FERC on Friday ordered show cause proceedings on PacifiCorp’s and NV Energy’s generator interconnection rules while approving, in part, rules aimed at limiting speculative projects in Nevada.
The first show-cause order (EL23-26) found that PacifiCorp’s large generator interconnection procedures might be unjust and unreasonable due to rules that trigger restudy of lower-queued customers when an interconnection customer suspends its agreement. The commission also questioned the requirement that the suspending customer pay for the restudies.
FERC Order 2003 requires interconnection customers to pay for their own studies, even if it is a restudy caused by another firm’s decision to withdraw its higher-queued project. The order also allows projects to suspend their interconnection agreements for up to three years, which gives developers flexibility to deal with permitting and other delays that are likely to impact large projects.
FERC issued a preliminary finding that PacifiCorp’s requirement is unjust and unreasonable because the company can require restudies when a developer only suspends its interconnection agreement, even though a restudy would not be needed if the project ultimately proceeds.
The second show-cause order (EL23-27) directs Nevada Power to show why its large generator interconnection procedures are just and reasonable despite not specifying a method for allocating the costs of network upgrades among interconnection customers in a cluster.
FERC has approved serial cluster studies for both ISO/RTOs and independent utilities, including PacifiCorp and NV Energy, subsidiaries of Berkshire Hathaway Energy. NV Energy’s 2013 update to its large generator interconnection procedures includes pro forma language that said it “may allocate the cost of common upgrades for clustered interconnection requests without regard to queue position,” but the procedures do not specify how those costs are allocated.
The specific costs significantly affect rates and should be included in the utility’s tariff, FERC said. Without specific rules on file, the commission said, it cannot easily determine whether any cost allocations are consistent with its precedent.
The two utilities must show cause as to why their rules are just and reasonable within 60 days, or they can propose changes under Section 205 of the Federal Power Act to address FERC’s concerns. A 205 filing would put the show-cause proceeding in abeyance while the commission considers the proposals.
The third order (ER22-2933) approves some changes NV Energy proposed to discourage speculative interconnection projects and allow projects that are ready to move forward with construction to get through the line faster. The utility has seen the number of requests to connect to its grid spike, and recently, 42% of them have either gone into default, been withdrawn, or have interconnection agreements under suspension.
To cut back on the speculative projects, NV Energy proposed increasing deposit requirements; eliminating the use of a “Preliminary Plan of Development” (a document used by the Bureau of Land Management when firms seek to build on federal land) as a form of site control; and setting a withdrawal penalty to hold remaining customers harmless from restudy costs. It also would create a graduated deposit structure based on project size, ranging from $75,000 for up to 50 MW; $150,000 for 50 to 200 MW; and to $250,000 for 200 MW or greater.
FERC approved the stricter site control requirements, including raising the deposit in lieu of site control from $50,000 to $250,000. Those rules will increase the likelihood that only commercially viable projects will have a place in the queue, FERC said.
The commission rejected the withdrawal penalties NV Energy proposed because it found that requiring such customers to cover restudy costs would prove too burdensome. Other utilities have withdrawal penalties, but they are more limited, FERC said.
FERC also rejected NV Energy’s proposal to require interconnection customers who suspend their agreements to pay for restudies of lower-queued projects. Because suspended projects still have the option to move forward, FERC ruled it would be “inefficient for [NV Energy] to conduct a restudy based on the assumption that a suspending interconnection customer is going to withdraw from the queue.”
The commission also rejected a rule that would have let Nevada Power assign the cost of network upgrades that were only triggered by one project in a cluster to that specific project. FERC found the language was not specific enough.
In discussing that rule, the commission also noted that it launched the second show cause proceeding against Nevada Power because its tariff does not include how the utility allocates the costs of network upgrades among interconnection customers in a cluster.
Figuring out whether a new electric vehicle qualifies for one of the Inflation Reduction Act’s $7,500 tax credits got a little easier on Friday as the U.S. Treasury Department updated its guidelines to base vehicle classifications on the model information listed on the car’s price sticker.
Under the IRA, EVs classified as SUVs or pickup trucks are only eligible for the tax credit if their manufacturer’s suggested retail price is $80,000 or less. The MSRP cap for sedans and other passenger vehicles is $55,000.
In its previous guidelines, released at the end of 2022, Treasury had based these classifications on EPA’s Corporate Average Fuel Economy (CAFE) standard, which sets fleetwide averages for fuel efficiency. The information on vehicle price stickers is based on EPA’s Fuel Economy Labeling standard, which is calculated from a model’s fuel savings over a five-year period.
In some cases, the vehicle classification based on the CAFE standard was different from the classification on the automaker’s price sticker ― also available on EPA’s fueleconomy.gov website ― causing confusion and uncertainty for both consumers and auto dealers.
For example, Treasury initially classified the Ford Mustang Mach-E SUV as a sedan, limiting the availability of tax credits to consumers buying a model with an MSRP $55,000 or less. Under this classification, only two of the Mach-E’s four 2023 models, the Select and Premium, would have qualified for the tax credit.
The update reclassifies the car as an SUV, putting all four of its 2023 models ― top price, $63,995 ― well below the $80,000 MSRP price cap for SUVs.
Chris Smith, Ford’s chief government affairs officer, welcomed the update. “We recognize that the Treasury Department has a huge task in front of them in implementing the Inflation Reduction Act. We sincerely appreciate their consideration and hard work to make sure that more customers are able to access clean vehicle tax credits under the [IRA],” he said.
General Motors and Tesla faced similar limits on some of their models, specifically GM’s Cadillac Lyriq SUV and Tesla’s Model Y.
GM lobbied the department for changes, as reported by The Street. The automaker argued that “in determining how vehicles should be classified, Treasury should leverage existing U.S. government definitions and practices. … This drives consistency across existing federal policy and clarity for consumers.”
A statement from the automaker on Friday noted that the change “will allow crossover vehicles that share similar features to be treated consistently,” according to The Street.
Tesla had already cut prices on its Model Y in January, The Verge reported. But the company raised prices on both Model Y configurations ― the Long Range and Performance ― hours after Treasury issued its update.
Domestic Content Delay
The updated guidelines on vehicle classification clears up some of the confusion about the EV tax credits. But Treasury’s delay in issuing critical guidelines for the IRA’s domestic content requirements remains a point of ongoing controversy.
The law required Treasury to issue these guidelines by Dec. 31, 2022; however, Friday’s announcement reiterated the department’s plan to release them in March. (See Treasury Delays Key Rules for IRA’s EV Tax Credits.)
As originally written in the IRA, to qualify for the full $7,500 tax credit, an EV’s battery must contain a certain percentage of critical minerals sourced in North America or from a country with which the U.S. has a free-trade agreement. A certain percentage of other battery components must also be sourced in North America.
The domestic content requirements start this year at 40% for critical minerals and 50% for battery components, ramping up in subsequent years.
If one of the domestic content requirements is not met, a consumer may only get half the credit. While delaying the guidelines on domestic content, Treasury is allowing EV buyers to claim the full $7,500 credit.
European automakers and government officials have widely criticized the requirements, labeling them as protectionist and likely to cause a “subsidy war.”
Speaking at the Washington Auto Show last month in D.C., EU Ambassador Stavros Lambrinidis warned that with both the union and U.S. putting billions into transportation decarbonization, “the biggest mistake that governments can do is to get into a subsidy war.”
“That’s a danger because the IRA, the way it’s structured, in a sense is endangering investment in Europe. It is sucking away investment potential, especially at a time of very high energy prices,” he said. “Nothing could be worse for the strength of the U.S. economy and U.S. companies than a weak European economy.” (See Tracking the Contradictions of the US EV Market at the DC Auto Show.)
Sen. Joe Manchin (D-W.Va.) has also criticized the delay, introducing a bill that would require the department to implement the guidelines immediately and make them retroactive to Jan. 1. As chair of the Senate Energy and Natural Resources Committee, Manchin has consistently argued that the IRA’s domestic content requirements are aimed at building out a domestic supply chain and cutting U.S. dependence on China for critical mineral processing and battery component manufacturing.
“We’re moving rapidly into the EV markets — and I think, recklessly — as we were going into that before we were able to supply [domestic production] and be held captive by China,” he said during a Senate floor debate on Jan. 26. (See IRA’s EV Tax Credits Spark Senate Debate.)
The bill has yet to receive a committee hearing or a vote in the Senate.
ERCOT easily met demand last week as icy weather swept through the state and created local distribution outages affecting as many as 400,000 customers at one point.
The grid operator’s load never averaged more than the 65.56 GW it did during the early evening hours of Jan. 31, when the storm swept through the northern half of state. Demand peaked at 73.96 GW during the December winter storm, a 16-GW increase from ERCOT’s previous high for the month.
Most of the outages were centered on Austin and Northeast Texas, where trees succumbed to the icy accumulation in what locals referred to as an “oakpocalypse.” Some observers pointed to lax vegetation management and opposition to tree-trimming measures as the primary reason for the outages.
The National Weather Service’s forecast for icy conditions in Texas. | WeatherBell
Austin Energy, the city’s municipal utility, had more than 163,000 customer outages at one point. By Sunday morning, it had reduced that total to 44,000, meaning some customers had been without power for 102 hours, longer than they were during the deadly 2021 winter storm.
Oncor, which serves much of North Texas, said Saturday it had restored power to the “vast majority” of its customers. The utility reported more than 140,000 customer outages Thursday morning.
Texas still had more than 65,000 customer outages Sunday morning, according to poweroutage.us.
Texas Gov. Greg Abbott said ERCOT maintained “ample supply” during the week and reminded his Twitter audience that outages were caused by “local issues.” On Saturday, he declared disaster conditions for seven counties affected by the storm.
Calpine to Develop Gas Peaker
Calpine said Friday it will begin developing a 425-MW peaking facility at an existing power plant site following the Texas Public Utility Commission’s recent adoption of a framework intended to incent new generation.
The PUC last month agreed on the principles necessary to replace ERCOT’s energy-only market with a performance credit mechanism (PCM). The design rewards generators with credits based on their performance during a determined number of scarcity hours. Those credits must either be bought by load-serving entities, or exchanged between them and generators in a voluntary forward market. (See Texas PUC Submits Reliability Plan to Legislature.)
“The PCM framework adopted last week by the [PUC] sends a strong signal of support for maintaining a reliable grid in [Texas] through market-based mechanisms rather than government mandates,” Calpine tweeted.
The company is a member of Texas Competitive Power Advocates, which promised to build 4.6 GW of additional capacity if the PCM is adopted.
“We are encouraged that the PUC is acting to ensure Texas maintains a reliable power supply through market-based mechanisms rather than government handouts,” Calpine said in a press release. “Regulatory certainty on PCM will be critical as Calpine continues to move this project forward.”
The peaker will be built next to the Freestone Energy Center, a 794-MW combined cycle gas plant between Dallas and Houston. Calpine must secure an air permit from the Texas Commission on Environmental Quality; a spokesman said the project’s front-end development will take 12 to 18 months.
61-MW Gas Plant to Retire
Blue Cube Operations, a wholly owned subsidiary of Dow Chemical (NYSE:DOW), notified ERCOT on Friday that it plans to decommission and retire a gas-fired plant south of Houston on July 4.
The combined cycle steam turbine has a 61-MW summer seasonal net max sustainable rating and a 58-MW minimum rating. The unit was commissioned in 1982 and is paired with a Dow cogeneration facility.
ERCOT normally conducts a reliability-impact analysis before approving a resource’s suspension of operations. It said in a market notice last month that it has not designated any generation facility as necessary to avoid an adverse reliability impact in the planning horizon of more than one year.
ERCOT.com Adds 6-day Forecast
ERCOT on Friday unveiled a new six-day forecast on its supply-and-demand dashboard as part of its continued effort to increase transparency into grid operations. The dashboard displays the system’s current capacity and demand using real-time data from hourly forecasts and other sources.
The forecasts can be found from the Grid and Market Conditions page on ERCOT’s website.
“While the supply and demand forecasts may change, as weather forecasts do, the dashboard provides a general ‘heads-up’ on the trends based on currently known information,” Dan Woodfin, vice president of system operations, said in a release.
If money were the only object, most coal plants providing power to the U.S. grid could be replaced today with regional or local renewable energy made cheaper by tax credits and other funding in the Inflation Reduction Act, according to a new study from industry analysts Energy Innovation.
Based on 2021 costs for operating 210 coal plants across the U.S., the new Coal Cost Crossover 3.0 report found that all but one of those plants “are more expensive to run than replacing their generation capacity with either new solar or wind.”
“It costs more to continue to run coal than it would be to build entirely new wind and solar resources,” said Michelle Solomon, an Energy Innovation policy analyst and lead author on the report.
Many U.S. utilities are already planning to close their remaining coal plants by 2035, the timeline President Biden has set for the U.S. grid to be powered 100% by clean electricity. Energy Innovation’s previous Coal Cost Crossover 2.0 report, issued in May 2021, found that 80% of the 235 plants then in operation were more expensive to run than new solar or wind.
With its more dramatic results, the new report does not push for any accelerated timelines, but “it tells every utility in the country that they need to take a hard look at every single coal plant,” Solomon said. For “every single coal plant, the energy is more expensive than renewables.”
The report also argues for the added benefits of “local” renewables, defined as solar, wind or storage sited within a 30-mile radius of a closed or soon-to-close coal plant. These include the potential jobs and tax revenues for communities as well as the potential for shorter interconnection times.
Both economics and the environment are driving the phaseout of coal in the U.S. In the last decade, the share of U.S. electricity produced by the dirtiest fossil fuel has plummeted from 50% to 21.9%, as coal has been replaced by natural gas and renewables, according to the U.S. Energy Information Administration.
But even at that lower level, coal still accounts for 60% of greenhouse gas emissions from the U.S. electric power sector and 20% of emissions from the nation’s energy consumption overall.
Looking ahead, EIA says, “23% of the 200,568 MW of coal-fired capacity currently operating in the United States has reported plans to retire by the end of 2029.”
Those plants are in 24 states, including several that have not set targets for utilities to provide a specific percentage of their power from renewable or other clean energy sources, EIA says.
Energy Innovation sees the IRA as providing new economic momentum to take more coal offline. Both solar and wind owners can now choose between a 30% investment tax credit, more of a capacity-based incentive, or a performance-based 2.6-cent/kWh production tax credit, providing they pay workers prevailing wage and offer registered apprenticeships.
The law’s bonus incentives for locating new renewable projects close to “energy communities” that have been affected by the closure of coal mines or coal-fired power plants could further cut costs, while driving “up to $589 billion in clean energy investment” in these areas, the report says.
States across the country could see billions of dollars in new investments by replacing coal plants with solar, according to Energy Innovation. | Energy Innovation
Money saved from coal plant closures could also be used to take advantage of the IRA’s energy storage investment tax credit, also 30%, to finance up to 137 GW of four-hour duration storage, which could replace 62% of the coal fleet’s 220 GW of nameplate capacity, the report said.
Still another big plus is that new local solar or wind projects could use existing power lines, cutting interconnection time and costs and reducing the need for new transmission and distribution lines, the report says.
“The combined impacts of energy community, labor and domestic content bonuses reshape solar economics in coal communities,” the report says. “The median cost of new solar in these communities is about $24/MWh with low variance, while the median marginal cost of coal is $36/MWh with higher variance.”
In this context, Solomon said, “variance” means “the coal plant costs vary more than solar costs.”
Stranded Assets and Reliability
But Michelle Bloodworth — president and CEO of America’s Power, a coal industry trade association — called the report “misleading because it does not account for all the costs and challenges associated with replacing the coal fleet with wind and solar.”
Replacing coal with renewables could cost at least $1 trillion and another $300 billion for the new transmission that would be needed, Bloodworth said in an email to RTO Insider. “Just as important, the report fails to consider the value of reliability, fuel diversity, fuel security and high-capacity value of the coal fleet, none of which can be matched by wind or solar.”
Solomon countered that Energy Innovation’s calculation of the cost of renewables, based on computer models developed by the National Renewable Energy Laboratory, does account for the all-in capital investments that will be required. The report also recognizes that the early closure of coal plants can leave utilities with millions in unpaid debt on their balance sheets and embedded in the higher rates their customers may have to pay as a result.
The IRA provides two potential options here, the report says. The law’s Energy Infrastructure Reinvestment program provides low-interest loan guarantees to utilities replacing old energy infrastructure with new projects that “avoid, reduce, utilize, or sequester air pollutants or anthropogenic emissions of greenhouse gases,” according to the Department of Energy.
The program is administered by DOE’s Loan Programs Office which, under Director Jigar Shah, has already set rigorous guidelines for applications. During a recent interview, Shah said the office takes 12 to 18 months to process a typical loan application.
For electric cooperatives, which may be particularly dependent on coal for their electricity supply, the IRA also provides $9.7 billion in loans and grants for the purchase of renewables or other zero-emissions energy systems. The Rural Utilities Service at the Department of Agriculture is administering this program and has recently finished a series of stakeholder roundtables to gather input on its implementation.
Bloodworth’s concerns about reliability are a more complex issue that Energy Innovation acknowledges as a major challenge for utilities and grid operators moving from coal to renewables. Delaware’s 445.5-MW Indian River Generating Station, owned by NRG Energy, is a case in point, the report says. Though it was scheduled to close in June 2022, PJM requested it stay online through 2026 to ensure system reliability while transmission upgrades were made.
The RTO has “an established 90-day process to review generator retirement requests and their potential effects on the transmission system … to be sure reliability is not impacted,” according to Jeffrey Shields, media relations manager for PJM. “This does not have anything to do with what kind of generator it is; it is a matter of how the system will be impacted without the particular generator providing power in a certain area.”
In the case of Indian River, continuing to run the plant “was the only real solution to address immediate reliability needs until a long-term solution is built,” Shields said in an email. “Longer-term replacement generation could certainly include solar, offshore wind or hybrid renewable units paired with storage.”
While the plant is still online, it is run under a reliability-must-run agreement, which means it is run only in situations where system reliability cannot be provided by other sources; for example, in a “capacity emergency when … scheduled reserves are not sufficient,” according to Shields.
Delaware ratepayers are paying an estimated $6.45/month extra on their electric bills, according to the Delaware News Journal, which called the plant “one of the state’s top polluters.”
Energy Innovation also said Indian River was “the eighth most expensive plant we analyzed due to low capacity factor and high estimated fuel costs.”
“Local replacement of this plant [with wind or solar] could assuage reliability concerns by providing generation and capacity needs at the same location on the grid,” the report says. “Our local analysis finds that 246 MW of storage could be funded via savings,” which could provide more than half of the plant’s capacity.
The Takeaway
Making such diversified portfolios of renewables a core element of regular resource planning is one of Energy Innovation’s recommendations for utilities, grid operators and regulators going forward. Both local and “regional” siting is also recommended, as are continuing efforts to improve and streamline interconnection processes.
Specifically, Energy Innovation calls on grid operators to “improve methods to assess reliability and resource adequacy reflecting the reliability value of renewable portfolios and valuing the reliability attributes of a high-renewables grid.”
“PJM has already begun this process,” Shields said. “We have adopted the effective load-carrying capability rating method to better reflect the reliability capacity value of renewables; and we will be making an additional filing at FERC to make sure that capacity matches up with the existing Capacity Interconnection Rights.”
Renewable projects that are able to use a retiring coal plant’s interconnection rights also “may reduce or eliminate the amount of network upgrades required for [a] new interconnection” Shields said. Fewer network upgrades could help to move a project up in the queue under PJM’s new first-ready, first-served approach to interconnection, he said.
The takeaway here, while hopeful, is that long interconnection queues and the need for transmission upgrades and expansion are systemic problems that will continue to slow the transition to clean energy as the IRA’s incentives and regulators’ efforts at change work their way through a risk-averse, reliability-focused industry.
But the Energy Innovation report makes clear, among the many challenges an accelerated phaseout of coal could raise, the increasingly lower cost of renewables, combined with local siting could be critical drivers for finding solutions faster.
Directors, Members Approve Resource Adequacy Revisions
SPP’s Board of Directors and Members Committee last week approved two revision requests related to resource adequacy requirements, ending a last-minute dash to gain stakeholder approval.
The tariff changes, RR536 and RR537, would provide load-responsible entities with a short-term, nonpunitive alternative approach to deficiency payments for the summer resource adequacy requirement (RAR). They breezed through a gauntlet of stakeholder groups the week before and were then approved by the Regional State Committee on Jan. 30. (See SPP MOPC Approves Late Resource Adequacy Revisions.)
Staff have been working on the mitigation strategy since July, when SPP increased the planning reserve margin (PRM) from 12% to 15%, effective this year. That left some members complaining they would not have enough time to meet the requirements. (See SPP Board of Directors Briefs: Dec. 6, 2022.)
“There is no doubt that we’ve had some fairly lively discussions on some probably critically important issues over the last three quarters,” board Chair Larry Altenbaumer said during the Jan. 31 meeting. “I believe that despite some of the concerns that had been raised, we did end up with a balanced and a constructive outcome. I think it does legitimately help us fulfill our overall planning reserve requirement for SPP’s footprint, and because it is limited to a two-year window, it is responsive to the original desires that were laid out by our stakeholders … to their planning.”
Stakeholders modified RR536 to clarify that LREs can make a sufficiency payment only when the PRM is increased within the previous two years and the entity demonstrates it had adequate capacity to meet the PRM before it was changed. A deficiency cannot result from selling accredited capacity to another region after the PRM’s increase is approved.
Under the change, capacity could only be claimed for accreditation by one asset owner in the SPP footprint. Capacity used to resolve deficiencies could not be sold to another region for the applicable RAR season.
The measure includes the Market Monitoring Unit’s sufficiency valuation curve for the market’s capacity. The curve would start at twice the cost of new entry (CONE) at or below the sum of noncoincident peak loads, then slope downward to a net CONE value when regional accreditation reaches the PRM. When the region has sufficient accredited capacity, the net CONE would drop down to zero at 115% of the PRM.
RR537 emerged from the stakeholder process with revised language that removes a tariff violation when LREs fail to make a resource adequacy payment. As modified, LREs would be deemed sufficient for the adequacy requirement with a deficiency payment.
The change was also modified to clarify that only capacity resolving deficiency is obligated to stay in SPP; the obligation would only apply to a specific RAR season; and that a deficiency payment is based on a kilowatt-year.
Staff hope to gain FERC’s approval in time to accredit resources for the summer season (June 1-Aug. 31).
The Advanced Power Alliance’s Steve Gaw abstained from the Members Committee vote on the two measures, warning of unintended consequence from a permanent tariff change. American Electric Power’s Antonio Smyth also abstained but did not explain his decision.
“We accommodated the fact that the [PRM] increase was pretty steep in a fairly short time frame,” said Gaw, who supported the RRs’ approach to the increase. “However, I am very concerned about this going into the tariff as a permanent fix. This is a significant lessening of the consequences of not increasing individual LREs’ accredited capacity under the resource-adequacy obligation when the PRM increases. The tariff language change allows this to kick in on any increase to the PRM in the future without really having a longer look and understanding of all the consequences.”
“The increase was fairly quick. … Steve makes a good point that you’re setting yourself up potentially for some unintended consequences,” Basin Electric Power Cooperative’s Tom Christensen said. “There are some safeguards so that it appears it won’t be abused. If there are some unintended consequences that come about, I think we’ll just need to make sure that we deal with those as they come.”
COO Lanny Nickell agreed. “The language that we have arguably allows this to be used time and time again. My sense is that there is appropriate focus and discipline … to make sure that nothing happens that will abuse what’s provided here,” he said.
The RSC’s members had brought up a similar issue during its discussion the day before. The committee’s president, Kansas Corporation Commissioner Andrew French, resisted an attempt to table RR536 over concerns FERC could reject a previously approved tariff change (RR515) that would allow LREs to qualify for and receive exemptions from deficiency payments.
SPP General Counsel Paul Suskie assured the regulatory group that all three revision requests are designed to stand on their own.
French said 536 and 537 are “acceptable responses to the current situation” but “perhaps another planning reserve margin increase” is necessary if a more “holistic” design is not put in place.
“I would only support [the RRs] as an interim approach. They are not a good long-term resource adequacy construct to support long-term resource planning,” he said.
French joined with the other members in rejecting the motion to table and then in approving RR536. The measure passed 8-3, with Nebraska, North Dakota and South Dakota regulators in opposition.
The RSC passed RR537 9-2, with North Dakota Public Service Commissioner Randy Christmann and South Dakota Public Utilities Commissioner Kristie Fiegen dissenting.
“I get the point of it. [LREs] are making a deficiency payment, but you’re either compliant, or you’re not compliant. You’re either deficient, or you’re not deficient,” Christmann said. “Paying the penalty doesn’t change that. It’s just the penalty that’s associated with being deficient.”
Board Grants CRSP More Time
The directors and members both approved new terms and conditions for RTO West membership that make allowances for Western Area Power Administration’s Colorado River Storage Project (CRSP) to potentially join the market, granting a four-month extension for the acceptance period.
The federal power marketing administration now has until July 1 to accept the new membership terms and conditions. The extension is contingent on CRSP publishing its intent to purse SPP RTO membership in the Federal Register by Feb. 28.
The new terms include crediting CRSP’s point-to-point (PTP) transmission service and a federal service exemption (FSE) of replacement energy to satisfy its statutory load obligations. The Strategic Planning Committee endorsed the recommendation during its January meeting. (See “CRSP Faces Tx Rate Issues,” SPP MOPC Approves Late Resource Adequacy Revisions.)
CRSP was built to move federal hydropower, but low water levels are increasingly risking the utility’s ability to meet its service obligations. In addition, about 88% of CRSP’s transmission obligations sink outside its zone, leaving the remaining 12% exposed to rate increases because of SPP’s treatment of PTP revenues.
Working with eight other Western parties interested in RTO West membership, staff were able to modify the conditions to allow CRSP’s PTP revenue from using its facilities to meet contractual or statutory obligations be distributed back to the agency.
Because SPP’s tariff won’t allow replacement power that CRSP may need to meet its obligations be classified as an FSE, the parties agreed that replacement energy delivered from the utility’s zone be eligible for the exemption. Replacement energy delivered to CRSP’s zone would be subject to tariff provisions and charges.
Director John Cupparo, who led a $6 billion transmission investment program in the West while with Berkshire Hathaway Energy and also served as PacifiCorp’s CIO, said adding Western members and strengthening the seam between the two interconnections is “going to pay huge benefits.”
“I think it’s clear that something’s going to happen in the West for the first time in decades,” he said. “Market development is going to occur in some form, and as those lines get drawn, they don’t typically get redrawn.
“So, I’ve encouraged the [SPC] and this group to keep an open mind and be supportive as we look to advance these initiatives,” Cupparo added.
Sugg Lays out 2023 Goals
CEO Barbara Sugg said resource adequacy and resilience will continue to top SPP’s list of corporate goals for the year, saying that while the RTO will dedicate “significant attention” to completing its strategic plan, “none of it matters if we don’t get resource adequacy right.”
She said clearing the generation interconnection queue is also one of SPP’s top goals. Staff are on track to clear the 2018 and 2019 clusters this year and to work through the 2020 and 2021 clusters next year, Sugg said.
SPP CEO Barbara Sugg kicks off the Board of Directors/Members Committee’s virtual January meeting. | SPP
Other priorities for 2023 include process improvements to the queue and the consolidated planning process; maturing the enterprise risk management program; and making “significant and measurable progress” on the strategic plan’s goals.
“We know that standing still is not a good option for SPP, and it’s only through our collaborative stakeholder process that we will achieve what we’ve set forth in that strategic plan,” Sugg said.
Altenbaumer, Martin to Leave Board
Joshua W. Martin III | SPP
The meeting marked Altenbaumer’s last as the board’s chair. He and Joshua W. Martin III are both leaving the board at the end of the year, taking a combined 38 years of service with them. Martin has served as a director since 2003 and Altenbaumer since 2005.
Vice Chair Susan Certoma, now the board’s most senior member with three years of experience, will succeed Altenbaumer as chair. Liz Moore will become vice chair.
“I want everyone to know that it has been and continues to be a cherished honor to serve on this board,” said Altenbaumer, who took over the chairmanship in 2018. “At the time that I became board chair, I felt that it was appropriate to only do so for about five years. I believe there is value in rotation for an organizational leadership, and I think that this is a good time to make that change.”
“You have brought a lot of collaboration. You listen and you have listened as chair to our variety of different interests. Your patience is incredible,” Gaw told Altenbaumer. “This organization is far better today for your service, especially from how you are able to listen to the concerns of all of those stakeholders and still find a way to bridge the gaps and move things forward.”
The Corporate Governance Committee will begin the process of filling the vacancies during the second quarter before, as Sugg said, “Larry and Josh ride off into the sunset listening to Jimmy Buffett.”
The committee will use the search firm that is already under contract from last year. Sugg said the committee has the “full expectation” of bringing recommendations to annual members meeting in October. (See “Membership Elects 2 New Directors,” SPP Board/Members Committee Briefs: Oct. 25, 2022.)
Moore has announced her intention to serve another three-year term when her current term expires at the end of the year. “I have no doubt that we will be very happy to renominate her,” Sugg said.
The CGC also has two vacancies to fill on the Members Committee and another on the Human Resources Committee, following Sunflower Electric Power CEO Stuart Lowry’s retirement last year. The committee plans to bring nominations for the vacancies to the board’s April meeting.
Consent Agenda Flies
The board consented to approval of the SPP Transmission Expansion Plan (STEP); a sponsored upgrade study of NextEra Energy’s proposal to add a 345/138-kV transformer at Oklahoma Gas & Electric’s Cimarron substation; and two revision requests, all previously approved by the Markets and Operations Policy Committee:
RR505: streamlines the approval of remedial action schemes with more defined criteria and clarifies RASes’ appropriate uses.
RR519: formalizes the SPP operating criteria’s requirement to perform an annual resource real-time availability evaluation and report findings and recommendations to the appropriate stakeholder group.
It also consented to withdrawing notifications to construct for a Sunflower 115-kV capacitor bank and a 69-kV Western Farmers Electric project; removing the suspension of Basin Electric’s Kummer Ridge-Roundup project in North Dakota, comprising a new 33-mile, 345-kV line and substation upgrade; and modifying the NTC’s approval date for NextEra Energy Transmission Southwest’s 345-kV Wolf Creek-Blackberry project in Missouri and Kansas, from Jan. 1 to May 17.
A California judge ruled Wednesday that there was enough evidence to put Pacific Gas and Electric (NYSE:PCG) on trial for four counts of involuntary manslaughter and felony charges of recklessly starting a fire for the September 2020 Zogg Fire in rural Shasta County.
The blaze killed four people, including a mother and her young daughter; burned more than 56,000 acres; and destroyed 204 structures. The California Department of Forestry and Fire Protection (Cal Fire) determined the fire started when a leaning gray pine tree fell onto a PG&E power line.
The Shasta County District Attorney said in its September 2021 criminal complaint that PG&E had failed in its “legal duty to safely operate electrical transmission and distribution lines in a manner that minimizes the risk of catastrophic wildfires” by failing to clear the tree.
The judge dismissed 20 of the original 31 charges, including those related to air pollution from the fire, but the DA’s office indicated it intended to press forward with the remaining counts.
“Following a seven-day preliminary hearing, Pacific Gas and Electric was held to answer today for multiple felony and misdemeanor criminal charges for its role in starting the Zogg Fire,” the prosecutor’s office said in a Facebook post. At its next court date on Feb. 15, PG&E “will be arraigned on the information, and a trial date may be set.”
The company could seek a negotiated settlement, but in a statement last week, it continued to argue it was not criminally liable for the fire.
“We believe PG&E did not commit any crimes,” the utility said, contending that its employees and tree-trimming contractors had exercised “good-faith judgment” in deciding not to cut down the pine tree.
When the charges were filed in September 2021, PG&E CEO Patti Poppe said the utility “accepted Cal Fire’s determination … that a tree contacted our electric line and started the Zogg Fire,” but “two trained arborists walked this line and, independent of one another, determined the tree in question could stay.”
“We trimmed or removed over 5,000 trees on this very circuit alone,” Poppe said at the time.
Another Case of Manslaughter?
The Zogg Fire was the second time that the state’s largest utility has been charged with manslaughter.
PG&E pleaded guilty in June 2020 to 84 counts of involuntary manslaughter and one count of arson in the 2018 Camp Fire, which, along with a spate of fires in 2017, forced the utility into bankruptcy proceedings and led to a multibillion-dollar settlement with fire victims.
In August 2016, jurors convicted PG&E of six felonies stemming from the San Bruno gas pipeline explosion, which killed eight people and destroyed part of a suburban San Francisco neighborhood. PG&E was not charged in the deaths; it was found guilty of obstructing a federal investigation and violating pipeline safety standards.
A federal judge sentenced the utility to five years’ probation starting in January 2017.
In April 2021, Sonoma County prosecutors charged the utility with five felonies and 28 misdemeanors from the October 2019 Kincade Fire, including “recklessly causing a fire with great bodily injury” to firefighters and emitting harmful contaminants, such as wildfire smoke and ash, harming children.
Those charges were dropped after PG&E reached a $31 million settlement with the county and four affected cities.
MISO said last week it will begin discussions next month on inverter-based resource performance requirements as the industry inches toward standardization.
Patrick Dalton, a power studies engineer, said during an Interconnection Process Working Group meeting Tuesday that the RTO has an imperative to get ahead of potential IBR performance issues noted in recent NERC disturbance reports. Dalton told stakeholders that by June, MISO hopes to have detailed performance requirements that can be drafted for the tariff.
“We are seeing this as part of how reliability attributes work,” Dalton said, referencing the grid operator’s ongoing discussion on attracting generation with certain system reliability attributes. Staff have defined six attributes as essential: availability, delivering long-duration energy at a high output, rapid start-up times, voltage stability, ramp-up capability and fuel assurance. (See MISO Considers Resource Attributes as Thermal Output Falls.)
“The level of alarm continues to increase here,” he said, noting that one of two disturbances near Odessa, Texas, caused about 1 GW of solar resources to trip offline in ERCOT. “If there is any silver lining of these NERC reports, it’s that these events can be prevented if we were to implement standardized functions.”
MISO has time to avert issues, Dalton said, because most IBRs have yet to come online. He said the time to act is a “luxury” that other regions don’t have.
The RTO said standard IBR requirements are likely to benefit voltage stability, small-signal stability, voltage control and detection of short-circuit faults.
The discussions coincide with and are inspired by FERC’s notice of proposed rulemaking issued last year to implement IBR reliability standards (RM22-12). The grid operator said it will draw on the Institute of Electrical and Electronics Engineers’ recent standard for the resources’ interconnection and performance (IEEE 2800-2022) to form its requirements.
FERC on Tuesday approved Great River Energy’s request for transmission rate incentives for two MISO Multi-Value Projects (MVPs) it is working on: the Iron Range-Benton County-Cassie’s Crossing project and the Big Stone South-Alexandria-Cassie’s Crossing project (ER23-513).
The incentives for the two transmission projects include construction work in progress (CWIP) for the Iron Range project and the recovery of 100% of prudently incurred costs in the event they are abandoned.
GRE is an electric generation and transmission cooperative in Minnesota that provides wholesale electric service to 28 co-ops there and in Wisconsin. The Iron Range and Big Stone projects are both part of the MVPs that MISO approved in its 2021 Transmission Expansion Plan.
Iron Range involves the construction of a new 150 mile, double-circuit, 345-kV line from Minnesota Power’s existing Iron Range Substation to GRE’s existing Benton County Substation, replacing some existing lines and upgrading substations. GRE owns 52.3% of it, with the rest belonging to Minnesota Power, and its total cost is $969.9 million.
The Big Stone project involves the installation of a new 128-mile, single-circuit, 345-kV line between the Big Stone substation in South Dakota and the Alexandria substation in Minnesota, and a second 345-kV line being added between Alexandria and Monticello substations. The total cost of the project is $573.5 million, but GRE is only responsible for $27.5 million, as multiple firms are building the line.
Both lines should relieve potential reliability issues, while the Iron Range line is expected to help connect renewable power to market as well.
FERC said that because the two projects cleared MISO’s planning process, which evaluated whether they would improve reliability, they are entitled to a rebuttable presumption that they meet commission requirements for incentives. Firms also have to prove that the incentives sought are connected to the investments being made, meaning they address demonstrated risks or challenges the transmission developer faces.
The Iron Range project is the largest transmission dollar investment ever made by GRE, and with multiple permits and owners, it created a more complex negotiating, decision-making and implementation process. Both the capital structure of 50% debt and 50% equity for both lines and the CWIP for Iron Range should ensure GRE can make the needed investments without lowering its credit rating.
FERC agreed that the incentives were tailored to meet the project’s risks, with the CWIP helping GRE avoid higher costs on the project itself and other investments.
GRE also won approval for the abandoned plant incentive to deal with regulatory and siting risks that are outside of its control. FERC found the incentive would protect GRE and its member co-ops if the projects are canceled for reasons beyond its control.
Christie’s Concurrence
Commissioner Mark Christie concurred with his colleagues, saying that while the order complies with FERC’s current transmission incentives policy, those should be revisited. The CWIP incentive effectively makes consumers the bank for transmission development, while the abandoned plant incentive makes them the insurer of last resort, he said.
“Just as consumers receive no interest for the money they effectively loan transmission developers through CWIP, they receive no premiums for the insurance they provide through the abandoned plant incentive if the project is never built,” Christie said.
FERC has a pending proposal to limit the adder for RTO membership to just three years after utilities join, and another one to eliminate the CWIP incentive altogether. Christie also wants the procedures and criteria for the abandoned plant incentive to be reconsidered.
“Revisiting all these incentives is imperative at a time of rapidly rising customer power bills,” Christie said.
New York Gov. Kathy Hochul on Wednesday released a legislative framework for the cap-and-invest program she is proposing to help the state meet its greenhouse gas-reduction goals.
Money gained from auctions of emission allowances would go into a climate action fund, at least 30% of which would be set aside for consumers and up to 3% for industrial small businesses that face increased costs from the program.
The remainder of the fund, minus operating expenses, would be used by the New York State Energy Research and Development Authority (NYSERDA) to help pay for the clean energy transition codified in the state’s Climate Leadership and Community Protection Act (CLCPA).
Hochul indicated that the Department of Environmental Conservation (DEC) would write the program regulations in consultation with NYSERDA. But she needs the State Legislature to amend state Environmental Conservation Law, Public Authorities Law and Finance Law to enable certain aspects of it.
The governor included the measure in the $227 billion executive budget proposal for fiscal year 2024 that she released Wednesday because creating the program would require spending $6.5 million and 10 full-time-equivalent employees.
DEC would prioritize affordability as it designs the program and design it to be able to link with similar programs in other states.
The program would ease clean-energy transition costs for consumers and make New York a better, more livable state.
It would prioritize disadvantaged communities and be designed to ensure proceeds of the allowances are invested in such communities and to avoid disproportionate burdens on them.
At least six regional public hearings would be held on the draft criteria for the program and on the draft list of disadvantaged communities.
Energy-intensive and trade-exposed facilities — those that use a lot of energy and are at competitive risk if that energy costs more in New York than in other states — would receive a no-cost allocation of allowances; DEC would determine what facilities qualify and how to allocate those allowances.
The Scoping Plan flagged the risk of “leakage”: an industrial operation that faces high costs in New York shifting production to states with looser rules. Leakage is doubly bad, the plan’s authors wrote, because not only is that operation still contributing to global warming, it is also economically harming New York by moving payroll and tax payments out of state.
The program would set a cap on greenhouse gas emissions, establish allowances for a percentage of those emissions, and shrink the percentage each year as the state moves to reduce emissions 40% from 1990 levels by 2030 and 85% by 2050.
An agreement signed by California’s three electricity planning entities will help coordinate resource and transmission planning in California to better reach the state’s clean energy goals while maintaining grid reliability, CAISO CEO Elliot Mainzer told the ISO’s Board of Governors on Thursday.
The memorandum of understanding signed by the California Energy Commission, the state Public Utilities Commission’s and CAISO is a “new blueprint for our state” thatprovides for closer links between the planning processes of each party, Mainzer told the board in his monthly CEO briefing.
In California’s divided energy planning process, the CEC forecasts demand while the CPUC handles resource planning and CAISO deals with transmission needs.
“All of those are [gears] that need to be synchronized so that we can effectively onboard resources in California,” Mainzer said.
Outmoded planning was partly to blame for the state’s rolling blackouts in August 2020, CAISO, the CEC and CPUC said in an October 2020 report to the governor. (See CAISO Says Constrained Tx Contributed to Blackouts.)
The recent MOU was signed in December and posted by CAISO to its website Jan. 19. It supersedes a 2010 agreement that included only CAISO and the CPUC.
The MOU draws closer links between the CPUC’s Integrated Resource Planning (IRP) process, the ISO’s transmission planning process, including its conceptual 20-year outlook, the CEC’s Integrated Energy Policy Report (IEPR), which identifies the state’s energy needs and its activities under Senate Bill 100, which requires all retail customers to be served with 100% clean energy by 2045.
The MOU’s provisions include a requirement that the CEC, CPUC and CAISO “implement a joint work plan” on the CEC’s IEPR and SB 100 proceedings to align the three parties’ planning processes and maintain a flow of information between them. For example, under the new MOU the CPUC must incorporate the CEC’s longer-term forecasts into its IRP process, and CAISO has to supply the results of its transmission planning and interconnection studies to the CPUC for resource planning.
CAISO intends to “put that MOU into practice [this year] and … to transition from what I’ve characterized as sort of reactive transmission planning to much more leading and proactive transmission planning,” Mainzer said.
The ISO expects to release its annually updated transmission plan in May and to “identify the forward-looking zones where we think the next big resource batholiths will be opened up,” he said. “Our hope and expectation is that we’re going to be using [our] transmission planning … to do a much more effective job of shaping queuing and procurement … because we simply can’t be in the place of having to react and then we need 5,7, 10 years to get developed.”
“Transmission is a leading indicator of planning rather than a lagging indicator,” Mainzer told the board. “I’m hoping to be here by the end of this next year with a significant improvement in establishing those orders of operations.”
As an example of the need to improve the process, Mainzer cited CAISO’s efforts to deal with its “Cluster 14” queue of interconnection requests, which he detailed in his memo to the board.
“In April 2021, the ISO received 373 interconnection request applications totaling more than 50 gigawatts (GW) of renewable generation and more than 100 GW of energy storage in the Cluster 14 application window,” Mainzer said in the memo. “This was more than three times the average of 113 applications over the last decade, and more than double the previous high of 155. Because of the challenge for the transmission owners and the ISO to process that many applications, the ISO extended the phase 1 study process by a full year.”
At least 160 of the applications are moving to phase 2, and “that number may yet grow to more than 200 projects representing more than 67 GW, since a number of interconnection customers are still in the final validation process.”
The next group of interconnection requests, Cluster 15, could generate 300 new applications by April, putting additional strains on transmission planners, Mainzer wrote.
“The excessive number of applications also provides even more impetus to move forward with overhauling our interconnection process in keeping with the objectives of the recently signed MOU with the CPUC and the CEC to focus on prioritization through alignment of state resource planning, ISO transmission planning, procurement processes, and the interconnection process,” he said.
