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November 5, 2024

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PJM General Session Focuses on Clean Energy Transition

CAMBRIDGE, Md. —
PJM’s biannual General Session last week focused on how to ensure both reliability and equity during the transition to a clean energy-based generation mix.

NERC CEO Jim Robb moderated the first panel, introducing it by saying that reliability, environmental impact and affordability will all be challenged during the transition to relying on renewable power. Over the next 10 years, NERC expects to see increased risk from extreme weather and tight supply margins as the decommissioning of fossil fuel generation runs up against increasing demand from electrification.

Jeff Craigo of ReliabilityFirst said the regional entity has had success with an initiative to survey generation facilities’ winterization efforts, which has allowed it to share those experiences across the industry.

Peter Brandien, ISO-NE vice president of system operations and market administration, said the RTO is focusing less on specific percentages of capacity, and more on understanding what kinds of resources are available and their characteristics.

The RTO’s response to the transition has centered on four pillars, Brandien said: handling the influx of clean energy resources; a supply of balancing resources to preserve reliability; maintaining resource adequacy to meet demand when solar and wind power aren’t available; and having adequate transmission to import more renewable energy and to ensure renewable resources aren’t constrained when they’re needed.

Resource adequacy in particular has been challenging within New England. Unlike other areas of the country where the problem is getting through the peak load day and resetting for the next, New England has limited storage (LNG, oil, hydro or long-duration batteries) and can run short of supply, particularly during extended cold weather. Siting has also proven to be another challenge, and Brandien noted the struggle of the New England Clean Energy Connect transmission line.

Confidence in the reliability of the grid is crucial to industries looking to make investments, which Brian George, lead of Google’s energy regulatory and policy engagement team, said is reflected in the company’s heavy investments in PJM.

“Our users expect and demand reliability all the time and everywhere, so that’s at home, that’s in the office. … Whenever they pull up the browser, they expect us to be there,” he said.

To meet the company’s climate goals, he said Google has shifted its focus to the procurement of energy for when and where it’s needed, rather than the installation of additional renewable resources. He said the open markets, which have created affordable and reliable power in PJM, will play a key part in addressing that focus while meeting its growing demand.

Nancy Bagot, senior vice president of the Electric Power Supply Association, said the transition is the time to double down on competition to encourage more innovation, while shielding customers from the risks of finding the right balance of resources. There will have to be an acknowledgement that markets are being asked to break new ground, she said, and the conversations on how to do so will need to remain grounded in reality and based on the voices of reliability experts.

That will involve reimagining the capacity market in what it signals and procures for different regions of the country, including a look at what the mix of capacity available is, rather than the raw amount in the market, Bagot said.

Bobby Jeffers, program manager at the National Renewable Energy Laboratory, spoke about the lab’s efforts to improve the models, tools and calculators available for gauging reliability. Incorporating a better understanding of how supply chains function and geopolitics is necessary for creating modeling for a system that works.

NREL is also upgrading its Interruption Cost Estimate calculator to reflect the societal costs of extended outages, Jeffers said. The economic impacts currently incorporated into the tool fail to reflect the toll outages can take on customers.

Responding to the question of whether FERC should play an activist role or take a more passive, judicial approach to the transition, the panelists largely agreed that stability and deference to RTOs were preferable.

Brandien said that grid operators know their regions best and they can carry out their responsibilities more effectively without NOPRs and filings confusing the waters. George said it’s important that if FERC has a preference on a policy, it should make it known and take the lead, rather than leave RTOs in the dark.

Equity and Environmental Justice

The second panel focused on ensuring that the costs of the transition don’t fall disproportionately on disadvantaged communities and examining how to reconcile the need to expand energy infrastructure and the burden it often places upon the communities that host it.

One of the largest challenges in ensuring the equity of wholesale energy markets remains the lack of public knowledge about their functioning, said Damali Rhett Harding, managing principal for the Regulatory Assistance Project.

“How do we incorporate equity into a marketplace that probably 99% of Americans don’t realize exists?” she questioned.

To provide equity in energy, she said companies need to examine the procedures that prevent people from participating in the siting process.

Beyond just educating the neighbors of a proposed project, former U.S. Rep. Joseph P. Kennedy III (D-Mass.), now managing director of Citizens Energy, said developers and utilities should explore ways to ensure that the expansions directly benefit those communities. He pointed to a project in which his nonprofit partnered with a utility to invest in a large transmission project in California’s Imperial Valley, and then used the profits it earned to construct a 30-MW community solar installation in the city of Calipatria. In addition to improving reliability, the solar project provides about $500 in annual savings every year over 20 years to 12,000 low-income households in a region where temperatures can exceed 110 degrees Fahrenheit, he said.

Such arrangements can prove worthwhile even to for-profit companies by alleviating residents’ concerns that large transmission projects could lower property values or disrupt their neighborhoods with no visible benefit to them, Kennedy said. The costs of the delays or resiting of projects can often well exceed the expense of profit sharing with those communities, he argued.

Delaware Public Service Commissioner Harold Gray, who moderated the panel, said incorporating more voices can help companies find more forms of value than immediate profit alone. In his work on the commission, he has had success showing utilities that by keeping their customer’s interests in mind, they can discover new customers and potentially expand profits.

Former FERC Commissioner Colette Honorable, now a partner at Reed Smith leading the firm’s energy regulatory group, noted that getting all parties on board with a project in the early phases can reduce the likelihood of prolonged, and expensive, delays at FERC and the federal courts.

“You’re in trouble if you have a matter pending and the first time you hear them is when they object,” she said.

Likewise, she said incorporating equity into the work done by RTOs can be accomplished by examining what voices are missing at the table and including those stakeholders who aren’t represented. On public education, she said FERC’s new Office of Public Participation has been making strides in ensuring that individuals at all levels are empowered to make their concerns heard.

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Monitor Finds PJM’s 2023/24 Base Residual Auction Competitive

The 2023/24 Base Residual Auction held by PJM in June yielded competitive results, the RTO’s Independent Market Monitor announced in a report released last month, owing largely to the implementation of a 2021 FERC order reworking the derivation of the market seller offer cap (MSOC).

Monitoring Analytics’ report, released Oct. 28, said the shift from basing the MSOC off the net cost of new entry (CONE) to using the avoidable-cost rate (ACR), as ordered by FERC, addressed concerns about the ability to exercise market power and uncompetitive outcomes leading to customers being overcharged. (See PJM Capacity Prices Crater and FERC Backs PJM IMM on Market Power Claim.)

“The net CONE times B offer cap assumed competition where it did not exist and led to noncompetitive outcomes and led to customers being overcharged by a combined $1.454 billion in the 2021/2022 and 2022/2023 BRAs,” the Monitor said. “The logical circularity of the argument, as well as the fact that key assumptions are incorrect, means that the [Capacity Performance] market seller offer cap was not based on economics or logic or math.”

Despite believing the auction succeeded in securing competitive results, the Monitor wrote that the Reliability Pricing Model still has many components of a “significantly flawed market design.” These include the shape of the VRR curve; the participation of demand response resource in the capacity market; capacity imports; and the overstatement of intermittent capacity offers.

In addition to taking issue with intermittent resources offering capacity at a higher rate than permitted by their capacity interconnection rights, the Monitor said exempting those resources from the must-offer rule raises market power issues stemming from the ability to withhold supply.

“The failure to apply the must-offer requirement will create increasingly significant market design issues and market power issues in the capacity market as the level of capacity from intermittent and storage resources increases and the level of demand-side resources remains high. The failure to apply the must-offer requirement consistently could also create price volatility and uncertainty in the capacity market and put PJM’s reliability margin at risk,” the report says.

The report called for a consistent definition for capacity that includes being a physical resource at the time of the auction for all resource types. That requirement is not currently being applied to DR, nor to energy efficiency, both of which the Monitor said should be shifted to the demand side of the market. It also wrote that EE is accounted for in PJM’s load forecasting and the payments such resources receive don’t provide added incentive for participant behavior.

The use of a sloping VRR curve procures excess capacity and masks the flaws of “permitting the participation of inferior demand-side resources in the capacity market” by avoiding the need to rely on those resources, the Monitor argued. It said that the use of a vertical demand curve “equal to expected peak load plus a required reserve margin” would reduce capacity payments by nearly $1 billion. The report noted that the IMM’s recommendation was to rotate the curve halfway toward vertical for the current quadrennial review, while PJM opted for a curve rotated a quarter of the way.

“Use of the VRR curve increased the purchase of capacity [by] 10.1% and increased the total load payments for capacity by $983 million, or an increase of 81.1% compared to a vertical demand curve,” the report says.

Adam Keech 2022-10-18 (RTO Insider LLC) FI.jpgAdam Keech, PJM | © RTO Insider LLC

During an Oct. 18 panel at the Organization of PJM States Inc.’s Annual Meeting, PJM Vice President of Market Design Adam Keech said that a vertical curve would temporarily lead to lower capacity prices, but in the long term, it would replicate the very volatility that led to the creation of the capacity market in 2005. That volatility could lead to more generation owners deciding to retire their units, ultimately driving prices higher.

Though it hailed the shift to basing the MSOC on the ACR going forward, the Monitor that the ACR definition should be reworked to be based on the cost of producing additional capacity. Currently it’s defined in the tariff as the costs of operating a generator for the given delivery year.

“Avoidable costs are the marginal costs of capacity and therefore the competitive offer level for capacity resources and therefore the market seller offer cap. Avoidable costs are the marginal costs of capacity, whether a new resource or an existing resource,” the report says.

The report found that 139,399.5 MW of generation and DR cleared in the BRA, with a reserve margin of 21.6% and a net excess of 7,835.3 MW over the reliability requirement. The net excess increased 175.1 MW up from the 2022/23 BRA, which had an excess of 7,660.2 MW.

The report said that a vertical demand curve would have reduced revenues by 44.8%, bringing the total from auction clearing prices, quantities and uplift from $2,196,444,791 down to $1,212,977,260.

The accuracy of the peak load forecast also had a “significant impact on the auction results,” with the forecast for the third incremental auction being on average 3.1% lower than the forecast for the corresponding BRA. If the forecasted results had been 3.1% lower, total auction revenues would have been $1,729,724,427, a decrease of $466,720,364, or 21.2%, compared to the actual results.

The report found that the 15.5% decrease in the Commonwealth Edison capacity emergency transfer limit (CETL), amounting to 1,058 MW, did not have an impact on the auction results.

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NYISO Identifies 35 Projects for Narrowed SRIS Scope

NYISO has proposed narrowing the system reliability impact study (SRIS) scopes for 35 generation projects in the queue in order to expedite the interconnection process.

The Transmission Planning Advisory Subcommittee on Nov. 1 unanimously recommended that the Operating Committee approve the proposal at its next meeting, currently scheduled for Nov. 17.

The SRIS evaluates the impact of a project on the existing electric system, including future firm transmission projects. As a growing number of projects request interconnection in New York, the ISO has sought to find ways to move the SRIS process along in a timelier manner without jeopardizing grid or project reliability. (See “Interconnection Queue Streamlining,” NYISO Operating Committee Briefs: Oct. 13, 2022.)

Thinh Nguyen, senior manager of interconnection projects, said that certain evaluations in the projects’ studies were removed because they were identified as being “redundant” or could be “conducted at a later stage.” There are also “informal ways” for developers to provide the additional information related to the study, he said.

Not every SRIS scope was narrowed in the same way. Mark Reeder, representing the Alliance for Clean Energy New York, asked how the ISO determined which evaluations to remove from each of the scopes and why they were not removed from every identified project.

Nguyen responded that they went on a “case-by-case” basis because not every scope had a particular evaluation; some projects’ evaluations were already ongoing; and other scopes already completed certain evaluations.

Howard Fromer, who represents the Bayonne Energy Center, asked whether removing the evaluations from the SRIS scopes required modifications or updates to any ISO procedures, manuals and tariffs, or if this was simply within NYISO’s discretion.

Nguyen responded that no modifications or other changes were needed, with the only requirement being OC approval, as well as transmission owner sign off, as the ISO lacks the “unilateral authority” to make these changes outright.

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FERC Orders Clarification in ERO Budget Filing

Citing concerns about NERC’s accounting for costs related to the Electricity Information Sharing and Analysis Center (E-ISAC) in its 2023 Business Plan and Budget, FERC on Wednesday instructed the ERO to submit an array of additional information on the cost by early January (RR22-4).

The commission directed the additional compliance filing as part of its order accepting NERC’s budget, along with the business plans and budgets of the regional entities and the Western Interconnection Regional Advisory Board (WIRAB). NERC’s Board of Trustees approved the final budgets at its August meeting in Vancouver, following what board members called “the most comprehensive budget process” to date at the ERO. (See “Board Approves ERO Budgets,”  NERC Board of Trustees/MRC Briefs: Aug. 17-18, 2022.)

Next year’s NERC budget is set to rise to $101 million, up 13.7% from last year. The total amount includes $38 million for the E-ISAC, including the Cyber Risk Information Sharing Program (CRISP), an increase of 15.8% from the 2022 budget. (See NERC FAC Approves Final 2023 ERO Budgets.) NERC’s assessment will also rise by 11.1% to $87.1 million.

Budgets, Assessments Up Across the Board

Budgets and assessments for the regional entities are set to increase as follows:

WIRAB’s 2023 budget is set to decrease by 3.9% next year to $883,520; its $681,920 assessment represents a 2.4% decrease from last year’s level.

FERC accepted all the budgets in its order, while also granting NERC’s request for a waiver of its Rules of Procedure (ROP) to allow it to use $1 million from its Assessment Stabilization Reserve (ASR) to offset its 2023 assessment.

NERC also requested a waiver of the ROP to allow MRO, NPCC, SERC and WECC to deposit penalty funds received between July 1, 2021 and June 30, 2022 — totaling $23.9 million — into their ASRs. FERC granted this request as well, along with approving WECC’s application to use $595,000 in funds gifted upon the dissolution of Peak Reliability in 2019 for two technology projects included in the RE’s business plan for next year.

E-ISAC Costs Require Follow-up

But the commission’s acquiescence came with strings attached in the form of the compliance filing that FERC demanded within 60 days of the order’s publication. Its direct inspiration is a comment submitted by the Edison Electric Institute in response to NERC’s original filing of the business plans and budgets.

EEI’s comment supported NERC’s budget overall; however, the size of the increase — NERC’s biggest budget hike since 2015 — spurred the organization to call for “a subsequent analysis to ensure the effectiveness of the expenditures.”

Specifically, EEI noted that a significant driver of the growth is the E-ISAC budget, which accounts for $5.1 million of the $12.2 million increase. The institute suggested that “all expenses associated with E-ISAC … should be detailed in separate line items,” and that electric industry stakeholders should also be given enough information to tell “whether other critical sectors are fully funding their participation” when they collaborate with the E-ISAC so that “electricity customers are not solely financially responsible for E-ISAC’s shared functions.”

ERO Enterprise budget (NERC) Content.jpgThe total ERO Enterprise budget, including the regional entities and WIRAB, is set to rise to $250.1 million in 2023, a 10.1% increase over the 2022 budget. | NERC

FERC agreed that its oversight duties would be better served by “additional transparency into certain E-ISAC costs” and ordered NERC to provide information on several aspects of the program’s operations. In addition, the commission asked NERC for data on E-ISAC’s relation to outside partners and vendors.

First, FERC asked for “a detailed explanation of costs attributable to E-ISAC” in light of what it called insufficient transparency about how the ERO allocated direct and indirect costs to the program in the 2023 budget. As an example, the commission listed NERC’s new Business (Information) Technology department, which has a budget item labeled “E-ISAC” but does not specify “whether the technology costs relating specifically to E-ISAC are directly allocated to E-ISAC or whether NERC indirectly allocates these costs among all program areas.”

To address this alleged lack of clarity, FERC asked that NERC explain which of the new department’s costs, if any, are attributable to E-ISAC. If the department’s budget item does not attribute costs directly to E-ISAC, then NERC must explain “why these costs are more appropriately allocated as indirect costs to all statutory program areas.” The ERO must also explain its written policies and procedures that determine how costs are allocated.

FERC also pointed to NERC’s proposed $5.3 million expenditure for capital software investments, $4 million of which is to be funded by loan proceeds. According to NERC, the investments “span across [its] Statutory Program and Administrative Program departments” and represent several cost categories. The commission questioned the assignment of fixed asset costs and ordered the ERO to be clearer about how these funds are to be allocated, as well as its policy on assigning loan funds to program areas and a breakdown of how the $5.3 million are to be distributed.

Concerns over Collaboration Fairness

Along with questions about the direction of funds, the commission raised questions about the E-ISAC vendor affiliate program, a membership plan for suppliers of hardware and software products to the electricity sector. The program provides three levels of annual membership for vendors; higher levels cost more but confer additional benefits, such as access to networking sessions at the GridSecCon security conference or participation in GridSecCon panels.

FERC said it “is generally supportive of increased collaboration between E-ISAC members and the vendor community,” but said it is not clear how the tiered structure supports this goal while preventing participating vendors from engaging in sales and other “business development opportunities.” The commission directed NERC to explain why it chose this structure for the program, how it promotes collaboration and information sharing, and how the ERO provides oversight of the program to prevent business development.

Finally, FERC claimed that NERC’s budget was not sufficiently transparent regarding the division of costs in efforts involving collaboration with the natural gas sector. In particular, the commission focused on CRISP, the operational costs of which are split between program participants and assessment carried out under Section 215 of the Federal Power Act. FERC feared that because natural gas-only companies do not pay Section 215 assessments, they do not contribute to CRISP operations to the degree that their counterparts in the electric sector do.

While FERC acknowledged NERC’s claim that “the natural gas industry provides the funding to support their own collaboration,” the commission also pointed out that NERC has said elsewhere that “natural gas-only participants will also have access to other E-ISAC benefits, such as the E-ISAC portal.” FERC said this makes it unclear whether gas participants will pay for all or only some of their E-ISAC costs. The commission therefore directed NERC to explain what additional costs gas companies incur while participating in CRISP and E-ISAC, and how they fund those costs.

[Correction: An earlier version of this article included a mistaken reference to the location of the NERC board’s August meeting.]

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Texas PUC Briefs: Nov. 3, 2022

ERCOT to Add Reliability Monitor to its Responsibilities

The Texas Public Utility Commission last week approved staff’s recommendation that ERCOT serve as the footprint’s reliability monitor, formalizing a two-year collaboration that has resulted in several enforcement investigations (54248).

The commission agreed to direct ERCOT to assume the reliability monitor duties and responsibilities as part of the consent agenda during its open meeting Thursday. With Chair Peter Lake out on personal leave, Commissioner Will McAdams led the meeting.

PUC staff said ERCOT has for years adopted reliability-related regulations that are found in the organization’s nodal protocols, operating guides and other binding documents. For the past two years, it has worked with the commission’s Division of Compliance & Enforcement to jointly monitor and investigate potential noncompliance with the grid operator’s reliability rules.

As the reliability monitor, ERCOT will gather and analyze data; protect confidential information; provide expert advice to commission staff during the investigation, prosecution and litigation of reliability-related enforcement proceedings; and work under the PUC’s direction.

A spokesperson said the grid operator will need additional staff to perform the monitor’s duties. Its budget will be funded through the system administration fee that has historically included the function’s costs, she said. ERCOT staff will begin performing the function “immediately.”

The Texas Regional Entity had served as the grid’s reliability monitor from 2010 until 2020. The PUC ended its contract with the agency over concerns it wasn’t getting its money’s worth. (See PUC Cancels Texas RE as ERCOT’s Reliability Monitor.)

The Texas RE enforces NERC’s federal reliability and security regulations, which are subject to FERC oversight, in the state. Most entities operating on the transmission system in the ERCOT region are subject to NERC’s standards.

The state’s Public Utility Regulatory Act requires the PUC to adopt and enforce rules related to ERCOT’s reliable operation of the region’s system. It also allows the commission to delegate the responsibility for adopting or enforcing these rules to an independent organization.

ENGIE Case Set for Hearing

The commission approved in part and denied in part ENGIE’s and Viridity Energy Solutions’ (NYSE:ORA) complaint against ERCOT regarding the settlement of ancillary services during the February 2021 winter storm (53377).

Lori Cobos (Admin Monitor) FI.jpgCommissioner Lori Cobos | Admin Monitor

The PUC approved a preliminary order that sets issues to be addressed, but it denied ENGIE’s request to depose commission staff. It also denied its staff’s request for a protective order from providing depositions as being too broad.

“The commission can’t be deposed, given our quasi-judicial role in this matter,” Commissioner Lori Cobos said. She said ENGIE could request to depose specific commission staff by name as fact witnesses, making staff’s request too broad.

The companies allege that the grid operator did not properly credit Viridity for providing responsive reserve service (RRS) during the storm and that ENGIE was assessed $47.7 million in charges for replacement RRS. They argue that Viridity should be credited $67.4 million to $140.6 million for providing RRS and that ENGIE should not be charged for the replacement service.

The commission referred the docket to the State Office of Administrative Hearings (SOAH) to conduct a hearing and issue a proposal for decision to resolve any contested issues.

Entergy Power Plant not Considered

The PUC did not take up Entergy Texas’ (NYSE:ETI-) application to construct its 1.22-GW Orange County Advanced Power Station in Southeast Texas, despite an administrative law judge’s approval of the project (52487).

The ALJ in September recommended the project’s approval but removed a hydrogen component and imposed a cost cap. The project’s costs have already risen from $1.19 billion to $1.58 billion in a year. Entergy’s plans the facility to be able to burn 30% hydrogen upon commercial operation and eventually support 100% hydrogen operation.

“We continue to believe that Day 1 hydrogen co-firing capability for [the facility] is in the best interest of our customers,” Entergy CEO Drew Marsh said during the utility’s third-quarter analysts call Nov. 2. (See related story, Entergy Learning from Florida to Improve Resilience.) He noted that Texas Gov. Greg Abbott has “indicated” his support for the plant’s hydrogen capability.

“Capped hydrogen capability is less than 5% of the total investment, and it provides a critically important option for fuel diversity and ensures the plant’s continued value at the low-carbon future,” Marsh said.

PUC Adds OK to ADER Pilot Project

The commission formally approved ERCOT’s Aggregate Distributed Energy Resource (ADER) pilot project, which was also approved last month by the grid operator’s Board of Directors (53911). (See ERCOT Board of Directors Briefs: Oct. 18, 2022.)

The project will evaluate how ADERs can support reliability, participate in the wholesale market and play a role in emergency situations.

“This is a victory for the stakeholder process all the way around, from the commission to ERCOT staff to the industry stakeholders to the average everyday consumers who were able to participate,” said McAdams, who spearheaded PUC’s involvement in the project with Commissioner Jimmy Glotfelty. “Big things have small beginnings, and I think this is going to be a big thing.”

“I think that this puts us in a driver’s seat of leading again. … We’re going to learn a lot from this,” Glotfelty said.

In other actions, the PUC:

    • denied El Paso Electric’s rehearing request to correct an error in one of its rate schedules. The utility filed an uncontested settlement with other parties to the proceeding in July that was approved by an administrative law judge in September (52195).
    • assessed a $72,000 administrative penalty to South Texas Electric Cooperative for failing to telemeter the appropriate resource status code and for failing to timely and properly assign its ancillary service capacity obligation in 2019 (53691).
    • agreed to open an investigation into Texas Excel Property Management for possible violations related to the denial of tenants’ rights to choose a retail electric provider in ERCOT’s footprint where retail customer choice has been introduced (54225).
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A New Era for Climate Action at COP27: ‘We Will be Holding People to Account’

U.N. climate conferences tend to open with stirring and urgent calls to action, and the 27th Conference of the Parties (COP27), which kicked off Sunday in Sharm el-Sheikh, Egypt, held true to form, with current geopolitical and economic realities challenging the rhetoric.

At last year’s COP26 in Glasgow, Scotland, 193 nations committed to coming to this year’s event with new, more ambitious targets for cutting carbon emissions, but only 29 have thus far delivered on those pledges, said Simon Stiell, the new executive director of the U.N. Framework Convention on Climate Change (UNFCCC).

“Today a new era begins, and we begin to do things differently,” Stiell told delegates at COP27’s opening plenary on Sunday.

“We will be holding people to account, be they presidents, prime ministers or CEOs … because our policies, our businesses, our infrastructure, our actions, be they personal or public, must be aligned with the Paris Agreement and [U.N.] convention. The heart of implementation is everybody, everywhere in the world, every single day, doing everything they possibly can to address the climate crisis.”

Stiell’s top priorities for the conference include across-the-board commitments to steeper emission reductions, solid financial support to help developing countries adapt to and recover from the damages of climate change, and new levels of transparency and accountability.

“Environmental integrity and the reliability of the commitments made are paramount,” he said. “I am not in the habit of rescinding on my word; I firmly expect all parties to act the same way. Stick to your commitments; build on them here in Egypt. I will not be a custodian of backsliding.”

Further, the pull of current political and economic crises — such as inflation, the war in Ukraine, and energy and food insecurity — must not be allowed to slow progress on climate action, said Egyptian Minster of Foreign Affairs Sameh Shoukry, who is also serving as COP27 president.

“If some people think that such challenges will hamper international collective action in the field of climate action, we here in Sharm el-Sheikh need to prove the contrary,” Shoukry said. Conference outcomes must “show the whole world that we are aware of the challenge awaiting us and that we have the political will to counter it.”

He called for “moving from negotiations and pledges to an era of implementation, as well as the acceleration of implementation,” while also “scaling up ambitions according to countries’ capacities and the nature of their resources.”

Alok Sharma, the U.K. official who led COP26, agreed that in the face of ongoing extreme weather events — such as the catastrophic flooding in Pakistan and Nigeria — “we must find the ability to focus on more than one thing at once. … This conference must be about concrete action.”

1.5 Alive, Barely

Whether these strong words will translate into action remains to be seen as the conference unfolds over the next two weeks, with national leaders expected to begin their statements of progress and new commitments on Monday. President Biden is scheduled to be at the conference on Friday.

The legacy of COP26 was to keep the goal of limiting the increase in the average global temperature to 1.5 degrees Celsius alive — barely — and Sharma reported that if all emission-reduction commitments made at that conference were kept, worldwide emissions in 2030 would be about 6 GT less than at present.

“That’s the equivalent of 12% of today’s global annual emissions” but would still result in a 1.7-degree increase in global warming, he said.

A recent report from UNFCCC suggests that those figures may be overly optimistic. According to the report, current commitments from the 193 countries that signed the Paris Agreement could result in a 2.5-degree increase. By 2030, carbon emissions are on track to increase 10.6% over 2010 levels, the report said.

Past 2030, emissions may not increase but still do not achieve the radical and sharp decreases that are needed, the report says. Such figures “could not be sharper, stronger or more sobering,” said Hoesung Lee, chair of the U.N.’s International Panel on Climate Change (IPCC).

Lee sees action on climate change as caught in a self-defeating cycle. “We have the technology and the know-how to tackle climate change, but these options are limited by the availability of finances, [and] adaptation options are limited by global warming levels. … Therefore, the prerequisite to a successful adaptation is ambitious mitigation.

“Adaptation gaps, especially in developing countries, are particularly driven by widening disparities between the cost of adaptation and financing available [for] adaptation,” he said. “We can achieve the greatest gains by prioritizing finance to reduce climate risks for low-income and marginalized communities.”

Fit-for-purpose Finance

Sharma, Shoukry and Stiell joined Lee in urging action to provide developing nations with the hundreds of billions they need to rebuild from the devastating impacts of extreme weather they have sustained to date, commonly referred to as “loss and damage.”

These countries, who produce only a small amount of the world’s greenhouse gas emissions, have long argued that the top emitting countries, like the U.S., should pay restitution.

But climate change negotiations in past decades have been “remarkably polarized, which has slowed down progress” and raised a range of concerns, particularly on finance, Shoukry said.

Developing nations are still waiting on the $100 billion per year that developed nations pledged to help them deploy clean energy technologies, when the original Paris Agreement was signed in 2015, Shoukry said. “The financing currently available focuses on curbing emissions and not adaptation efforts. Also, most of the financing is based on loans,” he said. “We do not have the luxury of continuing this way.”

Solutions must be found that “prove we are serious about not leaving anyone behind,” he said.

Stiell agreed. “We must cement progress on these critical work streams [of] mitigation, adaptation finance and, crucially, loss and damage. We need to enable enhanced finance to flow to addressing impacts. What is said in these negotiating rooms has to be reflected in the urgency of what is happening outside. …

“Let’s look closer at how the global financial architecture can be made fit for purpose in line with the Paris commitments,” he said. (See related story, COP27: Will Countries Step up on Climate, Financial Commitments?)

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DTE Unveils Renewable Energy Plan, Speeds Up Ending Coal Use

DTE Energy (NYSE: DTE) unveiled its latest proposed integrated resource plan Thursday, pledging to end its use of coal by 2035 and go carbon free by 2050.

The utility’s  proposed “Clean Vision Plan,” released in a 141-page report, also calls for DTE to boost its renewable energy generation to 60% by 2040, as promised at its most recent earnings call. (See DTE Energy Pledges Fast-tracked Energy Transition.) CEO Jerry Norcia also said the plan would invest $9 billion into the Detroit area’s economy over the next 10 years.

Under the proposal, DTE will significantly increase its electric storage capacity to 1,800 MW.

Current generation mix (DTE Energy) Content.jpgDTE’s current generation mix | DTE Energy

DTE, the electric generating source for 2.3 million people and businesses in Detroit, unveiled the plan about five months after Michigan’s Public Service Commission approved a similar IRP for CMS Energy (NYSE: CMS).

DTE released its plan shortly after the PSC revised the parameters of IRPs in line with the state’s MI Healthy Climate Plan.

Norcia said across the U.S. and Michigan the energy landscape is changing “as coal gives way to natural gas and renewables to power what we call the modern grid.”

Norcia said DTE intended to cut carbon emissions by 32% in 2023, two years ahead of a similar statewide goal in the state’s MI Healthy Climate Plan. Carbon emissions would be further slashed by 85% by 2035 and 90% by 2040.  In 2017, DTE had called for cutting carbon emissions by 80% in 2050.

Now, the DTE plan calls for eliminating carbon emissions by 2050, the deadline set in the Healthy Climate Plan.

In cutting carbon emissions, DTE plans to end coal use at the Belle River Power Plant by 2026 and repurpose it to run on natural gas.

The 3,280-MW Monroe Power Plant, one of the largest coal-fired generators in the U.S., will close by 2028. The closure could affect the southern Michigan city’s economy.  The Monroe harbor, which has handled coal for the power plant as one its major commodities, has received an $11 million federal grant to help convert part of its piers along Lake Erie to handle wind turbine components.

DTE said it will provide retraining for plant workers and “partner with the local communities.”

DTE’s plan calls for increasing renewable energy production to 15,000 MW by 2042. Renewables currently represent only 10% of the company’s 11,840-MW system capacity, with coal representing 59% and nuclear 22%.

Bob Allison, deputy director of the Michigan League of Conservation Voters, said DTE was falling short in what it should achieve. Blasting DTE for its electric rates and its struggles with power outages during major storms, Allison said, “We are at a pivotal moment in our state’s clean energy future, and DTE must meet the moment with more ambition.”

Reacting to the criticism, DTE spokesperson Cindy Hecht said, “In preparing our Integrated Resource Plan, DTE Electric undertook a year-long, comprehensive analysis that reflected insights shared by the company’s customers and other stakeholders to build the plan, and we look forward to continued collaboration.”

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Texas PUC’s Proposed ERCOT Market Design to be Released Soon

AUSTIN, Texas — Keynoting the Energy Bar Association Texas Chapter’s Energy Symposium last week, Lori Cobos, the only lawyer sitting on the state’s Public Utility Commission, said ERCOT stakeholders will soon get a look at the market’s long-awaited redesign.

“Around Nov. 10,” a consulting firm will release its review of the PUC’s market redesign blueprint, Cobos said, which the commission agreed to almost a year ago. The PUC has since added an open meeting to its calendar for that date. A spokesman confirmed the commissioners plan to take up and discuss the consultant’s report and recommendation.

Expect the recommendations to be heavy on dispatchable generation, which includes the usual thermal resources and energy storage. Since the February 2021 winter storm crippled ERCOT’s system, the PUC, ERCOT and Texas legislators have prioritized baseload generation over renewable resources. (See PUC Forges Ahead with ERCOT Market Redesign.)

“If Texas is to continue to lead the country as an economic powerhouse, that will require a reliable, resilient and affordable supply of power to fuel our economy and serve our growing population base,” Cobos said during the symposium Nov. 1. “Texas must maintain year-round reliability under all weather conditions, and to do this, we will need to drive investment in new and existing dispatchable generation through market-based price signals and a reliability-driven framework.”

She said the market must incentivize “fast-responding dispatchable generation” that can respond to wind’s and solar’s variability and retain the existing baseload generation “that is available 24/7 to meet our continuously growing electricity demand and extreme weather conditions.”

A load-side reliability mechanism, proposed in a study funded by generation heavyweights NRG Energy (NYSE:NRG) and Exelon (NASDAQ:EXC), is expected to be the central recommendation. Referred to as the load-serving entity obligation (LSEO), the study’s authors have said it will directly address resource adequacy concerns by introducing a formal reliability standard and the mechanism to ensure an LRE has sufficient resources to meet this standard.

PUC Chair Peter Lake quickly latched onto the LSEO proposal late last year. The other commissioners at the time offered some pushback but agreed to include it on the new market blueprint.

Indirectly responding to criticism from some that the LSEO would be a “capacity-light” market, NRG’s Bill Barnes, senior director of regulatory affairs, said, “People think, ‘Oh, NRG, they just want a capacity market.’ No, we want a competitive market that can survive through reliability events, so that we can preserve our successful market structure. That’s the No. 1 priority for us.”

Barnes did not mention that the consultant reviewing the PUC’s blueprint, E3 Consulting, is the same firm that produced the NRG-Exelon report. The commission chose E3 over ERCOT’s Independent Market Monitor, the only other bidder on the contract.

Energy consultant Alison Silverstein, a former PUC and FERC staffer, has worked with the Texas Consumer Association (TCA) and ICF International, a global consulting services firm, to produce an analysis on the cost and reliability impacts of ERCOT’s recent and proposed market changes. She said deep concern over “a teeny bit of bias and conflict of interest” of E3’s ability to fairly review the PUC’s proposal led to their own analysis.

“The PUC hired E3, apparently untroubled by that same concern, and E3 went off and did the study, and nobody’s heard anything,” Silverstein said, speaking on the same panel with Barnes.

The commission’s blueprint also includes a backstop reliability service (BRS) and the use of dispatchable energy credits (DECs).

BRS would procure accredited new and existing dispatchable resources as an insurance policy to help prevent emergency conditions. Its principles include nonperformance penalties and clawbacks for noncompliance; deploying resources in a manner that doesn’t negatively affect real-time energy prices; and allocating costs to load based on a load-ratio share basis measured on a coincident net-peak interval basis.

The DEC proposal would establish a dispatchable portfolio standard for certain qualifying generators to create the DECs, which would be bought, sold or traded is the same manner as ERCOT’s existing renewable energy credit program.

“Does our market structure provide the right incentives for reliability?” Barnes asked, referring to the market design discussions. “It’s efficient. It’s cost efficient; brutally efficient. So, you’re getting the lowest-cost solution out of our current market design, but that doesn’t always mean reliability.”

Cobos assured her EBA audience that the commission will take public comment before making a final decision in January. She said the Texas Legislature, which begins its 2023 session on Jan. 10 and runs through Memorial Day, will also provide feedback on the blueprint, “in addition to looking at investments in dispatchable generation.”

PUC’s Market Design Costs

The PUC “had three primary options that have been sitting around, and to date, there has been minimal information released about what the specifics of those proposals were, or what the design and cost and reliability implications of those would be,” Silverstein said.

ICF analyzed the proposed designs using available public information and various models. Based on that, it said none of the current proposals would, by themselves, improve reliability enough to yield one outage every 10 years, the industry’s generally accepted standard of 0.1 loss-of-load expectation (LOLE).

“We thought it was a very reasonable set of assumptions and scenarios and methodology,” Silverstein said.

Texans should expect, on average, about five outages every 10 years (a 0.5 LOLE), ICF said. It noted reliability is expected to further deteriorate by 2030 if no further policy measures are taken.

Calling the LSEO proposal a “California-style redesign” of the ERCOT market, in that consumers would pay more for power plants that might not operate, ICF’s study found it would cost Texans an additional $22.8 billion from 2025 to 2030, including $8.5 billion more in 2025 alone, without significantly increasing the grid’s reliability. It forecast the LSEO would add another 2.5 GW of gas generation by 2030.

ICF said the BRS proposal, based on an energy storage entity’s recommendation, would yield less than two outages a decade (0.17 LOLE) at a total cost of $2.6 billion from 2025 to 2030. It projected the BRS would also retain about 8 GW of capacity that would otherwise retire under the current market construct.

The DEC proposal would cost consumers $1.3 billion during its first three years (2023-2025) but would then reduce the total costs to consumers by approximately $2 billion each year from 2027 to 2030, ICF said. It forecasts DEC, based on an energy storage provider’s recommendation, to bring online 3.4 GW of additional two-hour battery storage by 2030.

“Yes, there’s a wide range of uncertainty around LSEO cost,” Silverstein said during an Oct. 26 virtual press conference unveiling the study. “The one thing that is not uncertain, that is absolutely clear, is the LSEO costs are potentially huge. And as of now, the program is so significantly undefined that there is no way to narrow in the parameter for how expensive it could be or how effective it could be at improving reliability.

“Texans need a reliable grid, but not at any cost,” she said.

New Study on Energy Efficiency, DR

TCA plans to release a companion report later this month comparing the cost and reliability effects of using high levels of demand-side resources to improve reliability, with the results contrasted with its supply-side analysis.

Silverstein called it a follow-up, parallel piece to “the one scenario that the PUC chose not to study.”

“What happens if we actually do what customers do a lot more of with energy efficiency and demand-responsive distributed assets?” she said. “What does that do for reliability and affordability in ERCOT?”

Silverstein said Texas energy efficiency requirements are tied for last among the 28 states with such requirements. “We deliver such minimal energy efficiency to so few Texans, it’s criminal,” she said.

Liz Jones, Oncor’s vice president of regulatory affairs, said she expects energy efficiency to be one of the key issues debated within the legislature next year.

“There is a cottage industry about what kinds of programs are effective and efficiently implemented,” Jones said. “There is always a struggle because when we undertake energy-efficiency measures, we are collecting funds from all customers, and we are dispersing them to the customers who are qualified for the energy efficiency. It turns out it takes a lot of money to weatherize. Is it crucial for the person that lives in that home? Yes, and so we’re going to see a fight, I think, at the legislature about how we spend on energy efficiency.”

“The programs today are all over the map. They are not always focused, and they are tiny,” Silverstein said, agreeing with Jones. “The reason the winter storm caused so much damage is because Texas homes are under-insulated, because Texas heaters are ineffective and because the energy demand before the power started going out was 20% above anything that ERCOT had forecast. That was because of a lack of energy-efficient homes and lack of energy-efficient heaters. We deserve better, both for winter and for summer.”

Market Provides Expert Feedback

Jones and NRG’s Barnes both said market participants need to have a greater role in the rulemaking process. They and other ERCOT participants have seen their input sharply reduced with Senate Bill 2, which passed by last year’s 87th Legislature. The legislation created an independent board at ERCOT and gave more accountability to the PUC.

“One of the issues is how much should market participants — like Oncor; like NRG; like the city of Austin — have in making ERCOT rules. I would contend that you need us,” Jones said. “First of all, we’re free labor. We can provide feedback about how a particular rule would or would not be able to be effectuated in real-time operations or in planning. One of the things that I’m personally very interested in is making sure that the ERCOT rulemaking process, like the PUC rulemaking process, incorporates the feedback of interested parties in making those rules. It’s procedural due process, substantive due process. It’s a sensible way to try to do this.”

“I completely agree with Liz’s comments on Senate Bill 2,” Barnes said. “As a stakeholder in a marketplace, we have a stake in it. We have invested a lot of money [and] people time, and we should have a voice. Our folks are the experts. They’re the ones that turn the wrenches to start the power plants, and ERCOT needs to hear from us.”

Barnes added that he hopes the legislature avoids “tinkering” with market rules that have already passed. He pointed to the PUC’s weatherization requirements for power plants and transmission facilities as an example of changes that have already been instituted and that work.

“We like to have rules that are predictable and are certain to be done,” he said. “It would be great for the legislature to let that process play out, but they’re not going to. I would hope that there will be a lot of robust debate and discussion at the legislature, but let’s let the process play out at the PUC where the experts are. It will take time. It’s not like we’re going to be to snap our fingers and have an answer. These things are complicated, and we want to make sure we get them right.”

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Duke CEO: IRA Tax Credits Will Offset 15% Corporate Income Tax

Duke Energy (NYSE:DUK) sees the U.S. clean energy transition — and clean energy tax credits from the Inflation Reduction Act — as providing growth and profit drivers for its regulated utility business, even as the company moves ahead with the sale of the 3.5-GW portfolio of its commercial renewable energy business.

Speaking during the company’s third-quarter earnings call Friday, CEO Lynn Good reported that Duke’s board had authorized the sale of the utility’s commercial and distributed renewable business. The sale will allow the company to focus on its “core” regulated electric and gas utilities, she said.

“We have indications of interest — robust indications of interest — from credible counterparties and have a high degree of confidence we will transact on this business,” Good said. A “definitive” announcement could come in the first quarter of 2023, with the sale closing “as early as mid-year,” she said.

The commercial portfolio includes 1.53 GW of solar, 1.96 GW of onshore wind and 20 MW of battery story, according to company figures.

Lynn Good (Duke Energy) FI.jpgDuke Energy CEO Lynn Good | Duke Energy

As previously announced during Duke’s second-quarter earnings call, the proceeds from the sale will be used to pay down the utility’s debt “and allow us to fund our clean energy transition,” Good said. (See Duke Considering Sale of 3.5-GW Portfolio.)

The IRA’s production and investment tax credits will also act as a counterweight to the law’s 15% minimum corporate tax rate, which, Good said, is not expected “to have a material impact on our cash flows.” According to utility estimates, Duke could be eligible for “several hundred million dollars” per year from the IRA’s nuclear production tax credits, beginning in 2024.

Producing about half of the utility’s electricity in the Carolinas, Duke’s nuclear fleet includes 11 units totaling 10.7 GW of capacity, all located at six sites in the two states, according to the company’s website.

The utility is also estimating that the solar production tax credit will be worth about $60 million per year given the 13 to 17 GW that it could be putting on its system over the next decade. Potential investments in energy storage, estimated at $2.5 billion to $4.5 billion, would be eligible for the 30% investment tax credit for standalone storage, according to utility figures presented during the call.

Besides providing hefty tax write-offs, Good said the tax credits would be “returned to our customers, lowering our overall cost of service and providing for a more affordable energy transition.”

Duke is also capitalizing on the growth of electricity demand from new clean technology manufacturing across its service territory. Good pointed to recent announcements, such as the multibillion-dollar semiconductor plant Wolfspeed is building in North Carolina, and BMW’s expansion into electric vehicles and EV batteries in South Carolina.

Inflation, Supply Chains

With such positive business indicators, including ongoing population increases in its service territories, Good said the utility is projecting an earnings growth rate of 5 to 7% from 2023 to 2027.

The company reported net income of $1.356 billion ($1.78/share) for the quarter, compared to $1.435 billion ($1.88/share) for the same period last year.

Good acknowledged that Duke, like other businesses across the country, is facing headwinds in terms of both inflation and supply chain constraints. To counter inflation, the company has upped its cost-cutting efforts from $200 million to $300 million, Good said.

Responding to analysts’ questions, she said the cuts will come from digitalization initiatives that will “streamline our governance processes and reporting processes.” Duke is also “looking at supply chain and … other things that we could do to potentially move [costs] out of [20]23,” she said.

At the same time, the utility is countering supply chain constraints via multiyear contracts with key vendors. “We have confidence around supply into [2026] and beyond, with options to continue. We’re putting similar arrangements in place for battery storage,” Good said.

Duke’s long-term plan for the energy transition calls for $145 billion in capital investments over the next 10 years, with $75 billion earmarked for grid investments, $40 billion for “regulated zero-carbon generation” and $5 billion for “hydrogen capable” natural gas generation.

Carbon Plan Update

But Duke’s regulatory landscape, particularly in North Carolina, is still uncertain as the utility works through its compliance with H.B. 951, passed in 2021, which requires the Utilities Commission to approve a plan that will cut the state’s carbon emissions 70% by 2030. The commission asked Duke to draft the plan, which under the law must be approved by the end of the year.

Submitted in May, Duke’s draft plan includes the closure of 4.9 GW of coal and the addition of 5.4 GW of solar, but also calls for 3.5 GW of new natural gas generation. The plan also includes alternative pathways to the 70% reduction that would take two to four years longer. (See Duke Files Carbon-reduction Plan for North Carolina Utilities.)

Environmental and clean energy groups and state Attorney General Josh Stein have roundly criticized Duke’s plan and submitted alternatives of their own. But following recent series of public hearings, Duke filed a proposed order for the NCUC to approve its plan, and Good remains confident.

“This process is something that looks reasonable and somewhat predictable to us,” she said Friday. “The solar industry is interested in more solar; the industrials are interested in low prices. Low-income [organizations] are interested in the impact to low-income [customers]. The attorney general and the environmental community want us to go as fast as we can to reduce carbon [emissions].”

Good said that the comments and testimony from such stakeholders provide “fertile ground for the commission to make decisions” and defended the company’s approach.

“In the near term, it’s all about solar and battery [storage], and we have time on the long term to make decisions about some of the more difficult [technologies]: pumped storage; [small modular nuclear reactors]; offshore wind. So, we think there is strength to our recommendation to use the next couple of years to look at development on those key technologies so that we’re prepared by the middle of the decade to make the decisions about where to go.”

In particular, Good said, the company is in “evaluation mode” on offshore wind.

“It’s a renewable resource, but … we also recognize it’s expensive. It has transmission requirements, especially here in the Carolinas where you’ve got to get the power to the load centers that are further west than the coast,” she said. “The approach we’re taking is one of studying and learning more and also allowing the commission and stakeholders and the communities that could be impacted by both offshore and onshore transmission to be involved.

“We will not move first, and we will not move outside of the regulated business,” Good said. “The risk [versus] reward for investors and customers has to be appropriate for us to move forward.”

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Vistra’s Generation Produces During Texas Summer

Vistra (NYSE:VST) said its generation fleet provided 96% commercial availability during Texas’ record-breaking summer, helping smooth the volatility of fuel prices, weather and rising inflation.

CEO Jim Burke told financial analysts during the company’s third-quarter earnings call Friday that its thermal fleet reached maximum capacity on July 13, when wholesale prices reached the $5,000/MWh cap three times.

“A well maintained fleet is key to delivering reliable power for our customers and our communities and ensuring value is captured during these weather events,” Burke said.

Vistra reported quarterly earnings of $1.04 billion as measured by adjusted EBITDA from ongoing operations, as compared to $1.19 billion for 2021’s third quarter. The company uses adjusted EBITDA as a performance measure because, it says, outside analysis of its business is improved by visibility into both net income prepared in accordance with GAAP and adjusted EBITDA.

Burke said management has been pleased with how its Vistra Zero assets performed this summer in Texas and California. It is attempting to extend by 20 years the operating licenses at generation subsidiary Luminant’s Comanche Peak Nuclear Power Plan. That would keep the 2.4-GW plant’s two units operating until 2050 and 2053.

“We continue to see how important a role our diverse set of assets are playing throughout the U.S. and ensuring reliable, affordable and sustainable power,” he said.

The Irving, Texas-based company said its full-year results are tracking at the midpoint of their $2.96 billion to $3.16 billion guidance. It is amid an upsized $3.25 billion share repurchase program, having bought back about $2.05 billion in outstanding shares (18%) as of Nov. 2.

Vistra’s share price lost 40 cents on Friday, closing at $22.85.