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November 18, 2024

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PJM MRC/MC Briefs: Feb. 24, 2022

Max Emergency Changes

Stakeholders expressed concerns at last week’s Markets and Reliability Committee meeting over a PJM plan to address the extension of a temporary change to maximum emergency status for gas combustion turbines and steam generators.

Chris Pilong, of PJM’s operations planning department, reviewed proposed revisions to Manual 13: Emergency Operations in a problem statement and issue charge. To address concerns with fuel security and new emission standards in states that emerged in recent months, Pilong said, PJM made a temporary change to section 6.4 of Manual 13 in a “note” to modify the remaining hours under which a resource may be offered as maximum emergency generation.

Chris Pilong-2018-12-11-(RTO Insider LLC) FI.jpgChris Pilong, PJM | © RTO Insider LLC

The changes, which were endorsed in October, state that PJM may request a generation owner to move steam units, which are mostly coal-fired, into the maximum emergency category if their remaining run time falls below 240 hours, or 10 days. The units could be restricted from operating during that time unless required to meet reliability needs for the grid. (See Global Fuel Supply Prompts PJM Manual Changes.)

Units could remain in maximum emergency status until their fuel inventory rose above 21 days, or 504 hours, Pilong said, and the designation would only be implemented to address concerns with local or regional reliability resulting from fuel supply shortages. The previous run-hour threshold for maximum emergency was 32 hours.

Pilong said the manual change is set to expire April 1, but it needs to be extended to give PJM and stakeholders more time to work on a permanent solution. Additional work is being requested to take place under a new problem statement and issue charge titled “Max Emergency Changes for Resource Limitations.”

The issue charge calls for reviewing and modifying existing rules in response to concerns with the fuel and non-fuel supply chain, as well as the increasing environmental restrictions on generators that are creating challenges with managing run hours. Pilong said PJM wants to spend four months working on the issue in the Operating Committee and have a solution in advance of the summer 2022 peak period.

Bruce-Susan-2020-02-20-RTO-Insider-FI-1-1-1-1.jpgSusan Bruce, PJM ICC | © RTO Insider LLC

“We want to allow PJM and stakeholders to take a step back and take a more detailed look at Manual 13 and make sure we have the right changes and have those discussions,” Pilong said.

Susan Bruce, counsel to the PJM Industrial Customer Coalition (ICC), said she was concerned over what units the rules will apply to. It will be important for PJM and stakeholders to “take a big picture view” in discussions for any changes, she said.

“There are some really big issues that are going to be within this work effort that have implications for the nature of capacity,” Bruce said. “We don’t want to make decisions here that have ramifications in other places or that the work goes by the wayside because of efforts in other task forces.”

Independent Market Monitor Joe Bowring said stakeholders should keep in mind scenarios in which a lack of fuel or other consumables resulted from contractual issues that were theoretically controllable by the generation owner and how those situations should be treated differently compared to supply chain issues.

Bowring-Joe-2019-02-06-RTO-Insider-FI-1-1-1.jpgPJM Monitor Joe Bowring | © RTO Insider LLC

Bowring also requested clarification of what PJM intends to include in the definition of “running for reliability” in the issue charge.

Pilong indicated that PJM will respond to the requests.

John Rohrbach, representing Southern Maryland Electric Cooperative, said resources following PJM’s dispatch while also trying to preserve themselves for a reliability event and reserve run hours could experience a “conundrum” through the language in the issue charge.

“It can create a challenge for a resource to guess when there’s going to be an event and to take itself out to procure fuel in advance of a switching event,” Rohrbach said.

Pilong said Rohrbach’s point is included in the expected deliverables of the issue charge for education on existing tariff language regarding unit eligibility and any practices and analysis for scheduling resources in max emergency.

Stakeholders will vote on the issue charges at the March 23 MRC meeting.

CCSTF Sunset

Melissa Pilong of PJM presented a first read of the Capacity Capability Senior Task Force’s (CCSTF) sunset. Pilong also presented the final report of the task force’s work completed.

The task force was originally created in March 2020 to consider using effective load-carrying capability (ELCC) to set the capacity value of limited-duration resources such as battery storage.

Stakeholders ultimately endorsed a joint proposal in September 2020 to use the ELCC method to calculate the capacity value of limited-duration, intermittent and combination (limited-duration plus intermittent) resources. FERC approved PJM’s proposal in August. (See FERC Accepts PJM ELCC Tariff Revisions.)

Pilong said work originally endorsed by stakeholders for a second phase of discussions has been moved to the Resource Adequacy Senior Task Force. The additional work includes a discussion of other rules or rule changes that may be necessary for limited-duration resources to participate in energy and ancillary service markets.

“It just made sense with all of the work that paralleled a lot of the efforts,” Pilong said.

The committee will be asked to endorse the task force sunset at its March meeting.

Minimum Run Time Guidance

Tom Hauske, principal engineer in PJM’s performance compliance department, reviewed a proposal that includes adding language to Manual 11: Energy and Ancillary Services Market Operations to address pseudo-modeled combined cycle minimum run time guidance.

Pseudo-modeled combined-cycle unit (PJM) Content.jpgExample of a pseudo-modeled combined-cycle unit. | PJM

Hauske said market sellers can model a combined cycle generation unit as multiple “pseudo units” that are made up of a single combustion turbine and a portion of a steam turbine. But he said the potential exists for one or more of the pseudo-modeled units to operate for a period beyond the minimum run time parameter limit compared to an identical non-pseudo-modeled combined cycle unit if the market units of a pseudo-modeled combined cycle unit are dispatched at different times because the steam turbine takes extra time to reach operative levels.

Hauske said the proposed solution calls for adding language to Manual 11 to require market sellers to update the minimum run time of any subsequent pseudo-modeled unit to remove the associated steam turbine start-up time included in the parameter limit when it’s dispatched.

PJM removed language calling for “hourly” updates of the minimum run time parameter in order to avoid creating a “compliance trap” for market sellers who have several pseudo-modeled combined cycle units.

Hauske said PJM wants to have a final endorsement by the March 23 MRC meeting because the RTO’s unit-specific parameter adjustment process started Monday. PJM must provide a determination on the requests by April 15.

PJM will provide guidance developed in the initiative to any pseudo-modeled combined cycle unit requesting an adjustment the review period, Hauske said, or to existing pseudo-modeled combined cycle units with an approved unit-specific minimum run time parameter.

Manual 18 Revisions

Jeff Bastian, senior consultant in PJM’s market operations department, provided a first read of revisions to Manual 18: PJM Capacity Market to conform with several recent FERC orders. The changes from the orders included:

  • revisions to the application of the minimum offer price rule, which became effective by operation of law in September when the commission deadlocked (ER21-2582);
  • an October compliance filing to amend several sections of Attachment DD of the tariff establishing a replacement market seller offer cap (EL19-47);
  • restored tariff provisions restoring the prior backward-looking energy and ancillary services (E&AS) offset for the 2023/24 Base Residual Auction and beyond (EL19-58); and
  • the removal of the 10% cost adder for the reference resource used to establish the variable resource requirement curve (ER19-105).
<img src="https://rtowww.com/wp-content/uploads/2023/06/140620231686782139.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

Jeff Bastian, PJM

” data-credit=”© RTO Insider LLC” data-id=”8009″ style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: right; width: 200px;” alt=”Bastian-Jeff-2019-03-06-RTO-Insider-FI” data-uuid=”YTAtNTUxNzU=” align=”right”>Jeff Bastian, PJM | © RTO Insider LLC

Bastian said language in section 3.3.2 was updated to reflect that the net E&AS of the reference resource combustion turbine will be calculated using the forward-looking methodology with application of the 10% adder for only the 2022/23 delivery year. The net E&AS will be determined using the historical approach and without application of the 10% adder for all other delivery years.

The revisions also delete language in section 5.4.5.2 describing the consequences of accepting a state subsidy after electing the competitive exemption or certifying that a resource is not state-subsidized.

“These are all conforming changes and the changes are all to be made effective with the 2023/24 BRA, which is scheduled to be conducted very shortly,” Bastian said.

A final vote on the changes is scheduled for the March 23 MRC meeting.

Manual First Reads

PJM staff presented several manual changes resulting from the periodic review for first reads. They included:

MRC Consent Agenda

Members unanimously endorsed two manual revisions as part of the MRC consent agenda, the only voting items at the meeting. They included:

  • conforming revisions to Manual 27: Open Access Transmission Tariff Accounting related to a recent FERC order in response to industrial customers’ protest of PJM’s proposed revisions to its administrative rates. The revisions included reorganized wording to distinguish between administrative rates and pass-through rates, and a new section to only be reconciliation for transmission owner scheduling system control and dispatch service.
  • revisions to Manual 40: Training and Certification Requirements resulting from the periodic review. The change included the addition of Maureen Curley as manager of PJM’s state and member training department. Curley replaced Michael Sitarchyk who retired as manager earlier this year.

MC Consent Agenda

Stakeholders unanimously endorsed one set of revisions clarifying fuel-cost policy standards in Manual 15 and Schedule 2 penalty language of the Operating Agreement as part of the consent agenda at last week’s Members Committee meeting.

The changes require that generation unit market sellers verify that all intraday offer triggers are specified in the unit’s fuel-cost policy. The Manual 15 updates include changes to the intraday update triggers. Fuel-cost policies will require providing a fuel price that can be calculated by the Monitor or PJM “after the fact with the same data available to the generation owner at the time the decision was made and documentation for that data from a public or a private source.”

The proposal was endorsed at the January MRC meeting and will take effect upon approval by the PJM Board of Managers and FERC. (See “Fuel-cost Policy Standard Clarifications Endorsed,” PJM MRC/MC Briefs: Jan. 26, 2022.)

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Changing Grid, State Policies Favor Western RTO

If history is any guide, any attempt to form a West-wide RTO would seem doomed to failure. But now the creation of such a market appears almost inevitable.

In the two and a half decades since the first try at creating an organized market in the Western Interconnection, multiple initiatives have faltered as utilities and their state regulators resisted the idea of turning over control of the grid to a central operator.

Now CAISO, SPP and the Western Power Pool (formerly the Northwest Power Pool) simultaneously maneuver to organize the Western electricity sector, and conditions finally seem ripe for change.

That was the view shared by the four industry insiders speaking during the first panel of a virtual conference hosted by the Western chapter of the Energy Bar Association on Thursday.

“The West has had plenty of fits and starts in this area over the last two decades or so, but there are several things that are happening today that I think are likely to make this time different,” panel moderator Brian Cole, general manager of resource management at Arizona Public Service, said in opening the panel. “These include the need for clean energy integration, reliability and affordability, not to mention some state mandates that require [adoption of organized] markets in those particular states by the end of the decade.”

Providing a rundown of the West’s failed efforts was former Bonneville Power Administration (BPA) executive Steve Kerns, now senior technical adviser for the Public Generating Pool, an association of 11 publicly owned utilities in the Pacific Northwest. He tallied off IndeGo (1995-1998), RTO West (2000-2004), Grid West (2004-2006) and NWPP’s MC initiative (2012-2016), which sputtered in the face of growing interest in CAISO’s lower-cost Western Energy Imbalance Market (WEIM).

CAISO’s three-year attempt to regionalize its own market stalled in 2018 after stakeholders and California legislators failed to resolve concerns over the ISO’s governance, which is subject to oversight by California officials. (See CAISO Expansion Bill Dies in Committee.)

Kerns pointed out that organized electricity market design is fundamentally rooted in NERC’s Reliability Functional Model, which envisions market structures that employ shared transmission planning, a single tariff and transmission service provider (TSP), a single balancing authority and a central market operator.

But implementing those has proved challenging in the West, Kerns said. For instance, shared transmission planning introduces the problem of how to allocate costs for new projects that may provide uneven benefits. Similarly, a single tariff will likely result in cost shifts for existing transmission, forcing some entities to fund transmission from which they derive no benefit.

Additionally, one of the region’s largest transmission owners, BPA, faces statutory restrictions on transmission cost sharing, as well as on its ability to cede control of its lines to another TSP.

Furthermore, the NERC model’s call for a single BA has long cut across the desire for local control in a region with dozens of BAs of varying size. Finally, as Kerns noted, the estimated cost of standing up a central operator has caused “sticker shock” among stakeholders, as in the case of the NWPP MC effort.

‘Dramatic Shift’

But the changing energy landscape in the West could erode much of the resistance to an RTO, Kerns said.

Like Cole, Kerns pointed to the favorable impact of state clean energy policies, which simultaneously drive deployment of variable renewable resources and retirement of fossil fuel plants but also increase stress on the grid and raise concerns about regional resource adequacy.

“There’s also been an increase in independent power producers that are developing renewable generation at locations distant from load centers that require substantial investments in transmission,” along with a growth in large power users that seek to be served by renewables, Kerns said.

In the Northwest, the power industry confronts a trend of decreased flexibility from the region’s massive hydroelectric network, which is subject to greater operational restrictions to protect endangered species while at the same undergoing changes in streamflow patterns because of climate change.

Lastly there’s the “missing money” problem, Kerns said. “This is the perception that there are inadequate incentives for market participants to develop capacity resources that will provide sufficient capacity and energy to meet demand. And the belief is that if you create an organized market with the correct price signals, that could help resolve that issue.”

Phil Pettingill, director of regional integration at CAISO, agreed with his fellow panelists that a “dramatic shift” to renewables in the Western Interconnection has sparked renewed interest in a Western RTO.

“What we’ve already seen is wholesale electric markets can really, really help in terms of the integration of these renewables,” Pettingill said. “In this footprint, we have now about [38] balancing areas, and so they’re all operating basically independently, and one of the benefits we have with wholesale market is [to] actually start to integrate that operation and look at being able to facilitate a much more efficient dispatch in the system.”

And while a real-time market such as the WEIM provides a foothold, Pettingill noted that real-time transactions represent less than 5% of the energy delivered in CAISO, indicating the “value” of adding day-ahead trading to the market, as the ISO is planning to do with its extended day-ahead market (EDAM) initiative.

“It is in the day-ahead where we actually decide which generation resources will be put online, in order to match or work with the renewable fleet that’s now expanding,” he said. “It also gives us an opportunity then to optimize the transmission that’s being used across that larger footprint, because multiple balancing areas across multiple states are now working together.”

Because they often operate at zero marginal cost, renewables are typically dispatched ahead of other, greenhouse gas-emitting resources.

“So it’s not only the economic benefit, but also the environmental benefits that come from the success of the Western Energy Imbalance Market,” Pettingill said.

The West will ultimately “land” with an RTO, Pettingill thinks, “but that’s down the road. If there’s one thing we’ve seen in the Western Interconnection, things go incrementally.”

That incrementalism will entail “layering” new services onto the WEIM, such as EDAM, eventually leading up to inclusion of transmission planning in a full RTO, he said.

Competitive Field

A layered approach is what SPP envisions for the Markets+ program it plans to offer on top of other services it’s already providing in the West.

SPP is currently reliability coordinator for 11 entities in the Western Interconnection, and its Western Energy Imbalance Service (WEIS) has seven participants, many of whom plan to join the full RTO. In addition, the Western Power Pool last year selected SPP to operate the Western Resource Adequacy Program (WRAP), whose reach will extend across much of the West when it launches its nonbinding RA program later this year. (See NWPP Rebrands as Western Power Pool.)

Like CAISO’s EDAM, SPP’s Markets+ will add a voluntary day-ahead option to the RTO’s WEIS, Kara Fornstrom, SPP director of state regulatory policy, explained. Markets+ will also be made available to participants in the WRAP, putting it in direct competition with the WEIM.

“If you’re in the EIM and want to join Markets+, you’ll have to leave the EIM to do so,” Fornstrom said.

In developing Markets+, Fornstrom said, SPP identified three “buckets” that it thinks rekindled the West’s interest in “market evolution”: economics, reliability and the need to integrate clean energy resources. She touted SPP’s experience in the third category.

“SPP was the first RTO to have wind as our primary fuel resource. … Last year it was 36% of our total,” she said. “We’ve got all of that energy into our system — a lot of it — because of our transmission availability, data transmission planning and our investment in transmission, along with our established cost allocation principles.”

All three panelists agreed that governance remains a key impediment to forming a full RTO in the West, but Fornstrom, a Wyoming Public Service Commissioner before joining SPP, sees a positive development on that front.

“I think it’s hard to overstate the positive impacts that the WRAP governance structure has made for the West,” Fornstrom said, referring to the progress WPP and its stakeholders have made in developing the program’s oversight bodies. “It’s helped us come to the first time [of] being able to do something on a wide regional basis. And that really should not be overlooked.”

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ERCOT Technical Advisory Committee Briefs: Feb. 23, 2022

Stakeholders Delay Decision on Changes to RUC Usage

AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week agreed to table discussion on a proposal to reduce the offer floor for reliability unit commitments (RUC) and remove opt-out provisions, holding its comments on the process until a March 10 workshop.

Despite pressure from the Texas Public Utility Commission to move quickly on market changes, commission staff said during Wednesday’s meeting that they were amenable to tabling the proposed revision request (NPRR1092) given the substantive comments the proposal has generated.

“The use of RUC has changed over the last year. If we take a month to table, we might be able to come up with some middle ground,” said Eric Goff, representing residential consumers.

Stakeholders have complained about ERCOT’s use of RUCs since last summer as part of the grid’s conservative operations management. They have said deploying more reserves to build up a healthy reserve margin only increases the wear and tear on generators not designed for frequent operations and hastens their retirements.

The subject quickly came up last week during a panel discussion on thermal generation as part of Infocast’s ERCOT Market Summit.

“We used to use RUCs for reliability. Now, it’s become commonplace way for ERCOT to provide an extra cushion of reserve margin,” said Michele Richmond, executive director for the Texas Competitive Power Advocates trade association. “It’s a problem we hope to see that rectified … so [gas units] come online in a manner they were supposed to run.”

“The use of RUC is really a symptom,” Calpine’s Brandon Whittle said. “It’s a symptom of a broken market design.”

RUC Resource Hours (London Economics) Content.jpgERCOT has made heavy use of RUCs to increase its online reserves. | London Economics

In a study contracted by Vistra, Texas’ largest generation owner, London Economics said that 96% of RUC commitments last year were instructed to maintain additional online reserves and not for resolving local issues. The consulting firm said that were the RUC offer floor to be lowered from $1,500/MWh to $75/MWh, as NPRR1092 would mandate, RUC capacity offers would be dropped down in the dispatch stack.

London Economics said that since June, system prices have only exceeded the $75/MWh threshold for more than 200 hours, or about 5% of the time. With the change in position, it said, more “out of market” RUC capacity would be dispatched, displacing other economic offers and leading to a lower clearing price.

It also said that were the lower RUC offer floor to increase the amount of energy produced by RUC resources, the real-time deployment price adder and the operating reserve demand curve (ORDC) would both be negatively affected.

Shell Energy’s Resmi Surendran filed extensive comments opposing NPRR1092, asking her fellow stakeholders to “carefully consider” the proposed changes’ unintended consequences.

“It is important to determine the need for the proposed changes in light of the impacts of, and expected market participant behavior changes that will result from, the market design changes that have already been directed by” the PUC, Surendran wrote.

She said Shell’s comments will show why reducing the RUC offer floor would have been a possible solution if ORDC changes were not possible; why the reduction is not needed to address Independent Market Monitor-identified incentive problem; and a possible alternative if $1,500/MWh is considered a high offer floor for RUC resources.

Members Approve Firm Fuel Measures

Committee members endorsed a pair of measures that would create a firm fuel product, as directed last year by Texas lawmakers and regulators. (See “Staff Rushes Firm-fuel Product,” ERCOT Technical Advisory Committee Briefs: Jan. 31, 2022.)

NPRR1120 would create a firm fuel supply service (FFSS) designed to provide additional grid reliability and resilience during extreme cold weather and to compensate generators that meet a higher resilience standard in the face of a natural gas curtailment or other fuel supply disruption. The PUC ordered that the standalone, auction-based product be procured similarly to ERCOT’s black start program and serve as a stopgap should weatherization not be incorporated into a load-serving entity’s obligation.

The change has a narrow scope so necessary changes can be made to ERCOT’s settlement and billing system first in meeting the 2022-2023 winter deadline. The grid operator said in a filing with the PUC that if it meets the deadline, it would be the first ISO or RTO with a firm fuel product.

Staff said stakeholder concerns regarding qualifying technologies, pricing methods and desired FFSS quantities will be addressed as part of a larger discussion with the PUC and during the development of an FFSS request for proposals that will be issued later this year.

Resources providing FFSS would need to meet technical requirements specified in the proposal and also be prepared to deliver during fuel supply disruptions. A qualified scheduling entity representing an FFSS resource would, when deployed by ERCOT, have to restore its firm fuel service capability within the RFP’s restocking period.

Demand Control 2’s Chris Hendrix, representing the retail segment, cast the lone dissenting vote. “This is moving us to a capacity market,” he said.

Hendrix also opposed the accompanying other binding document change (OBDRR039) that would remove FFSS-deployed resources’ high sustained limits from the ORDC’s reserve calculation. He was joined by South Texas Electric Cooperative (STEC) and Golden Spread Electric Cooperative.

STEC’s Clif Lange said “it seems kind of odd” that the measure’s language would pull assets that already have firm-fuel capability from the ORDC’s reserves calculation.

“I think the assumption is that those assets would have been able to operate on their alternate fuel, but for the FFSS payments, and I don’t know that that’s a correct assumption,” he said. “It’s not logical to conclude that FFSS deployments are an out-of-market action.”

IMM Carrie Bivens, who suggested the OBDRR’s ORDC language, said she looked at the issue differently.

“It’s not so much whether or not they would have been there without the service,” she said. “The fact that if there’s a small number of resources that are getting the side payment, then they really have no costs. And you’ve got other resources that are not allowed [side payments] because they are generating and providing a reliability service to the event and they’re not being compensated appropriately on the scarcity pricing.”

The revisions’ quick development and passage drew praise from American Electric Power’s Richard Ross.

“I never would have believed the revision request would have appeared to come through as easily as it did,” he said. “I would have expected a lot more bloodletting.”

In recognition of staff’s ability to incorporate stakeholder feedback into the final proposals, Ross promised ERCOT staff working on NPRR1120 a Richard Ross Gold Star Award. Ross does not take dispensing the award lightly.

“It’s a very sought-after award. It’s something people can put on their performance reviews and comes with a certificate of authenticity,” Ross said, his tongue apparently planted firmly in cheek.

The TAC also approved:

    • NPRR1097, which would create reports posted three days after each operating day that document forced outages, maintenance outages and forced derates of generation and energy storage resources.
    • A Planning Guide revision (PGRR095) that would establish minimum deliverability criteria over the entire real power capability range of each ERCOT resource whose output is primarily within the grid operator’s control through dispatch instructions.

ERCOT to Resume In-person Meetings

The TAC’s next meeting, rescheduled from March 23 to March 30 at ERCOT’s new MET Center facilities, will mark the resumption of in-person stakeholder committees.

The grid operator said Friday that all other in-person stakeholder meetings can resume in April. Voting members will still be able to participate and vote remotely and be counted toward the quorum.

The Board of Directors will hold the first in-person meeting at ERCOT’s new facility March 7 and 8.

Staff said they continue to take into consideration its Travis County COVID-19 guidelines and will issue updates accordingly.

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MISO, SPP Regulators to Engage on Tx Cost Allocation

MISO and SPP state regulators plan to ensure they are involved in the grid operators’ ongoing discussions about sharing costs from their joint targeted interconnection queue (JTIQ) study.

The RTOs last month identified a $1.755 billion portfolio of seven suggested projects. The portfolio would deliver $724 million and $247 million of adjusted production cost (APC) benefits to customers in the MISO and SPP footprints, respectively, with a cumulative benefit-to-cost ratio of 0.56. (See MISO, SPP Roll out $1.755B Joint Tx Portfolio.)

The JTIQ study team is finalizing its report and plans a series of cost-allocation workshops through midyear. Once it has agreed on a cost-sharing mechanism, it will be filed for approval with FERC.

“Future comments to FERC need to be approved. I see us being involved in every meeting moving forward,” Ryan Silvey, chair of the Missouri Public Service Commission, said during the Seams Liaison Committee’s (SLC) meeting Feb. 22. Cost allocation is “something that we continue to talk about pretty much every time we get together.”

“The biggest knot to untie is cost allocation,” South Dakota Public Utilities Commissioner Kristie Fiegen said, noting differences between the RTOs’ stakeholder processes. “That’s been some of the issues the last few years. We just need to ensure we have a clear understanding of what that looks like in the near future.”

The SLC, comprising members from the Organization of MISO States and SPP’s Regional State Committee, also discussed early results from a working group inventorying rate-pancaking types along the MISO-SPP seam. Grandfathered agreements that result in “hundreds of megawatts flowing across the seam” remains an issue that hasn’t been addressed yet, said Marcus Hawkins, OMS’ executive director.

The working group and the SLC will regroup May 18 for additional discussion on pancaking issues.

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Fierce Bidding Pushes NY Bight Auction to $4.37 Billion

Six companies offered a record $4.37 billion for 5.6 GW of offshore wind capacity in the New York Bight Friday after three days of fierce bidding.

The bids for the six sites, in one case topping $1 billion, even exceeded previous federal auctions for offshore oil and gas leases, according to the Interior Department’s Bureau of Ocean Energy Management (BOEM). The average cost per acre for the auction — $8,837 — was more than eight times the $1,083/acre average in BOEM’s 2018 auction for three sites off the Massachusetts coast, which totaled $405 million.

Interior Secretary Deb Haaland hailed the auction results as evidence that “the enthusiasm for the clean energy economy is undeniable, and it’s here to stay.”

The auction sites in the Bight — a bend in the coast of New York and New Jersey — vary from 20-69 nautical miles from shore, with minimum depths of 31 to 50 meters and maximum depths of 46 to 63 meters.

Covering more than 460,000 developable acres, the six sites have the potential to generate more than 19 million megawatt-hours of electricity per year, enough to power close to 2 million homes, based on BOEM’s estimate of 3 MW/sq km. The 5.6 GW of capacity represents more than one-sixth of the 30 GW of offshore wind President Joe Biden wants online by 2030.

In descending order, the provisional winning bidders and bids are:

      • Bight Wind Holdings | $1.1 billion | 1,387 MW
      • Attentive Energy | $795 million | 964 MW
      • Atlantic Shores Offshore Wind Bight | $780 million | 924 MW
      • OW Ocean Winds East | $765 million | 868 MW
      • Invenergy Wind Offshore | $645 million | 934 MW
      • Mid-Atlantic Offshore Wind | $285 million | 523 MW

The online auction, which began Wednesday with 25 eligible bidders, was a rollercoaster ride for the nascent industry, with bids on some sites climbing precipitously in a matter of hours. Bidding on the largest site — labeled OCS-A 0539 — started at $12.6 million on Wednesday morning, hit $900 million on Thursday and broke $1 billion an hour after bidding opened on Friday morning. At different times during the auction, as many as six companies were vying for the lease, with bids jumping $15 million to $30 million between rounds.

According to BOEM, the next step in the leasing process for the provisional winners is an anti-competitiveness review of the auction, to be conducted by the Department of Justice and Federal Trade Commission. The companies will also be required to pay up on their winning bids and provide financial assurance to BOEM.

The New York Bight auction is the first of seven potential offshore wind auctions the DOI is planning over the next three years, according to a plan Haaland outlined in October. (See BOEM to Auction Six New Lease Areas in NY Bight.) The second auction, scheduled for later this year, will be for a single lease off the coast of North Carolina.

BOEM is also evaluating sites in Central and Northern California, the Gulf of Mexico, the Mid-Atlantic, Oregon and the Gulf of Maine. BOEM has identified three call areas off Oregon with a total capacity potential of 17 GW, according to a presentation the agency made at a Feb. 25 meeting of its Oregon Intergovernmental Renewable Energy Task Force. (See related story, Energy Bar Weighs OSW in Oregon, California.)

Investors Confident in OSW

Bidders and other clean energy stakeholders celebrated the results and the infrastructure, supply chain and jobs it will create.

Prior to the auction, the U.S. offshore wind market had drawn in $6.7 billion in leases and other investments, according to the Business Network for Offshore Wind, an industry trade group. A report from the Special Initiative on Offshore Wind, another industry group, estimates it will require $109 billion in investments to create the supply chain needed to reach Biden’s 30-GW goal.

Liz Burdock, CEO of the Business Network, said the auction reflected “the pent-up demand for new lease areas.”

“The New York Bight benefited from clear political support, an emerging yet robust local supply chain and a years-long preparation window, which should allow the winning bidders to quickly begin the permitting process and put steel in the water by the end of the decade,” she said.

New Jersey Gov. Phil Murphy has set a goal of developing 7,500 MW of offshore wind by 2035, and to date, the state’s Board of Public Utilities (BPU) has held two solicitations, awarding three projects totaling 3,758 MW. New York’s offshore wind goal is 9,000 MW by 2035. The state has five offshore projects in development, for a total of more than 4,300 MW.

In 2020, consulting firm Wood Mackenzie predicted lease auctions in 2020-2022 in the New York Bight, California, North Carolina and South Carolina could “support 28 GW of offshore wind development and generate $1.2 billion in U.S. Treasury revenue” — an estimate that turned out overly conservative.

Aaron Barr, one of the authors of the report, told Grist the high bids were “a clear signal that offshore wind developers and investors are convinced of the sound business case for offshore wind in the United States.”

Indeed, RWE Renewables, one of the companies behind Bight Wind Holdings, said winning the $1.1 billion lease for the largest site in the bight is “an important step on the road to tripling our offshore wind capacity to 8 GW by 2030.”

RWE Renewables, the U.S. subsidiary of German utility RWE, is partnering with National Grid on the project, reflecting the strong European interest in the U.S. market. OW East is a partnership between Global Infrastructure Partners, an infrastructure fund manager, and the offshore developer Ocean Winds, a joint venture between EDP Renewables, the U.S. subsidiary of Spain’s EDP Renovavéis, and ENGIE, the French multinational utility.

According to a report on offshoreWIND.biz, an industry trade publication, other winning bidders with strong European ties include Attentive Energy, a joint venture of EnBW (Germany) and TotalEnergies (France), and Mid-Atlantic Offshore, which is owned by a Danish firm, Copenhagen Infrastructure Partners. Shell and EDF Renewables are the companies behind Atlantic Shores Offshore Wind.

‘Too Much, Too Fast’

Strong business support notwithstanding, local environmental groups had mixed reactions to the auction results. Doug O’Malley, director of the Environment New Jersey Research and Policy Center, said the auction’s “eye-popping valuations send the market a clear signal that offshore wind is poised to become the key driver of clean, renewable energy on the East Coast.

“Once we tap offshore wind, we’ll be able to green our region’s electric grid and cut the cord with fossil fuels,” he said.

But Clean Ocean Action, a New Jersey-based coalition of fishing, recreation and other community groups, criticized the auction as “too much, too fast.”

“The fast tracking of offshore wind puts marine life and a clean ocean economy at risk,” the group said in a statement released on the first day of the auction.

“There are unanswered questions with this newly proposed industry, especially at the magnitude, scale, and speed of development currently proposed,” the group said. “The leasing of these half million acres is too premature given the current gaps in scientific literature concerning the impacts of offshore wind turbines and related infrastructure on marine species and their habitats.”

The Atlantic Coast fishing industry has also raised concerns that BOEM’s requirements may not ensure that winning companies will seek and act on input from local business, community and environmental groups. (See Fishing Industry Concerned About NY Bight OSW Plan.)

Local Economic Impact

New Jersey and New York have been investing heavily in offshore wind, with their own state-level auctions and investments in local infrastructure.

Both states are also providing financial incentives for offshore wind development and are planning port facilities, spurring an emerging supply chain of local businesses. For example, New Jersey has approved $350 million in tax credits linked to offshore wind-specific facilities in the state. New York has tied its awarding of offshore wind renewable energy credits (ORECs), in part, to economic benefits projects provide, including supply chain buildout, benefits to disadvantaged communities and workforce development programs.

The impact of offshore wind development in both states has already been significant. In its 2022 U.S. Offshore Wind Market Report, the Business Network for Offshore Wind analyzed its database of potential supply chain companies, finding that Massachusetts leads the East Coast with 387 firms listed, but New Jersey (361 companies) and New York (287 companies) are close behind. An analysis of the database also found that close to half of the companies listed are small businesses with fewer than 100 employees.

BOEM has similarly incorporated economic development into the leasing process for the New York Bight, requiring lessees to describe their plans for contributing to the development of a domestic supply chain. As outlined in the January final notice on the auction, lessees that “meaningfully and substantially” assemble or manufacture major components in the U.S. could qualify for a 50% reduction in the “fee rate” for five years, which would cut the fee rate from 2% to 1%.

The operating fee will be based on a proxy for the wholesale market value of the power generated from each project. The proxy will assume a 40% capacity factor for the first six full years of commercial operations, with potential adjustments based on actual generation in future years. BOEM will use the simple hourly average of the spot price for NYISO’s Zone J in New York City. At a wholesale power price of $40/MWh, the annual 2% fee for a 1,028-MW facility, would be $2.9 million.

Officials from the BOEM and the two states have created a supply chain working group that will meet quarterly to coordinate their efforts.

The Transmission Imperative

Capitalizing on OSW’s economic potential will require the states to develop efficient transmission to deliver power to customers.

In its final notice for the NY Bight Auction, BOEM urged strategic planning of transmission, noting that the agency is considering “the use of cable corridors, regional transmission systems, meshed systems, and other mechanisms.” It said it may condition approval of construction and operations plans “on the incorporation of such methods where appropriate.”

The National Renewable Energy Laboratory is partnering with the Pacific Northwest National Laboratory on an Atlantic offshore wind transmission study “to evaluate multiple pathways to offshore wind goals through coordinated transmission solutions.” A final report is expected late in 2023, according to the study webpage.

PJM last year opened the first transmission-only solicitation for the U.S. offshore wind industry at the request of the New Jersey BPU. PJM is currently reviewing the 80 proposals received. Under PJM’s state agreement approach, New Jersey would commit to paying 100% of the cost of the transmission but could seek to allocate some costs to other generation projects that use the additional capacity. (See PJM, NJ Seek FERC OK for OSW Tx Process.)

The Business Network anticipates even broader collaboration, not just between states, but between ISOs and RTOs in “concentric circles of transmission coordination,” especially as offshore wind is developed on the West and Gulf coasts.

“The offshore wind transmission conversation is steadily expanding outwards in terms of complexity, geographic area covered and level of coordination needed by planning frameworks,” the network’s 2022 market report said. “All U.S. regions seeking to integrate offshore wind into their grids face a similar challenge — the electricity transmission system tends to be less robust in coastal areas.”

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NERC Cold Weather Project Moves Forward

The Executive Committee of NERC’s Standards Committee (SCEC) voted to move ahead with NERC’s latest cold weather project, in what Standards Committee Chair Amy Casuscelli, of Xcel Energy, acknowledged to be an “unusual” open meeting Friday.

The SCEC currently comprises Casuscelli and Vice Chair Todd Bennett, of Associated Electric Cooperative Inc., along with Sarah Snow of Cooperative Energy, Venona Greaff of Occidental Chemical and independent member Philip Winston, formerly of Southern Co. Members voted to accept the standard authorization request (SAR) for Project 2021-07 (Extreme cold weather grid operations, preparedness and coordination) and appoint the SAR drafting team as the project’s standard drafting team (SDT).

With approval from the SCEC, the SDT can begin drafting the standard now, rather than wait for the Standards Committee’s next regular meeting, scheduled for March 23. The project is intended to carry out the recommendations of NERC and FERC’s joint inquiry into last February’s winter storms, including requirements for identifying and protecting cold weather-critical components, building and retrofitting generating units to operate to specific ambient temperatures and weather, and performing annual training on winterization plans. (See FERC, NERC Release Final Texas Storm Report.)

The “time-sensitive nature of the project” was the justification for the full Standards Committee delegating its authority over SAR approval to the SCEC at its meeting the previous week; SAR drafting team members wanted to “build on the momentum” of previous meetings so that any new standards could be implemented as quickly as possible. (See NERC Standards Committee Fast Tracks Cold Weather Project.)

At that meeting, Marty Hostler of the Northern California Power Agency was the only member to express misgivings about delegating authority; he worried that leaving the decision up to the SCEC would limit committee members’ ability to question the drafting team’s response to industry comments. Hostler again spoke up on Friday, the only member to do so.

Though he did not object to the SAR overall, Hostler did suggest that more could have been done to “resolve all expressed objections” from industry, and he questioned whether the drafting team could follow through on its promise to address issues raised in the comment period during the standards drafting process.

“There’s been numerous objections to at least one of the recommendations that are in the SAR, and that has been addressed [by] saying that they’re basically going to table it and send it back to NERC for consideration. However, experience has shown that [these issues] don’t get considered later,” Hostler said. “And when you’ve got a SAR that is close to or has been approved, then the legal [department] tells us, ‘Well, you can’t discuss that anymore; now you have to follow the SAR.’”

Specifically, Hostler pointed to the SAR’s proposed requirement for retrofitting existing generating units; despite this being one of the recommendations of the joint inquiry, Hostler pointed out that the measure had been “very contentious” and that even the SAR drafting team’s chair said it would “take a lot of time” to resolve. He suggested that this requirement be “bifurcated” into a separate standards project so as not to distract from the work of Project 2021-07, though he also acknowledged he was not sure how this could be done within the standards process.

“I know the Standards Committee can’t actually tell them to bifurcate it, but that is an issue, and it doesn’t have support, which is also required of a SAR. Now the concept does, I agree with that, but not the entire SAR,” Hostler said.

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Connecticut EV Right-to-charge Bill too Broad, Attorney Says

A new bill that would ensure Connecticut’s condominium owners and renters can access electric vehicle charging at home is “inappropriate” as written, an attorney told legislators Thursday.

Andrea Dunn, a condominium association lawyer at Bender, Anderson and Barba, said the “one-size-fits-all nature” of the bill fails to address the “vast difference” between condos.

The Joint Energy and Technology Committee took up the bill (H.B. 5117) at the request of the Department of Energy and Environmental Protection (DEEP) and accepted comments on it during a public hearing.

“This legislation would … provide a process through which residents can seek approval for charging equipment installation while simultaneously protecting the property interests of associations and landlords,” DEEP Commissioner Katie Dykes said in testimony.

As written, the bill would prevent associations and property owners from restricting unit owners and renters from installing chargers, and it sets out the parties’ responsibilities for their installation.

“In short, this bill places financial responsibility solely on the unit owner or tenant,” Dykes said. Six other states, she added, have enacted right-to-charge laws in recent years that apply to associations and rental properties.

Committee members acknowledged the bill’s importance to the state’s EV goals during a legislative session preview hosted by the Connecticut Power and Energy Society on Wednesday.

“This bill will allow an owner or tenant to approach their association or landlord and petition for a charging station,” ranking committee member Rep. Charles Ferraro (R) said during the event.

Establishing a right-to-charge law for the people living in condos and rental properties is complicated. Condos are “common interest ownership properties,” and what one owner does affects other owners, committee co-Chair Sen. Norm Needleman (D) said at the event.

The intentions of the bill, Dunn said, are good, but it would not allow for the “unique makeup” of condo communities that may have no space for charging stations or immediate access to an electrical source. It also interferes with the authority of associations’ governing documents, she said.

One of Connecticut’s largest property owner organizations opposed the bill’s approach to forcing business decisions on property owners and its ambiguity over cost responsibilities. The bill is not clear, for example, about what would happen to the charging equipment after a tenant moves, it said.

EV charging as an amenity for renters “should be left to the property owners and the tenants to negotiate for themselves,” John Souza, president of the Connecticut Coalition of Property Owners, said in testimony. The free market, he said, should set the pathway for EV charging.

Needleman suggested during the hearing that representatives of the real estate community could help the committee as part of a working group to craft more suitable language for the bill.

Hydrogen Study

The committee will take public comments this week on a priority bill (H.B. 5200) that it introduced Wednesday to create a task force for studying hydrogen in the state.

“We have … all the ingredients to create a very vibrant green hydrogen hub in the region,” committee co-Chair Rep. David Conti (D) said during the legislative preview.

One of the task force mandates would be to examine how the state can take advantage of incentives for hydrogen under the Infrastructure and Investment Jobs Act (IIJA), which included $8 billion in funding over five years to develop Regional Clean Hydrogen Hubs. A U.S. Department of Energy request for information issued earlier this month seeks input on the hydrogen hub funding solicitation process.

The task force would submit its study to the legislature in January 2023 so that the committee can “craft policy” to “incorporate Connecticut into a hydrogen future,” Conti said.

U.S. Sen. Charles Schumer (D-N.Y.) is already taking steps to position New York as the center of a hydrogen hub. In a Feb. 15 letter to Energy Secretary Jennifer Granholm, Schumer urged DOE to work closely with the state as the department begins to implement the hydrogen hubs program.

Four Western states have also made a move to compete for the IIJA funds, signing an agreement Thursday to develop a Western Inter-States Hydrogen Hub. (See related story, Mountain States Partner to Secure Hydrogen Hub.) And in Washington, the State Senate unanimously passed a bill Feb. 12 to create a state office that would support hydrogen development and help put the state in the running for a hub designation. (See related story, Fast-moving Bill Seeks to Win Hydrogen Hub for Wash.)

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MISO Long-range Tx Plan Overlaps with SPP Study

MISO will complete a draft portfolio of billions of dollars’ worth of long-range transmission projects by the end of March, although two recommended projects bump up against its interregional planning effort with SPP to clear backlogs in their respective generator interconnection queues.

“We’re shoring up business cases to proceed,” Jarred Miland, senior manager of transmission planning coordination told stakeholders during a special workshop Friday on the long-range plan’s Midwestern portion.

MISO will add a two-day workshop in late March to focus on the 345-kV projects’ technical analysis and business cases. The Planning Advisory Committee will conduct an advisory vote on the package during its mid-April meeting. (See MISO Promises Long-range Tx Project Reveal Soon.)

Stakeholders expressed discomfort during the workshop with the project’s overlap of routes being pursued in MISO’s and SPP’s Joint Targeted Interconnection Queue (JTIQ) study. They pointed out that the long-range plan’s recommended lines in the Dakotas and Minnesota echo two JTIQ solutions. (See MISO, SPP Roll out $1.755B Joint Tx Portfolio.)

The proposed projects, Ellendale to Jamestown in southern North Dakota and a line from Big Stone South, S.D., to Cassie’s Crossing, Minn., will solve thermal overloading issues and ease congestion on the existing system. MISO planners said solving those reliability issues has been on their radar for some time.

Miland said staff will recommend the two joint projects under the RTO’s regional planning process. He said the projects might be in the distant future because the grid operators don’t have a cost-allocation process in place.

“With the JTIQ, cost allocations are still in discussion, and it probably has a much, much longer time ahead of it,” Miland said.

Aubrey Johnson, executive director of system planning, said MISO stands to benefit more than SPP from the two projects. He also said the long-range transmission plan takes precedence over the JTIQ effort in MISO’s hierarchy of transmission planning.

“It is appropriate for the MISO customers to carry these costs,” Johnson said.

The RTO’s director of resource utilization, Andy Witmeier, said the JTIQ cost-allocation talks are in their “infancy.” He said it would be “imprudent” to sit on beneficial projects while lengthy joint cost-sharing negotiations take place.

“It’s a little unfortunate that not all the beneficiaries will be paying for these projects,” Wolverine Power Supply Cooperative’s Tom King said, referring to SPP members.

When asked, Johnson said MISO has not yet projected in-service dates for either the long-range plan or JTIQ projects.

However, staff said they intend to have the long-range projects in service as quickly as permitting and construction allow. Witmeier said the RTO envisions in-service dates within seven or eight years because of the immediate need for new transmission.  

“Essentially, all of these projects have as-soon-as-possible in-service dates,” he said.

Billions in Costs, More Billions in Benefits

MISO said preliminary analysis of its first cycle of long-range projects “indicates total economic benefits significantly exceed cost.” However, staff hasn’t yet attached specific costs to individual projects or the portfolio. Johnson said a $12-$16 billion cost range contained in a MISO presentation was an “illustrative example” that “represented real numbers.” Staff said they have more work ahead analyzing project alternatives before they can narrow costs.

Should FERC approve MISO’s filed cost allocation for long-range projects, the cost splits will be based on postage stamp rates limited to either the RTO’s Midwest or South regions.

The grid operator’s analyses show that the first Midwestern projects can facilitate 20 GW in capacity additions and could save MISO Midwest $16.6 billion in congestion and fuel costs over the transmission projects’ first 20 years.

Decarbonization benefits could range from $2.25 billion to almost $11.5 billion over a 40-year project lifespan, MISO said. It also said it could achieve $1 billion in savings because the first long-range projects would increase transfer capabilities between local resource zones, thereby lowering capacity-clearing requirements.

MISO said the projects might also prevent a few billion dollars’ worth of load shed over 40 years, and significantly more if it raises its value of lost load beyond the current $3,500/MWh. Many stakeholders say that figure is an underestimate.

The RTO also said it continues to see value in including a massive 345-kV project corridor that would span Iowa, Illinois, Indiana and Michigan and not branch out into smaller city-to-city segments.

The grid operator said it could avoid about $760 million in additional transmission work by using a portfolio package instead of chasing standalone, incremental fixes.

“Past experiences with transmission studies like the multi-value projects indicate that a regional approach will be more cost effective than a purely local buildout,” staff said.

The Midwestern long-term projects come as MISO state regulators face federal pressure to focus on new energy infrastructure.

The U.S. Department of Energy’s Pat Hoffman appeared during a Feb. 14 Organization of MISO States (OMS) meeting to request that regulators concentrate on infrastructure buildout. Hoffman asked the audience to speak with “one voice” on how grid investment should look.

“It’s going to take off, and I’m worried the system is not prepared on what’s to come,” Hoffman said of the MISO footprint. She said the industry is poised to shift rapidly due to fossil fuel plant retirements, integrating renewable energy, and extreme weather changes.

“You do a good job of walking that fine line between optimism and terror,” OMS President Sarah Freeman said after Hoffman’s presentation.

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AEP to Sell Unregulated Renewables Portfolio

American Electric Power (NASDAQ:AEP) said last week that it intends to sell some or all of its unregulated contracted wind and solar energy resources and redirect capital previously allocated to that business to its transmission assets.

Executives told financial analysts during AEP’s year-end earnings call Thursday that it plans to dispose of about 1.6 GW of renewable capacity. That will free up $1.5 billion in capital spending to its regulated transmission business between now and 2026.

CEO Nick Akins said during the call that the company is “fully confident” the portfolio’s sale will “both simplify and derisk” the business and allow it to “assign additional capital to our regulated business.”

The move doesn’t affect AEP’s regulated renewables business, which plans to add 8.6 GW of wind and 6.6 GW of solar by 2030. The company is allocating $8.2 billion of its current $38 billion, five-year capital plan to the regulated portfolio. The capital expenditure plan also includes $24.8 billion for grid investments.

“The migration from contracted renewables to significant increases in regulated renewables will ensure that AEP maintains the talent and resources to execute this plan,” Akins said.

AEP expects to close the $2.8 billion sale of its Kentucky operations, Kentucky Power and AEP Kentucky Transco, in the second quarter. Akins said he doesn’t think the recent withdrawal of a FERC filing related to a coal-fired power plant’s operating agreement to affect the timing.

The Columbus, Ohio-based company reported its “strongest-ever” fourth quarter with earnings of $538.9 million ($1.07/share). A year ago, quarterly earnings were $435.5 million ($0.88/share).

AEP’s year-end earnings were $2.49 billion ($4.97/share), compared to $2.2 billion ($4.44/share) in 2020.

Wall Street reacted favorably to the news, driving AEP’s share price up 5.7%, from $84.64 before the earnings announcement to $89.46.

Vistra Recovers from Winter Storm

Vistra (NYSE:VST) on Friday brought a tough year to a close by delivering $1.94 billion in year-end adjusted EBITDA from ongoing operations. A year ago, the Texas-based company reported $3.77 billion in adjusted EBITDA from ongoing operations a week after February’s devastating winter storm that eventually inflicted a $1.6 billion hit.

Last year “was undoubtedly a challenging year and, in many ways, a pivotal one for Vistra. … The financial strength we worked so hard to put in place was challenged,” CEO Curt Morgan told financial analysts during a conference call. “I’m proud of how our team came together to not only confront and mitigate the impact, but to then shift to building a stronger company. That strong balance sheet we built and the resilience of our team helped us stabilize the company and ultimately get back on track within months.”

<img src="https://rtowww.com/wp-content/uploads/2023/06/140620231686782162.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

Vistra CEO Curt Morgan

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Executives said Vistra was able to “derisk” the company after the storm and shift its strategic direction; begin an improved capital allocation plan with substantial share repurchases; and accelerate Vistra Zero, its portfolio of zero-emission resources. Vistra has announced plans to operate 7.3 GW of zero-carbon generation by 2026, a number that includes its 2.3-GW Comanche Peak Nuclear Power Plant. The company plans to bring two solar facilities offering 158 GW of power and a 260-MW energy storage facility online by this summer.

The company reduced debt by about $625 million during the fourth quarter and is on target to reduce debt by $1.5 billion by the end of 2022.

“We feel like we’ve turned the corner here and strengthened our company,” Morgan said in closing the conference call.

For the quarter, adjusted EBITDA from ongoing operations was $1.17 billion, compared to $802 million for the same period in 2020.

Vistra’s share price gained 22 cents Friday, closing at $21.90. It had dropped to $17.25 in February after the company disclosed its winter storm losses. (See Vistra Stock Plunges After Market Losses.)

OGE Turns in Solid Year

OGE Energy (NYSE:OGE) on Thursday reported year-end earnings of $737.3 million ($3.68/diluted share), compared to a net loss of $173.7 million ($0.87/diluted share) for 2020.

For the quarter, earnings were $319.2 million ($1.59/diluted share), up from $54.8 million ($0.27/diluted share) for the year prior.

Most of the gains came from OGE’s Oklahoma Gas & Electric subsidiary, which turned in 2.4% load growth and increased revenues from capital investment recovery. That was partially offset by the February winter storm’s effects and higher depreciation on a growing asset base.

“Every single employee contributed to the excellent results we delivered this year especially when you consider the headwinds we faced in early 2021,” CEO Sean Trauschke said in a statement.

The Oklahoma City-based company forecasts long-term utility earnings growth of 5 to 7% per share.

OGE’s share price gained $1.75 and finished the week at $37.18, a 5% increase following the earnings announcement.

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MISO Steering Committee Blocks Adds to Stakeholder Guidelines

MISO stakeholder committee chairs last week elected not to adopt rules regulating stakeholder presentations during meetings.

On Wednesday, the Steering Committee, comprising chairs from eight MISO committees reporting to the grid operator’s Advisory Committee, declined to advance a suggested insert drafted by Clean Grid Alliance’s Rhonda Peters to its Stakeholder Governance Guide.

The addition would have dictated that stakeholders presenting during meetings must be “treated uniformly and without discrimination or preference.” It also would have compelled the RTO to deliver its own presentations and discuss suggested changes by stakeholders before it could adopt them.

“Stakeholders cannot adequately and sufficiently represent MISO’s interests or accountability,” the language said.

Peters said the grid operator’s adoption of stakeholder suggestions without fully vetting them with the larger stakeholder community has been an issue that has come up several times over the 14 years she’s been participating in the stakeholder process. She said staff will sometimes file with FERC tariff modifications on stakeholders’ recommended changes without addressing the edits with stakeholders.

Peters said the most recent example arose after a Planning Advisory Committee meeting when MISO filed tariff changes pertaining to transmission owners’ reinstated option to self-fund network upgrades. She said staff should have vetted the edits pertaining to the self-funding option with the Interconnection Process Working Group before drafting and filing the changes.

MISO in 2018 acted on FERC’s direction and reinstated TOs’ right to self-fund network upgrades necessary for new generation. The decision has been a hot-button issue, spawning three years’ worth of reopened contracts, refunds to interconnection customers and condemnation from one FERC commissioner. (See FERC Upholds MISO Self-fund Order, Glick Dissents.)

“There are some stakeholders that MISO feels represent them,” Peters said. “All stakeholders should be treated in the same manner, and that has not been happening.”

She implied that TO recommendations carry more weight with the RTO than those from other stakeholders.

Committee chairs said while they were sympathetic to the issue, they didn’t see a need to add a section on stakeholder presentations to the governance guide.

“I’m worried if we try to add language to address every situation in the Stakeholder Governance Guide, it will become unwieldy and collapse under its own weight,” WEC Energy Group’s Chris Plante, the Resource Adequacy Subcommittee chair, said.

Plante said he’d rather see committee chairs handle these types of situations. Planning Advisory Committee Chair Cynthia Crane, with ITC Holdings, agreed that the new section would be “overly prescriptive.”

Ameren’s Ray McCausland, who chairs the Reliability Subcommittee, asked stakeholders to bring specific violations of stakeholder treatment to the Steering Committee instead of prescribing vague language in the governance guide.

Market Subcommittee Chair Megan Wisersky, with Madison Gas and Electric, said that the guide’s addition could discourage some stakeholders from coming forward with presentations. In MISO’s stakeholder process, any stakeholder is free to present in meetings if it gives the grid operator enough notice.

Clean Grid Alliance’s Natalie McIntire asked how the issue could effectively be addressed by the committee chairs and vice chairs. “I just feel like there needs to be another solution, one that does function,” she said.

Peters said if she couldn’t get the language accepted, the next step might be taking the issue to MISO’s alternative dispute resolution process.

Customized Energy Solutions’ David Sapper said he’d be interested in hearing MISO’s process for accepting stakeholder suggestions and making FERC filings based on them.

The Steering Committee has no current plans to further address the issue.