MISO said its first crack at long-range transmission planning in the South region likely would take about three years to culminate in potential project recommendations.
Director of Expansion Planning Jeanna Furnish said MISO would form the scope of transmission and build system models over 2026. From there, an assessment of need could continue into 2027, Furnish told the Entergy Regional State Committee Working Group on Oct. 7.
The RTO expects to wrap the study with project recommendations in 2028.
Furnish reiterated MISO’s stance that the first long-range transmission study in MISO South would begin with the Amite South and Downstream of Gypsy load pockets in southeastern Louisiana. She said the study would result in “options that can inform our next steps” and that new generation as well as new transmission would be on the table to solve constraints. (See MISO Kicks off South’s Long-range Tx Plan with More Restrained Approach.)
Given the amount of time, Yvonne Cappel-Vickery, of the Louisiana-based Alliance for Affordable Energy, asked whether MISO would explore other load pockets in MISO South.
Furnish said the study would be limited to Louisiana.
Southern Renewable Energy Association Transmission Director Andy Kowalczyk asked if scoping would be flexible enough to include more of MISO South. The RTO is conducting an assessment to measure reliability risks in the southeastern Louisiana load pockets, along with the West of the Atchafalaya Basin pocket, which extends from southwestern Louisiana into East Texas, and the Western pocket, which is entirely in Texas.
Furnish said MISO hasn’t identified all elements of the study scope yet but said the focus would be the state of Louisiana and would not extend to Texas. It will examine Louisiana’s transfer patterns alongside the state’s “unique weather conditions.”
Windy Beck, of the Deep South Center for Environmental Justice, asked why the study would be limited to a particular geographic area when long-range planning works best at a regional level. She also pointed out the South system mainly comprises Entergy’s assets.
Furnish responded that Louisiana has seen the most load growth and generation retirements when compared to other MISO South states.She promised more to come on the long-range analysis and that her update is merely a “teaser.”
MISO South has accounted for billions of dollars in transmission investment in recent years, mostly classified under reliability needs. In MTEP 23 alone, Louisiana and MISO’s relatively small portion of southeast Texas comprised $3.9 billion of the $9 billion 2023 MISO Transmission Expansion Plan (MTEP).
The South took an almost $2 billion share of the $6.7 billion MTEP 24. For MTEP 25, Louisiana is to receive the most investment of all MISO states, at more than $3.4 billion in reliability projects and projects needed to meet load growth. (See MISO 2025 Tx Expansion Estimate Drops Slightly to $12.4B.) Louisiana contains four of the 10 most expensive projects in MTEP 25. That portfolio is destined for a vote from the MISO Board of Directors in early December.
MISO South states still are weighing whether to propose their own cost allocation under FERC’s Order 1920, which could override the RTO’s current 100% postage stamp-to-load rate used in its long-range planning. (See State Regulators Weigh Drafting Alternative to MISO Tx Cost Allocation.) Southern regulators expect the Organization of MISO States would allow them to form their own agreement to establish a subregional cost allocation for long-range projects.
AUSTIN, Texas — The Gulf Coast Power Association celebrated its 40th anniversary — and the Texas Public Utility Commission’s 50th — during its annual Fall Conference Sept. 30-Oct. 2.
“Two institutions that have fundamentally shaped the Gulf Coast energy landscape,” GCPA Executive Director Barbara Clemenhagen said in welcoming the 860 registered attendees.
The GCPA originally began as the Gulf Coast Cogeneration Association in a new industry birthed by passage of the Public Utility Regulatory Policy Act of 1978. Recognizing that its members’ interests were broader than cogeneration, the organization officially changed its name in 1995 and now boasts 150 corporate members and 350 individual members.
A panel of ERCOT stakeholders kicked things off by agreeing that while the grid operator’s projections of an 80% increase in load by 2030 present a challenge for the market, they are also an opportunity.
“I think we saw the evolution of that perspective throughout the conversation of [Senate Bill 6],” said Data Center Coalition’s Dan Diorio, referencing recently passed Texas legislation that directed the PUC to determine a cost allocation for large loads to ensure they’re paying their fair share of infrastructure expenses. (See Texas Bills Targeting Renewables Come up Short.)
“SB6 started as a challenge … or we can view this is an opportunity. It’s an opportunity for Texas to lead the way,” Diorio said. “There’s a small, little project in Abilene [the massive $500 billion Stargate Project, an artificial intelligence network that includes a 200-MW substation] that got announced that I think is emblematic of that. It’s emblematic of the opportunity for Texas to lead the way in our global competitiveness for digital infrastructure, AI development, all the innovative technologies that we all rely on. So, this is an opportunity for Texas to be that.”
“There’s an opportunity, right? This is a good problem to have, right?” said Casey Kelley, Constellation’s vice president of state government affairs-South. “If you go back five years ago, every market in the country was talking about struggling with low growth. We weren’t seeing this economic boom that’s coming. This is a good thing. We should be looking at this as a chance to build the Texas economy, to build the U.S. economy, to be a leader in artificial intelligence. If we lose the AI race, we lose to countries that probably don’t have the same good intentions that our country [has], so we should look at this for what it is: an opportunity to go out there and try to find ways to seize it.”
Former Texas Commissioner Brandy Marty Marquez, who now runs an eponymous public affairs firm, cautioned against further legislation reacting to the explosion of large loads. Lt. Gov. Dan Patrick said in 2024 that the data center and crypto mining industries produce “very few jobs compared to the incredible demands they place on our grid.”
“We live in a time of scary headlines and knee-jerk reactions and public policy is the last place where we need a knee-jerk reaction,” Marquez said. “The education that’s been done to explain what this AI increase means to the state, what it means to the nation, has been incredibly helpful. It’s incumbent on all of us in this room to make sure that when we’re talking about challenges, there are probably very few people in here who have faced a challenge and not immediately had a few ideas about what the solution is. The market will come up with such innovative answers to questions that are raised that keeping politics out of these conversations can sometimes be the most vital thing that all of us have to grapple with.”
“We see over and over again that, ever since ERCOT was created, the market does figure this stuff out,” Kelley said in agreement. “I believe as long as we keep things within a rational market structure, then we will figure this out and it will be managed.”
Gleeson: We Must Explain Costs
PUC Chair Thomas Gleeson keynoted a pre-conference session Sept. 30 of the commission’s 50th anniversary. In drafting a seven-minute speech for a 45-minute agenda item, he gave himself a “ton of time” to respond to audience questions, “As long as it’s not a question that I do not want to [answer],” he joked.
Asked how Texas regulators can “properly balance” reliability and economic efficiency through markets, Gleeson acknowledged ERCOT participants were comfortable with “operating right on the edge” during tight conditions before Winter Storm Uri dropped the grid to its knees in 2021.
“We heavily focused on affordability, right? We had cheap rates, and it worked really well for a long time,” he said. “People’s relationship with electricity … changed in 2021. There is more tension than there was previously because of that new relationship that Texans have with their electricity delivery. But I do believe that we have to move away from some of the tools we used and some of the policies that we had to implement right after Uri and get back to this being more of an economic market where we provide the incentives, we’re clear about what those incentives are, what our goals are, and then allow private corporations in the industry to respond to those economic incentives.”
Texas Gov. George Bush (left) swears in Pat Wood III to a seat on Texas’ Public Utility Commission in 1999. Family friend Sister Gertrude Levy holds the Bible. | Texas PUC
However, Gleeson said the need for transmission infrastructure, including 765-kV lines, to meet staggering demand growth and the cost of implementing new policies will invariably increase energy prices.
“All of these changes that are happening are going to cost a lot of money, and when a lot of money is involved, people really want to ask a lot of questions, and rightfully so,” he said. “The transmission needs of this state are going to be massive. What we need is the conviction of our decisions. We have to be willing to make those investments, to be honest about what is needed, and educate and inform folks about those costs so they understand the benefit of what they’re getting.”
Balancing Reliability and Costs
The discussion on affordability continued with a panel of four PUC commissioners from the past. Clemenhagen dredged up an old quote from former ERCOT COO Mike Cleary — “Reliability is king and the queen is competition” — and asked Barry Smitherman (2004-2011) how to balance reliability imperatives with the competitive market.
“It’s tricky,” he responded. “We always talk about the three-legged stool. So I can give you reliability, I can give you cheap prices, I can give you clean energy, but you can’t get all three. And over time, one of them has been predominant, but not always predominant. In the beginning of competition, it was about price. We wanted to get the cheapest price.
“Yes, we want them all. We want to balance it, but I think we always need to be cognizant that first and foremost, this market was created to be competitive and pure,” Smitherman added. “Competition should be the North Star of our market design. We want companies banging up against each other to produce power at the cheapest price, and we want [retail electric providers] to be competing against each other for customers, and that’ll translate into cheap prices as well. I understand the focus on reliability, but I think it’s always the case that we should be balancing or rebalancing these three legs of the stool.”
Bob Gee (1991-1997), asked whether ERCOT remains an energy-only market with its ancillary services, heavy use of operating reserves and the $10B Texas Energy Fund to incent more gas generation, responded, “Only nominally.”
He recalled the development of ERCOT’s operating reserve demand curve, a mechanism that rewards traditional capacity and investment in batteries, quick-start thermal units and other new technologies. Gee said he was told by a Ph.D. economist that the ORDC effectively works like a capacity market “because you were asking folks to basically have a plant on standby.”
“You’re giving them [generators] a revenue stream. And then ERCOT has all these other different things that they’re contemplating trying to put into place,” Gee said, referring to yet-to-be-deployed real-time co-optimization and dispatchable reliability reserve service.
“When you layer on all these protections, these band-aids or whatever you want to call it … you become less reliant upon the open and transparent operation of the market to send the price signal,” he said. “I think you’re moving away from an energy-only construct, and more of an administrative oversight regime, which would mask the clear transmission of prices.”
Collaboration Necessary with ERCOT
A pair of longtime ERCOT stakeholders discussed changes they have seen in the ISO’s stakeholder process.
GCPA President Beth Garza, a senior fellow with the R Street Institute, has served as ERCOT’s Independent Market Monitor and currently represents consumers on the ISO’s Technical Advisory Committee. She said as the organization has grown in strength and capabilities, “it has become more of the driving force for change.”
“I compare and contrast that to sort of my day in the stakeholder process, when ERCOT was a group of maybe a couple, 300 people and the first wholesale [deregulation] was driven completely by stakeholders and that was the way that carried us forward,” Garza said. “I think in many ways, a lot of things are sort of before Uri and after Uri. In the aftermath, combined with the sort of growth and development and expansion of expertise and capability of the ERCOT organization, we see that organization being a more powerful and stronger voice for change.
“I’m concerned that may diminish multiple stakeholder perspectives on reaching the good solution, and that’s the concern as I step back into the stakeholder process — that I’m not seeing as much sort of collaboration from a problem-solving perspective. I’m worried about the loss of the multidimensional, problem-solving capability.”
“Today, it is much more of a collaborative effort, and I would give ERCOT kudos for its ability to integrate and make changes to its systems,” said Mark Dreyfus, who represents commercial entities on TAC. “I think the whole market has confidence in ERCOT’s ability to implement these major market changes. But like Beth, I think that policy development has to be collaborative … the policy input from ERCOT has to be balanced with the policy input for this stakeholder community, and I’m worried that today, it’s not quite in balance. I’m working as a stakeholder to work within the process to restore that balance … these issues we face are really challenging. They’re really meaningful for the bottom lines of everybody in here.”
GCPA Award to LCRA’s Holt
The Lower Colorado River Authority’s Blake Holt was presented with the GCPA’s 2025 emPOWERing Young Professionals Award, given annually to an individual under the age of 40 who has demonstrated excellence in the power industry and serves as a role model and leader for others.
A third-generation Texas utility veteran, Holt has more than a decade of experience in the industry. He currently serves as LCRA’s director of ERCOT regulatory policy, overseeing advocacy efforts at ERCOT and the PUC and has spent more than a decade in the industry. Previously, he spent 12 years at ERCOT (2011-2023), working in settlements and leading the Market Designs and Analysis department. He currently represents LCRA on the Technical Advisory Committee and chairs its Wholesale Market Subcommittee.
“Blake exemplifies the kind of leader our industry needs: someone who combines technical acumen with genuine care for developing the next generation of professionals,” Emily Jolly, LCRA’s chief regulatory and compliance officer, said in a statement. “His dedication to mentoring others and his ability to navigate complex regulatory challenges make him a standout choice for this recognition.”
Rising demand and power bills are giving an extra push to expand demand-side management programs like efficiency and virtual power plants, but experts agree the industry needs to do more to educate consumers to take advantage of the resources.
“You have to make sure that you’re not only educating the end-use customer, but you’re educating those that are executing implementing these strategies,” Melissa Washington, Commonwealth Edison senior vice president of customer operations, said during an Oct. 7 webinar hosted by DNV and Canary Media.
Utilities have done a lot of that work already on programs they can market directly to consumers such as efficient lighting and smart thermostats, but the more challenging part is when they have to deal with third parties like contractors, said Andy Frank, president of Sealed, which provides contractors with software and solutions that are aimed at getting more weatherization and electrification programs installed.
“As we move away from the low-hanging fruit of these measures that can be sold directly to consumers, you’re starting to see more and more savings, and more and more impact come from deeper home energy retrofits on weatherization,” Frank said. “And so, regardless of any other information source that they’re getting, homeowners are going to tend to trust the contractor in the home.”
Sometimes consumers will hear about heat pumps from their utility, or a state program, but then a contractor will argue that it does not work and will not save them any money, Frank said. By ensuring that they have access to the right tools to educate and confirm savings, that can be avoided.
Alliance to Save Energy President Paula Glover agreed, calling the lack of education on efficiency among contractors a real gap in rolling out energy efficiency applications.
“Many times, a contractor may not even mention that there’s a more efficient technology. They may not know about it,” Glover said. “And so, I do think it’s time for us to make a significant effort to really make sure that they have all the information that they need about what works, where and how, so that they can best inform customers.”
ComEd has helped its customers save $12 billion with efficiency upgrades, Washington said, and “implementation partners” like contractors are key to getting that done.
“We try to make sure that we’re spending time with our implementation partners to ensure that they have consistent information so that they can have a consistent experience with the customer,” Washington said. “But what we’ve also learned is that there’s opportunities to grow the number of implementation partners in all of these communities, because what we have learned is that people tend to listen to those that they trust.”
The Chicago-area utility has found working with community-based organizations that are trusted in different neighborhoods has helped to get small business and residential customers signed up for energy and money-saving programs because they can spread the word on benefits and how to sign up, she added.
ComEd saw an uptick in interest in such programs during the COVID-19 pandemic as consumers were increasingly interested in ways that they could save money on their utility bills, she noted.
Energy efficiency programs have not been popular on Capitol Hill lately, and ASE’s Glover argued that was partially from lawmakers not looking at it as an “affordability play,” despite her group’s efforts. She argued utilities could help get that message across.
“I’ll use weatherization as an example,” Glover said. “It is very easy to get lots of utility companies in support of LIHEAP [the Low-Income Home Energy Assistance Program]. LIHEAP really rises to the top, but weatherization has been under attack all summer, and we struggle to get people to see that as equally as important and … that absent weatherization, that’s just more people who need LIHEAP.”
Another major issue facing efficiency and the demand side more generally is the regulatory construct, Glover added, because cost-of-service regulation does not favor utilities cutting the amount of electricity that they sell.
Price signals would help to grow efficiency and other demand-side resources more than anything, especially with demand growing in a major way for the first time in decades, Frank said.
“The market needs to have those simple and strong price signals to be able to act,” he added. “And, so, I think it’s all of our responsibility to kind of figure out ways to deliver those price signals.”
The U.S. Senate voted Oct. 7 to approve Laura Swett and David LaCerte to the open seats on FERC, in a package with more than 100 other nominees from around the federal government in a party-line vote of 51-47.
While former Chair Mark Christie was a nominee from President Donald Trump’s first term, the votes give the president nominees on the commission for the first time in his second term. Swett’s term runs until June 30, 2030, while LaCerte was nominated to fill the remainder of former Chair Willie Phillips’ term, which ends on June 30, 2026.
The vote comes less than a month after the nominees cleared the Senate Energy and Natural Resources Committee on a largely party-line vote, after a hearing in which a frequent topic was the future of FERC as an independent agency. (See Swett and LaCerte Nominations Clear Committee on Party Line Votes.)
The issue of whether independent regulatory agencies are constitutional is working its way through the courts, and the Supreme Court has indicated it is likely to overturn their legal precedent. (See Will the Supreme Court End FERC’s Independence?)
The Senate confirmed Swett and LaCerte, along with 105 other nominees, under new rules instituted by the Republican majority this year that allow for a simple majority vote on a batch of picks for sub-Cabinet-level, non-judicial posts. Under the old rules, such nominations could advance as a group by unanimous consent or voice vote, but a single senator could block the motion. It marked the second time the majority used the new rules to confirm a batch of Trump’s nominees after it grew frustrated by Democratic stalling.
Swett and LaCerte still need to be officially sworn in, and it then usually takes some time for new commissioners to set up their offices before they start voting on orders. With the federal government shut down because of a funding impasse, it is unclear how long that will take.
Swett is an energy lawyer at Vinson & Elkins, where she has worked since February 2023. She worked at FERC from 2014 to 2019, first in the Office of Enforcement and then as an adviser to Chair Kevin McIntyre and Commissioner Bernard McNamee.
LaCerte is senior adviser to the director of the Office of Personnel Management. He served in the Marine Corps and as secretary of the Louisiana Department of Veterans Affairs.
Reactions
Groups that do business before the commission were quick to welcome the nominees’ confirmations with statements after the vote.
Electric Power Supply Association CEO Todd Snitchler said the group looked forward to working with the two nominees once they take office, especially on the all-important issues of meeting growing demand and maintaining reliability.
“Long-term investment requires confidence in the rules of the road,” Snitchler said. “That’s why steady federal oversight is critical. Reducing uncertainty and ensuring that competitive auctions are run regularly, fairly and transparently will help unlock the private capital needed to strengthen our grid, support economic growth and meet rising demand from manufacturing, electrification and AI.”
Snitchler added that EPSA welcomes “their commitment to maintaining FERC’s independence, while focusing on reliability, affordability and fair, competitive outcomes,” which is vital to attract investment.
Americans for a Clean Energy Grid also welcomed their confirmation with a statement from Executive Director Christina Hayes.
“As they each recognized in their confirmation hearings, building out our nation’s transmission infrastructure is critical to meeting the energy demand challenges presented by artificial intelligence, data centers and advanced manufacturing,” Hayes said. “FERC serves a vital role in meeting that moment, and we look forward to working with both commissioners to advance common-sense solutions to promote transmission’s role in the American energy dominance agenda through a reliable, affordable and resilient energy grid.”
The Sierra Club struck a different tone, expressing concern that the Senate had approved two nominees that are aligned with Project 2025.
“We are disappointed that the Senate confirmed these new commissioners who have such deep ties to the fossil fuel industry,” Sierra Club Beyond Fossil Fuels Policy Director Mahyar Sorour said in a statement. “We will be watching FERC closely moving forward on behalf of American energy consumers who deserve clean, affordable access to energy.”
New analyses report record growth for the global renewable energy sector in 2025 and project continued expansion through the end of the decade.
Energy think tank Ember reported that solar and wind capacity additions outstripped demand growth in the first half of 2025 and that renewables produced more electricity than coal for the first time.
The International Energy Agency predicted that installed renewable capacity would more than double by 2030 despite supply chain, financing and grid integration headwinds. But IEA lowered its five-year growth forecast for two of the largest markets — the U.S. and China — because of their shifts in policy.
Ember issued its “Global Electricity Mid-Year Insights 2025” report Oct. 7. The U.K.-based think tank, which seeks to accelerate the clean energy transition, said its report is based on monthly electricity data from 88 countries accounting for 93% of global demand.
Global electricity demand grew only 2.6% (369 TWh) in the first half of the year, but solar generation increased 31% (306 TWh) and wind 7.7% (97 TWh).
In total, renewable output grew to 5,072 TWh, or 34.3% of global electricity, while coal decreased fractionally to 4,986 TWh, or 33.1% of the worldwide total.
But first-half results varied, Ember reported, with some countries or regions diverging significantly from the global trend.
Worldwide renewable power generation exceeded coal-fired generation for the first time in the first half of 2025. | Ember
China, the EU, India and the U.S. are home to about 45% of the world’s population but use 63% of its electricity. Fossil fuel generation deceased in China and India but increased in the EU and U.S. China retained its position as the global leader in clean energy growth, accounting for 55 and 82% of new solar and wind capacity, respectively, plus 73% of new nuclear.
The picture was different in the U.S., with solar and wind additions meeting only 65% of the country’s demand increase. This and higher natural gas prices caused a shift toward coal generation, which increased 17% (51 TWh).
“Globally, renewables growth met all the increase in electricity demand,” Ember said. “That certainly wasn’t the case in the U.S.”
IEA is expecting more of this trend in the years to come. “The report’s outlook for global renewable capacity growth is revised downward slightly compared with last year, mainly due to policy changes in the United States and in China,” it said in its Oct. 7 announcement of “Renewables 2025.”
“The early phaseout of federal tax incentives along with other regulatory changes in the United States lowered our growth expectations for renewables in the U.S. market by almost 50% compared with last year’s forecast. China’s shift from fixed tariffs to auctions is impacting project economics, resulting in a reduction in our forecast for renewables’ growth in the Chinese market.”
Beyond the policy changes in the U.S. and Chinese markets, IEA sees other headwinds for much of the world:
Supply chains remain concentrated in China.
Offshore wind delays and cancellations continue.
Major manufacturers of solar and wind components have reported large losses.
The rise of variable renewables has been accompanied in some places by a rise in curtailments and negative prices; demand-side flexibility and dispatchable power plants will be increasingly necessary.
But IEA revised its growth projections upward in some regions because of supportive new policies, faster permitting and proliferation of rooftop solar, particularly in India, Europe and most developing or emerging economies.
With this balance, IEA is projecting 4,600 GW of new renewable capacity to be installed by 2030, 80% of it solar. This would be 2.6 times the capacity in 2022, but it would fall short of the pledge to triple capacity at 2023’s COP28 in the United Arab Emirates. IEA also maps out an accelerated scenario of more supportive polices, under which 2030 capacity would reach 2.8 times 2022 levels.
In its “Renewables 2024” report a year ago, IEA predicted 5,500 GW of new renewable energy by 2030, bringing the worldwide capacity to 2.7 times its 2022 level.
2024 set a record for renewables deployment — 685 GW — and IEA is predicting 2025 will set another record: more than 750 MW under its main scenario, or 840 GW under its accelerated scenario.
FERC approved Tri-State Generation and Transmission’s request to update a program designed to allow its member utilities more flexibility in how they procure power, finding the proposed revisions will help members tackle large new loads from data centers.
Specifically, FERC approved revisions to Tri-State’s Bring Your Own Resource (BYOR) program in an Oct. 6 order (ER25-3109).
The company launched the BYOR program in 2024 to provide members with increased flexibility to build or contract their own energy projects, according to a news release.
The initial BYOR tariff allowed utilities to procure up to 40% of their power from sources other than Tri-State based on the wholesale power supplier’s 2022 system peak period.
However, the company argued in the FERC filing that “relying on a single year historical test period had the potential consequence of relying on low outlier data, because utility member peak demand fluctuates over time; and therefore, using a single historical year test period risks BYOR allocations being set at unfairly low levels.”
Under the new tariff, the amount of power utilities may procure from other sources than Tri-State remains at 40% but is now based on the utility member’s highest monthly Tri-State Peak Period/Member Coincident Peak value over a three-year historical period, rather than Tri-State’s 2022 system peak, according to the order.
“We find that the revised BYOR tariff is just and reasonable and not unduly discriminatory or preferential,” FERC’s order stated. “We agree with Tri-State and its utility members that the proposed revisions to the BYOR tariff will provide Tri-State’s utility members with additional flexibility in procuring power resources for their retail ratepayers and provide them with the benefits the BYOR tariff was originally developed to provide.”
FERC also approved increased flexibility to BYOR funding mechanisms and cost savings associated with DERs as well as other “minor improvements,” according to the order.
The tariff revisions also provide members with energy project development rights related to new large loads — specifically those exceeding 45 MW — being developed in their service territories, “in direct response to the forecasted proliferation of large data center and industrial [high-impact loads] across the country,” according to the order.
“[W]e find that the proposed revisions to expand the BYOR tariff to allow utility members to contract for, or build, their own generation resources to serve specific HILs will help Tri-State’s utility members serve HILs being developed in their service areas, and we agree with Tri-State that tying Tri-State’s obligation to procure power for its utility members from a HIL BYOR project to the operation of the HIL that the HIL BYOR project was designated to serve mitigates risks related to over-procurement of power,” FERC wrote.
The FERC order comes shortly after Tri-State filed an application for approval of a new tariff designed to manage the heavy volume of data center load expected to materialize in its member utilities’ service territories over the next decade. (See Tri-State Seeks FERC Approval for Data Center Load Tariff.)
The Los Angeles Department of Water and Power (LADWP) has agreed to pay a $350,000 penalty to the U.S. Treasury, FERC said in an Oct. 2 filing alleging that the utility withheld information from WECC and provided false information to the regional entity during a 2020 compliance audit (IN25-11).
FERC’s Office of Enforcement and Regulatory Accounting wrote in the filing that LADWP neither admitted to nor denied the accusations but agreed to pay the penalty and other compliance obligations, including submitting annual compliance monitoring reports for at least two years.
The case involved the infringement of NERC’s Rules of Procedure as they stood at the time, specifically sections 401.3 and 403.10. Section 401.3 required utilities to “provide to NERC and the applicable [RE] such information as is necessary to monitor compliance with the reliability standards,” while 403.10 directed registered entities to “submit timely and accurate information when requested by the [RE] or NERC.”
LADWP provides electricity and water services to the city of Los Angeles, with a generation, transmission and distribution system that extends across California, Arizona, New Mexico, Nevada and Oregon. The utility’s generation system has a total nameplate capacity of more than 8 GW.
According to FERC, the alleged violation arose from an incident in October 2018 when LADWP granted a third-party consultant access to some cyber assets for a test, the details of which were not discussed in the commission’s filing. NERC’s reliability standards required that LADWP perform quarterly reviews to ensure only authorized individuals access their cyber systems. However, LADWP’s review for the fourth quarter of 2018 did not include any information about this testing event and consequently never was finalized.
WECC later issued a data request during a routine audit for the utility in 2020 that LADWP failed to satisfy because to do so would require sending the incomplete quarterly review. Instead, LADWP told the RE it could not locate the material and later indicated the quarterly review for that period had never been done at all.
According to the filing, LADWP developed this response with a third-party audit consultant, which warned the utility that “the language … could be perceived as hiding information or not being completely forthcoming with WECC.” FERC wrote that members of LADWP’s management responsible for compliance and risk management knew about the testing event, its omission from the quarterly review and the false responses submitted to WECC’s request.
After an internal investigation, LADWP self-reported this sequence of events to WECC in 2023. FERC noted that during its own subsequent investigation, the utility “fully cooperated with” OERA.
OERA concluded that LADWP violated 401.3 and 403.10 by withholding information from NERC and WECC, emphasizing that this finding did not include any potential violations of NERC’s reliability standards associated with the 2018 testing event or discovered in the 2020 WECC audit.
OERA also called the audit consultant’s role in the violations “problematic,” because it provided the language for the utility’s false response to WECC’s information request and acknowledged that the information was not accurate. The consultant thereby “involved itself in the submission of false, inaccurate and misleading information … and the concealment of relevant information,” behavior that “was inconsistent with the obligation of third-party consulting firms to advise … only truthful, accurate and complete responses.”
Monitoring Report Required
In addition to the financial penalty, which is to be paid within 10 days of the effective date of the agreement, LADWP also agreed to submit an annual compliance monitoring report to OERA for at least the next two years. The first report is to be filed no later than 60 days after one year following the effective date, with the second to be filed a year after the first. OERA may determine that a third report is needed based on the first two.
Each report must include:
Any known violations subject to FERC’s jurisdiction during the prior year, along with any mitigation actions taken.
Any compliance measures and procedures instituted or modified by LADWP related to its participation in FERC-jurisdictional markets.
All commission-related compliance training administered by LADWP during the prior year.
Additional mitigation and compliance measures performed with WECC related to any standard violations implicated by the 2018 testing event and the 2020 WECC audit.
LADWP also must submit an affidavit with each report, executed by an officer of the utility, that states the report is true and accurate.
In a statement to ERO Insider, LADWP staff said they have “worked proactively with FERC, NERC and WECC to resolve any non-compliances associated with the responses” to the 2020 WECC audit. They noted the utility appointed Joanne Martin as chief risk and compliance officer this year “to lead and strengthen [LADWP’s] regulatory compliance procedures and practice.”
“LADWP leadership and the board have, at all intervals, encouraged complete cooperation with federal investigators and have worked to improve compliance functions,” staff said. “LADWP takes seriously its ongoing compliance obligations to FERC, NERC [and] WECC and will continue to work to demonstrate its commitment to compliance moving forward.”
Eight businesses and advocacy groups are suing EPA, seeking to reverse its termination of Solar for All.
The program was an effort to expand lower-income Americans’ access to small-scale solar power generation; $7 billion was allocated to 60 recipients in 2024.
Administrator Lee Zeldin announced Aug. 7 that EPA no longer would implement Solar for All, saying it was part of the $27 billion Greenhouse Gas Reduction Fund (GGRF), the allocation for which was rescinded July 4 as part of the One Big Beautiful Bill Act.
The plaintiffs counter in their complaint that Congress did not repeal the Solar for All program retroactively and that it rescinded only the unobligated balances of the GGRF; the $7 billion for Solar for All was obligated, they state, and the termination violated the law in multiple ways.
The complaint, filed Oct. 6 in U.S. District Court in Rhode Island (1:25-cv-00510), asks the court to find that EPA’s action was illegal and to reinstate the program.
The Southern Environmental Law Center is among the organizations bringing the litigation to federal court. Senior attorney Nick Torrey framed the case as a matter of economic justice: “Families all over the country were counting on energy bill relief that disappeared overnight when the administration unlawfully terminated Solar for All. This popular program was poised to bring more solar to our communities; provide jobs for the small businesses installing those projects; and help families get cheap, clean power.”
As he said EPA would stop implementing Solar for All, Zeldin invoked the metaphor of the Biden administration throwing gold bars off the Titanic. The GGRF was wasteful and rife with documented instances of self-dealing, conflicts of interest, unqualified recipients and reduced oversight, Zeldin charged, while Solar for All entailed dilution of grant money due to the multiple pass-through layers.
The Clean Energy States Alliance said in a news release that EPA itself previously estimated that 900,000 households would benefit from the program; CESA’s own analysis placed participants’ utility bill savings at up to 70% for 20 years.
“This lawsuit is a welcome step,” said CESA Deputy Director Vero Bourg-Meyer. “We hope that EPA reverses course so that Solar for All grantees can all return to work, delivering savings to American households.”
The complaint names EPA and Zeldin as defendants. The eight plaintiffs are potential beneficiaries of Solar for All; they include a labor organization, a homeowner, nonprofits focused on energy affordability, and solar consultants and installers.
All the plaintiff organizations claim significant harm from cancellation of Solar for All.Two are based in Rhode Island.
The complaint states that EPA based its termination of Solar for All solely on Section 60002 of the One Big Beautiful Bill Act, which reads: “This section repeals and rescinds unobligated funds for the Greenhouse Gas Reduction Fund, which provides financial and technical assistance to states and other eligible recipients to help enable low-income and disadvantaged communities carry out activities to reduce greenhouse gas emissions.”
The complaint states that this wording is not ambiguous, does not apply retroactively and does not extinguish prior liabilities. It states that the vast majority of funding was fully obligated by Sept. 30, 2024, the statutory deadline set in the Inflation Reduction Act of 2022, under which Solar for All was created.
TORONTO — The Ontario government’s efforts to align IESO and the Ontario Energy Board to make the province an energy “superpower” were the dominant theme at the 2025 Ontario Energy Conference on Sept. 29.
Premier Doug Ford, the first speaker at the conference, received a standing ovation after laying out his plan for using the province’s energy sector to “build the strongest economy in the G7.”
Ford’s ambitions were spelled out in the Ministry of Energy and Mines’ Integrated Energy Plan (IEP) in June, which called for expanding nuclear power and natural gas and making economic development a core mission of both IESO and the OEB. (See Ontario Integrated Energy Plan Boosts Gas, Nukes.)
The conference, sponsored by the Ontario Energy Association and the Association of Power Producers of Ontario (APPrO), attracted more than 450 attendees to the Marriott Downtown at CF Toronto Eaton Centre.
Outside the hotel, members of the Ontario Clean Air Alliance protested the government’s support for gas-fired generation, calling for the province to instead triple wind and solar generation. They were joined by members of the Toronto East Residents for Renewable Energy, who rallied against a proposal to expand Ontario Power Generation’s Portlands Gas Plant by 50 MW from its current 550 MW. They said the plant should be shuttered by 2030.
Inside the hotel, however, there was no overt opposition to the government’s plan, although some speakers acknowledged the likelihood of rate increases and warned of the risks of building new nuclear generation.
IESO CEO Lesley Gallinger referred to the ministry’s “bold and pragmatic vision.”
“Economic growth, supporting population growth, supporting sovereignty and supporting First Nations reconciliation. I mean, this is a grand slam home run if we do this right,” enthused Harry Taylor, CFO and interim CEO for Hydro One.
In addition to a “relatively well-managed” transmission system and successful generation procurements, “for the first time in decades, we have also a vision,” said Robert Reinmuller, Hydro One’s vice president for transmission system planning and large accounts.
A.J. Goulding, president of London Economics International (LEI), gave the strongest critique of the IEP in his keynote address, raising questions about bullish load forecasts, the nuclear investment and the risk of policies being reversed after a change in government. (See related story, Goulding Hasn’t Drunk the ‘Energy Dominance’ Kool-Aid.)
Province and Federal Government Aligned on Nuclear Expansion
Ford called for making Ontario “more competitive, more resilient and more self-reliant” to “build the strongest economy in the G7.” Central to that vision, Ford said, was its “massive potential as an energy superpower.”
The IEP developed by Energy Minister Stephen Lecce calls for the construction of four small modular reactors totaling 1,200 MW and the addition of up to 4,800 MW of nuclear capacity at the Bruce Nuclear Generating Station.
“I love the guy,” Ford said of Lecce. “I talk to him every single day, four or five times.”
Ford, a member of the Progressive Conservative Party, praised Liberal Party Prime Minister Mark Carney, who identified four SMRs planned at Ontario’s Darlington nuclear power plant as one of the “nation-building” projects he said are needed to bolster the country’s economy in response to U.S. President Donald Trump’s escalating tariffs. (See Ontario Environmentalists Slam New Nuclear Units.)
“He’s all in on large-scale nuclear [and] on the SMRs,” Ford said. “He understands it. He gets it.”
That comity was apparent later in a panel discussion featuring André Bernier, director general of Natural Resources Canada, the federal government agency responsible for energy and minerals, and Sam Oosterhoff, the province’s associate minister of energy-intensive industries.
“I think we might be in danger, minister, of finishing each other’s sentences,” Bernier told Oosterhoff.
Later, in a keynote speech at the conference’s evening gala, Lecce noted that though the provincial and federal governments are headed by different political parties, “we are on the same team in this moment. We’re fighting for a similar cause. We have to stand up for our country, safeguard our workers against [the] great level of risk from the U.S., in China and Iraq.
“I like what I hear from the feds … moving with speed … nation building, regulatory reform, ending duplication [of environmental reviews, things] so important to the province’s and the country’s economy. But we now need them to do those things. We need an impact assessment law that does not take five years to assess projects [that] in the European Union can be done in 12 or 18 months. We need the feds to end duplication on critical projects.”
Lecce also called for federal support to help meet the “massive, massive financial challenge” for needed infrastructure.
“We need a commitment on investment tax credits and the clean energy credits. … All of this [is] really important if we want to provide stability to the sector, which is why we’ve asked for a 50% commitment for the feds to help us derisk those investments and … protect ratepayers.”
Ontario Energy Minister Stephen Lecce (left) and Carla Nell, IESO’s executive VP of corporate relations, engagement and strategy (right), with IESO colleagues Saiyma Monnan and Jamie Jang. | Minister Stephen Lecce
Lecce called it a “moment of pride” that Canada will build the first grid-scale SMR in the Group of Seven, “before the Brits or the French or the Japanese or the Americans.”
“We need to get into the business of net new [nuclear],” Lecce said. “We can’t just refurbish. We can’t tweak. I think that incrementalism is really of the past. … There is no path to decarbonization; there’s no path to economic growth; there’s no path to … a domestic policy of jobs if we don’t invest in new nuclear, embracing Canadian technology.”
Numerous speakers cited the importance of distributed energy resources and demand response in helping meet a projected 75% increase in electricity demand by 2050.
Sheikh Nahyaan, executive vice president and chief operating officer for Toronto Hydro, said his company is “using non-wires solutions in a really meaningful way.” It is seeking to acquire about 30 MW this year.
“We’re trying to forecast what’s going to happen in 10 or 15 years,” said Philippe Dunsky, president of Dunsky Energy + Climate Advisors. “DERs are really a risk mitigator — in addition to a cost reducer — for that uncertainty.”
Market Design’s ‘Stress Test’
IESO’s Gallinger said summer 2025 was a “stress test” for the grid operator’s new market design, which launched May 1.
“It was a remarkable season for our system,” Gallinger said. After a 2024 summer peak of 23,852 MW, multiple heat waves pushed the region past the 2024 peak seven times in 2025.
The summer “put in sharp focus the value and the strengths of Ontario’s diverse supply mix, using our all-of-the-above approach to keep the system reliable, including new resources like the [250-MW/1,000-MWh] Oneida Energy Storage project that came online in May,” Gallinger said. “We also saw important contributions from demand response. Peak Perks adjusted more than 270,000 thermostats to achieve an average load reduction of more than 200 MW in what has become the largest virtual power plant built in Canada.
“Commercial and industrial customers also provided significant reductions through the Industrial Conservation Initiative and the capacity auction. In total, consumers lowered demand by up to 7% over the peak periods.”
Delivering on Promises, Controlling Costs of Transition
Numerous speakers talked about the challenge of winning public support for infrastructure investments that will be needed to meet growing demand.
“Don’t kid ourselves about how much money this buildout — of essentially doubling the size of our electricity system — [will cost],” Oosterhoff said. “It’s hundreds and hundreds of billions of dollars. You know, last year, I think the number I saw for generation and for transmission was $400 billion. I’m sure by now it’s higher. … That is a lot of money that people, ratepayers [and] taxpayers will have to pay.”
But, he added, not building to meet need “is going to cost more than action. And the economic costs of not having that capacity for the next Volkswagen plant or the next LG plant, or the next tech company … is something that we have to be very upfront with people about.”
Hydro One’s Taylor said utilities will have to execute “almost flawlessly.” He said First Nations partnerships would be essential to building transmission across tribal lands.
And he said innovation is essential. “If we are still doing building … the way we did 10 years ago, even five years ago, we’re taking too long [and] it’s costing too much,” he said. “We’ve got to find a way to bring innovation to everything that we do so that we can tighten time frames and reduce capital expenditures.”
Customers and policymakers are not the only ones who will be watching how utilities deliver, he said, noting that some of his company’s largest investors are from Australia, Asia and Europe. “How do we compete across the globe for scarce capital?” he asked.
Hydro One’s Reinmuller called for more certainty for investors’ cost recovery and quicker decision-making.
“A lot of the things that [will be proposed from IESO’s] bulk regional planning this year, we probably knew some of the answers two, three years ago,” he said.
Natural Resources Canada’s Bernier acknowledged that “when I think of the discipline of getting projects approved and built, getting through regulatory barriers … our recent track record is maybe not all the way we want it to be.” He praised the nuclear refurbishments in Ontario, saying they “have done a great job [keeping the] projects on budget.”
Moderating a panel on “Coordinated Integrated Planning for Growth,” Dunsky asked whether a drive for increased coordination and agreement on common assumptions could concentrate risk. “In other words, if we’re wrong, we’re all working together, right?
“We are talk[ing] about launching a very complicated, exhaustive, coordinated process involving essentially the entire village,” he continued. “How do we avoid this process becoming a kumbaya that slows us down instead of an alignment that speeds us up?”
Toronto Hydro’s Nahyaan said having multiple parties at the table creates transparency and ensures multiple perspectives.
“It reduces the risk of being wrong, because you’re now having multiple parties and interested groups … keeping you on your toes in terms of making sure that you are remaining agile.”
LEI’s Goulding weighed in on the question in his keynote speech. “Focused, time-limited consultation will lead to better plans,” he said. “Risk management requires process. The worst mistakes I have made in my career have come from failure to consult and be deliberate, exacerbated by a belief in my own invincibility.”
Municipalities Warming to Energy Development
Spencer Sandor, senior adviser for the Association of Municipalities of Ontario (AMO), said his organization is helping its members evaluate potential energy projects’ impacts and benefits.
“The average municipality has only six full-time employees, so that would be a clerk, a treasurer an administrative staff, and probably three guys driving the snowplow or a road grader, depending on what season it is,” he said.
Over the past two years, AMO, IESO, the province and organizations including the Ontario Energy Association have helped municipalities develop resources, such as a procurement tool kit, a guide “to help both municipalities and developers understand how to talk the same language to each other,” he said.
At AMO’s annual conference in August, Sandor said, representatives from multiple municipalities approached the IESO booth “saying, ‘How do I get one of these projects?’”
Sandor said municipalities are looking for impartial sources of information to address their concerns. “If, say, it’s a battery storage project, they are inevitably going to say, ‘Is this thing going to catch fire?’
“There’s kind of two responses to that question. One is, ‘Don’t worry, it won’t catch fire, trust me.’ And the other one is … ‘You’re right, they have caught fire in the past. The technology has evolved. … Here are several resources from the Fire Chiefs Association, from the Energy Storage Association, from Hydro One, that talk about how the technology has improved, and more importantly, what we can do as a fire service to respond to that.’
“I’ll give you one guess which one of those answers is more likely to get a municipal support resolution.”
During IESO’s first long-term solicitation, “the story that was being told [was that] these municipalities are saying ‘no,’” Sandor said.
“Coming out of that process, IESO was still able to get contracts for more capacity than they targeted,” he said. “Now that municipalities do have more expertise, the dialogs are a lot more constructive.”
Gas not Going Away
Minister Lecce cited the province’s Natural Gas Policy Statement, calling it “the ultimate insurance program” for the power sector.
Lecce said the Ontario grid will reach a target of 99% non-emitting generation by 2050, largely through more hydro and nuclear power.
“Renewables will play a critical role in this space. … But we’re not going to … negate the role of having [gas] on the option lists. That is just ideological insanity, and that’s the type of policy, frankly, that led to Ontario having the highest energy cost on the continent.”
A year or two ago, “the world’s messaging was, ‘We’re getting out of fossil fuels,’” said Brian Johnson, general manager and senior vice president of Enbridge.
On the coldest day this year, he said, the gas system produced 4.9 times the energy of all other sources combined. “So, I think we’re getting, hopefully, back to some practicality.”
Elexicon at the ‘Tip of the Spear’
Amanda Klein, CEO of electric distribution company Elexicon Energy, said customer demand growth in the Greater Toronto Area East is “nothing short of bananas,” with a projected customer increase of nearly 20%.
“That’s a whole SkyDome full of new customers for a utility that fills about five SkyDomes today,” she said, referring to the Toronto Blue Jays’ stadium (now called the Rogers Centre).
While other utilities are projecting peak demand by 2060, “we’re going to have most of that happening in the next decade, rather than the next 25 years,” she said.
“So what I see at Elexicon is that we’re going to be, for the industry, really the tip of the spear in terms of population and economic growth in Ontario that we’re seeing.
“We’ve got a capital program that’s doubled in recent years. It’s about to double again.”
The Minnesota Public Utilities Commission approved the $6.2 billion sale of Allete to BlackRock’s Global Infrastructure Partners and the Canada Pension Plan Investment Board in a unanimous decision Oct. 3.
All five commissioners agreed that the transaction, which would make Allete a private company, is in the public interest (E-015/PA-24-198). Allete — which owns Minnesota Power; Allete Clean Energy; and Superior Water, Light and Power — said in 2024 that the buyout is necessary to fund the fleet transition necessary to hit clean energy targets. (See Canada Pension Board, Global Infrastructure Partners to Buy Allete.)
The Minnesota PUC will issue a written order later in 2025. It gave Minnesota Power until Jan. 15, 2026, to file an alternative resource plan that reflects its new owners’ commitments.
During deliberations at the commission’s Oct. 3 meeting, Assistant Attorney General Richard Dornfeld said provisions to the deal negotiated in summer allowed it to cross the threshold of the public interest.
GIP and CPPIB agreed to several settlement provisions, including $50 million in rate credits for customers; another $50 million in clean energy funding for future resources that cannot be recovered in rates; $10 million in home efficiency improvements for low-income customers; up to $3.5 million in residential customer arrearage forgiveness; a reduction in return on equity from 9.78% to 9.65%, with a future cap of 9.78% through Dec. 31, 2030; a pledge to maintain local employment levels and seek local staffing on future projects; an agreement to participate in audits conducted by the Minnesota Department of Commerce; and penalties for noncompliance with commitments.
Additionally, GIP and CPPIB have guaranteed Allete will have access to capital to fund its five-year transmission and renewable energy plans. Allete is set to retain its Duluth, Minn., headquarters and be governed by a majority independent board of directors, with multiple seats reserved for residents of Minnesota and Wisconsin.
Minnesota regulators addressed Minnesota Power’s new ties to BlackRock before their vote. BlackRock, the world’s largest asset manager at more than $12 trillion in accounts, acquired GIP in a $12.5 billion deal in 2024. Consumer advocacy groups are apprehensive that GIP, motivated by profit, would raise rates.
The sale is the latest in a trend of private equity snapping up public utilities. GIP is reportedly exploring the purchase of AES. Blackstone Infrastructure, on the other hand, announced intentions to close on TXNM Energy, the parent of the Public Service Co. of New Mexico and Texas-New Mexico Power, for $11.5 billion.
Commissioners Tell Firms to Build Trust
All five commissioners said they had reservations about the sale but were assuaged by the firms’ additional promises.
Vice Chair Joseph Sullivan said that while he didn’t know what would happen in the long term, the near- and medium-term benefits of the transaction are undeniable over Minnesota Power’s status quo. He said the sale likely would “take a very significant bite” out of the utility’s next rate case.
Sullivan advised Minnesota Power and its new owners to build credibility with its ratepayers and those who opposed the sale.
“If you don’t build that credibility, that will redound unfavorably to everybody, including this commission,” Sullivan said. “My hope is you take that seriously. … In the world right now, in this country, there’s a significant amount of uncertainty and concern, and I think for a lot of people in northern Minnesota right now, a lot of people in the state, they’re probably saying, ‘Well, just another crappy thing that’s happened today.’”
Sullivan told GIP and CPPIB to leverage the current doubt surrounding the sale, calling “trust the currency of the realm.”
Commissioner Audrey Partridge said she was pessimistic about the motivations of private equity and examined the deal assuming “the absolute worst” of GIP and CPPIB. Partridge said in every scenario she tested, she could not see a way that the investors would simultaneously profit while harming the utility and its customers.
“I cannot remark on the character of these investors before us, but I was unable to maintain my cynicism as I went through the exercise of applying these commitments to all of the possible scenarios raised in the docket of how they might take advantage of customers and our communities,” Partridge said.
PUC Chair Katie Sieben said Minnesota Power needs “massive investment,” not only because of the state’s 100% carbon-free energy mandate by 2040, but because many resources in the utility’s fleet are aging out and need investment.
The Citizens Utility Board of Minnesota said in a statement following the decision that it continued to agree with an administrative law judge who reviewed evidence in docket in July and concluded that risks of an earlier version of the deal “outweigh the possible benefits.”
“Though we disagree with the commission’s decision, we genuinely hope they are correct in their assessment. We also appreciate the commission’s efforts to impose conditions that help mitigate risk of harm to ratepayers,” CUB said. Regardless of Minnesota Power’s owners, the organization would continue to advocate for ratepayers, it said.
The Sierra Club predicted the sale would “pad private equity investors’ pockets.”
“BlackRock and predatory private equity firms have long proven that their mission will always be to relentlessly pursue profit, no matter the harm it causes to communities,” said Jenna Yeakle, with the Sierra Club’s Beyond Coal campaign.
Before the approval, Minnesota environmentalist advocacy group CURE had said, “Short-term and illusory commitments do not mitigate taking this utility into the shadows of private equity management and cannot fully remedy the harms to transparency, reliability, affordability and public confidence that will flow from an approval of this deal.”
‘Valuable’ Pushback
Commissioner Hwikwon Ham said overall, the PUC had to balance Allete’s continued risk exposure to the financial market and its industrial customers’ susceptibility to business cycles against the potential risk of partners’ misbehavior. He said GIP and the CPPIB offered a higher probability of providing Minnesota Power with more stable equity.
Ham urged all the opposing parties in the docket to stay vigilant and participate in Minnesota Power’s upcoming rate cases, resource planning and other financial filings.
“You guys develop the record; bring it to us. If there’s any misbehavior, we can deal with it. So, a lot of those risks can be managed through our regulatory process,” Ham said. He also asked stakeholders not to hold preconceived notions that the new ownership will be bad.
Ham noted a potential abuse of affiliated interests but said he believes existing U.S. Securities and Exchange Commission regulations are adequate to manage BlackRock.
“I started with very strong skepticism in this transaction,” Ham said. He thanked opposing parties and ratepayers for their arguments and said he was surprised by the firms’ flexibility to agree to new provisions.
Ham also advised GIP and CPPIB against making “Minnesota Power ratepayers mad.”
Commissioner John Tuma likewise said he was uneasy about what the deal would mean for Minnesota’s regulatory compact and that the concerns around affiliated interests are “real.” However, he said if the deal grows Minnesota Power as promised, it would be a win for ratepayers.
“This is a new, different way of doing it, as opposed to, say, some of the other mergers we’ve seen in the past,” Tuma said. He said the “pushback” from CUB was valuable and asked it to continue to serve as a watchdog.
“It’s a new path; there’s a lot more bramble-clearing to be done. And we want you to help clear that bramble so we can cut a new path,” Tuma said.
GIP founding partner Jonathan Bram told the commission the company’s fiduciary duty means it would not disadvantage Allete to benefit another company under BlackRock’s umbrella.
“Trust … is our stock in trade, and establishing that trust, maintaining that trust, is paramount to how we will … manage this. It is essential,” Bram said.
Bram also said the SEC and “international equivalents” regulate what GIP does, even before the BlackRock acquisition.
Andrew Alley, CPPIB’s head of infrastructure for North America, said the board could face “significant ramifications” if it tried to benefit one account at the expense of another.
“By our research, no other utility acquisition in America is generating this amount of value per customer, which we estimate to be approximately $200 million,” Jennifer Cady, Allete vice president of public policy and external affairs, told the commission before the vote. “None of these financial benefits exist without this transaction.”
Sieben said she was proud of the work the firms, environmental groups, labor unions and other stakeholders did to hammer out the final terms of the transaction.
“I think it’s pretty clear that because of the collective work of the agency, of us, our staff, the process we’ve engaged in a public and legal manner, we have made the petition better, and it will be to the betterment of Minnesota Power customers,” Sieben said.
