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November 5, 2024

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Cap-and-trade Driving up Washington Gasoline Prices, Critics Say

Critics of Washington’s cap-and-trade system are blaming the six-month-old program for leaving the state with the highest gasoline prices in the nation.

But cap-and-trade defenders urge caution in drawing that conclusion, saying there are multiple reasons Washington drivers are paying so much at the pump.

What’s not up for debate is that Washington’s gas prices currently far exceed those in the rest of the country and outpace other pricey Western states. American Automobile Association figures show U.S. gas prices averaged $3.54/gallon on July 11, while stations in Washington averaged $4.959. Rounding out the top four markets were California ($4.882), Hawaii ($4.702) and Oregon ($4.615), typically among the most expensive for gas.

AAA data from a year ago showed Washington sixth in the nation at $5.36, well below No. 1 California ($6.088) but still above the national average of $4.81.

Washington’s high gasoline prices coincide with unexpectedly steep prices for carbon allowances in the state’s most recent cap-and-trade auction in May. The auction administered by the Department of Ecology cleared all 8.585 million vintage 2023 allowances on offer at a settlement price of $56.10, compared with $48.50 for first auction in February.

The clearing price exceeded the $51.90 soft cap that triggers use of the program’s Allowance Price Containment Reserve (APCR), a mechanism designed to rein in market impacts when allowance prices reach a level considered overly burdensome for emitters. (See Wash. Cap-and-Trade Prices Break Soft Cap.)

‘Not in the Realm of Possibility’

Todd Myers, environmental director for the Washington Policy Center, a Seattle-based conservative think tank, acknowledges  that many factors affect fluctuating gasoline prices. However, he pins current costs on the cap-and-trade program.

“The question is why Washington is the most expensive in the United States. Why are Washington’s prices going up faster than everyone else?” Myers asked.

Myers cited the calculation that a gallon of gasoline produces 1/100th of a metric ton of pollution. With auction prices hovering around $50 per metric ton, that translates into a 50-cent increase per gallon if all the costs are passed on to drivers, he said.

Yoram Bauman, a liberal economist based in Salt Lake City, agrees with Myers’ calculations. In 2016, Bauman helped lead the failed effort to pass Washington’s Initiative 732, a ballot measure that called for creation of a cap-and-trade program coupled with a 1% drop in the state’s sales tax to offset increased fuel costs. Voters rejected I-732 by 18%.

Bauman said I-732 advocates expected cap-and-trade costs to be passed on to customers at the pump.  “The idea that the oil companies are gonna suck it up is not in the realm of possibility,” he said.

Oil major Chevron also agrees that cap-and-trade is what is driving Washington prices. In an email to NetZero Insider, the company said “recent carbon cap-and-trade compliance costs raise gasoline prices by about 10% in the state. … The Washington program is designed to force rapid cuts to carbon intensity in a way that requires consumers to pay higher gasoline prices.”

But disputing that link is the office of Gov. Jay Inslee, a strong supporter of cap-and-trade. In an email, Inslee spokesperson Jaime Smith wrote that gas prices “fluctuate widely due to a variety of factors,” noting that geopolitical events have increased the price of crude oil and pointing out that AAA has said maintenance work at Washington refineries has been a “significant factor” for the region’s prices.

“In May, prices rose more quickly in Oregon than in [Washington]. Despite that, gas prices in Washington are currently about 55 cents a gallon less than they were a year ago,” Smith wrote. “While critics of our climate policy will try to pin any and all price increase on the [2021’s Climate Change Act], they conveniently ignore that fossil fuel suppliers have always had some of their highest profit margins in the Northwest. Recent numbers from the industry indicate their profit margin in Washington ranges between 60 [and] 80 cents per gallon.”

Washington and California have the only full-fledged cap-and-trade programs in the nation. Washington has made noises about possibly joining the Western Climate Initiative, which includes both California and the Canadian province of Quebec.

Relief in Sight?

Meanwhile, possible measures to address the high prices have begun to surface in Washington.

“There are many things that can be done. I don’t think the governor or the supporters want to do anything, however,” Myers wrote in a follow-up email. “The higher the price of the allowances and the larger the impact on gas prices, the more money that goes into the state coffers. Plus, as much as the governor plays dumb, he knows the high allowance prices increase gas prices and he wants that because he wants to push people into [electric vehicles].”

“It’s important to note that with only two auctions complete, it is too soon to accurately assess the policy’s price impacts,” Smith said.

Smith also noted that Washington’s program is designed to eventually link with California’s, which would provide auction participants access to a larger marketplace, trimming allowance prices.

And in light of the high allowance prices, the Department of Ecology will hold the APCR auction Aug. 9, potentially relieving some of the pressure on fuel suppliers.

On July 5, state Sen. Chris Gildon (R) sent the Ecology Department a note asking it to take action on its own before the next legislative session.

He wants the department to slow the pace of reducing state emissions and is asking for more allowances to be offered in the quarterly auctions to help prevent bidding wars.

Gildon also asked the agency to give itself the power to temporarily suspend the cap-and trade program when needed. He wants more emphasis on giving farmers a break on gasoline prices, and he seeks no-cost allowances for state industries competing with foreign companies that don’t have caps on their carbon emissions.

Ecology already is meeting with agriculture stakeholders to come up with a formal proposal to help farmers by September.

Near the end of the 2023 legislative session, state Sens. Mark Mullet (D) and Joe Nguyen (D) introduced a bill that would require the state to set up a remittance program for farm fuel users and freight haulers of agricultural products.

Under Senate Bill 5766, covered users would submit receipts every quarter showing the purchases for fuel used for farming and transporting agricultural products. For each gallon of fuel consumed, the user would be eligible for a remittance equal to the price of a ton of carbon at the most recent state emissions auction, multiplied by 0.8%.

The bill appeared too late for a full vote last spring but will be in the hopper when the 2024 session begins.

“When we passed the [cap-and-trade law], we made a promise to Washington’s farmers to protect them from additional costs that could potentially be passed on from the bill. We need to keep that promise,” Mullet said in an April press release. “We hoped this was going to be addressed in implementation, but we heard clearly in budget hearings that this issue still needs to be addressed. This bill is a small, reasonable step that keeps our promise to our farmers.”

Meanwhile, foreign competition to Washington’s smokestack industries — one of Gildon’s concerns — has been on the state government’s radar for years. This category of “energy-intensive, trade-exposed” (EITE) industries are responsible for roughly 10% of the state’s carbon emissions. EITE industries in Washington include petroleum refiners, manufacturers in the metals, paper, aerospace, wood products, chemicals, computer and electronics sectors, and food processors and cement producers.

In 2022, Rep. Joe Fitzgibbon (D) introduced House Bill 1682 to help EITE industries compete with foreign counterparts who would not have to deal with Washington’s stricter carbon emissions standards. The bill would have slowed down how quickly EITE industries would be required to comply with the state’s increasingly stricter emissions standards.

Fitzgibbon’s bill would have ordered EITE plants to submit 2015-2019 data to the state in 2022, setting a baseline for future calculations. Then, in 2023, each EITE plant would have received a free allowance of permitted emissions equal to the baseline set in 2022. The free allowance would then drop to 97% of a plant’s baseline in 2027, to 94% in 2031 and to 88% in 2035. After 2035, the free allowances would decrease 6% annually from the preceding year.

The bill also would have allowed a facility to request an increase in its allowance if it could prove it was using the best available pollution-fighting technologies.

But EITE industries opposed the bill, arguing they did not have the technologies to deal with emissions on the state’s timetable. The Western States Petroleum Association originally opposed the bill, but eventually switched to neutral with concerns on a revised version. BP America West Coast supported the bill from the beginning. In a 2022 interview, Fitzgibbon said opposition from the EITE industries and their supporters killed the bill behind the scenes.

For Myers, one problem to be addressed is that oil companies are limited in the percentage of allowances they buy per auction, leaving them at the mercy of speculators who also buy the credits to sell later at higher prices. He also called for measures to encourage lower final auction prices, which would translate to decreases in gas prices.

To Bauman, the I-732 approach still holds a key for the success of the current cap-and-trade program. High gas prices provide an incentive to shift away from fossil fuels, which is a key component in combating climate change, he said.

“The best option is to balance the price increase on fossil fuels by reducing taxes elsewhere. This is what we tried to do with I-732: offset the impacts of a carbon tax with a reduction in the state sales tax and other tax cuts that would have put money back into people’s pockets,” he said.

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ERCOT Demand Exceeds 82 GW for 1st Time

AUSTIN, Texas — “Welcome to the heat dome, y’all,” Austin-based energy consultant Alison Silverstein said during a panel discussion at NARUC’s Summer Policy Summit, acknowledging the sizzling temperatures outside that had the Texas capital city under an excessive heat warning until 8 p.m.

Temperatures in Austin topped out at 105 degrees Fahrenheit, helping ERCOT to again set a record for hourly peak demand when load averaged 82.03 GW during the hour ending at 4 p.m. That broke the record set Monday when demand averaged 81.91 GW during the 6 p.m. hour.

Demand averaged 82.54 GW during the hour ending at 5 p.m., raising the previous high.

Temperatures are forecast to remain above 100 degrees in much of the state into next week. ERCOT’s six-day forecast projects demand to approach 84 GW Wednesday and exceed 80 GW through Friday.

The record came on the last day of ERCOT’s third weather watch of the season. The grid operator says it’s continuing to operate the grid conservatively and bringing generating resources online early in case of sudden changes in generation or demand.

ERCOT had more than 7,000 MW of operating reserves available late Tuesday afternoon.

With the new peak, the ISO’s hourly average demand now has exceeded 80 GW 23 times this summer. It reached that mark once last year.

Average prices were less than $30/MWh Tuesday, a sign that congestion was not an issue.

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Maryland Climate Report Lays out Pathways to Achieving Goals

To cut its greenhouse gas emissions 60% below 2006 levels by 2031, Maryland will need to grow solar and wind generation 500% across the state, while pushing for early closure of natural gas plants and convincing the 11 other states in the Regional Greenhouse Gas Initiative (RGGI) to up their emission-reduction targets to 100% by 2045.

Those ambitious goals are just a few of a long list of actions the state could take to reach the GHG-reduction and clean energy targets set out in the Climate Solutions Now Act (SB 528) passed in 2022, according to the Maryland Climate Pathway report released recently by the state’s Department of the Environment (MDE). (See Md. General Assembly Sends Climate Solutions Bill to Hogan.)

The 60% cut is an interim step toward the law’s goal for Maryland to slash GHG emissions to net-zero by 2045, one of the most ambitious climate goals in the country. Another provision of the law required MDE to draft a plan for implementing the CSNA, to be submitted to the governor and General Assembly by June 30.

Emissions trajectory to reach Maryland’s net-zero target in 2045 | MDE/CGS

The Center for Global Sustainability at the University of Maryland College Park authored the report, which was released on June 30, kicking off a comment period and a series of live and virtual public hearings. The first live public hearing is scheduled for July 25 at Bowie State University in Bowie.

A final virtual hearing is scheduled for Sept. 26, and a final report is due by year-end.

Gov. Wes Moore (D) hailed the report as a “science-based path” and “a major step forward in addressing the historic challenges we face when it comes to our climate goals.”

“The report outlines a host of options to not only help address climate change, but also to help create a new center for industry in Maryland that will promote equity, ensure economic benefit and make Maryland a world leader in sustainable practices for generations to come,” Moore said.

“The integrity of the report is strong,” Kim Coble, executive director of the Maryland League of Conservation Voters, agreed, while stressing the 118-page document is neither a policy statement nor a final set of decisions or recommendations.

“It was never meant to be a policy statement,” Coble said. “It says, ‘Here are pathways to get to this very ambitious reduction goal. … You can do this; you can do that; you can accelerate here.’”

Accelerated action by lawmakers and others will be critical, Coble said. The report notes that Maryland already is halfway to the 60% target, with GHG emissions down 36.7 million metric tons (MMT) as of 2020.  But the report says that even if all of the CSNA’s provisions, along with other existing state policies, are fully implemented, Maryland still will fall short of the 2031 target by about 10.6 MMT.

Timeline with milestones set by Maryland for achieving climate goals | MDE/CGS

Filling that gap will require new policy actions that may or may not be politically or economically feasible, says Michael Powell, an environmental lawyer at Gordon Feinblatt, who previously served as principal counsel for MDE.

For example, the report calls for new standards requiring zero-emission home appliances and all-electric new construction, goals that Powell says may be overly ambitious, given the diverse demographics and political leanings across different regions in the state.

“People seem a little more willing to look at heat pumps in new construction, but there seems to be very strong resistance to giving up gas stoves,” he said.

Other potential steps on the report’s pathway to the 60% cut in GHG emissions include:

  • creating an in-state, economy-wide cap-and-invest program, in addition to RGGI;
  • shifting the passenger vehicle fleet and medium- and heavy-duty trucking fleet to zero-emission vehicles via implementation of California’s Advanced Clean Cars II rule, which Moore adopted earlier this year, and the clean trucks targets set in the Clean Trucks Act signed into law in April;
  • updating the state’s building codes and setting new building performance standards;
  • shifting the electricity Maryland imports to clean power by getting RGGI to set a 100% emissions reduction goal by 2045; and
  • leveraging the green hydrogen and carbon capture tax credits in the Inflation Reduction Act to develop alternative fuels and energy sources in the state.

Under the Advanced Clean Cars II rule, all new light-duty and passenger vehicles sold in the state will need to be zero-emission by the 2035 model year. The Clean Trucks Act calls for MDE to set regulations for increasing sales of zero-emissions trucks by Dec. 1, 2023, but also to perform a needs assessment report by Dec. 1, 2024.

Possible, not Probable

A major concern about the report is its lack of specificity on how its ambitious goals will be achieved, what the price tag will be and how those costs will be allocated.

For example, Powell pointed to considerable obstacles to decarbonizing imported power, which accounts for about 40% of its electric power, according to the U.S. Energy Information Administration.

Beyond PJM’s massive interconnection queue — which stands around 290 GW, most of which is renewable energy and storage — Powell sees growing opposition to utility-scale solar across the state, a trend that is occurring across the country.

“Pile those one on top of the other, [and] it means that utility-scale solar is actually down in the state,” he said. “The plan calls for PJM [states] to adopt a net-zero target. Looking at the political landscape, I think that’s a real challenge.”

Coble also noted that the report makes some faulty assumptions about current levels of renewable energy adoption in the state. The state’s current renewable portfolio standard — calling for 50% of the state’s power to be renewable by 2030 — includes a 14.5% carve-out for solar. But according to the Solar Energy Industries Association, solar now provides only 5.17% of the state’s power.

Powell sees the goals set out in the report as possible, but maybe not probable.

“We need to find out, is the General Assembly willing to put the kind of funding and incentives for some of the proposals in the report?” he asked. “Because I personally do not believe that private enterprise can achieve those goals without a lot of state funding.”

Coble said another key factor will be “courageous leadership from our elected officials, from this administration. Courageous leadership is going to make or break the success of this, more than anything else.”

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Rhode Island Energy Rejects Revolution Wind 2 Proposal

Rhode Island Energy said Tuesday it would not move forward with a power purchase agreement with Revolution Wind 2, which submitted the only proposal in Rhode Island’s most recent offshore wind solicitation.

The 884-MW proposal by Ørsted and Eversource was determined to be too expensive and to not meet all the requirements of the state’s Affordable Clean Energy Security Act (ACES).

Rhode Island Energy, a subsidiary of PPL, ran the solicitation and would have purchased the electricity generated by a successful project. The company said in a news release that it will continue to work to expand the amount of power flowing off the ocean and into the Ocean State.

“We recognize some will be disappointed that we didn’t choose to move forward on negotiating this PPA, but that doesn’t mean we are abandoning our commitment to offshore wind in Rhode Island,” Rhode Island Energy President Dave Bonenberger said. “In fact, we are already in discussions with state and regional leaders about new opportunities to bring more offshore wind to the state, which we hope to progress in the coming months.”

Among those unhappy with the decision was Ørsted, the world’s top offshore wind developer.

A spokesperson told NetZero Insider via email:

“We’re disappointed that Rhode Island Energy did not select Revolution Wind 2. This project would put Rhode Island’s 100% clean energy future in reach, delivering renewable energy to hundreds of thousands of homes and creating more than $2 billion in direct economic benefits to the state, with historic investments in local union jobs, workforce training, ports and the supply chain. We will assess our options for Revolution Wind 2.”

The news came one day after federal regulators issued the environmental impact statement for Revolution Wind 1, poising it to be the fourth wind project permitted in federal waters. It would stand at least 16 miles south of Rhode Island and send 400 MW to Rhode Island and 304 MW to Connecticut.

Revolution Wind 1 also is a product of the Ørsted-Eversource partnership, which is in the process of dissolving as Eversource exits offshore wind development.

Rhode Island’s latest solicitation was launched in mid-2022, a time when developers were starting to seek renegotiation of existing deals amid soaring construction costs and interest rates.

New York attracted a robust response to its 2022 solicitation, but it included the option for a future inflation adjustment, an option that potentially will raise costs for consumers.

Rhode Island Energy, by contrast, received just the one proposal in March 2023, and its comments soon after suggested that the deal with Revolution Wind 2 would be costly.

After four months of review, the company expanded on those comments Tuesday, saying the costs were deemed too expensive for customers to bear.

“The economic development benefits included in the proposal were weighted and valued appropriately by our evaluation team, but ultimately it was determined those features did not outweigh the affordability concerns and other ACES standards,” Bonenberger said in the news release.

Rhode Island Energy said that within 60 days, it will submit a comprehensive explanation of its decision to the state Public Utilities Commission. The state Office of Energy Resources and the Division of Public Utilities and Carriers will file comments as well, the company said, and the bidders will have a chance to respond.

Rhode Island Energy said it would continue to work with the state agencies and stakeholders to find more affordable ways to bring additional offshore wind energy to the state.

Offshore wind power is an important part of the state’s strategy to use 100% renewable energy by 2033 and achieve net-zero status by 2050.

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FERC Seeks More Info on NYISO DER Aggregation Proposal

FERC staff asked NYISO to provide additional detail on the ISO’s proposed tariff revisions for integrating distributed energy resource aggregations into its markets, including a rationale for its 10-kW minimum (ER23-2040).

FERC’s July 18 deficiency notice requested an explanation for the 10-kW threshold, “as opposed to another threshold,” and asked whether the ISO’s position would change once it deploys the automation features it is currently developing. State regulators and clean energy groups have protested the 10-kW minimum, which the ISO said was needed to save staff time reviewing aggregations for interconnection. (See NYISO Defends DER Aggregation Proposal, 10-kW Minimum.)

FERC’s letter also sought detail on other revisions, including how long utilities would have to review DER reliability and safety study results and what the review would entail. Staff also asked what would constitute a “material modification” to a DER and how the ISO would conduct its aggregation derating process.

Additionally, FERC asked NYISO to justify its new DER metering and telemetry requirements, explain why it is appropriate to use certain reference levels for aggregations, and expand on its definitions related to the elimination of locational-based marginal pricing and bid-based reference levels for aggregations.

NYISO must respond to FERC’s letter by Aug. 17.

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MISO Convening Task Team to Shore Up Credit Policy

CARMEL, Ind. — MISO said it will debut a task team dedicated to improving its credit policy as market participants experience more price volatility in the market and default risk grows.

Brian Brown, of MISO’s credit and risk management team, said MISO is in the process of forming the Credit Policy Enhancements Task Team, with meetings to begin in September. At the July 13 Market Subcommittee meeting, Brown said risky circumstances, such as widespread winter storms, are occurring more frequently and could give rise to “defaults or near-default situations.”

Brown said the task team will examine extreme weather events to see how MISO’s credit policy can be strengthened to discourage defaults. Brown said MISO will look at its minimum capitalization requirements to account for increased price volatility, review its estimated exposure calculations and credit requirements for virtual transactions, and explore the possibility of adding a minimum collateral requirement for all market participants — something MISO doesn’t have.

He also said MISO may update the bankruptcy language in its tariff to align with Federal Bankruptcy Code requirements and consider tariff language that allows MISO to implement flexible payment terms in the event of a marketwide event that causes “large, unexpected market charges.”

Brown said as a result of the task team’s work, MISO may begin to make some FERC filings to reinforce its credit policy in the first quarter of 2024.

“We really hadn’t experienced any losses prior to 2021. What we’re noticing is there’s an increase in volatility in the markets. … Frankly, we’ve got some scar tissue from dealing with some issues,” Brown said, referencing virtual traders who nearly defaulted and lost $150,000 in the market in January 2021 and the market participants who lost $38,000 related to the Brazos bankruptcy following Winter Storm Uri in February 2021. The storm led to MISO making 140 margin calls totaling $325 million. MISO makes margin calls when a market participant’s credit exposure is greater than the financial security and unsecured credit they have in place, and MISO requests additional collateral or reduced activity in its market.

MISO said it avoided defaults during the December 2022 winter storm, though it had to issue more than 100 credit exposure warnings. (See MISO Defends Energy Exports During December Storm.)

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Major Fishery, Visual Impacts Expected from Revolution Wind

Federal regulators on Monday issued their final environmental impact statement for the 704-MW Revolution Wind project proposed off the New England coast.

As with every other EIS drafted or completed so far, it projects major negative impacts on fisheries, on the ability to monitor or survey those fisheries, and on the view people enjoy of the ocean horizon.

The EIS is one of the final milestones in the federal review process — the U.S. Bureau of Ocean Energy Management said Monday it expects to issue a record of decision this summer on whether to approve, modify or reject the project. Approval would greenlight Revolution as the fourth commercial-scale offshore wind project on the U.S. Outer Continental Shelf.

Revolution’s developers began fabricating components this spring and hope to begin construction this year. Upon completion, which is projected in 2025, Revolution would send 304 MW of power to Connecticut and 400 MW to Rhode Island via one or two lines making landfall in Rhode Island.

As proposed, it would consist of up to 100 turbines standing one nautical mile apart on a grid pattern at least 16 miles south of Rhode Island.

In an attempt to reduce the project’s impacts on the view from shore and on fisheries, BOEM developed a preferred alternative that would reduce the maximum number of turbines to 65 and the number of positions on that grid pattern to 79. The plan would remain the same in most other details, including power output and supporting transmission infrastructure.

The EIS rates the project twice each on 23 separate criteria ranging from bats and turtles to environmental justice and the economy — once for its impact individually and once cumulatively with all the other offshore wind development anticipated off the Northeast coast.

The project is projected to have minor or moderate adverse or beneficial impacts on most of the 46 metrics; some metrics could see both adverse and beneficial impacts.

Potentially major individual and/or cumulative negative impacts are projected on commercial fisheries; for-hire recreational fishing; cultural resources; demographics, employment and economics; environmental justice; scientific research and surveys, such as federal fisheries monitoring; and scenery.

No major beneficial impacts are projected on any of the metrics.

The EIS also projects the impacts of six alternatives to the project as proposed: the preferred alternative, four other alternatives and a sixth scenario in which the project is not built at all.

However, there is little variation in the degree of projected impacts among the various alternatives; most impacts remain minor, moderate or major under all seven scenarios.

The EIS projects that if Revolution Wind were not built, the continuation of current environmental trends could have a moderate to major adverse impact on both of the fishing sectors; cultural resources; demographics, employment and economics; and environmental justice.

In other words, the details might differ from one scenario to another, but the specific metrics likely will face significant influencing pressures whether Revolution Wind is built or not.

Revolution Wind would occupy an area BOEM leased out in July 2013. It is proposed by Ørsted and Eversource, the world’s largest offshore wind developer and New England’s largest electric utility.

The two are pursuing several other offshore wind proposals in the Northeast waters, including Revolution Wind 2, an 884 MW proposal submitted in March in Rhode Island’s most recent solicitation.

Eversource is in the final stages of selling off its share of the partnership and exiting the offshore wind generation sector. It expects to remain active in transmission of offshore wind power.

Monday’s final EIS began as a draft issued in September 2022. BOEM said it incorporated comments from stakeholders as it developed the final EIS.

“BOEM used the feedback we received from tribal nations, industry, ocean users, communities and stakeholders to help inform our decisions throughout the environmental review process and ensure that we are addressing potential impacts,” BOEM Director Elizabeth Klein said in a news release. “This milestone represents another important step forward in building a new clean energy economy here in the United States.”

Environmental Impact

The EIS issued Monday is the latest in a series prepared by BOEM as it leads an effort to install tens of thousands of megawatts off the U.S. coast in pursuit of President Biden’s goal of 30 GW of offshore wind capacity by 2030.

Much of the early development is proposed in clusters between Nantucket, Mass., and Cape May, N.J., a concentration that raises the potential for a combined impact greater than the impact any single project would have.

BOEM has issued final EIS reports for three other projects that it has since greenlighted. The details differ, but each one forecasts many of the same major adverse impacts as are predicted for Revolution Wind:

    • The Vineyard Wind EIS (March 2021) saw potentially major negative impacts on environmental justice; cultural, historical and archaeological resources; both fishing sectors; navigation and vessel traffic; scientific research and surveys; and search-and-rescue efforts.
    • The South Fork Wind EIS (August 2021) flagged both fishing sectors, cultural resources, research/surveys and visual impact.
    • The Ocean Wind 1 EIS (May 2023) flagged commercial fishing, the North Atlantic right whale, research/surveys and cumulative scenic/visual impacts.

The draft environmental impact statements completed for other offshore wind projects follow similar themes, projecting potentially major impacts on fishing, visual and/or cultural resources, and scientific research and surveys.

Additionally, those draft EIS reports state:

    • Empire Wind (November 2022) and Sunrise Wind (December 2022) are expected to have a major negative impact on Coast Guard search and rescue operations.
    • SouthCoast Wind (February 2023) is projected to have a potentially major adverse impact on environmental justice and marine mammals.
    • Atlantic Shores (May 2023) is projected to have a major negative impact on right whales, military/national security operations, and vessel traffic/navigation.

Today’s EIS reports show a marked contrast to early efforts.

The Revolution Wind EIS issued Monday totals more than 4,900 pages with its appendices.

The final EIS for the ill-fated Cape Wind Energy Project, issued in January 2009, was just 800 pages. The Marine Management Service, as BOEM was known then, projected few moderate adverse impacts in the EIS (fisheries not among them) and only one major negative impact: on the view nearby.

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RF Urges Consultations on Generator Winter Preparations

Regional entities and utilities have a lot to gain by taking a collaborative rather than an adversarial approach to compliance with NERC’s new extreme winter weather standards, participants in a ReliabilityFirst webinar said on Monday.

The webinar was part of the RE’s regular “Technical Talk with RF” series. RF’s Brian Thiry said in his introduction that RF staff had jokingly dubbed the event “Christmas in July” because of its focus on “all things cold weather,” particularly the new standards that began to take effect earlier this year.

Topics included NERC’s first Level 3 alert, issued earlier this year after the ERO’s Board of Trustees approved it at its meeting in May. (See “ERO to Issue First Level 3 Alert May 15,” NERC Board of Trustees/MRC Briefs: May 10-11, 2023.) The alert requires registered entities to provide NERC an extensive set of information by Oct. 6, including their total net winter capacity and how they have prepared their systems for cold weather. It also identified eight essential actions for entities to take to prepare for cold weather, although implementing them is voluntary.

Darrell Moore, NERC’s director of situation awareness, emphasized the importance of abiding by the Level 3 alert in his presentation, stressing that “it has become increasingly important to understand how entities have taken steps to prepare for extreme weather conditions” in light of the storms that caused widespread power outages in the last two winters.

RF representatives also talked up their organization’s cold weather winterization (CWW) program, which is intended to help registered entities with their winter preparations by having RF consultants visit generating plants to check their weatherization measures personally.

Staff emphasized that despite the CWW program’s reliance on site visits and audits, it is not part of the RE’s compliance monitoring and enforcement program; nor is it intended to formally certify a generating facility’s preparedness for winter operations. Rather, the aim of the program is to inform and educate generator owners and operators in what RF’s Senior Reliability Consultant Joseph Jagodnik called “a more relaxed, constructive and forward-looking atmosphere.”

This year’s program will focus on plants commissioned in 2023, along with existing generation that has experienced a cold weather-related outage. The RE will send out a survey in late summer or early fall to identify site candidates, with visits to follow from late October through mid-December. Visits are expected to last a day with two to four RF staff members on site.

Nicholas Poluch, senior manager of NERC relations at Talen Energy, joined the webinar to describe a visit last year by CWW staff to the utility’s Lower Mount Bethel plant in Pennsylvania. He credited the RF team with helping Talen reorganize its winterization operations and consolidate its compliance program.

“I think overall, [there was] a lot of benefit, not only to this plant, but we took the ideas that RF gave us for this facility and rolled them out across the fleet, and I think it really upped our game,” Poluch said. “I think we as an organization [also] became more accountable [on] weatherization and more disciplined in implementing it. We were doing stuff [before], it just wasn’t to the same level as, say, our protective systems program.”

RF staff encouraged utilities to take advantage of the CWW program, describing it as a chance to put RF’s knowledge and experience to work for their benefit. Thiry said it fits into the RE’s goal of being a partner to the industry, rather than solely an enforcement mechanism.

“Our winterization program is … something we take a lot of pride in, and it’s something that we do want to continue to grow and expand upon,” Thiry said. “At the end of the day, what matters to ReliabilityFirst is that you are reliable, resilient and secure. So if there’s any consulting work that we can do with you before or after an audit engagement, we’d love to engage with you on that.”

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PJM Completes CIFP Presentation; Stakeholders Present Alternatives

PJM completed presenting its proposal to overhaul the capacity market, and stakeholders continued refining their own proposals, during the Critical Issue Fast Path (CIFP) process meeting last week.

Wrapping up a presentation that spanned multiple full-day meetings, PJM focused on its proposed changes to market power mitigation and fixed resource requirement (FRR) entities.

The proposed market power changes would create an explicit calculation of unit-specific Capacity Performance (CP) risk based on its parameters and reliability risk modeling. PJM’s Skyler Marzewski said the goal is to ensure that market sellers can fully represent the risks and costs of taking on a capacity obligation.

PJM’s package also would shift to using a forward-looking energy and ancillary services offset for the market seller offer cap (MSOC) and minimum offer price rule (MOPR). And the exemption that intermittent and storage resources currently have from the must-offer rule would be ended under the proposal.

Ken Foladare of the Tangibl Group said removing the must-offer exemption seems designed to impair intermittent resources by forcing their participation in the capacity market while they’re subject to penalties if there is an emergency while they’re unable to operate.

“I don’t see how this isn’t going to be a very large negative for renewable and intermittent resources in general,” he said.

PJM Senior Director of Economics Walter Graf said CP penalties currently don’t reflect the actual expectations of how a resource would perform, while the overall proposal aims to capture that in each unit’s accreditation and corresponding obligation. While the proposal would introduce more risk intermittent resources, he said the volatility would average out with the likelihood of them overperforming during other periods.

Calpine’s David “Scarp” Scarpignato said thermal resources are held to their capacity obligations even during weather conditions under which they weren’t designed to operate and questioned why intermittents should be treated differently if they were subject to the must-offer requirement.

“I could use the same logic and argue [combustion turbines] should be excused from penalties because it’s not designed to run in those conditions,” he said.

He added that intermittent resources are being built without participating in the capacity market, signaling that there aren’t market power concerns with those units and they might not need to be held to the requirement.

The PJM proposal also would rewrite the rules for planned capacity resources to enable net cost of new entry (CONE) values to be calculated on a unit- or default technology-specific basis.

The FRR changes would aim to align the regulated utility structure with the proposed capacity market rules by creating seasonal obligations for FRR plans, with corresponding accreditation and qualifications for those generation resources.

The option for FRR entities to elect a physical penalty would be removed, leaving them subject to a deficiency charge in the event their generators underperform during a performance assessment interval (PAI).

The charge rate would be set to the insufficiency penalty — which itself is based on the CONE — which raised questions among some stakeholders who said pegging the FRR penalty to CONE rather than the Base Residual Auction (BRA) clearing price — which is the basis for the penalty rate for capacity resources — strays from the goal of aligning the two structures.

PJM Shifts Timeline Within Fuel Security Presentation

PJM has revised its proposal to evaluate natural gas resources’ fuel security and incorporate those variances into their capacity accreditations to begin with the creation of a dual-fuel class of resources in the next Base Residual Auction (BRA). Director of Planning Operations Chris Pilong said including fuel assurance in accreditation would allow for the quantification and recognition of the value that enhanced availability brings and incentivize new investments that improve overall reliability.

Resources seeking dual-fuel status would be required to either demonstrate that capability or have plans in place to install the necessary equipment by the start of the delivery year. PJM expects that resources will attest to their status for the initial rollout, likely followed by inspections down the road.

PJM also plans to have generators submit their fuel transportation status prior to each BRA starting with the 2025/26 auction, with the aim of incorporating that into accreditation in the future as well once sufficient data have been collected.

Dual-fuel resources also must have access to enough secondary fuel storage to operate for 48 hours to qualify for the higher rating.

Old Dominion Electric Cooperative’s Mike Cocco said many resources have shared fuel storage and gave the example of two CTs that share a tank with enough fuel for one to operate for two days. The generation owner would be able to offer only one of those resources as having dual-fuel capability, which could limit dispatchers’ options during an emergency. He suggested that PJM instead offer more granular levels of storage, such as 12-, 24- and 48-hour categories.

“That’s precisely the wrong signal that PJM wants to support because you’re going to lose the ability to operate that CT on oil when you otherwise had it,” he said. “I think you’re really going to hit some unintended consequences if you just stick with the one value.”

Economist James Wilson, a consultant to state consumer advocates, said that while he is in favor of PJM’s proposal to create a seasonal capacity market, it has some shortcomings, and it may be beneficial for the RTO to work with stakeholders to create an alternative model that works toward a goal of being more transparent and understandable. Having a variable resource requirement (VRR) curve that’s known in advance of auctions would be one component he’d like to include.

Graf said PJM is willing to work with Wilson and others in drafting additional options in the proposal matrix, and it acknowledges that the complexity in its proposal is a downside.

Calpine Proposes Additional FRR Changes

Presenting for Calpine, Scarp said PJM’s proposal doesn’t go far enough to bring the FRR rules into alignment with the capacity market, with the largest issue being that there is no sloping demand curve for FRR entities, which only have to meet the reliability requirement identified by PJM.

This has led to the capacity that FRR entities are required to procure being an average of 6.7% lower than the rest of the pool over the past five years, he said, amounting to a difference of about 9,408 MW each year. Clearing long — above the reserve margin — has produced benefits for capacity market participants, which the FRR side has been able to “lean” on. He argued that FRR participants are receiving reliability benefits from the rest of the pool for which they aren’t paying.

Scarp proposed setting a FRR procurement requirement reflecting the amount of capacity that has cleared above the IRM over the past five years, with a rolling average.

Economist Roy Shanker agreed, saying that allowing certain parties to benefit from carrying a lower reserve margin is wrong.

“Fundamentally what is going on right now is discriminatory. … What they do is create a basis for rate-based resources to arbitrage against the rest of the pool,” he said.

Wilson said over-procurement is an undesirable aspect of the Reliability Pricing Model that has to be tolerated to get the benefits of a sloped demand curve.

Calpine also proposes that PJM expand the portion of its proposal that bars capacity sellers from substituting replacement capacity for resources that underperform during an emergency during the billing process to also be applicable to FRR entities.

Daymark and EKPC Propose Base and Emergency Capacity

A joint package from Daymark Energy Advisors and East Kentucky Power Cooperative also aims to expand on PJM’s proposal by further splitting capacity into two products differentiated by the type of system conditions the resource would be best suited to address.

Base capacity (BC) would center on meeting the needs of regular system conditions and wouldn’t include higher winterization than those already mandated by NERC — a requirement PJM’s proposal would include for all resources participating in its envisioned winter capacity market.

Emergency capacity (EC) would be designed to address extreme weather and would be required to have firm fuel or a technical equivalent, be available for dispatch within two hours’ notice and demonstrate the ability to pay any non-performance penalties if not able to operate. It also would be procured on a multiyear basis, while BC would follow the status quo annual auction schedule.

Daymark CEO Marc Montalvo said EC could be provided by resources that already are online, such as a steam unit, or by peaker plants. When energy is needed quickly during an emergency, he said having access to units that already are online and can ramp up or can start quickly is a valuable attribute.

All resources would be subject to the must-offer requirement, similar to PJM’s proposal, and their offers would be risk-adjusted under the joint proposal. Montalvo said BC resources would require little to no adjustment, while EC offers are exposed to higher penalty risk.

Independent Market Monitor Adds Detail to Hourly Approach

Independent Market Monitor Joe Bowring presented an alternative proposal during the June 28 CIFP meeting that features an annual capacity auction and clearing price paired with hourly matching of load and capacity throughout the delivery year.

Rather than using accreditation to define the amount of capacity a resource may offer and is obligated to deliver, the Monitor’s proposal would reduce its installed capacity by its modified equivalent availability factor, which is based on historical hourly availability and its location.

The market clearing engine also would take the hourly historical performance of resources into account, including ambient derates, planned maintenance and forced outages. Bowring said this would ensure that intermittent resources would not be dispatched at times when they would not be able to perform, such as solar at night.

Under the model, a capacity resource would be paid only for the times in which it is available to provide energy according to its capacity obligation. Contrasted against the accreditation and seasonal model in PJM’s proposal, Bowring said this ensures resources are paid only when they can meet their obligation and avoids the arbitrary nature of defining seasons.

Bowring’s concerns about a seasonal market also include the ability to represent an annual avoidable-cost rate and energy and ancillary service revenue offsets.

“PJM’s seasonal approach will create issues that it is not possible to solve analytically; for example, how to allocate avoidable costs across seasons and for annual offers,” Bowring said in an email. ”There is no magic to the definitions of seasons. Seasons are arbitrary. It’s great that PJM recognizes that there are risks in the winter. The logical end point is to recognize hourly differences in required and available supply. Hourly captures the winter issues and the summer issues and issues that may arise in any hour, as well as locational issues, without creating the unnecessary complexity of seasonal cost allocations.

“In addition, PJM’s approach to market power and the market seller offer cap is inconsistent with FERC’s order on the MSOC and inconsistent with the role of the capacity market. There is no reason that energy market net revenues should not offset all avoidable costs, without exception. Recognizing that the cost of mitigating risk is another cost that can be offset is essential, given that the role of the capacity market is to provide the missing money (the portion of avoidable costs not covered by the energy market) and not to add money that was never missing. Including the cost of mitigating risk as part of avoidable costs fully recognizes risk,” he said.

Speaking to RTO Insider after the June meeting, Bowring said the underperformance aspect of the Monitor’s proposal likely will be revised so that if a resource is called and does not start, it would not be paid its hourly capacity revenues back to the last time it did successfully start. If a generator fails one of its biweekly tests, it also would be required to return payments going back to the last time it successfully started.

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FERC Briefs: Orders Addressing Arguments Raised on Rehearing

FERC issued explanations for denying rehearing requests in several cases in the past week. Requests to rehear FERC orders are automatically deemed denied “by operation of law” unless the commission acts within 30 days. The orders below elaborate on why the commission declined to reconsider its prior orders.

MISO
NextEra Request for Rehearing of Canceled MISO Competitive Project

ER23-865-001

NextEra Energy asked the commission in April to stay its order terminating the only competitive regional transmission project in MISO. (See NextEra Asks for Rehearing of Canceled Competitive Project.) The commission’s March order allowed MISO to abandon the $115 million, 500-kV Hartburg-Sabine Junction project in East Texas. The RTO approved the project in 2017 but determined last year that the project’s benefits had evaporated due to recent generation additions in the region.

The commission reiterated its conclusion that MISO followed its tariff in the matter and said it disagreed with NextEra that no other parties would be harmed by granting the requested stay. “As the commission explained in the termination order, ‘the mounting delay in commencing construction’ of Hartburg-Sabine resulted in economic uncertainty for MISO stakeholders due to the modeling of a project that will not be built, which will eventually create reliability concerns,” FERC said. “Even if the threat of reliability issues was not concern enough, MISO asserts that requiring it to reinstate Hartburg-Sabine into its generator interconnection models would cause queue delays for a number of generator interconnection customers. In light of these findings, we find that granting the stay would harm third parties.”

Eliminating Schedule 2 Reactive Power Charges

ER23-523-001

Vistra, Invenergy and others sought rehearing on the commission’s January order approving MISO transmission owners’ request to eliminate Schedule 2 charges for reactive power within the standard power factor range. Opponents said FERC failed to consider the effects of eliminating reactive power compensation on the MISO markets, particularly regarding independent power producers’ reliance on such compensation.

In approving the MISO TOs’ proposal, FERC cited its policy “that the provision of reactive power within the standard power factor range is … an obligation of the interconnecting generator and good utility practice.” In its July 12 order, the commission rejected the challenges “as collateral attacks on that longstanding policy.”

Commissioner James Danly, who dissented from the January order, repeated his opposition, saying the MISO TOs failed to overcome “the record’s substantial unrebutted evidence of the rate impacts this proposal would have on generators not affiliated with the MISO TOs.”

PJM
PJM Interconnection Queue Procedures

ER22-2110-002

Petitioners challenged the commission’s Nov. 29, 2022, order accepting PJM’s proposal to transition from a serial first-come, first-served queue process to a first-ready, first-served clustered cycle approach. (See FERC Approves PJM Plan to Speed Interconnection Queue.)

Lee County Generating Station complained that the commission failed to address arguments that the rule changes were unfair to existing generators making long-term firm transmission service requests. In its July 6 order, FERC acknowledged that the transition from a serial approach to a cluster approach “may present delays for existing customers that had previously been avoidable due to PJM’s pre-existing practice of removing from the interconnection process and advancing firm transmission service requests that did not contribute to the need for network upgrades.” But it said the generator “has not demonstrated that PJM’s proposal is unduly discriminatory.”

Hecate Energy, a Chicago-based renewable power developer and operator, challenged FERC’s acceptance of a $5 million cap on network upgrades for projects seeking to interconnect through PJM’s expedited process, saying it was arbitrary. “Despite Hecate’s disagreement with PJM’s observation that new service requests associated with network upgrades at or below the $5 million threshold are ‘fairly straightforward’ and that ‘the majority of new service requests do not proceed when they are assigned network upgrade costs … in excess of $5 million,’ Hecate provides no contrary evidence,” FERC said.

PJM Order 2222 Compliance

FERC defended its March approval of PJM’s Order 2222 compliance filing after rejecting rehearing requests by the Ohio and Pennsylvania public utility commissions, Advanced Energy United (AEU) and the Solar Energy Industries Association (SEIA) (ER22-962-003).

FERC responded to the Ohio and Pennsylvania commissions’ jurisdictional concerns by saying its order does not give PJM authority over disputes with state laws but found the RTO’s proposal “unreasonably restricts” a DER aggregator’s use of PJM’s dispute resolution procedures.

AEU and SEIA argued that the proposal’s provisions to prevent double counting of energy and capacity would prevent net energy metering programs from participating in PJM’s markets, pointing to narrower language from NYISO and ISO-NE. FERC said it was granting RTOs flexibility in their double-counting restrictions and that PJM’s proposal is sufficiently narrowly designed.

Commissioner Mark Christie concurred with the July 11 order, reiterating his dissent in Order 2222-A over jurisdictional concerns. “This fundamental issue raised by these two state commissions has, of course, been among the daunting practical challenges of implementing Order No. 2222 from the beginning because that order egregiously invaded the long-time authorities of the states and other relevant electric retail regulatory authorities (RERRAs) to regulate retail rates,” Christie wrote. “We are also beginning to see some of the other consequences, including the costs that consumers will now be forced to bear towards implementing Order No. 2222.”

PUERTO RICO

APPA Request for Rehearing or Clarification re: Alternative Transmission Inc.

EL23-14-001

The American Public Power Association sought rehearing or clarification of FERC’s March 16 order granting Alternative Transmission Inc.’s petition for a declaratory order regarding the jurisdictional consequences of a proposal to build one or more HVDC undersea transmission lines connecting Puerto Rico to the mainland. The commission said the interconnection proposed by ATI would result in Puerto Rico’s utilities becoming subject to the commission’s jurisdiction unless an exemption were granted under Section 201(b)(2) of the Federal Power Act. (See FERC Weighs in on Jurisdictional Questions over Puerto Rico Project.)

APPA responded that because Puerto Rico is considered a state under the FPA, “a utility owned by the government of Puerto Rico would not be a public utility as defined in the FPA.” Thus, the Puerto Rico Electric Power Authority would be considered a “municipality,” which is excluded from the definition of “public utility,” APPA said.

In its July 10 order, FERC said that whether a particular utility in Puerto Rico would be considered a public utility as a result of ATI’s proposed interconnection would be dependent on the company’s specific characteristics. “For example, if an electric or transmitting utility in Puerto Rico qualifies as a municipality under section 3(7) of the FPA, then that utility would not become subject to the commission’s jurisdiction as a public utility under section 201(e) of the FPA as a result of the interconnection proposed by ATI, although such utility would be subject to the commission’s jurisdiction under other provisions of the FPA, including, but not limited to, Section 215 of the FPA,” which created the Electric Reliability Organization to develop mandatory reliability standards.

SPP

City of Nixa, Mo., Annual Transmission Revenue Requirement

ER18-99-007

Numerous parties challenged FERC’s February order approving SPP’s proposal to include the annual transmission revenue requirement (ATRR) for the city of Nixa, Mo., (owned by GridLiance High Plains) in transmission pricing Zone 10. The commission said it was consistent with cost causation principles. (See “Order on GridLiance ATRR,” FERC Grants Rehearing of SPP Capacity Accreditation Proposal.)

The order was challenged by several municipal utilities in Arkansas and Missouri and a group of SPP transmission owners, including Evergy and American Electric Power’s Public Service Company of Oklahoma and Southwestern Electric Power Co., which said the commission should have focused on the non-Nixa transmission customers in evaluating the impacts of including the Nixa assets in Zone 10.

In its July 5 order, the commission said the challengers’ arguments “focusing on the extent to which they derive benefits specifically from the Nixa assets are inconsistent with SPP’s zonal rate design.”

Empire District Electric Co. Generation Replacement Under SPP Rules

ER23-928-001

Empire District Electric challenged the commission’s March 29 order denying its request for a tariff waiver to allow Empire to replace its Riverton Unit 10, a 16.3-MW simple cycle facility damaged in a fire Feb. 8, 2021. The commission ruled that Empire’s waiver request was retroactive and prohibited by the filed rate doctrine because the company failed to file the waiver request within the one-year deadline in SPP’s replacement rule.

In its July 12 order, FERC rejected Empire’s contention that its request was “prospective” because SPP could modify its generator replacement process in the future. “Whether SPP will revise [its tariff] in the future is not only speculative, but … also irrelevant, given that Empire is requesting that the commission provide retroactive relief to excuse Empire’s failure to submit a generating facility replacement request by the Feb. 8, 2022, tariff deadline,” the commission said.