Arizona regulators voted to allow UNS Electric to expand its gas-fired Black Mountain Generating Station without a certificate of environmental compatibility — a decision critics said sets a “troubling” precedent.
The Arizona Corporation Commission voted 4-1 on June 11 to grant a “disclaimer of jurisdiction” to the 200-MW expansion. UNS successfully argued that the project’s four natural gas-powered units, each with a nameplate capacity of 50 MW, individually fall under the 100-MW threshold at which a certificate of environmental compatibility is required.
The commission’s vote overturned a decision from the Arizona Power Plant and Transmission Line Siting Committee, which viewed the expansion as a 200-MW project that needed an environmental certificate.
In another decision from the June 11 meeting that’s facing criticism, the commission voted 4-1 to remove the requirement for an independent, third-party review of utilities’ integrated resource plans. The decision came after ACC staff said they couldn’t find a consultant to do the work within budget after issuing two requests for proposals.
The decision applies to IRPs filed in November by Arizona Public Service, Tucson Electric Power and UNS, as well as future integrated resource plans.
1st Time in 50 Years
UNS’ application for the Black Mountain expansion is the first time any company has sought a disclaimer of jurisdiction for a power plant since the state legislature enacted line siting statutes in 1971, according to the Line Siting Committee.
The process for obtaining a certificate of environmental compatibility includes public outreach and hearings before the Line Siting Committee and the ACC.
Western Resource Advocates said the commission’s decision “creates a troubling new precedent for gas and electric utilities seeking to build new generation facilities.”
“This is a disappointing decision that overturns decades of commission practice to essentially exempt most gas plants from commonsense environmental review, depriving Arizonans of a voice in siting these large, polluting industrial facilities,” WRA attorney Emily Doerfler said in a statement.
In a statement after the vote, ACC Executive Director Doug Clark said that “the law as written left the commission no choice but to disclaim jurisdiction.” It’s up to lawmakers to change the wording, he said in a release.
The Black Mountain expansion still must obtain permits from state and local agencies, including the Arizona Department of Environmental Quality, Clark said. And UNS will need a certificate of environmental compatibility for interconnection with related transmission lines.
UNS said an expansion of the Black Mountain Generating Station is needed for reliability in its service territory. The power plant, near Kingman in Mohave County, now has two 61-MW units that started operating in 2007.
The expansion is expected to cost $218 million and to begin operations in 2027.
IRP Review
The requirement for third-party review of utilities’ integrated resource plans came from a commission decision in 2018 aimed at improving the IRP process.
The decision ordered an independent review of scenarios and resource portfolios in each IRP and projected costs and benefits. The review could include the development of alternative scenarios and portfolios that the third-party analyst thinks should be considered.
“Their specialized experience … allows them to provide an unbiased and critical assessment to validate or challenge the assumptions and conclusions presented by the utilities in their IRP filings,” WRA said in a letter to the commission.
Alex Routhier, WRA’s senior policy adviser in Arizona, said the third-party review is even more important because ACC is short-staffed and lacks the expertise to run complex modeling on its own. The third-party analysts are familiar with what’s happening industry-wide and best practices that are in use, he said.
Commissioner Anna Tovar said the requirement for third-party review is needed to counter inaccurate data and modeling the commission receives.
“You’re assuming that all that data and modeling is correct, and you don’t have the skill set to deviate and prove that it’s not,” said Tovar, who cast the lone vote against removing the requirement. “I would say that is my biggest issue in regard to that.”
Commissioners who voted in favor of removing the requirement for third-party analysis said staff still could hire a consultant to review IRPs, but the step no longer would be required.
Commissioner Nick Myers said some stakeholders had been given access to the modeling platform the utilities use and could run their own analysis or hire someone to do so.
And Chair Jim O’Connor noted the commission only “acknowledges” IRPs rather than voting to approve them.
NERC and the regional entities are making “tremendous strides” on the congressionally mandated Interregional Transfer Capability Study and expect to have a draft of the final report ready for stakeholder comment by August, John Moura, the ERO’s director of reliability assessment and system analysis, said this week.
Addressing the quarterly meeting of NERC’s Reliability and Security Technical Committee in Seattle, Moura reminded attendees that the ITCS represents an “unprecedented” effort on the part of the ERO. NERC began work on the study last August, following an order from Congress in the Fiscal Responsibility Act to deliver to FERC a report on the total transfer capability between neighboring regions, additions to transfer capability that could strengthen grid reliability, and recommendations to meet and maintain total transfer capability. (See FERC Approves NERC Transfer Study Funding Request.) The law stipulates that NERC must submit the final report to FERC by December.
The study “is on schedule, and really … lays out important groundwork for our future assessments,” Moura said. Elaborating on this point, he explained that the tight deadline had provided an incentive for the ERO to quickly develop new ways of working together.
“One of the biggest challenges has been integrating diverse systems and ensuring that our assumptions are internally consistent across the planning regions. That’s the one unprecedented thing about this study, and it’s difficult to get that consistency across the different planning coordinators,” he said. “However, it’s also led to a lot of innovations in how we conduct such a large-scale study. … We’ve developed a common modeling approach and [been] working with our stakeholders in new ways.”
To give a sense of the overall size of the effort, Moura explained that for the first part of the study — the overall transfer capability — the team is examining 114 bidirectional transfer points across North America and assessing winter and summer peak cases for 2023 and 2032 applied to each point, equating to 456 individual studies with 30 contingency analysis results.
Moura observed that the requirement to suggest prudent additions to transfer capability also requires NERC to study transfer points that don’t exist yet. One example is a currently theoretical interface between Texas and WECC’s Southwest subregion. The team must determine what kind of transfer such a connection may be capable of, and then assess whether such capability would be “prudent” to add for grid reliability.
The draft report will be released in stages to “allow longer periods of comment and input,” Moura said. “This year’s publications will focus on the U.S., he said, with results relating to interprovincial transfers in Canada to be released in the first quarter of 2025.
“The ITCS [is] more than a study: It’s a road map for the future of our interconnected power system and how the ERO will conduct assessments in the future,” Moura said. “We appreciate the ongoing support and input from all stakeholders as we navigate the complex but crucial task.”
A FERC administrative law judge on June 11 found that Basin Electric Power Cooperative improperly included the costs of a for-profit gasification business in its wholesale electricity rates, admonishing the co-op for its business practices and for apparently not understanding “some fundamental facts about what it means to be subject to independent regulation” (ER20-2441-002, et al.).
In his 905-page initial decision, ALJ Scott Hempling opened with some of the basics of FERC’s regulations under the Federal Power Act. This, he wrote, was because Basin only came under FERC jurisdiction in 2019, after providing wholesale services since 1962.
“This half-century absence of independent regulatory constraint explains the breadth, depth and intensity of the disputes over Basin’s rates for 2020 and 2021,” Hempling wrote. “Perhaps recognizing how remote are Basin’s practices from normal, customer-focused regulatory principles, Basin’s able counsel and witnesses have repeatedly sought refuge in such phrases as ‘the cooperative way,’ ‘the customers are the owners’ and the ‘democratic process.’ …
“But the cooperative movement’s venerable principles, and its honorable history, provide no logical or legal justification for the managerial mistakes, financial errors and discriminatory practices revealed by the record in this proceeding. The cooperative way shouldn’t create divisions among the cooperative’s members. A democratic process doesn’t always produce prudent decisions. And in a democracy, the majority shouldn’t discriminate against a minority.”
‘Thousands of Unnecessary Hours’
Basin is the largest rural electric cooperative in the country, based in North Dakota, and serves 3 million customers and 140 member co-ops in nine states in both the Eastern and Western Interconnections. When it filed its wholesale rates with FERC in 2020, having readmitted the jurisdictional Tri-State Generation and Transmission Association, several of its members and the Sierra Club protested, and the commission initiated an investigation under FPA Section 206. (See FERC to Investigate Basin Electric Rates; Danly Dissents.)
Basin also owns for-profit subsidiary Dakota Gasification Co. (DGC), which produces natural gas from coal and urea that is used for fertilizer, among other products. The company bought the Great Plains Synfuel Plant from the Department of Energy in 1988, which is located next to Basin’s Antelope Valley Station coal generator in North Dakota.
The co-op has set its electricity revenue requirement since 2016 at a level it says is needed to provide the financial health of the entire consolidated corporate family, taking into account all of its businesses’ losses — including DGC’s.
“Because Basin’s consolidated corporate family includes nonutility businesses, most prominently DGC, the annual electricity revenue requirement reflects not only the costs of providing electricity, it also reflects DGC’s financial experience, positive or negative,” Hempling wrote. DGC’s losses added hundreds of millions of dollars to Basin’s electricity revenue requirement, he said.
One of Basin’s members, McKenzie Electric Cooperative, argued that other than the products that it needs to provide power, none of DGC’s costs should be reflected in rates, and it should update its revenue requirements to reflect that.
Hempling not only agreed; he castigated Basin for wasting his and intervenors’ time by ignoring FERC precedent.
“Basin made no change in its pre-jurisdictional practice — the practice of basing rates on its consolidated income statement. Basin thus ignored commission precedent that protects a utility’s jurisdictional customers from the costs and risks of non-jurisdictional affiliates,” he wrote. “Basin also ignored commission precedent prohibiting the collection of amounts for unspecified, merely possible future events.
“Insisting that ‘the cooperative way’ justifies its disregard for commission precedent, Basin has caused intervenors, and this tribunal, thousands of unnecessary hours — hours spent seeking, reading, interpreting and critiquing thousands of internal document — all to do what Basin should have done on its own: Take seriously the rule of law, as Congress enacted it in the Federal Power Act and as this commission has applied it in interpreting that act. Taking seriously the rule of law means presenting a revenue requirement that reflects the cost of electric service and only the cost of electric service.”
Hempling also addressed the prudence of Basin and DGC’s business decisions. Though he ruled that this ultimately did not matter as to Basin’s electricity rates, “McKenzie and Basin have litigated the question of prudence, [so] they and the commission deserve my conclusions on that question.”
The ALJ ruled that Basin failed to assess cheaper alternatives compared to investing in existing coal plants. He outlined numerous flaws in the companies’ decision-making process, from the overlapping structure of their boards to lacking a culture that encouraged internal debate.
“Basin’s board failed Basin’s members — the ultimate consumers — by making them involuntary risk-takers in DGC’s business prospects, he wrote. “Worse, the board did so without any knowledge of, or any concern for, their members’ risk appetites.”
Hempling also found that Basin treats some of its members who had contracts with it through 2050 differently from those who had contracts through 2075, charging the latter more favorable depreciation rates and providing them relief from pancaked transmission rates.
“This dissimilar treatment of similarly situated customers violates the statutory prohibition against undue preference or advantage,” he wrote.
Precedential?
“In the absence of competitive pressure or regulatory oversight, Basin has spent its members’ money on costly and polluting generation resources without ever assessing whether cleaner alternatives would better serve customers’ interests,” Sierra Club Managing Attorney Kristin Henry said in a statement. “Instead, Basin blindly spent tens of millions of dollars on aging coal plants that were already uncompetitive in the energy market. This initial decision makes significant strides forward in holding Basin accountable for its egregious disregard of customers’ interests.”
Initial decisions still have to be voted on by the entire commission before any of its findings actually go into effect. Sierra will continue to participate in the case as it is considered by the full commission, so any final order, or future rate case, provides relief from the imprudent spending, Henry said.
If FERC adopts the initial decision’s findings, it would be precedential in finding cooperatives are not exempt from accountability under the FPA, nor from the general regulatory principle that monopoly utilities must minimize costs, Sierra said.
“This decision sends a clear signal: Instead of doubling down on these expensive and outdated coal plants — without even considering alternatives — Basin should commit to replacing coal plants with readily available, low-cost renewable sources of energy,” said Sierra Club Chief Energy Officer Holly Bender.
The initial decision did not recommend disallowances, or ratepayer refunds, associated with the coal plant spending, but it could be liable for some monetary remedy if Sierra Club can present enough evidence on transmission infrastructure and other alleged deficiencies in future dockets, it said.
Basin said in a statement that it was still evaluating the initial decision.
“But there are a number of findings that are contrary to the positions we made in the case,” the co-op said. “Discussing an active proceeding in front of FERC is a delicate matter, but we will continue to aggressively defend our collective interests in the proceeding as this moves to the full FERC commission. This is one step in a long process, and Basin Electric Power Cooperative remains committed to the cooperative principles and serving our members.”
MINNEAPOLIS — The 2024 Mid-America Regulatory Conference (MARC) June 9-12 showcased a tug-of-war of positivity and cynicism over meeting growing demand with a fleet that should evolve faster to meet clean energy goals.
‘Kitchen Renovations’
“You know how it feels when you’re renovating your kitchen, and you have to live there at the same time? It’s uncomfortable. … And that’s how it’s going to feel in the clean energy transition,” Smart Electric Power Alliance’s Yok Potts said in opening a panel on virtual power plants.
Much like the reward of a new kitchen after the inconvenient remodeling, the grid will emerge modernized and smarter, Potts said.
Illinois Commerce Commissioner Conrad Reddick said it’s challenging to enter a new territory of unpredictable load growth after years of expected patterns.
“The years of, ‘the grid isn’t growing so we don’t need to replace things’ are gone,” he said.
Sen. Tina Smith (D-Minn.) also said the messaging around the clean energy transition has changed in recent years.
“The old story of the energy transition is ‘we have to do this, or we’re all going to die,’” she said. Now, she said it’s “a story of opportunity” that can result in economic booms, good jobs, a cleaner environment and a more equitable supply of energy.
Smith said she will never forget during her time as Minnesota’s lieutenant governor when a teenage climate activist asked, “What are you going to do with your power?” She asked commissioners and regulatory staff to reflect on that question themselves.
The Data Center Question
Minnesota Public Utilities Commissioner Joe Sullivan said load growth from data centers could expedite the move to clean sources of energy. However, he said the rising growth carries risks of moving backward in the clean energy transition, or over-forecasting demand and then overbuilding generation that ratepayers get stuck with.
“Data centers are giving us a lot of bad news and good news,” Minnesota PUC Commissioner Hwikwon Ham said.
Xcel Energy’s Ryan Long said the rise of data centers comes at an opportune time, with Xcel switching off its remaining coal plants. He said he sees an opportunity for data centers to facilitate the “last firm clean energy” sources needed to get utilities to 100% carbon-free electricity.
But Long said utilities should craft contracts carefully so data centers pay a fair rate for energy and so utilities can “spread fixed costs among more sold kilowatt hours.”
Long said in the past, developers behind data centers were more likely to ask for discounts while insisting on 100% clean energy, whereas now they’re more willing to “ride out the rest of our energy journey with us.” He emphasized that utilities should keep commitments to existing customers and environmental goals at the forefront. He said data centers shouldn’t be subsidized by the existing customer base.
Aaron Tinjum, of the Data Center Coalition, said data centers generally are “highly efficient facilities” and his member companies’ “North Star” is clean, reliable electricity that decarbonizes the existing grid.
MISO Executive Director of Resource Adequacy Scott Wright said spot load growth from data centers is new to MISO, whose load growth has been “lackluster” for years.
“We haven’t seen anything like this on the load side in a couple decades, before MISO’s formation,” Wright said.
However, Wright said MISO’s load-serving entities cannot account for some of the growth in their forecasts because the projects are speculative. Wright said MISO likely will introduce probabilistic load forecasting to capture a plausible level of growth.
Wright said MISO has so far accumulated about 10 GW of demand from data center announcements in the footprint, with a new announcement occurring every few weeks. But he said aside from the data centers, the Midwest is entering a manufacturing renaissance.
“This is really an economic development opportunity for the Midcontinent,” Wright said. “A year from now, let’s talk about how we innovated, instead of being at the same place, talking about this tsunami of economic development at MISO’s doorstep.”
Wright said if load growth takes hold like some believe, it makes MISO’s long-range transmission planning (LRTP) even more essential. But he warned that MISO is still waiting for 50 GW of approved and unbuilt generation to emerge. Developers within MISO remain encumbered by supply chain challenges, he warned.
Sullivan said MISO’s switch from a deterministic forecast to probabilistic load forecast gives him pause. He said utilities are naturally incentivized to overbuild and he’s concerned a probabilistic approach could put “a thumb on the scale” toward construction.
Wright said its resource adequacy survey with the Organization of MISO States, due out publicly next week, is returning an uptick in demand.
“We’ve got to know how big this thing could be. We’ve got to scope it out,” Wright said. “The risk of not being prepared is bad for reliability and perhaps a huge, missed opportunity for economic growth.”
Pilot Project Effectiveness
CenterPoint Energy’s Muss Akram said it’s incumbent on utilities and regulators to share the results of pilot projects so others in the industry get a heads-up on which technologies on the cusp are practicable.
“I see the industry moving more and more in that direction, and it’s exciting,” Akram said.
“Everybody wants to pilot, right?” Heimdall Power CEO Jørgen Festervoll said, adding that regulators don’t always need a demonstration via a pilot because some technology has been in use and proven in other parts of the country for years.
Festervoll jokingly said he’s learned not to bring up what Europe is doing on its grid during his presentations. But he said the U.S. grid, which took 120 years to build, is set to see a doubling in demand soon. He said regulators and utilities must develop a willingness to deploy technologies that haven’t been in widespread use on the grid.
“There’s no way we’re going to be able to build ourselves out of this problem,” he said while pitching his company’s sensors that are mounted on power lines and use real-time conditions to flow more power.
“We’re in a phase right now where we’re not synchronizing very well,” said Iowa Utilities Board Commissioner Josh Byrnes. He said utilities are powering down old baseload plants as developers simultaneously “break ground” on data centers that will introduce new load. All this while breakthrough technology seems years away, he said. Complicating matters, the industry is struggling to attract new talent and secure supplies, Byrnes said.
“It’s a problem right now,” he summed up. “The grid is so tight. It makes me nervous. We really need to be squeezing out every electron.”
VPPs
Sparkfund founder Pier LaFarge said though the virtual power plants of today are too unsophisticated and slow to respond to influence utility planning, they will become “core” to generation and system planning in time. Virtual power plants eventually will reach gigawatt-scale with utility management, he said, and urged regulators to make participation free and give underserved customers the first opportunity to join.
“There’s been decades of antagonism between [distributed energy resources] and the utility,” LaFarge said. But he added that tension will dissipate as utilities “take DERs for what they should be” and develop tools and programs.
Midcontinent Considerations for Energy Storage
Clean Grid Alliance Executive Director Beth Soholt said several gigawatts of storage are lined up in MISO’s interconnection queue at a time when the RTO needs to overhaul its studies. She said MISO currently rigidly assumes storage charges at shoulder times and discharges on peak and imposes limits on charging that are in place for the life of the storage asset. Soholt said a “cookie-cutter” approach to every project is obscuring some of the benefits that storage can provide and returning expensive network upgrades.
“It’s a bit of a square peg in a round hole. … We’re focused on getting the model right,” Soholt said. “I just feel we need more storage online so utilities figure out exactly how they want to use it. We need to kick the tires and show exactly what it can do.”
Illinois Commerce Commissioner Stacey Paradis predicted there will be “sticky issues” around RTOs’ interconnection of storage that will need to be figured out in the next few years. She said even though the industry is “crawling toward” storage penetration at present, it will become a game-changer.
Energy Dome’s Eric Watson said any storage company would be happy to turn over extensive data to show they are the “technology of choice” and secure a place in utilities’ integrated resource plans.
Watson said his company uses modular domes to house turbines and compressors to store energy in the form of liquid CO2 under pressure. He said the domes use “off-the-shelf” components that don’t need special design.
“We’re effectively making large fire extinguishers,” Waston explained of the technology’s closed-loop, zero-emissions process.
Watson said the first U.S.-based dome will be at Alliant Energy’s retiring Columbia Energy Center in Wisconsin and will use the plant’s existing interconnection rights with MISO to come online sometime in 2026. He said he hopes the facility can return “good data” to show that Energy Dome technology is viable elsewhere.
Order 1920, Interregional Tx Planning
MARC secured a FERC commissioner to speak on last month’s Order 1920.
Commissioner Allison Clements said the order “is in a lot of ways modeled after what MISO is already doing” and said regulators of MISO states should feel good about that.
FERC even contemplated “not messing up” the planning MISO already engages in when drafting the rule, she said.
Clements said the rule requires players in the planning realm to consider needs years down the road and consider both intensive and lower-cost solutions. She said there’s an opening now to reassess what’s no longer working on the grid and deploy “emerging technologies that are in fact as old as the Walkman.” She said it’s time to innovate in the electricity sector, which historically hasn’t been a hot spot for technological advancements.
“If we can get past that color of molecule or that source of electron, if we all want to be grownups sitting around the table, there’s a lot of progress to be made,” she said.
MISO’s Jennifer Curran said MISO already is largely conducting the long-term, scenario-based transmission planning that Order 1920 prescribes.
However, a panelist from ITC said the same can’t be said of the RTO’s interregional transmission planning.
“There’s interregional coordination going on. Not so much planning,” ITC’s Krista Tanner said. “The current process isn’t producing projects.”
Tanner said planning between the RTOs only seems to work when they step outside their existing processes, like MISO and SPP’s Joint Targeted Interconnection Queue (JTIQ) portfolio of transmission projects. Tanner said MISO and PJM’s recently announced transfer capability study seems promising also because it’s a departure from the RTOs’ usual coordinated system plan studies. (See MISO, PJM Agree to Perform New Type of Joint Transmission Study.)
“Thinking out of the box is key,” Curran said of her experience working on the JTIQ with SPP.
Curran said a study dedicated to MISO and PJM’s seams is timely, with NERC and FERC focusing on transfers between grid operators. PJM’s Sami Abdulsalam said the RTOs have begun scoping the study and are focusing on avoiding complex, greenfield development. Abdulsalam also said PJM “isn’t quite there yet” on undertaking a JTIQ-like study with MISO.
Curran said MISO’s job is easier when the RTOs’ state regulatory committees come forward and articulate which issues they want MISO and its neighbors to address. The Organization of MISO States and the Organization of PJM States wrote a letter to the RTOs at the beginning of the year to call for more extensive joint planning.
Tanner asked RTO planners, regulators and utilities to contrast the costs of backbone, interregional projects with the more destructive outcomes of extreme weather events without the transmission. She said four days like with Winter Storm Uri in early 2021 can inflict as much cost in damages and fuel as the whole of MISO’s first, $10 billion LRTP portfolio.
Cooperation in Permitting
Energy consultant Charles Sutton said landowner fatigue with permitting has grown recently and will continue to increase as MISO’s LRTP projects enter the construction phase.
He said developers can blunt the negativity by awarding construction to local companies to show they support the local economy. Sutton added that developers should anticipate totally different reactions in different communities and that developers should be flexible and not rely on a single playbook to convince communities.
Robert Larsen, president of the Lower Sioux Indian Community, urged regulators to open honest communication at the very beginning stages of development “before things are too late, before things get disturbed.” He said groups should consult with tribal nations during scoping steps, not when they’re ready to begin construction.
“We’ve always said that progress is great, but we cannot have progress that destroys,” Larsen said. He urged utilities, developers and regulators to “do their homework” and research who historically lived in the areas they’ve designated for projects.
Larsen said for instance, wind developers have sited projects near Buffalo Ridge in Southwestern Minnesota, a high point in the geography where the native community comes to pray and fast. The “blinking red lights” of the turbines are a distraction, he said.
But Larsen said he was taken aback and touched when the Minnesota PUC last year voluntarily asked to be included in a state law that requires consultation with tribal nations.
Larsen urged young people in the crowd to remember their relationship with the land. He applauded Minnesota’s 2040 clean energy deadline and called for a restoration of land after “we’ve stripped it, mined it, polluted it.”
“We want to keep everything clean and useful,” he said.
Sen. Smith said utilities and regulators must regard tribal nations as sovereign entities, not special interest groups, with authority that is “inherent instead of bequeathed.”
NextGen Highways’ Randy Satterfield, whose company attempts to bundle infrastructure rights of way along roadways, said initiatives such as “co-locating infrastructure where there’s already infrastructure” is common sense.
Satterfield said Wisconsin for 20 years has allowed stackable rights of way for transmission in highway corridors, but many states ban combination permitting along interstates. Last month, Minnesota Gov. Tim Walz (D) ended the Department of Transportation’s ban on co-location of transmission along highways when he signed an omnibus transportation bill. NextGen Highways led the push for the language in the legislation.
Unions Make Appearance
In a MARC first, the annual conference featured a panel devoted to union labor.
ICC Commissioner Michael Carrigan, himself a member of the International Brotherhood of Electrical Workers Local 146, said it’s going to be an undertaking to recruit a workforce that can grow to meet demand.
Kurt Zimmerman, of the IBEW Local 160, said utilities must stay competitive when negotiating contracts, enough to ensure laborers have good careers. He asked commissioners reviewing projects to make sure the labor is from an indentured program to ensure a “solid, safe, reliable” workforce.
“Who builds projects is not something in the last 20 years that people have necessarily cared about,” said Jason George, of the International Union of Operating Engineers Local 49. “As a commissioner or developer, you should really care who’s building your projects.”
George said high schoolers these days don’t select their career field from a table at a career fair and want to know their work will be meaningful. He said aspiring apprentices now can take high school courses introducing them to engineering and take hands-on trade tours. George also said he’s on the lookout to recruit kids for training who don’t have experience with machinery, as well as the kids who grew up on a farm.
“People come in and change the course of their whole generational history with one job and a union card. It’s life-changing,” George said.
Richard Kolodziejski, of the North Central States Regional Council of Carpenters, said it’s important to seek out union labor so untrained people aren’t building the energy infrastructure of the future.
Kolodziejski said the construction trades culture needs to change to be more welcoming to women and people of color. He also said there should be more attention on the mental health of construction tradespeople, who experience some of the highest rates of suicide by vocation.
At their second in-person meeting of the year, held at Amazon’s headquarters in Seattle, members of NERC’s Standards Committee voted this week to reject a proposal to clarify the cyber systems to be addressed in an ongoing standards development project, while approving a separate standard authorization request involving the same project.
Both the accepted and rejected SAR relate to Project 2021-03 (CIP-002), which is working on five separate SARs involving revisions to CIP-002-5.1a (Cybersecurity — BES cyber system categorization). Committee Chair Todd Bennett of Associated Electric Cooperative acknowledged there are “a lot of things going on with this project,” which NERC staff have designated as one of 11 high-priority standards projects that must be completed by December. (See NERC Expecting Packed 2024 for Standards Actions.)
Introducing the first SAR, NERC Manager of Standards Development Alison Oswald explained that the project team “wanted to [list] the cyber assets that are going to be addressed” through altering one of the SARs attached to the project, “instead of using the umbrella term of ‘cyber assets.’” The assets to be named are electronic access control or monitoring systems, physical access control systems and protected cyber assets.
However, committee members wondered if the proposed changes still were necessary in light of changes in the ERO since the project began. Charlie Cook of Duke Energy observed that “we [in] the industry already have to provide a list of assets” as part of new audit procedures introduced by the regional entities since 2021 and suggested it was redundant to put the same specifications in the standard.
In response to Cook’s question, NERC Manager of Standards Development Latrice Harkness explained the SAR was intended as “a scoping mechanism to define what we are addressing” and to give the drafting team flexibility to discuss the topic if needed.
Cook then asked, “What gap are we trying to close [with this SAR] — is it a reliability gap, or is it simply a gap [that] makes the auditors’ job a little more difficult?”
Harkness replied again that the request was intended to ensure the specific terms would be included in the project’s scope, to which Cook responded that “there really didn’t seem to be a lot of support for this” proposal based on industry comments on the draft SAR.
Cook moved that the committee reject the SAR “for good cause” as provided for in NERC’s Standard Processes Manual, which passed with the required simple majority. The SAR will be sent back to the SDT for Project 2021-03 with a written explanation, which Bennett said he would work on with NERC staff.
The second SAR related to Project 2021-03 passed with no objections from committee members. This proposal was intended to revise CIP-002-5.1a and CIP-014-3 (Physical security) to provide consistency with changes introduced by Project 2015-09, which NERC’s Board of Trustees passed in 2021. (See “Approval and Standards Actions,” NERC Board of Trustees/MRC Briefs: May 13, 2021.) Oswald explained the proposed revisions to the standards were intended only to “clarify the functional entities responsible for” determining and communicating system operating limits.
The last two action items passed by the committee were to solicit nominations for drafting team members. In the first case, NERC staff requested members to supplement the team for Project 2021-01 (Modifications to MOD-025 and PRC-019). NERC Manager of Standards Development Jamie Calderon explained that the team has “a lot of modeling” experts and the ERO would like to “get more protection engineers” on board to address the project’s changing scope.
The second nominations item concerned creating a drafting team to address the Energy Assessments with Energy-constrained Resources in the Planning Time Horizon SAR, which the committee originally approved in 2022. Harkness explained that while the committee named a 15-member team to draft the SAR, that team now feels it would be best to split the work, with a new group tackling the long-term planning aspects of the project and the original team focusing on the near term.
The U.S. Senate on June 12 confirmed two of President Joe Biden’s three nominees, David Rosner and Lindsay See, to FERC and is poised to take a final vote on Judy Chang on June 13.
The votes mean FERC will be back to its full complement of five commissioners when the nominees take office, avoiding the loss of a quorum when Commissioner Allison Clements leaves at the end of the month.
“When it comes to fairly assessing all interests, five heads are better than one,” Energy and Natural Resources Committee Chair Joe Manchin (I-W.Va.) said on the Senate floor. “Bringing together five different people, with five different life experiences and perspectives, helps ensure that all affected interests will be heard and fairly considered and assessed.”
Rosner, a FERC staffer who has been detailed to Manchin’s committee for the last couple of years, was approved 67-27. He fills the seat left open by former Commissioner Richard Glick, who chaired the commission when Biden took office until the end of 2022. His term will end June 30, 2027.
Most of the votes against Rosner came from Republicans, but he also lost support from Sens. Ed Markey (D-Mass.), Bernie Sanders (I-Vt.) and Elizabeth Warren (D-Mass.), with environmental group Friends of the Earth opposing his nomination.
“Lame duck Manchin is being allowed to dictate the future of FERC from beyond his political grave,” said Lukas Ross, deputy director of Friends of the Earth’s climate program, referring to the senator’s decision not to run for re-election. “This dirty deal preserves the status quo by entrenching a pro-fossil gas majority. A paid cheerleader for the LNG boom like David Rosner has no business as a Democratic nominee.”
Before his time at FERC, Rosner worked at the Bipartisan Policy Center, whose energy program director, Sasha Mackler, said he was well qualified for the commission.
“David has a tremendously deep knowledge of U.S. energy policy, as well as a keen appreciation for the complexities of the interactions between consumers, households, businesses, energy providers and other key stakeholders, including state governments,” Mackler said. “It is hard to imagine a more qualified nominee, or one with a higher level of integrity and dedication to public service.”
See, the solicitor general of West Virginia, was approved 83-12. She takes the place of former Commissioner James Danly, who left at the end of last year. Her term ends June 30, 2028.
She received support from every Republican except both of Missouri’s senators, Josh Hawley and Eric Schmitt. Hawley, who voted against all three nominees at the ENR Committee, had criticized her response to his questions about the Grain Belt Express transmission project. (See Senate Energy Committee Advances Biden’s FERC Nominees.)
The Senate also voted to invoke cloture on the nomination of Judy Chang, former undersecretary of energy and climate solutions in the Massachusetts Executive Office of Energy and Environmental Affairs, 63-31, setting up a final vote for the next day. Chang would replace Clements after the latter leaves, and her term would end June 30, 2029.
“While I may not agree with each of the nominees on all the items all the time, all of them are well qualified,” ENR Ranking Member John Barrasso (R-Wyo.) said.
CAISO’s Board of Governors on June 12 unanimously approved the ISO’s Interconnection Process Enhancements proposal, the product of more than a year of stakeholder engagement and rigorous troubleshooting.
Intended to complement — but not replace — CAISO’s FERC Order 2023 compliance filing, the final proposal is designed to streamline the interconnection process in response to the “unprecedented volume” of requests the ISO received last year by reducing the number of projects it will have to study. (See Stakeholders Seek Clarity on CAISO Interconnection Process Plan.)
During the June 12 board meeting, Danielle Osborn Mills, CAISO principal of infrastructure policy development, presented slides showing that Cluster 15 in April 2023 vastly exceeded expectations and the interconnection queue now contains roughly three times the capacity needed to achieve California’s 2045 requirements.
“I cannot overstate the importance of this initiative and the challenges our team and stakeholders faced in developing these transformative changes to our interconnection process,” Neil Millar, CAISO vice president of transmission planning and infrastructure development, said at the meeting.
“The fundamental transformation we are seeking to implement is to shift more meaningful project development and procurement engagement to earlier stages in the interconnection study process,” Millar said. “While these changes will be disruptive and uncomfortable, they are necessary so that the ISO can deliver meaningful study results more quickly and phase out the habit of using the ISO interconnection process to simply screen potential sites.”
Responding to stakeholder feedback, CAISO staff made one key change to the final proposal not included in prior drafts: a requirement for load-serving entities to opt in to the point allocation process and publicly post both contact information for the department or individual responsible for the process and selection criteria for allocating capacity.
The change is intended to “increase the transparency and rigor of the load-serving entity allocation process,” Mills said. The prioritization of LSE interest in the scoring and point allocation process has been a significant area of concern for stakeholders.
Scoring Criteria Concerns
While the proposal received broad support during the board meeting, many stakeholders expressed concern about moving forward with the final proposal.
“One of the biggest concerns is the lack of allocation to the non-load-serving entities,” said Melissa Alfano, senior director of energy markets and counsel at the Solar Energy Industries Association. “There is the ability for the LSEs to withhold some things and strategically push forward less efficient projects.”
Other stakeholders echoed Alfano’s concerns.
“The scoring criteria are rooted in significant potential for a lack of transparency, unjust discrimination against non-LSE developers with viable projects and infringement upon principles of open access,” said Ryan Millard, senior director of West region regulatory and political affairs at NextEra Energy Resources. Other stakeholders “also highlighted instances of LSEs seeking concessions from developers in exchange for early points allocation which demonstrates a clear risk of exploitation.”
He gave an example of a recent instance in which an LSE indicated to NextEra that it issues a request for proposals that includes Cluster 15 projects and would require developers to grant the LSE a right of first offer and submit a $5/kW deposit to secure LSE point allocation.
“To put that into context for you, if you were to apply this to a 300-MW storage project, that’s a $1.5 million deposit that we would need to post 10 years before expected [commercial operation date] just to enter the queue. That’s untenable, even for some of the largest Western developers,” Millard said. “While we appreciate CAISO’s desire not to propose a prescriptive [request for information] process for LSEs, the absence of minimum standards introduces too much potential inequity.”
Mills responded that the setting of standards falls under the jurisdiction of the California Public Utilities Commission and individual local regulatory authorities, not the ISO. Additionally, she emphasized that the ISO would continue to monitor the LSE allocation process after implementation and that the CPUC will exercise oversight over the procurement process, “scrutinizing utility-owned contracts against other contracts” to make sure they were selected fairly and transparently.
“We did not want to do anything that was going to open the floodgates to only utility-owned generation, but at the same time, [we] didn’t want to do anything that was going to discourage or prevent it either,” Mills said.
CAISO CEO Elliot Mainzer also weighed in.
“We all know that any system of rules that you set up, including the existing system, can be subject to untoward behavior,” he said. “We know that there are risks here, and we have taken steps both within our tariff and in direct consultation with the leadership of the state and other local regulatory authorities to make sure that their processes are monitored carefully to make sure that we do not see untoward behavior or manipulation of the rules.”
The ISO said it intends to file the changes with FERC in July and hopes to begin study of Cluster 15 projects in October.
FERC on June 11 approved CAISO tariff revisions that will allow transmission owners to recover transmission revenue shortfalls attributed to transitioning their assets into the ISO’s Extended Day-Ahead Market (EDAM) (ER24-1746).
CAISO’s initial proposal for the “access charge” was the only provision in the EDAM tariff the commission rejected when it approved the market’s design and rules in December. (See CAISO Wins (Nearly) Sweeping FERC Approval for EDAM.)
In the December order, FERC found the ISO failed to justify the reasons behind the three components constituting the access charge, but Commissioner Allison Clements at the time emphasized that the rejection came “without prejudice” and encouraged the ISO to work with its stakeholders and file a revised proposal.
In the revised filing, CAISO explained that while participation in the EDAM will not alter a transmission owner’s (TO) transmission revenue requirement, it could cause the owner to lose out on transmission sales it could’ve made absent that participation, thereby reducing revenues.
“CAISO explains that stakeholders have raised concerns that these changes in transmission owners’ revenues due to transmission owner participation in EDAM may result in unexpected downstream cost shifts for ratepayers,” the commission said in the June 11 order.
The ISO said those cost shifts could be most pronounced upon launch of the EDAM and each time a new entity joins the market.
3 Components
Like the initial proposal for the access charge, the revised plan consists of three components.
Under the first component, TOs may include revenue shortfalls related to the transition from bilateral market transmission service to day-ahead market service. Those shortfalls could stem from EDAM transfers displacing revenues expected from sales of short-duration non-firm and firm point-to-point transmission service.
“CAISO explains that EDAM transmission owners will first calculate their recoverable transmission service revenue based on the annual average of revenues associated with qualifying eligible short-duration transmission products,” the order notes. “The transmission service revenue shortfalls recoverable under the EDAM access charge’s first component will consist of the difference between the actual short-term transmission service revenues recovered and the three-year pre-EDAM average short-term transmission service revenues.”
The second component of the EDAM access charge will permit TOs to recover a portion of the costs not reflected in the three-year “lookback” associated with the first component. This will include revenue shortfalls “from foregone sales of non-firm and short-term firm transmission service over certain new network upgrades and associated with the release of transmission capacity resulting from the expiration of EDAM legacy contracts,” the order noted.
Under this component, a TO’s access charge can include only lost revenues associated with new network upgrades that have been approved by FERC or a local regulatory authority and that function as available transmission in EDAM.
“CAISO explains that eligible new network upgrades are those that increase transfer capability between EDAM BAAs or between the CAISO BAA and an EDAM BAA, are in service and are energized after the EDAM Entity begins participation in the day-ahead market,” the commission wrote. The ISO also clarified that a TO cannot roll all its eligible new network upgrade costs or expiring legacy transmission contract costs into the EDAM access charge, but only an applicable percentage.
The third component of the access charge allows an EDAM TO to recover shortfalls “associated with wheeling through an EDAM BAA or the CAISO BAA in excess of the total net EDAM transfer of the BAA,” with costs based on the transmission used to wheel energy completely through a TO’s system.
“CAISO further states that in periods where this excess occurs, the EDAM Entity, on behalf of the EDAM transmission owner, will be compensated for the transmission use that supports the excess wheeling at the EDAM transmission owner’s non-firm hourly point-to-point transmission rate or the CAISO participating transmission owner will be compensated for excess wheeling through transmission use at the applicable wheeling access charge transmission rate,” the commission said.
‘Effective Indefinitely’
Under the rules, CAISO will calculate an access charge rate for each EDAM entity based on the entity’s gross load.
“CAISO proposes to calculate the rate using the aggregate projected annual transmission revenue shortfalls for each of the three EDAM access charge components of all other EDAM transmission owners, pro-rated to each EDAM BAA by its gross load ratio. As such, CAISO states no EDAM entity will be assessed its own projected recoverable revenue shortfalls,” the order said.
The order notes that while CAISO views the EDAM access charge as a temporary measure, it expects the mechanism to “be a necessity for the foreseeable future” and remain “effective indefinitely” as more participants integrate into the market over time.
Coming little more than a week after NV Energy confirmed its intent to join EDAM over SPP’s Markets+, FERC’s approval of the access charge marks another accomplishment for the CAISO market — and one that could draw additional commitments.
In a March 21 letter to CAISO COO Mark Rothleder signaling its intent to join EDAM, Idaho Power cited the need for a “transmission revenue recovery mechanism” as a key concern the ISO needed to address before the utility could formally commit to the market.
In addition to NV Energy and Idaho Power, the EDAM has won solid commitments from Balancing Authority of Northern California, Los Angeles Department of Water and Power, and Portland General Electric, while PacifiCorp in April became the first entity to fully commit to signing an implementation agreement with the market.
Emily Chen, an analyst with FERC’s Office of Energy Market Regulation, gave a briefing on Orders 1920 and 1977 to members of the NYISO Management Committee on June 11 during a joint meeting with the ISO’s Board of Directors.
Order 1920 requires transmission planners to use a 20-year horizon to identify long-term needs and the facilities to meet them. Long-term planning must occur at least once every five years using at least three plausible scenarios with the best available data and incorporating factors such as retirements, policy goals and corporate commitments.
“We also require that you consider at least seven benefits to evaluate these regional proposals, including production, cost savings, or mitigation of extreme weather and unexpected system conditions,” Chen said.
She noted that the order had been published in the Federal Register just that day, and it will go into effect Aug. 12.
The rule also requires transmission providers to propose a default method of cost allocation to pay for long-term regional facilities and to hold a six-month engagement period before submitting their compliance filings.
Order 1977 updates the process FERC uses when it is called upon to exercise its siting authority to include a Landowner Bill of Rights and a codified Applicant Code of Conduct for applicants to demonstrate good faith effort to engage with landowners in the permitting process. It also directs applicants to develop engagement plans to environmental justice communities and federally recognized tribes. The order was published May 29 and is effective July 29.
Project Prioritization Process
Kevin Pytel, director of product and project management for NYISO, presented the proposed internal project prioritization for 2025 and outlined changes to the process since last year.
“This process is not perfect, we know that, and we try to make it better every year,” Pytel said.
NYISO had 53 proposed market projects this year; of those, eight were continuing projects. They include implementing five-minute transaction scheduling and ancillary service shortage pricing.
The primary changes were to how NYISO handles “continuing” projects, which are those that were approved in a prior year that have progressed to the functional requirements specification, software design, development completion or deployment stages.
Stakeholders had requested that the ISO revise the timeline for stakeholders to decide whether to continue with a project; they now have until June, pushed back from March.
“The hope is that by moving this back three months, we will have a more healthy discussion and be able to come to a resolution quicker on which projects should be considered ‘continuing,’” Pytel said.
The ISO also shifted the stakeholder scoring survey from June to July, which it said will allow it to develop a project set for budgeting purposes by early August.
The Budget and Priorities Working Group will decide on the continuing projects at its meeting June 24; NYISO will also provide its own project scores at the meeting. The survey will be distributed July 3, with a deadline of July 14. The ISO will present the results to the working group July 31.
NYISO’s internally facing enterprise projects that do not involve market rule changes are not subject to stakeholder approval.
Rate Schedule 1 Allocation of the NYISO Budget
Chris Russell, senior manager of customer settlements for NYISO, reminded the committee of an upcoming vote to determine whether a new cost-of-service study should be conducted to evaluate the Rate Schedule 1 allocation between withdrawals and injections.
Rate Schedule 1 is used by the ISO to collect its operating costs from members. The 2024 rate is $1.281/MWh, with 72% from withdrawals and 28% from injections.
The current allocation was set by the committee in July 2011. It was originally scheduled to be effective for January 2012 to December 2016, but in 2016, the committee voted to decline conducting a study and has done so annually every third quarter through 2023.
Russell said market participants have indicated that a study is necessary in the future because of the evolving market. Last year, the committee voted to waive the study by an overwhelming majority of 91.22%. (See NYISO Management Committee Briefs: July 26, 2023.)
The vote will take place at the committee’s July 31 meeting.
SPP’s Board of Directors added its approval June 12 to a proposed tariff revision that establishes a cost-allocation framework for projects in the Joint Targeted Interconnection Queue (JTIQ) with MISO.
The revision request (RR620) addresses chronic transmission issues on the RTO’s seam with MISO related to generator interconnection requests and implements cost-allocation policies already approved by SPP’s state regulators. It also memorializes and defines how the JTIQ process will be implemented and applied once executed.
Combined with earlier endorsements from stakeholders June 7 and state regulators June 10, RR620’s approval ends a process that began nearly four years ago after repeated fruitless attempts to find interregional projects both RTOs could agree on.
SPP CFO David Kelley, who has assumed new responsibilities since the work began, told the board, “This feels like we are near the end of a really long marathon. It’s been a good journey.”
The trek began with a thawing of relations between the two RTOs and their CEOs and, Kelley said, “a challenge to both SPP and MISO staff to go and work out a solution to problems that were shared by both RTOs.”
The grid operators have identified five projects along their seam that can help unlock new generation and resolve congestion issues in the absence of interregional projects.
After being awarded a $464 million grant from the U.S. Department of Energy, the RTOs revised their original direct-billing approach for JTIQ projects to one that assigns 100% of the portfolio’s engineering and construction costs for interconnection requests that meet certain criteria. Those costs are estimated at between $1.6 billion and $1.8 billion before applying the DOE funds. (See MISO, SPP Propose 90-10 Cost Split for JTIQ Projects, DOE Announces $3.46B for Grid Resilience, Improvement Projects.)
“The more complicated piece of this would be associated with the funding and the handling of money from interconnection customers in both RTOs, as well as the transmission owners in both RTOs,” Kelley said. “That’s something that has never been done before, and it took a significant amount of time to figure those things out.”
The Members Committee’s advisory vote passed 17-2, with two abstentions. EDP Renewables and the Advanced Power Alliance (APA) both voted against the measure.
EDP’s David Mindham said that while his independent power producer sector supports transmission buildout and the JTIQ projects, the process itself represents a failure of planning in the two regions. He said a lack of coordinated assumptions and models has led to a “dysfunctional planning system that is broken.”
“Generators want this transmission to be built … and we’re willing to pay for it,” Mindham said. “But in order to do that, the entities paying for this transmission are being asked to compromise on a lot of other issues and a lot of additional things that have bad precedent nationally for us, and we just can’t support that today.”
Kelley reassured Mindham and the APA’s Steve Gaw that the framework’s structure is specific to the projects in the current portfolio and that their objections could be considered for the next round.
“We fully understand that should there be another round of [JTIQ projects], we’re going to have these conversations and justify either something different or something else that is viable going forward,” Kelley said.
The Regional State Committee unanimously approved the tariff revision June 10, and the Markets and Operations Policy Committee endorsed it June 7 with 89% approval.
SPP will coordinate the FERC filing with MISO once its neighbor gains approval of its tariff revision. It will seek board approval of the JTIQ portfolio if the commission accepts the tariff change and updates to its joint operating agreement with MISO.
