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November 2, 2024

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MISO Says System Volatility Here to Stay

MEMPHIS, Tenn. — MISO sees no end in sight to the system volatility that could plunge it into springtime emergency operations, staff said Thursday during a quarterly markets review.  

“We face a rapidly transforming energy landscape,” CEO John Bear told directors during a Board Week meeting, warning of a delicate load-supply balance.

He said when MISO introduced its ancillary services market 12 years ago, “load was the only thing that was moving around.”

“Everything else was pretty static and predictable,” Bear said. “Where we stand is not sustainable, and it’s not safe. We have a lot of work in front of us.”  

COO Clair Moeller said the RTO is laser focused on a “safe, reliable and affordable” transition despite proliferating operational complications.

“We’ve spent most of our time in committee meetings talking about volatility and uncertainty,” Moeller said, referring to the week’s activities.

“In the year 2000, volatility was a deterministic thing,” he said. “The volatility that’s facing us is more probabilistic than deterministic.”

Wayne Schug, MISO’s vice president of strategy and business development, said a growing renewables fleet and rapidly changing weather is driving increasing volatility and an “inability to deal with it.”  

By 2030, as little as 57% of the RTO’s fleet could be dispatchable, staff said. Dispatchable resources accounted for 84% of the fleet in 2020.

Schug said that since 2017, average daily output swings and forecasting errors have grown by gigawatts and percentages points, respectively. He said while the grid operator continues to get better at output forecasting, the expanding wind fleet has blotted out any signs of improvement.

“I caution you about averages,” Schug said. “Our extremes are much higher.”

Growing hourly wind Output (MISO) Content.jpg

Growing hourly wind output and volatility from 2008 to 2021

| MISO

 

Moeller said that for three days in 2020, MISO’s entire wind fleet in the upper Midwest failed to generate a megawatt. He also said unexpected cloud cover could make a solar farm “disappear within three minutes.”

MISO will work to pre-position its system for bad days, Moeller said. Executives said plans for seasonal capacity auctions and big-ticket transmission projects should help.

Director Mark Johnson asked staff to invite a control room operator to a board meeting to address their recent experiences dealing with grid volatility.

Staff Warns of Emergency Ops

MISO’s Zak Joundi said while the RTO should have adequate resources through spring, it could declare an emergency if faced with restricted generation output and high demand in April or May. He said the spring outlook echoes last year’s spring peak estimate and resource availability.

“Uncertainty can be especially exacerbated in spring,” he told the board’s Markets Committee Tuesday.

Joundi said MISO is working with an aging generation fleet more prone to outages with increasingly uncertain return-to-service dates. He said the footprint’s current rate of generation retirement — propelled, in part, by state and federal policies — is outpacing members’ capacity replacements.

Staff expects the number of emergency near-misses to rise every year, Joundi said. He said MISO may expand a weekly winter fuel security survey of fossil-fuel owners into a year-round task. (See MISO Winter Fuel Security Surveys Now Permanent.)

During the recent winter, MISO said renewable generation accounted for an increasing share of load. On Jan. 18, 24 GW of wind generation served 30% of the RTO’s load at one point. On Feb. 19, MISO reported its first seasonal solar generation peak of 1.6 GW.

“As the portfolio has transitioned to increased levels of wind output, operators are managing greater levels of volatility and uncertainty, making complex unit commitment decisions,” Joundi said. “How can we have the right market product to incentivize … the right kind of flexibility to complement this volatility?”

“There’s no magic bullet, market products and tools, or transmission,” Director Barbara Krumsiek said.

Joundi said that the control room now manages more intra-hour instability and intensifying “wind droughts,” where wind output drops off below forecasts.

“We’re seeing a lot more output and volatility on the wind side,” agreed MISO Independent Market Monitor David Patton.

Patton said MISO racked up about $750 million in real-time congestion costs during the winter, the most ever for a three-month period.

He said the grid operator is limited on wind generation it can export from the Midwest westward to SPP, saturating the system at times and lowering energy prices. Patton also said part of the congestion problem lies in SPP not modeling MISO’s constraints in its day-ahead market, making some uneconomic generation units appear economic in the SPP market. He said he was working with SPP and its monitor to fix the problem.

Patton also said drought conditions in the Canadian province of Manitoba led Manitoba Hydro to import more power from MISO, increasing constraints in the footprint’s northern portion. Manitoba Hydro’s Audrey Penner said a “deluge” of snow this winter will improve the situation as it thaws.

Coal generation’s share of energy output dropped from 41% last winter to 36% this winter, Patton said, because of retirements and limited coal supplies. Natural gas generation’s output share rose from 26% in 2021 to 29%. He said natural gas generation would have grown more this winter but for the “run up in gas prices.”  

Patton said he expects difficulties with securing coal to continue into the foreseeable future.

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DOE Calls for Better Engagement on Defense Infrastructure

In a report released this week, the Department of Energy found “significant opportunities” for improvement in its handling of the security needs of U.S. defense facilities and the utilities that serve them.

The report, titled “Strengthening the Resilience of Defense Critical Electric Infrastructure,” was produced by DOE’s Electricity Advisory Committee (EAC). It focuses on defense critical electric infrastructure (DCEI), defined in the Federal Power Act as “any electric infrastructure that serves” critical defense facilities (CDFs), themselves defined as critical to the defense of the U.S. and vulnerable to disruption of electric energy provided by an external service. It was based on interviews conducted with utilities that own and operate DCEI, which DOE dubs “responsible utilities” (RUs).

DOE launched its first program of outreach to RUs in 2019 under its Office of Electricity; the initiative was later shifted to the Office of Cybersecurity, Energy Security and Emergency Response (CESER). While the report’s intent was “not to criticize the DCEI program or its initial rollout,” the EAC found several areas where the implementation could be improved.

The first area has to do with the goals of the program — or rather the lack thereof. Many RUs complained about “DOE’s objectives for the DCEI program,” with one interviewee asking, “What are [the Department of Defense] and DOE trying to achieve here? That needs to be clearly articulated so industry can provide recommendations on how best to achieve” the program’s goals.

Others said they “don’t really know what DCEI is,” or complained that while the Fixing America’s Surface Transportation (FAST) Act of 2015 required DOE to identify CDFs and DCEI, it said “nothing beyond that.” This lack of clarity is compounded by the absence of a dedicated team within DOE to engage with industry, coordinate engagement between RUs and multiple DOE offices, and establish greater unity of effort between DOE and DOD. RUs reported feeling “whipsawed” with requests for engagement from both departments.

Questions on Funding and Resilience Targets

Another issue for many RUs is funding, specifically the question of how to pay for resilience improvements requested as part of the DCEI outreach.

This is a complex topic because a project intended to benefit a particular CDF may also benefit ordinary ratepayers in the region, leading some to suggest utilities should recover the cost for such projects through normal means. However, this is not guaranteed: A substation built in a remote location may benefit few or no ratepayers, while one in a crowded urban area may be expensive and have difficultly getting a permit.

In either case, such a project would not be the choice of the utility or the local customers, and requiring ratepayers to foot the bill would arguably be unjust. One RU observed that “the Pentagon never imagines that it could get F-35s for free” and criticized DOE for wanting “additional substations for free,” while another said that DOE and DOD should “find a pot of money to pay for” upgrades necessary for national security.

The challenge of identifying “specific resilience needs for DCEI” is “closely related” to that of funding, the report said, as it plays into the question of which projects to prioritize. The report called for resilience assessment tools, standards and metrics tailored to DCEI and the needs of utilities serving CDFs.

“What criteria should be established to assess progress toward achieving DCEI resilience goals? And are these goals appropriate to apply to DCEI and RUs, versus or in combination with applying them to CDFs for ‘inside the fenceline’ resilience?” the EAC asked. “These and other questions will take years to resolve and will need close coordination with initiatives on supply chain risk management, industrial control systems (ICS) security and other DOE resilience initiatives.”

Better Communication for Fast Response

RUs also suggested that DOE’s practices for sharing threat information with industry could be improved in light of the “harsh reality” that utilities serving defense facilities are likely to be targets in any coordinated action against the U.S. The report’s drafters noted a 2019 study that found “existing information sharing and partnership structures … neither agile enough nor tactical enough to respond to a cyberattack with the necessary speed.”

While the EAC acknowledged that progress has been made since then, it pointed to significant intelligence gaps that still prevent fast, flexible responses to new threats. Among the suggested solutions were:

      • a Critical Infrastructure Command Center: a secure space where senior executives and cybersecurity staff from different sectors can work with government to fight back against cyber threats; and
      • a Joint Collaborative Environment: a clearinghouse for sharing cyber threat data “among federal entities and between the U.S. government and the private sector.”

Finally, the report said its proposed DCEI team within DOE should lead more conversations on long-term policy changes. It is very possible that both the definition of CDFs and the understanding of their energy needs could change in the future, the report said; if they do, RUs will need to be informed promptly so that they can adapt their practices.

“Key to the success of improving DCEI resilience is establishing a structured, formalized team within DOE for industry engagement on DCEI issues,” the report said. “This would build upon the accomplishments made by DOE to date and serve as a prerequisite for moving forward on all the other proposals identified in this study.”

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FERC Extends Deadline to Justify Exceeding Price Cap in West

Sellers of spot electricity that exceeds the price cap for the Western Interconnection will have more time to justify the higher prices to FERC the commission ruled Thursday (EL10-56).

FERC approved a motion by Macquarie Energy and Mercuria Energy America to extend the deadline for cost-justification filings to 30 days after the end of the month in which an “excess sale” occurred.

Sellers currently have seven days to make the submission.

The commission established a price cap in the WECC area outside CAISO in July 2002 after the Western energy crisis of 2000/01, when widespread manipulation in the California market sent the wider region’s wholesale prices skyrocketing. The $250/MWh price cap set in 2002 was, with FERC approval, increased to $1,000/MWh in 2010 after CAISO raised its cap to that level.

When it set the price cap in 2002, FERC clarified that it was in fact a soft cap, saying that “prices can be above the cap but will be subject to justification and refund.” It also established the seven-day cost justification deadline.

In their identical requests to extend the filing deadline, Macquarie and Mercuria said the complexity of gathering information to submit a justification warranted more time.

After making an excess sale, the companies said they must identify the scope of trades above the soft cap and ensure the trades have been finalized from a contractual perspective. Then they need to “gather information about the market fundamentals and other factors driving prices,” as well as data related to production costs, opportunity costs and other indices supporting their arguments.

The sellers then have to identify other costs and risks and prepare the submission, including pleadings and declarations.

“Both parties argue that it is very challenging to complete these tasks in seven days, and they contend that 30 days from the end of the month of a trade is a more reasonable deadline,” FERC noted in its order.

The two parties also contended that changing the deadline would lessen the burden on FERC by reducing the instances when the commission must deal with repeated motions for extension and answers to those motions, as well as avoiding the need for sellers to make an initial filing to meet the seven-day deadline, followed by supplements to reflect changes.

Tenaska, Tri-State Generation and Transmission, Brookfield Renewable Energy and Trading and EDF Trading all filed comments in support of the plan. Tenaska said it appreciated FERC’s willingness to allow “one-off” extensions to the deadlines but said it was still challenging to assemble the needed data within seven days.

Tri-State said the commission’s recent approvals of extensions demonstrated the need for longer deadlines.

“We agree that allowing parties more time to gather the required information for a filing will likely lead to more complete filings, increase the likelihood that market participants will receive settlement data for relevant transactions that are billed on a monthly cycle, and will help ensure that market participants are considering all sales in a given month and are not making rolling submissions for each trade date,” FERC said in approving the motion.

“Finally, we expect that an extension will not only minimize the need for supplemental filings and amendments, but also reduce the number of requests for individual extensions,” it said.

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FERC Backtracks on Gas Policy Updates

FERC on Thursday walked back updates it made last month to how it would consider natural gas infrastructure applications, labeling the two documents as “drafts” and soliciting public comment.

The Democratic majority on the commission said they were concerned that the updates had created confusion and uncertainty, which the two Republican commissioners had predicted last month when they opposed the orders.

The commission had voted 3-2 to update its 1999 policy statement on natural gas infrastructure certificates (PL18-1) and released guidance on how it will evaluate the impacts of projects’ greenhouse gas emissions in its environmental analyses (PL21-3). (See Split FERC Updates Policies on Gas Infrastructure Applications.)

Combined, the two documents marked a significant change to how FERC would evaluate the need for gas projects and their impact on the environment, particularly the effect of their emissions on global climate change. But on Thursday, the Democrats said that after having conversations with and hearing feedback from developers, they reluctantly decided to delay the orders’ implementation.

“What I’ve generally heard is that the policy statements raise additional questions that could benefit from further clarification,” Chair Richard Glick said. “So we are re-engaging and inviting all stakeholders to comment on top of the 38,000 comments we’ve already received in response to two Notices of Inquiry.”

Glick was referring to the NOI issued under Chair Kevin McIntyre in late 2017 to revise the 1999 statement and the reissued notice in February 2021 that restarted the process after it had languished.

“This vote was a difficult one for me,” Commissioner Allison Clements said, “because I believe these policy statements were an important step forward in clarifying factors to be considered in making our public interest determinations and doing so consistent with court mandates. … Nonetheless, based on the engagement since last month’s meeting, I have concluded that we cannot move forward to effectively or efficiently consider and process individual project applications under the new policies without broader agreement across the commission.”

Based on statements from each of the Democratic commissioners, it was not clear what exactly gave them pause, and the orders had not been published as of press time. But Glick did say that after their finalization, they would only apply prospectively; they would not apply to any applications pending before the commission at that time.

While Republican Commissioners James Danly and Mark Christie had completely disagreed with the orders themselves, they were particularly incensed that they would apply to already filed applications without giving developers any chance to respond.

They also criticized FERC’s acting without public comment first, especially in the case of the GHG guidance, which the commission deemed “interim” while it gathered public comment by April 4.

Comments on the draft statements are due by April 25, with reply comments due May 25.

The move, along with three natural gas projects approved the same day (see below), were “case studies in why it is that every stakeholder should participate in the dockets in which they have an interest,” Danly said. “It was because in large measure of the participation of the affected parties that we find ourselves in the position we do. Never doubt the importance of the comments you file or the submissions you put into our dockets. They matter. They count. We read them.”

Consensus Possible?

Speaking to reporters, Glick said some developers were “interpreting [the two policies] in certain ways that I’m not entirely sure was intended. … Overall, we heard from them that there was a lot of confusion out there and … the goal here is to create less confusion and a framework for a legally durable approach.”

Asked whether he was concerned that the commission could reach any consensus on the policies, Glick said, “I still remain positive … that we can get to ‘yes’ in many [aspects]. I think we have to hear more and get a better record, which we’re going to do.”

But Glick made clear during the meeting and with reporters that the commission had to move forward with the changes. He noted that earlier this month, the D.C. Circuit Court of Appeals remanded another gas project approval back to the commission because of its failure to properly examine its greenhouse gas emissions. (See Court Again Rebukes FERC for Failure to Review Downstream Emissions.)

Willie Phillips 2022-03-24 (RTO Insider LLC) FI.jpgFERC Commissioner Willie Phillips | ©RTO Insider LLC

Glick was also asked if the move resulted from political pressure from Congress or the White House. Earlier this month the majority was strongly criticized by members of the Senate Energy and Natural Resources Committee, including its chair, Sen. Joe Manchin (D-W.Va.). (See Glick: No Regrets over Gas Policy Statements.)

“One hundred percent no, and I appreciate the question. I know you have to ask that question. I think … anyone who knows me knows that I’m not going to do anything for political purposes. FERC is an independent agency, and I very much honor that,” he said. He added that he believes the same of each of his colleagues.

The move also had nothing to do with the end of his term coming this June, he said.

“I actually like this job. If the president and the Senate are willing to let me stay, I will do so,” he said. “There’s things in life you can control, and there are things you can’t control. And I’m going to focus on the work and what we can control” at the commission.

After FERC’s open meeting, in what he said was his first speech since joining the commission, Commissioner Willie Phillips commented on the order at the American Council on Renewable Energy (ACORE) Policy Forum.

“You may have noticed that my colleagues and I had a couple of differences about a couple policy statements regarding natural gas recently that got a little bit of attention,” he said. “Today, we set those statements for additional comment to give us time to try to reach a more bipartisan solution. My colleagues and I take our independence as regulators very seriously. Some may even accuse us of digging into our positions and failing to compromise at times. I say: Let’s stop digging. That’s not FERC. That’s not me.”

3 Projects Approved

While FERC gathers public input, the commission will continue to consider gas project applications under the 1999 policy statement, Glick said.

On Thursday, the commission unanimously approved three such applications — though each commissioner issued a separate concurring statement for each of the projects. (These orders and statements were also not available as of press time.)

Glick said the commission found that the developers had demonstrated need for each project. He also noted that, based on his own projections, the projects’ emissions would not have a significant impact on climate change, though this was not a factor in the commission’s decisions. In fact, he said, one of the projects — Iroquois Gas Transmission System’s ExC Project in New York (CP20-48) — will actually reduce emissions because the transported gas will replace oil used for heating.

The other two projects approved were Kinder Morgan’s Evangeline Pass Expansion Project in Louisiana and Mississippi (CP20-50), and TC Energy’s East Lateral XPress project, also in Louisiana (CP20-527).

Rich Heidorn Jr. contributed to this report.

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Generators Vent Frustration with PJM, FERC to Ohio Senators

Glen Thomas (The Ohio Channel) Content.jpgGlen Thomas, P3 | The Ohio Channel

PJM stakeholders in the RTO’s generator sector Tuesday voiced frustration with FERC over recent decisions related to the capacity market, especially multiple delays to the Base Residual Auction (BRA), to a receptive audience in the Ohio Senate Energy and Public Utilities Committee.

The testimony from Glen Thomas, president of the PJM Power Providers Group (P3), prompted one senator to question whether the legislature could explore leaving the RTO.

Thomas told the committee that capacity resources in Ohio have done “very, very well” in the capacity market. Ohio has seen more than a dozen new power plants constructed in the last 15 years, leading to billions of dollars in investments and thousands of jobs, he said.

PJM’s capacity reserve margin numbers are currently “very strong,” Thomas said, creating short-term confidence in the market. But in the long term, P3 is “growing increasingly concerned” that reliability is going to become more of an issue in the future in PJM.

Steve Wilson (The Ohio Channel) Content.jpgSen. Steve Wilson | The Ohio Channel

“There’s a lot of things that have been occurring at the federal level that have a direct impact on Ohio’s energy policy, and there’s quite frankly some reasons to be concerned,” Thomas said.

Sen. Steve Wilson (R) said he was “scared to death” thinking about the long-term reliability issues Thomas talked about.

Wilson asked Lori Sternisha, director of the Office of the Federal Energy Advocate for the Public Utilities Commission of Ohio, what the legislature could do if FERC ends up forcing Ohio to pay for projects like offshore wind in New Jersey.

“Would we look to drop out of PJM, or what is our fallback plan if all of a sudden our reliability gets unacceptable and our price gets unacceptable?” Wilson asked.

Lori Sternisha (The Ohio Channel) Content.jpgLori Sternisha, PUCO | The Ohio Channel

Sternisha said her office is concerned with long-term reliability issues based on recent FERC decisions, but that PJM is responsible for making sure there are reliable resources throughout the RTO, and it continually conducts reliability studies. She said if new generation isn’t located close to load centers, new transmission may be a solution.

“It would be my hope going forward that we not run away from PJM but use our oversized voice to direct the policy and do the best we can in that regard,” Sen. Mark Romanchuk (R) said.

Regulatory Uncertainty

Panelists at the hearing spoke about the impact of PJM’s minimum offer price rule (MOPR) on Ohio’s energy sector.

PJM’s narrowed MOPR took effect in September after FERC deadlocked 2-2 on the RTO’s proposal to apply it only to resources connected to the exercise of buyer-side market power or those receiving state subsidies conditioned on clearing the capacity auction. The proposal became effective by operation of law under Section 205 of the Federal Power Act when the commission failed to act within 60 days. (See FERC Deadlock Allows Revised PJM MOPR.)

Thomas said PJM had used the MOPR to “keep competition fair and the playing field level” among states and to take subsidies out of the marketplace. But he said many states in the RTO are using subsidies to incent renewable generation, and without the MOPR, subsidized resources “enjoy a leg up” in the marketplace and Ohio resources are on an “uneven playing field.”

“We believe the market should dictate winners and losers,” Thomas said. “We believe that competition that drives down costs is a good thing.”

Thomas said P3 has also grown concerned about the pace of plant closures resulting from delays in the running of PJM’s capacity auctions. He said delays in the Base Residual Auction have led to closures for plants that may have been viable in an auction run on time.

The BRA for delivery year 2023/24 has been delayed three times — from May 2020 to December 2021, then to late January, and finally to mid-June — each from separate FERC orders on different aspects of the capacity market. (See FERC Approves PJM Capacity Auction Date Changes.)

Arn Quinn (The Ohio Channel) Content.jpgArnie Quinn, Vistra | The Ohio Channel

Arnie Quinn, chief economist for Vistra (NYSE:VST), cited the retirement of Vistra’s 1,320-MW coal-fired William H. Zimmer Power Plant, announced last summer.

The plant was originally scheduled to retire by 2027, but the deactivation was moved up to May 31. Quinn said the change was made after the results of the 2022/23 BRA last May — also delayed multiple times from its original May 2019 date — when auction prices cleared lower than Vistra expected, making the plant unprofitable. (See Capacity Prices Drop Sharply in PJM Auction.)

Quinn said Vistra debated keeping Zimmer in operation to see if capacity prices “rebounded” in the 2023/24 BRA. But he said FERC’s decision on PJM’s market seller offer cap (MSOC) and more delays in the auction made it “clear” that the commission was going to make it more difficult “to use our commercial and engineering judgment to reflect our costs” when the offers were presented to the capacity market.

“We should have had the opportunity to go to the market with a bid that reflected our view on how much it would take to keep that plant open,” Quinn said. “We didn’t give the market that option because we sensed a risk that those rules were going to disadvantage us.”

Sternisha said her office has voiced concerns before FERC on fair and competitive wholesale markets, ensuring Ohio ratepayers are not burdened by public policy initiatives of other states and advocating for control of increasing transmission costs.

FERC’s inaction on the MOPR and the repeated auction delays over the objections of PUCO are “concerning,” she said, and a wholesale capacity market without “appropriate guardrails” doesn’t provide reasonable price signals or compensation to all generating resources. The MOPR has been changed so many times that it was “watered down to the point that it provides little screen for subsidized, uneconomic resources entering the PJM capacity market.”

Senators’ Questions

Mark Romanchuk (The Ohio Channel) Content.jpgSen. Mark Romanchuk | The Ohio Channel

Sen. Romanchuk asked about Ohio and Pennsylvania’s combined energy consumption in PJM. 

Sternisha said Pennsylvania represents 19.7% of load in PJM, while Ohio is at 19.3%. 

Romanchuk said that should give the two states an “oversized voice” in PJM and federal policy decisions. Sternisha responded by saying she believes they “carry a lot of weight” in PJM and at FERC.

Sen. Teresa Fedor (D) asked if PJM’s capacity market has protections against generation resources that are “trying to game the system” through offering artificially low prices in auctions.

Quinn said the MOPR “is and was” the mechanism PJM has to deal with prices, and the new rule means “essentially no resource now has any limitations on how low they can get.”

Fedor asked Quinn what types of resources in PJM are “trying to game the system.”

Quinn said he wouldn’t characterize resources’ bidding behavior that way. “They have another revenue source that offsets the other costs that the wholesale market needs to pay for,” he said, referring to state subsidies. “That resource is reflecting that in their offer. I wouldn’t say the resource is gaming anything. The resource is expressing what their economic interests are. The state has changed the playing field for all resources.”

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Highlights from FCA 16: No New Gas, No Big Storage

New England’s Forward Capacity Auction last month offered no big surprises, but it did hint at coming shifts in the dynamics of the region’s energy supply.

While the FCA 16 clearing price fell in the Southeast New England zone, the market overall stayed relatively steady from the previous year’s auction, with minimal turnover in the generator fleet and relatively low prices. (See ISO-NE Announces Capacity Auction Results After Killingly Delay.)

It was, as one observer put it, the “calm before the storm” as New England prepares to transition away from the minimum offer price rule.

The new generation that entered this year came from storage and solar, with no new gas-powered generators or repowering projects.

“I think that reflects the fact that the economics are challenging for non-renewable resources,” said Scott Niemann, a director at the research and consulting firm ESAI Power. “And what’s coming in is really driven by public policy.”

ISO-NE published the full results of the auction in a FERC filing earlier this week.

Merrimack Station

New England’s last remaining coal plant, Merrimack Station in New Hampshire, cleared the auction.

But it did so after a dynamic delist bid that ultimately lowered its payments by 128 MW worth of capacity, or roughly $300,000 a month at the clearing price of $2.48/kW-month.

“That’s one of the units that’s clearly very much on the bubble in terms of being economic in the market, and that shows up in that some of those megawatts were not cleared,” Niemann said.

Storage

Standalone storage projects were “mostly locked out,” noted Aaron Geschiere, a senior analyst for Nexamp.

That likely stemmed from the end of the seven-year price lock rule, which allowed new resources to maintain their clearing price for seven years but was used for the last time in FCA 15 after FERC ordered its removal.

“There was more urgency to clear in the last auction so that the price could be locked in for seven years to facilitate financing and more certainty in returns,” Niemann said. “All of the projects that cleared in this auction were small batteries, compared to last auction where you had 100 or 200 MW individual projects clearing.”

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Consumers Threatens to Hold off Closing Mich. Coal Plants

LANSING, Mich. — Consumers Energy (NYSE:CMS), the state’s largest investor-owned utility, has warned it may drop its plans to close its remaining coal-fired power plants by 2025 unless the state’s Public Service Commission ensures it can recoup both the generation and revenues lost through those closures using gas-fired plants.

In a filing responding to a proposed decision presented to the PSC by Administrative Law Judge Sally Wallace on the company’s integrated resource plan, Shaun Johnson, general counsel for Consumers’ parent company CMS Energy, said that “without adequate assurance of cost recovery related to the early retirement of its remaining coal generating plants and without an adequate plan to replace the capacity and energy derived from those plants, [parent company] Consumers Energy will run those plants until their previously planned retirement dates, keeping Consumers Energy and Michigan reliant on coal for nearly two decades.”

Consumers can do that, Johnson said, because the Michigan law on utility IRP filings also allows utilities to “not accept a commission order in an IRP proceeding. And for that reason, the company is filing these exceptions to make clear that there are certain core principles to the plan — principles that the proposal for decision rejected and modified — that must be resolved to the company’s satisfaction in order to see the company accelerate its coal fleet retirement.”

The warning has raised alarms among environmental groups, which had also criticized Consumers’ IRP for the continued use of gas-fired generation, and comes at the time when the state’s Council on Climate Solutions will hold its final scheduled meeting before issuing the state’s proposed plan to go carbon neutral by 2050.

Consumers filed its IRP on June 30, 2021. In the proposal it called for closing the Karn coal plant in Exxeville in 2023, and all three units of the Campbell Generating Plant in West Olive by 2025. It had previously planned to close the Campbell plant by 2039. The IRP also called for replacing the lost generation with new renewable resources and gas plants, including plants it would acquire.

Wallace’s proposed decision calls for the commission to approve closing Karn and Campbell Units 1 and 2 as proposed. But it called for delaying closing Campbell Unit 3, the plant’s largest, for more analysis into its potential effect on availability. Wallace also urged the commission to reject the utility’s plan to purchase three natural gas plants from its subsidiary.

Under state law on IRPs, the PSC must make a decision within 300 days of when Consumers first filed its plan. While the commission took comments on the proposed decision until Monday, no further public hearings will be held on the issue before it rules.

The proposal to delay closing Campbell 3 led environmental groups to object. The Sierra Club, Michigan Environmental Council and the Natural Resources Defense Council joined in one objection, urging the PSC to approve closing Campbell 3 by 2025, calling it the “most forward-looking” item in Consumers’ initial proposal.

In Consumers’ objection to the proposed decision, Johnson said, “Without an actionable capacity plan using existing generating units to replace the retiring capacity in 2025, and without certainty on recovery of a reasonable return on the unrecovered book balance of the retired units, the entire plan falls apart. …

“Michigan will face a lost opportunity to expedite its transition to clean energy, reduce emissions, increase reliability and lower energy costs,” Johnson said. “That would mean no accelerated coal retirements … and no expanded solar buildout. That is not an outcome Consumers Energy wants to see. And we believe it is not an outcome the state of Michigan and this commission wants to see.”

Tim Werner, a Traverse City Commissioner and member of the city’s Board of Light and Power, said the threat to hold off closing the coal plants poses a risk to Michigan meeting a goal of carbon neutrality by 2050. “It would maybe not be impossible, but so difficult” to reach if the plants remained open until nearly 2040, he said.

Traverse uses electricity generated by the Campbell plants, and while city officials and residents would like the plants shuttered to boost renewable resources, Werner also recognized the complexities of reaching a decision. While many environmentalists are pushing for no natural gas in reaching carbon neutrality, Werner said that a compromise may be necessary to get the Karn and Campbell plants closed by 2025. That could include letting Consumers own and run the gas plants for a set number of years before closing them as more renewables come online.

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Congressional, White House Officials Hopeful for Passage of Tax Credit Package

WASHINGTON — Word that Sen. Joe Manchin (D–W. Va.) is open to resuming negotiations on a scaled-back version of the Build Back Better Act that he torpedoed in December buoyed speakers from Congress and the White House at the American Council on Renewable Energy (ACORE) Policy Forum Thursday.

Speakers said they hope to pass a package this spring.

National Climate Adviser Gina McCarthy reeled off a list of cost savings the bill’s clean energy investments could provide for U.S. families. For example, energy efficiency incentives could reduce home energy bills by $500 per year.

“This is what we can deliver to people,” McCarthy told an audience of almost 200 at the live event. “What’s wrong with this? Why aren’t we running as fast as humanly possible? What Congress needs [is] to get these investments on the table and to move them forward quickly. And we’re going to do whatever it takes to get these investments over the finish line.”

The Build Back Better Act contained $555 billion in clean energy tax credits and other incentives that organizations like ACORE lobbied hard for last year. The credits are critical for President Joe Biden and the industry to meet the president’s goal of a 100% decarbonized grid by 2035 and a net-zero economy by 2050.

In a string of recent media reports, the latest in E&E News, Manchin has signaled that he is still open to a reconciliation package that would include at least some of the clean energy incentives. At the same time, Manchin has said he believes responding to the war in Ukraine will require stronger “all of the above” energy policies.

Senate Finance Committee Chair Ron Wyden (D-Ore.), in an afternoon keynote delivered remotely from his Senate office, told the gathering he’s confident of having 50 votes in the Senate for his Clean Energy for America Act, which would eliminate 44 existing tax breaks and replace them with technology-neutral credits based on emission reductions.

“We will have in the future, a technology-neutral system, which was very important to Sen. Manchin,” Wyden said. “And a technology-neutral system would be tied to a very different lodestar, and that lodestar is: the more you reduce your carbon emissions, the bigger your tax savings.

“I think when Sen. Manchin says … we may need to make some additions to deal with Russia and Ukraine, I don’t think it means unraveling Clean Energy for America,” he said.

On a panel on the current state of play for energy tax credits, the name “Build Back Better” was, in most cases, strategically avoided. Rather, Will Conkling, Google’s (NASDAQ:GOOG) head of data center energy supply for the Americas, Europe, the Middle East and Africa, said the uncertainty surrounding the legislative package is making it increasingly hard for his company to sign contracts for renewable energy. Conkling said renewable energy developers “won’t even show me a price because they are so uncertain about all the different forces that are at work with that three- or four- or five-year timeline. … Will they even sign a contract today is in doubt.”

For clean energy developer Arevon, that uncertainty is being played out in supply chain delays, said Katherine Gensler, the company’s vice president of government affairs and marketing.

“Our team has spent a lot of time in the last six months renegotiating contracts and pushing schedules out into the future to try to get some alignment and a certainty about when deliveries will be made,” she said. “But it just continues to be a challenge, and there’s not a clear path.”

The Ukraine Conundrum 

The Russian invasion of Ukraine has quickly become a flashpoint in political debates about U.S. energy policy. Republicans in Congress continue to slam Biden’s clean energy agenda, calling instead for more drilling on public lands and a loosening of regulations to stimulate domestic oil production. Biden and the Democrats have countered that clean energy is now even more critical for national security.

“Clean energy is a triple-edged sword right now,” McCarthy said. “It can tackle climate change. It can bring down consumer costs for everyone. And it will be the way in which we drive to national security. This is what clean energy brings to the table every day. And with this brutal war raging in Ukraine, we’re seeing just how easy it is for autocrats to use fossil fuels as weapons, unleashing volatility in our global energy markets to pursue their own agenda.”

At the ACORE event, the Ukraine discussion centered on the challenge of balancing long-term clean energy goals with the immediate need to ramp up oil and gas production to meet the domestic and foreign demand resulting from import bans on Russian petroleum.

While responding to the current emergency and ensuring our European Union allies have stable energy resources, a longer-term view is still needed, McCarthy said.

“This is an emergency that we’ll get through,” she said. “But we cannot increase our dependency on fossil fuels. … We have to have this be a short-term, emergency fix toward a longer-term effort to achieve clean energy together, that’s consistent with the [climate] commitments that both the EU and the United States” have made.

ACORE CEO Gregory Wetstone agreed that “investments to deal with that short-term need [should] be consistent with the longer term. We want to make sure that we don’t see investments in infrastructure that become stranded assets. That’s what it comes down to,” he said. “That infrastructure needs to be compatible with a clean energy transition.”

Speaking on the tax credit panel, Bobby Andres, senior policy adviser for Wyden, similarly said that the war in Ukraine and “events in Europe may actually be spurring additional desire to move on the clean energy package.” Build Back Better was “designed to tackle climate issues, was designed for decarbonization, but the design choices also are things that help address energy costs that will spur clean energy development, which will then reduce oil and gas demand, both reducing costs for consumers and allowing us to export more of those [fuels] to our allies.”  

Failure is Possible 

Andres said he believes a reconstituted reconciliation package is the way forward, with a late spring target for passage. The window is narrow and closing, he said. With the Senate now focused on the confirmation of Supreme Court nominee Ketanji Brown Jackson, the work session between Easter and Memorial Day may be the last chance to get the package written and passed this year.

Beginning in the summer, the mid-term elections will provide significant headwinds, with representatives and senators up for re-election focused on short-term issues of concern to their voters and reluctant to push for large, expensive legislative packages, like BBB, said Jon Bosworth, legislative director for U.S. Rep. Earl Blumenauer (D-Ore.).

“Members are potentially nervous about taking bold legislative action,” Bosworth said. But, echoing Andres, he said the clean energy tax credits and other incentives can be framed as providing a longer-term solution to current economic stressors such as inflation and high gasoline prices.

“I think we have a good case that providing more energy security and stability in the years ahead [via a reconciliation package] will reduce this type of event from happening again,” he said.

But, outside Congress, selling such ideas to voters means shifting the conversation from political to more personal perspectives, McCarthy said.

“One of the things that we’ve desperately tried to do is to change the discussion from a planetary problem to a people problem,” she said. “I want people to understand that what we’re doing matters to them and to their families. … These tax incentives, the [production tax credit] and other manufacturing tax incentives are so important because they’ll put people back to work, because they will tackle the climate crisis, because they will give us security and independence.”

While Andres remains optimistic, he also admitted that failure is possible, and the fallback position for the industry would be to once again lobby to extend existing tax credits in end-of-year legislation, as occurred in 2020.

Gensler cautioned, however, that the extender option could leave out key incentives, such as a tax credit for standalone energy storage, a top priority for her company.

Echoing McCarthy, she said, “Speed is of the essence. We should be running as quickly as possible for each of these policies. Having a reconciliation bill framework presents us with a unique opportunity to lock in long-term policies. Anything we can do to really move the ball forward expeditiously is critically important.”

Rich Heidorn Jr. contributed to this report.

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FERC Issues Southern Show-cause Order on Rate Protocols

FERC on Thursday raised concerns about Southern Company’s formula rate protocols, issuing the utility a show-cause order to explain either why the protocols should remain in place under its Open Access Transmission Tariff (OATT) or how it would change the OATT to address the commission’s concerns (EL22-27).

In its order, FERC identified deficiencies with Southern’s formula rate protocols in three areas: scope of participation; transparency of information exchange; and ability of customers to challenge transmission owners’ implementation of the formula rate.

The first issue is based on the commission’s requirement that formula rate protocols allow “all interested parties [to participate] in information exchange and review processes,” including ratepayers, state utility regulatory commissions, consumer advocacy groups and state attorneys general. FERC found that the wording of Southern’s protocol may have inadvertently left some stakeholders out of the process.

“While Southern allows an ‘interested party or Commission Trial Staff’ to participate in the customer meetings, information exchange, and challenge procedures, its formula rate protocols do not define the term ‘interested party’ to generally identify which parties can participate,” FERC said. It ordered Southern to either rewrite the relevant section to specify who may participate in the procedures and to provide all such parties access to information about annual updates to the protocols, or to show cause why it should not be required to do so.

The commission’s transparency argument warns that interested parties might not be able to access the information they would need to evaluate the correctness of the formula rate, potentially leaving them unable to challenge it. This is because Southern’s protocol only requires that “workpapers and underlying service data” be filed as supporting documentation.

This requirement is a violation of previous FERC orders that mandate that “formula rate protocols must include greater detail regarding the financial and cost information from which a transmission owner’s rates are developed. This information must include underlying data and calculations supporting the formula rate annual updates … [including] underlying data and calculations supporting the formula rate annual updates.”

FERC also found Southern’s protocols deficient in several other ways: providing no procedure for making document requests, limiting the reach of potential information requests, failing to require disclosure of accounting changes that might impact the formula rate, and not providing for an annual meeting, among others. Again, the utility is required to justify its protocols or explain how it plans to remedy the issues.

Finally, the commission said Southern’s formula rate protocols do not provide sufficient detail relating to how interested parties can file formal and informal challenges to the utility’s rates. For example, Southern’s protocols do not require senior representatives to work with interested parties and improperly “limit the subject of a formal challenge to an interested party’s previous informal challenge.”

In addition, FERC said the language of Southern’s protocols “strictly [limits] the commission’s procedural options” regarding challenges to the utility’s rates. Specifically, the commission noted that Southern asserted its burden of proof in any FERC-ordered proceeding falls under Section 205 of the Federal Power Act; this raises the possibility of an attempt to prevent any proceeding under Section 206 of the FPA.

Under the commission’s order, Southern is required to file its response within 60 days. Interested parties are also invited to respond in the same docket.

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PG&E Rate Request Prompts Protests

Pacific Gas and Electric’s request for major rate hikes over the next four years, following substantial increases this year, provoked an outpouring of customer complaints during recent public forums held by the California Public Utilities Commission.

PG&E said it needs a huge boost in its 2023-26 General Rate Case (GRC) in part to pay for electric system upgrades to prevent wildfires.

In one CPUC forum Tuesday, however, residents objected to PG&E receiving more money for grid hardening to prevent wildfires after years of deferred maintenance and lax vegetation management led to some of the worst fires in state history over the last five years.

“I think these are unreasonable increases, and PG&E needed to address some of their problems years ago,” Bernadette Mcewen, a senior citizen from rural Tuolumne County, told two CPUC commissioners and an administrative law judge. “What are we going to expect from these increases? Just further increases, I would assume.”

Mcewen said her electric bill had increased by more than 20% since 2018.

PG&E “shareholders also need to take the burden of future [wildfire] prevention,” she said. “I do not believe that this hefty increase should be shouldered completely by the ratepayers.”

The combination of wildfire mitigation efforts, rising natural gas prices and California’s transition to renewable energy have led to steeply rising bills for customers of the state’s three largest investor-owned utilities, including Southern California Edison and San Diego Gas & Electric.

PG&E customers have borne the worst of it. The utility’s electric ratepayers were hit with a $1 billion rate hike in January followed by a $1.1 billion increase in March. The increases were mainly driven by higher-than-expected prices for natural gas, used in generation, and newly imposed FERC transmission-rate requirements.

Together, the increases worked out to a 19% rate hike in the past two months, or about $28 per month for the average customer.

In its 2023-26 GRC, now before the Public Utilities Commission, PG&E asked for a $15.5 billion base revenue requirement for its gas and electric operations — an “unprecedented” 30% increase over its 2020-22 GRC, according to the CPUC’s Public Advocates Office, which filed a protest in the matter.

That could translate to a 16% rate hike for residential electric customers in 2023 and a cumulative 23% increase through 2026. Combined with this year’s rate hikes, customers could see a 42% increase in their electric bills in five years. Average residential customers who paid about $135 per month last year would pay $186 by 2026.

In its protest, The Utility Reform Network (TURN) called the proposed rate hikes “shocking increases … not seen before in a major utility’s general rate case.”

The costs could be far higher than the GRC suggests, especially if the CPUC eventually approves a PG&E proposal to bury 10,000 miles of power lines in high-threat fire districts, TURN said.

Cost estimates for the effort have been scanty until recently, but information provided by PG&E to RTO Insider this week shows an estimated cost of nearly $11 billion for the undergrounding effort from 2022 to 2026. State and federal infrastructure funding could potentially pay for some of the effort, but ratepayers would likely have to absorb a significant share.

In the meantime, PG&E has asked for more than $1 billion in its GRC to prevent wildfires following five years of catastrophic blazes ignited by PG&E equipment. The money would pay for grid hardening and upgrades including undergrounding about 170 miles of power lines in and around Paradise, the town destroyed by the PG&E-caused Camp Fire in November 2018.

“PG&E’s most important responsibility is the safety of our customers and the communities we serve,” the utility said in its amended application filed March 10. “Our GRC forecast includes reasonable costs required to provide safe and reliable service and follow best industry practices.”

“Regulations require PG&E to take certain actions,” it said. “As an electric utility, PG&E’s wildfire mitigation proposals in this GRC follow the legislature’s mandate to ‘construct, maintain and operate its electrical lines and equipment in a manner that will minimize the risk of catastrophic wildfire posed by those electrical lines and equipment’ and achieve ‘the highest level of safety, reliability and resiliency.’”

The utility also asked for $900 million for its move from its century-old San Francisco headquarters, which it agreed to sell last year for $800 million, to its new building in nearby Oakland.

Other major expenses include a $220 million increase for utility pole and meter replacements, $172 million for new customer connections and upgrades associated with electric-vehicle adoption, and $168 million for hydropower plant improvements, the CPUC said in a summary.

PG&E’s 2023-26 rate case is a new four-year combined gas and electric plan ordered by the CPUC. Prior GRCs were two years, with gas and electric filings weighed separately.

The CPUC will decide PG&E’s rate case later this year. The plan is scheduled to take effect Jan 1, 2023