&T’s community solar program is just, reasonable, unduly discriminatory and/or preferential in applying a $0 add-back charge to program’s projects.

The commission disagreed with the decision that Tri-State must apply an any-degree-of-integration test and the seven-factor Mansfield test (a case-by-case analysis of local distribution’s indicators) to determine cost allocation. It said that the tests are applicable standards but are not necessarily the exclusive means for determining appropriate cost allocation.

FERC also agreed Tri-State’s application of the add-back charge to load served by community solar projects is inappropriate. However, it found the charge to be unjust and unreasonable, rather than unduly discriminatory as the judge had decided.

The commission gave Tri-State 45 days to make a compliance filing outlining how it will reimburse United Power for overcharges in one of the reserved issues.

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DC Circuit Affirms FERC Order on PJM MSOC

The D.C. Circuit Court of Appeals has upheld FERC’s 2021 order reworking PJM’s market seller offer cap (MSOC) to replace the default offer cap with a unit-specific review process (21-1214).

Tuesday’s decision overrules challenges from a series of generation companies arguing that the order deprived them of their right to set their own rates, didn’t allow for a full accounting of the financial risks that come with a capacity obligation and didn’t adequately explain why it eliminated the default offer cap instead of modifying it. (See Judges Skeptical of Capacity Sellers in PJM Offer Cap Dispute.)

The order was focused on increasing the instances in which generators’ offers will be subject to unit-specific review to determine if market power mitigation is necessary, particularly in the case of the marginal resource clearing the capacity market. With the default offer cap in place, as much as 99% of offers fell below the cap and were determined to not require mitigation, a rate the commission determined was too high (EL19-47).

The component the commission believed to be behind the high offer cap was the number of performance assessment intervals (PAI) a generator could expect to face on average per year. The order establishing the capacity performance (CP) construct pegged the anticipated number of intervals at 360 each year. However, in a complaint arguing that the offer cap was too high, the Independent Market Monitor said the subsequent four years saw 24 intervals. (See FERC Backs PJM IMM on Market Power Claim.)

Instead of basing when an offer is subject to unit-specific review on whether the marginal cost of taking on a capacity obligation — the resource’s avoidable cost rate (ACR) — exceeded the amount it expected to earn during PAIs, the commission’s 2021 order eliminated the default offer cap with unit-specific review of resources’ ACRs.

The court disagreed with the generators that they could not set their own rates under the new paradigm, finding that capacity auction offers are not rates, as they are submitted to PJM, rather than filed with FERC, and are confidential rather than public. Although the Monitor can suggest an alternative offer for PJM to consider, the RTO still holds the “primary role” in selecting an offer, the ruling states, and generators also can appeal to FERC if they disagree with the selection.

“To summarize the interaction, suppliers can submit their offers to PJM regardless of the Independent Market Monitor’s views, then ask the commission to referee if a dispute persists. As such, the current tariff and September 2021 Order make quite clear that suppliers do not play second fiddle when their proposed offers deviate from that of the Independent Market Monitor,” the ruling states.

The court also sided with the commission in finding that generators retain flexibility when accounting for the risks that come with taking on a capacity obligation. Past orders have made clear that costs that also would be incurred if the generator participated only in the energy market cannot be included in capacity offers and that by not outlining an “exhaustive” list of all costs that could be included in the ACR, the order does provide flexibility.

The generators’ arguments that alternatives to eliminating the default offer cap had not been given due weight by the commission also were denied. The court pointed to FERC’s argument in its 2021 order stating that while alternatives would have recalibrated the cap, they still would have resulted in a value so high that only a small number of offers would be subject to review and therefore would not have resolved the issue.

While it did not join in the appeal to the court, PJM filed a request for FERC to rehear its order arguing that unit-specific review of all resources could lead to over-mitigation of capacity resources. (See PJM Requests Rehearing of MSOC Change.)

“The harm of overmitigation under a unit-specific ACR approach is real and will inhibit the ability of capacity market sellers to base their offers on their respective cost estimates and assumptions about what is likely to occur three years in the future,” PJM said in its filing. “This is because each capacity market seller’s evaluation of risk relating to actual costs and revenues varies for various resources … and it is not appropriate for PJM or the Market Monitor to substitute their assessment of the risks for the capacity market seller’s demonstrable assessment of the risks.”

EPSA Says MSOC Structure Threatens Reliability

In a statement released Tuesday, the Electric Power Supply Association (EPSA) argued that the ruling leaves intact a capacity market that interferes with generators’ ability to earn an adequate return on their investments needed to service the grid reliably. The association joined Vistra, Constellation, LS Power, Calpine, Talen Energy and the PJM Power Providers Group in petitioning the court to overturn the commission’s order.

“The changes approved by the court to PJM capacity offers undermine the ability of private investors and developers to assume risk and earn an adequate return — jeopardizing PJM’s ability to procure sufficient generation to meet anticipated demand in today’s challenging landscape,” EPSA President Todd Snitchler said. “This decision from the court adds urgency to the Board-directed stakeholder process underway at PJM to develop reforms that substantially address the flaws in the capacity market — the vehicle by which the RTO ensures resource adequacy and system reliability.”

He noted PJM has raised alarms that the expected pace of resource retirements may exceed new resources coming online and threaten reliability, a dynamic he said will be exacerbated by the design of the capacity market.

“Now more than ever, with at least 40 GW of generation flagged by PJM for being at risk of retirement without sufficient replacement, it is critical that the resources needed for reliability have adequate incentives to stay running,” he said. “Yet FERC and PJM are once again making it harder for markets to procure much needed resources rather than enable greater participation of resources that provide reliability.”

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DOE: IRA, IIJA Could Add 475 GW of New Solar to US Grid by 2030

By 2030, the combined impact of the Inflation Reduction Act and Infrastructure Investment and Jobs Act could add up to 475 GW of new solar and 250 GW of new wind power to the U.S. electric grid, according to a new report from the Department of Energy.

Released on the first anniversary of the IRA’s enactment, the report looks at the combined impacts of the two laws across a range of key economic and climate measures from 2022 to 2030. Top line figures include:

    • electric bill savings for U.S. families of $27 billion to $38 billion, and a 13 to 15% reduction in commercial electricity bills for American businesses;
    • a cut in U.S. oil imports of 44 to 59%, which would also cut spending on imported oil by 13 to 22%;
    • an increase in clean energy — including nuclear, hydropower, geothermal and fossil fuels with carbon capture — on the U.S. grid from 42% in 2022 to 72 to 81% by 2030;
    • sales of zero-emission vehicles rising from 8% of total car sales today to 49 to 65% by 2030; and
    • a 35 to 41% drop in greenhouse gas emissions over 2005 levels versus a projected 27% decrease without the two laws.

The combined impacts of the IRA and IIJA are expected to cut U.S. greenhouse gas emissions 35% to 41% over 2005 levels by 2030. Without the laws, emissions would drop 27%. | DOE

The mostly rosy picture of the laws’ impact is based on new modeling by DOE incorporating the potential effects of the IRA and IIJA into its National Energy Modeling System, with scenarios projecting “moderate” and “advanced” uptake of the laws’ provisions. However, looking at the report’s technical documentation, it is unclear if the new modeling takes into account ongoing challenges to clean energy deployment ― specifically, permitting, interconnection and transmission.

Still, President Joe Biden pointed to many of the figures as he celebrated one year of the IRA being law at the White House on Wednesday, calling the law “one of the biggest drivers of jobs and economic growth this country has ever seen.”

IRA solar

The president spoke to a packed room of supporters. | The White House

Biden said the tax credits in the law will break the clean energy industry’s long dependence on China for a range of equipment, drawing manufacturing and supply chains back to the U.S. “We’re bringing critical supply chains and technologies home for electric vehicle batteries, solar panels, wind turbines [and] critical minerals.”

A White House fact sheet, also released Wednesday, pegged new clean energy manufacturing investments since the IRA was signed at $110 billion, including $70 billion in the EV supply chain and $10 billion in solar manufacturing.

Biden also hailed the IRA and IIJA’s $50 billion in investments for energy resilience.

“These laws support important priorities, from addressing historic drought on the Colorado River Basin … [to] responding to coastal erosion [and] sea-level rise in the Gulf of Mexico and helping reduce the effects of extreme heat by investing nearly $1.5 billion to plant trees and expand community parks,” Biden said.

Speaking before the president, Scott Strazik — CEO of GE Vernova, General Electric’s clean energy spinoff — also praised the IRA, saying the law “is working to drive action on climate change, energy security, manufacturing jobs and American competitiveness.”

In Schenectady, N.Y., where GE was founded, “we’ve invested $50 million this year, [and] 200 new union jobs, to create the first 6-MW wind turbine in the U.S.,” Strazik said.

Manchin Missing

Absent from the packed room at the White House — and the president’s speech — was Sen. Joe Manchin (D-W.Va.), who played a critical role in forging final compromises on the law last year. Biden recognized his work at the IRA signing, handing him the pen he used to sign the law and shaking his hand.

A year later, Manchin and the White House are at odds over implementation of the law. The West Virginian has said the IRA is primarily an energy security law, and he has criticized the Biden administration’s efforts to roll it out as a clean energy and climate initiative.

In a statement released Wednesday, Manchin recognized the benefits his state has received from the law, including major investments from long-duration battery startup Form Energy and Berkshire Hathaway subsidiary BHE Renewables.

While praising the law for “putting the interests of Americans and West Virginians first,” he pledged to “push back on those who seek to undermine this significant legislation for their respective political [agendas], and that begins with my unrelenting fight against the Biden administration’s efforts to implement the IRA as a radical climate agenda instead of implementing the IRA that was passed into law.”

When asked about Manchin’s criticism during a press briefing Wednesday, White House senior adviser John Podesta sought to downplay the situation as a matter of interpretation.

“We’re trying to implement it based on what the Congress passed, the law that was written,” Podesta said. “Now he has disagreed a little bit with some of those interpretations, but I think we are operating in good faith to get guidance out as quickly as possible so that these people have the confidence that they can make these long-term, 10-year investments that are included in the act.”

Stronger criticism came from Rep. Cathy McMorris Rodgers (R-Wash.), chair of the House Energy and Commerce Committee, who framed the IRA as “a reckless tax-and-spending spree.”

“One year later, inflation has risen an additional 3%, and people are still paying higher costs to feed their families, keep the lights on and fill up their gas tanks than when President Biden took office,” McMorris Rodgers said. “His disastrous agenda has led innovators to stop research into new, potentially lifesaving treatments and cures, while also increasing our reliance on China.”

But both Podesta and Biden noted that Republican opposition to the law has been tempered by the clean energy investments and jobs the law has brought to their states.

“Once those investments happen, once those jobs are created, once those people are at work in red districts, purple districts, blue districts, it’s very hard to walk away from that,” Podesta said.

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California, Australia Forge Climate Pact

Faced with similar threats from climate change, such as drought, extreme heat and wildfire, California and Australia have made a pact to battle the climate crisis together.

California Gov. Gavin Newsom (D) and former Australian Prime Minister Kevin Rudd, who now serves as Australia’s ambassador to the U.S., gathered with other officials on Tuesday to announce the five-year agreement.

Under a memorandum of understanding signed Tuesday, the officials pledged to work together in areas including zero-emission vehicles, renewable energy development, grid reliability and wildfire resilience.

Like California, Australia has been feeling the impact of wildfires that are becoming more severe as climate change intensifies.

From June 2019 to January 2020, Australian bushfires burned 46 million acres. Emissions from the fires may have contributed to a rare, three-winter string of La Niña weather events, researchers from the National Center for Atmospheric Research recently reported.

“If you’ve been to Australia much, you may have discovered that from time to time it gets a bit dry down there. It gets a bit dry here from time to time, as well,” Rudd said during a news conference in Sacramento on Tuesday. “The natural dryness of so much of California and of Australia is now being compounded by this ever-expanding climate crisis across the world.”

Newsom said California and Australia both are  “on the front lines of the climate crisis.”

“From extreme heat and historic drought to catastrophic wildfires and rising sea levels, the last few years have further crystallized the need for urgent action,” the governor said in a statement.

California has committed to achieving carbon neutrality by 2045, while Australia has set a 2050 net-zero target.

Rudd commended California for its work on electric vehicles, including a ban on sales of gas-powered cars that starts in 2035.

“It’s not just changing California, it’s changing America and changing the world,” Rudd said. “That’s leadership.”

Australia joins California’s growing list of climate partners, which includes Canada, China, New Zealand, Japan and the Netherlands. Earlier this month, California announced a climate partnership with Hainan Province in China. (See Calif. Enters Climate Agreement with China’s Hainan Province.)

In introductory remarks at Tuesday’s event, California Lt. Gov. Eleni Kounalakis (D) said the state’s partnership with Australia is well-timed, coming just a few months before the 2023 Asia-Pacific Economic Cooperation (APEC) CEO Summit. The theme of the event, which will take place in San Francisco in November, is “creating a resilient and sustainable future for all.”

“Today, California and Australia are elevating our joint commitment to combating climate change,” Kounalakis said. “We are signaling our resolve to work together to advance and lead the way to a more sustainable and technologically advanced future.”

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Wash. Raises $62.5M from Cap-and-trade Reserve Auction

Washington’s first cap-and-trade Allowance Price Containment Reserve (APCR) auction raised almost $62.5 million, the state’s Ecology Department said Wednesday.

The auction held last week put up 1,054,809 carbon emissions allowances for bid. Half were offered at a Tier 1 price of $51.90 and the other half at a Tier 2 price of $66.68, which reflects a benchmark set by the open market. The auction was open only to entities that need to cover direct emissions and was closed to financial traders of allowances.

The state was required to hold the cap-and-trade program’s first APCR auction, a mechanism designed to keep carbon prices in check, after prices in the May quarterly auction broke through a soft cap that triggers a requirement to tap the reserve. (See Wash. Auctions Reserve Carbon Allowances to Relieve Price Pressure.)

The list of eligible bidders included eight oil and gasoline companies. The cap-and-trade program has been blamed all summer for the state’s high gasoline prices, hovering around $5 per gallon. Throughout the summer, Washington and California have been swapping first and second place for the nation’s highest gas prices. (See Cap-and-trade Driving up Washington Gasoline Prices, Critics Say.)

Washington does not reveal the bidders’ or winners’ identities or the number of allowances awarded to individual entities to prevent market manipulation.

Washington has raised almost $920 million in the first seven months of the cap-and trade program, with two quarterly auctions left this fiscal year.

During the May 31 auction, the state sold 8.585 million allowances, for a clearing price of $56.01, exceeding the $51.90 soft cap price triggering the APCR auction. Half of those allowances were to be sold for $51.90 per share and half for $66.68 per share.