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November 16, 2024

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ERCOT Board of Directors Briefs: June 17-18, 2024

Contentious NPRR Revising ECRS Passes over Monitor’s Objections

ERCOT’s Board of Directors took up two contentious protocol changes during its June 18 meeting that have divided staff and stakeholders, tabling one it had previously remanded and approving the other over objections from consumer interests and the Independent Market Monitor. 

Potomac Economics President David Patton made his second appearance in less than six months before board members to press his case against the grid operator’s heavy use of ERCOT contingency reserve service (ECRS). 

Patton, whose firm holds ERCOT’s IMM contract, said he was “very disappointed” with the board’s approval of the protocol change (NPRR1224). The rule change sets a price floor of $750/MWh for the product, which procures capacity resources that can be brought online within 10 minutes and sustained at a specified level for two consecutive hours. 

“This is the first time I’ve seen [a grid operator] advocate for such a proposal that is designed to undermine the competitive performance of its market — reducing reliability to artificially inflate its real-time prices,” Patton told RTO Insider. 

The Monitor last year said the ECRS product, ERCOT’s first new ancillary service in 20 years, created artificial supply shortages that produced “massive” inefficient market costs totaling about $12 billion during the year. The service was first deployed in June. (See ERCOT Board of Directors Briefs: Dec. 19, 2023.) 

“I think this is one of the most important votes to approve something that you’ll ever take,” Patton told the board’s Reliability and Markets Committee on June 17. “The key objectives of any competitive, deregulated wholesale markets is that they produce efficient and competitive outcomes that maintain the reliability. NPR1224 violates all three of those objectives.” 

In his presentation to the committee, Patton said NPRR1224 will effectively have ERCOT administer a withholding framework where key economic units are physically withheld from the real-time market until they are deployed. He said it economically withholds the resources after deployment by attaching the $750 offer floor, “for which there is no competitive basis.” 

Because ERCOT doesn’t yet co-optimize energy and ancillary services in real time (that is scheduled to come online in 2026), ECRS is quarantined from the real-time market. The Monitor projects that if conditions this year are similar to 2023’s, the NPRR will generate “inefficient and anticompetitive” costs exceeding $5.7 billion. Patton recommended staff instead develop procedures that would anticipate a security-constrained economic dispatch (SCED) shortage and then deploy ECRS. 

Attorney Katie Coleman, who represents Texas Industrial Energy Consumers, advocated for a $100 price floor but supported 1224 as an interim step before real-time co-optimization (RTC) is added to the market. 

“We are concerned that with the $750 price floor, we are not making much progress relative to last summer’s experience,” she said. “We do support a stopgap between now and real-time co-optimization to insulate the market from those effects, but we believe that the $100 floor is the appropriate level.” 

ERCOT staff said they had drafted another protocol change (NPRR1232) as a follow-up to NPRR1224. It would introduce a mechanism to make some ECRS available to SCED every hour, assuming the latter NPRR’s price floor is codified into the protocols. Staff said the price floor represents the opportunity cost of depleting available reserves for use in the real-time market. 

Staff said ECRS has been deployed 52 times through May 2024, with 43 of those occasions providing frequency recovery or to cover net load ramps. ERCOT CEO Pablo Vegas used that data point in supporting NPRR1224, which he said is intended to provide some benefits during the summer. 

NPPR1224 “represents an improvement over what we saw last year in terms of lowering the price,” Vegas said. “The [Technical Advisory Committee] has worked together to try to find a pathway that addresses some of the cost implications that we saw last summer. It preserves the unique characteristics of ECRS and what we’re able to do under manual deployments today with our control room. It represents the first step in a series of … steps that are going to track us towards RTC. 

“I would recommend we move forward with the work that TAC has done and take this first step to see the benefit this summer. We’ll be able to take continued lessons learned into 1232 as we set up the automation of the release of ECRS. We’re going to have to get comfortable as a committee and as a board dealing with issues where there are strong pros and strong cons. We’re not going to be able to necessarily find the middle ground that makes everybody happy on these kinds of issues.” 

The R&M Committee, divided over the deliberative stakeholder process and a lack of transparency into the price floor, voted 3-1 to approve NPRR1224. The Office of Public Utility Counsel’s CEO, Courtney Hjaltman, cast the dissenting vote over concerns the price floor is too high. She abstained from the full board’s unanimous vote. 

NOGRR245 Bifurcated, Delayed

The board also agreed with staff’s recommendation to table a revision to the Nodal Operating Guide (NOGRR245) that has been bandied back and forth between stakeholders and staff since late last year. The proposed rule change would impose voltage ride-through requirements on inverter-based resources. 

Staff said tabling the measure will give them additional time to hammer out an agreement with some stakeholders by bifurcating or decoupling parts of the exemptions and extension process for legacy assets unable to meet ride-through requirements. 

“ERCOT believes one more opportunity to work with joint commenters is appropriate to potentially give regulatory certainty,” staff said. 

Chad Seely, ERCOT | ERCOT

General Counsel Chad Seely said ERCOT will work to schedule a special board meeting before the regular Aug. 19-20 bimonthly meetings to take up NOGRR245’s exemptions and extension process issues. He said that will allow staff to quickly hand off the measure to the Texas Public Utility Commission for policy discussions. The measure’s reliability assessment process and criteria for hardware upgrades necessary to meet its requirements will go through the normal stakeholder process, with a December target to go before the board. 

“This is a critical reliability issue for the grid. It’s time to move this forward and hand this off to the commission as expeditiously as possible,” Seely said, expressing optimism that staff will be able to “effectively bifurcate” the issue. 

TAC endorsed the rule change June 7 after several months of trading and reviewing comments with ERCOT, gaining staff’s support in the process. The committee inserted gray-box language with potential modifications that wouldn’t become effective until March 2025. The language was aimed at those entities for which upgrade costs are less than 40% of the full, in-kind replacement cost of a plant’s inverters or turbines and converters. (See ERCOT TAC Endorses Rule for Inverter-based Resources.) 

However, the joint commenters — primarily renewable developers — protested the change and threatened to file a complaint at the PUC, saying TAC attempted to defer issues around hardware changes by placing them in the gray-box language. They urged the board to ensure that the ride-through standards “do not have the unintended consequences of harming reliability by eliminating existing generation and harming future investment in infrastructure in the ERCOT market.” (See Renewable Developers Oppose Proposed ERCOT IBR Rule.) 

The NOGRR is meant to align the grid operator’s protocols with NERC reliability guidelines and the most relevant parts of the Institute of Electrical and Electronics Engineers’ standard for IBRs interconnecting with the grid. The board in April remanded the NOGRR back to TAC, directing that the language be modified to address ERCOT’s reliability concerns. 

ECRS Slows Energy Prices’ Drop

ERCOT IMM Director Jeff McDonald said that while he wasn’t going to focus on ECRS in briefing the board, the ancillary service had a profound effect on the market last year. 

“I know it comes up repeatedly in the report … but you will see it is the focus in certain areas in the report because it had a fairly profound effect on energy prices and overall cost,” he said in sharing the Monitor’s annual State of the Market report. 

McDonald said the load-weighted average energy prices were down about 13% to roughly $65/MWh in 2023 from the year before, even though natural gas prices declined more than 60% during the same period. The report attributes that difference to the “adverse” effects of ECRS’ implementation, noting that real-time prices drive those in the day-ahead and forward markets. 

“Electricity prices will be correlated with natural gas prices in a well-functioning market because fuel costs represent the majority of most suppliers’ marginal production costs, and natural gas units are generally on the margin in ERCOT,” the report says. 

ECRS’ effect on real-time prices was largely confined to the hotter months of June through September, McDonald said. “So, it did roughly double the real-time energy price during that period.” 

McDonald said the IMM spent a “fair amount” of time looking at the market’s competitiveness, finding it to be competitive with little evidence that suppliers exercised market power. He said that while the market has provided sufficient revenues to signal the need for more generation in four of the past six years, he was unable to explain why it took the subsidization of gas plants’ construction through the Texas Energy Fund to make that more of a reality. (See Vistra Joins Rush for Dispatchable Generation Loans.) 

“As a project developer, you need to see a series of revenues in the market that would support your investment before you undertake it,” he theorized. “In the investment world, policy risk is a big factor, especially for large capital … investments. So I’ll be spending more time trying to find a satisfactory answers to your question.” 

ERCOT: Another Hot Summer

Dan Woodfin, ERCOT’s vice president of system operations, told the board that staff meteorologists expect this summer to be among the hottest on record, as have the past few summers. 

“Probably not as hot as last summer, where we just had lots and lots of hot temperatures,” he said. “We’ve actually had quite a few of the summers within the last few years that have been well above normal, and so we expect this summer to fit in with that. Given what we’ve seen in June, I think that we’re trending that way.” 

“We’re seeing a pretty significant little bit higher growth during the summer period than what we’ve seen in some of the other seasons,” CEO Vegas said. “It’s a little bit higher than what we’ve seen across other seasons over that same period, and it’s likely due to the very hot summers recently that we’ve just had. So we’ve seen some very recent high weather that has helped to boost some of the demand growth.” 

According to a recent University of California, Berkeley study, the state’s average temperature has risen by about 2.7 degrees Fahrenheit since the dawn of the industrial age. However, the heat index has been as many as 11 degrees higher during that same period. 

The past two summers have been the second- and third-hottest on record, and four of the 10 hottest summers have come in the past six years, Vegas said. September 2023 was the hottest September on record and included ERCOT’s first energy emergency since the disastrous February 2021 winter storm. 

ERCOT set a new demand market record last August of 85.5 GW during a summer in which it issued 17 weather watches, voluntary conservation notices or conservations appeals. As of June 20, it was projecting more than 80 GW of demand on June 26, marking the first 80-GW day of the season. The June record for peak demand came last year at 80.8 GW. 

“We are prepared for this summer,” Vegas said, citing weatherization inspections, “meaningful” growth in generation resources and tabletop exercises. 

2nd DR RFP Canceled

Vegas said ERCOT is canceling a request for four-hour demand response after it received three offers with less than 10 MW. 

A request for 3,000 MW of six-hour DR last fall was canceled when the grid operator received 11.1 MW of potential eligible capacity. 

“It is clear from the two recent experiences with capacity [requests for proposals] … that we need to modify the approach for developing the next set of demand response capabilities in the ERCOT market,” Vegas said, echoing similar comments he made last year. (See ERCOT Cancels RFP for Additional Winter Capacity.) 

IMM’s David Patton argue against ECRS’ use. | ERCOT

He added that he is confident there is “significant potential” in both residential and commercial and industrial demand response classes. “We need to take a more in-depth approach working with market participants to develop a demand response product that will be additive to the reliability capabilities at an ERCOT market level,” Vegas said. 

ERCOT staff are working with PUC staff on a study Vegas said “shows meaningful potential for incremental demand response.” Texas A&M University is nearing completion of the study in advance of next year’s Texas legislative session, PUC Commissioner Kathleen Jackson said. 

“Our stretch goal is that we want to look at the lay of the land and come up with recommendations that hopefully we can bring forth during the next legislative session,” Jackson said. 

Board Approves $1.12B Project

The board approved ERCOT’s recommended $1.12 billion project to rebuild 345-kV infrastructure in West Texas that will address thermal overloads and petroleum production load-growth issues in the region. The project was also unanimously endorsed by TAC. 

Oncor, the transmission provider, will disconnect existing 345- and 138-kV transmission lines before rebuilding about 245 miles of new line and switches. It will also build a new substation and upgrade terminal equipment. The utility plans to complete the work by summer 2028. 

The board’s consent agenda included seven NPPRs, two NOGRRs and three revisions to the Planning Guide (PGRRs):  

    • NPRR1198, NOGRR258 and PGRR113: add an extended action plan as a constraint-management plan suitable to managing congestion resolvable by SCED. 
    • NPRR1212 and PGRR114: clarify a distribution service provider’s obligation to provide an electronic service identifier for a resource site that consumes load other than wholesale storage and is not behind a non-opt-in entity tie meter. 
    • NPRR1218: updates the state’s renewable energy credit trading program to clarify that it only applies to solar renewable energy. 
    • NPRR1220: modifies the market’s restart process to require board and TAC approval and provide an alternative mechanism to board approval under certain circumstances. 
    • NPRR1222: elevates final approval of the “ERCOT Methodologies for Determining Minimum Ancillary Service Requirements” other binding document from the board to the PUC, consistent with commission discussions. 
    • NPRR1223: updates a protocol form to require transmission and/or distribution service providers to provide contact information to ERCOT. 
    • NPRR1228: decreases the number of firm fuel supply service obligation periods awarded in a procurement from two to one. 
    • NOGRR255: establishes high-resolution data requirements. 
    • PGRR112: sets requirements for interconnecting entities to submit dynamic data models and for transmission service providers to submit final full interconnection studies for approval at least 30 business days before the quarterly stability assessment deadline. 
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Sunrise Wind Cleared to Begin Construction

Sunrise Wind has received final federal approval of its construction and operations plan and expects to begin seabed preparations off the New England coast this year. 

The Bureau of Ocean Energy Management announced the decision June 21. BOEM had formally greenlighted the project with its record of decision March 26, but other pieces of the review process remained.  

BOEM’s final approval clears the way for offshore construction of the 924-MW project, which will be the second offshore wind farm to feed into the New York grid and the third project begun by the Ørsted/Eversource partnership. Sunrise’s onshore transmission infrastructure preparations have been underway for months and now will accelerate. 

The June 21 announcement was BOEM’s third offshore wind update in four days. 

BOEM said June 20 it had determined its plan to lease parts of the Gulf of Maine for wind energy development would have minimal environmental impact, and on June 18, it issued a call for input as it begins to consider a wind lease auction off the coast of a U.S. territory, tentatively targeted for 2028. 

Sunrise Wind

The announcements that Sunrise Wind could and would begin construction complete a turnaround from a remarkably bad year for that project and for most other wind farms planned along the Northeast U.S. coast, as soaring costs made offtake contracts negotiated years earlier untenable. 

New York state rejected Sunrise’s request for more money in late 2023 but invited a rebid in a rush solicitation. Sunrise submitted a new bid with much higher costs, and New York announced a new contract June 4. 

Along the way, Ørsted and Eversource recorded billions of dollars in impairments and losses from their joint venture. There also were some high points: This year, the partners completed South Fork Wind, the first utility-scale wind farm in U.S. waters, and started construction on Revolution Wind. 

The two companies are in the late stages of terminating their partnership — Eversource has decided to limit its work in the offshore wind sector to onshore transmission infrastructure. It has reached deals to sell its share of Sunrise to Ørsted and its share of South Fork and Revolution to Global Infrastructure Partners.  

“Sunrise Wind is a centerpiece of New York’s clean energy vision, and with this final federal approval, we can officially put the construction phase in motion,” Ørsted Americas CEO David Hardy said in a news release. “BOEM’s approval is an important milestone not just for New York, but also for America’s domestic energy sector.” 

Sunrise Wind is to be built in lease area OCS-A 0487, which is 109,952 acres situated more than 30 miles east of the eastern tip of Long Island, closer to Massachusetts and Rhode Island than to New York. 

Sunrise is targeted to come online in 2026. Its export cable will stretch about 100 miles to Holbrook on the south shore of Long Island. Port Jefferson Harbor, on the north shore, will host the operations and maintenance hub. 

Gulf of Maine

The Gulf of Maine draft environmental analysis announced June 20 is a preparatory step for the auction of up to eight lease areas totaling nearly 1 million acres and holding the potential for up to 15 GW of wind generation capacity. 

The Department of the Interior announced in April it is targeting such an auction for 2024. Also this year, it hopes to auction leases in Central Atlantic, Gulf of Mexico and Oregon regions. 

The water is so deep in the Gulf of Maine and Oregon lease areas that wind power development there would rely on floating technology, which still is being developed.  

The draft environmental assessment does not examine the environmental impact of installing and operating thousands of floating wind turbines off the Maine, New Hampshire and Massachusetts coasts.  

It assesses only the reasonably foreseeable consequences of site characterization and site assessment activities that would occur as developers conduct the research that would form the basis of their construction and operation plans. 

The draft analysis concludes this work would have negligible or negligible-to-minor impacts. 

BOEM has been advancing the Biden administration’s offshore wind goals vigorously. While so far it has fended off legal challenges from wind power opponents, it has given consideration to feedback from stakeholders and the public.  

BOEM reduced the number of turbines in the Sunrise Wind plan, for example, and reduced the size of the Gulf of Maine Wind Energy Area, both in response to concerns raised in public comment periods. 

Before it finalizes the Gulf of Maine environmental analysis, BOEM once again is seeking feedback. A 30-day public comment period on the draft will run through July 22. 

US Territories

On June 18, BOEM issued a request for suggestions for baseline environmental and socioeconomic studies that will shape its decisions about potential offshore wind development near U.S. territories. 

BOEM also is looking for local entities that could carry out studies and environmental monitoring. 

“BOEM develops, funds and manages rigorous scientific research to ensure our decisions are informed by the best science and Indigenous knowledge available,” Rodney Cluck, chief of BOEM’s Environmental Studies Program, said in a news release. “Additional research focused on the U.S. territories will increase our understanding of these important areas, and the potential impacts of offshore wind energy development on their residents and resources.”   

The U.S. has territories in both the Caribbean Sea and Pacific Ocean, and BOEM’s request for letters of information references both regions. 

The regulator is considering a wide range of study subjects, including sea turtles, whales, workforce capabilities, public values, submerged archaeological sites and larval dispersal. 

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Offshore Wind Leaders Project Confidence amid Election Year Uncertainty

BOSTON — Offshore wind executives and government officials expressed tentative optimism at an offshore wind conference about the industry’s rebound from last year’s spate of contract cancellations. 

With construction underway on Vineyard Wind, Revolution Wind and Coastal Virginia Offshore Wind and several earlier-stage projects back under contract or rebid in ongoing state solicitations, the industry is building a foundation heading into the uncertainty of the 2024 election, several speakers emphasized at the June 17-18 Reuters event.  

Walter Musial, chief engineer of offshore wind energy at the National Renewable Energy Laboratory, said recent project cancellations have delayed offshore wind’s growth in the U.S. but do not seem likely to have a major impact on its long-term outlook. 

Most indicators “generally support the long-term viability of the industry,” Musial said.  

Heading into the election, “something that we have not done well enough as an industry is selling the job creation story,” said Teddy Muhlfelder, head of Empire Wind for Equinor.  

“It’s a truly exciting story for the U.S., which hasn’t seen new major manufacturing in a long time,” Muhlfelder added. “This impacts red states and blue states.” 

Despite the recent rebound, the nascent industry remains reliant on federal and state governments as it scales up. A recent report by the Global Wind Energy Council projected 410 GW of additional global offshore wind capacity to be installed over the next decade, contingent on continued policy support. (See Decade of Strong Growth Forecast in Offshore Wind Sector.) 

While the Biden administration has approved eight commercial-scale offshore wind projects, former President Donald Trump did not issue a single offshore wind permit during his presidency and has expressed his disdain for offshore wind on the campaign trail. 

Speaking about the Atlantic Shores project at a rally in May, Trump said “we’re going to make sure that that ends on day one — I’m going to write it out in an executive order.” 

“We must not take a day for granted,” said Daniel Runyan, head of offshore wind development at Invenergy.  

Runyan stressed the need to continue building up the domestic supply chain, noting that “we have the opportunity to see some major investment throughout the United States” that would provide job and economic development benefits “beyond just the megawatt hours.” 

Despite the uncertainty at the federal level, speakers applauded the Northeast states’ continued commitment to offshore wind amid the recent rocky waters. 

David Ortiz, head of government affairs and market strategy at Ørsted, praised the ongoing coordinated procurement of Connecticut, Massachusetts and Rhode Island. The combined solicitation of up to 6,000 MW received 5,454 MW in bids in March, with winning bids set to be announced Aug. 7. (See New England States’ OSW Procurement Receives 5,454 MW in Bids.) 

“We think that this coordinated procurement is a really strong step in the right direction and is really leading this industry,” Ortiz said. “Other states should look this way and follow.” 

The coordinated procurement is intended to unlock economies of scale and enable the more efficient use of regional supply chains and ports to reduce overall costs to ratepayers.  

Ortiz said the Northeast states could further improve their procurement processes by more closely aligning the commercial operations date requirements and inflation index mechanisms of the three state requests for proposals. 

Speakers at the conference also called for permitting improvements to help reduce costs and timelines. 

“Permitting needs to be accelerated for offshore wind and every other infrastructure project in the U.S,” said Sy Oytan, COO of offshore wind for Avangrid Renewables. He noted that allocating more resources and funding to relevant government agencies could be one way to speed up timelines.  

Beyond just permitting speed, “clarity of time frame is absolutely critical,” said Diane Leopold, COO of Dominion Energy. Leopold said uncertainty regarding the length of the permitting process can directly increase costs, particularly for booking contractors.  

Muhlfelder of Equinor also stressed the importance of timeline certainty, calling offshore wind a “schedule-driven” industry. 

“You’re forecasting eight years out when a vessel’s going to arrive in a four-month window,” Muhlfelder said. “Having a really good understanding of your schedule is going to be key.” 

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PJM MRC/MC Preview: June 27, 2024

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. 

RTO Insider will be covering the discussions and votes. See next week’s newsletter for a full report. 

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. Endorse proposed revisions to Manual 18: PJM Capacity Market to reflect redesigns drafted through the Critical Issue Fast Path (CIFP) process and approved by the commission in January (ER24-99). The changes expand the use of effective load-carrying capability in the accreditation of all generation classes, require that planned resources notify PJM of their intent to participation in auctions at least 90 days in advance and change how unforced capacity (UCAP) values are calculated. (See “Stakeholders Endorse Manual Revisions to Implement CIFP Changes to Capacity Market,” PJM MIC Briefs: May 1, 2024.)

Issue Tracking: CIFP Resource Adequacy 

Issue Tracking: Local Considerations for Net Cost of New Entry

C. Endorse proposed revisions to Manuals 14B: PJM Region Transmission Planning Process; 20: PJM Resource Adequacy Analysis; 20A: Resource Adequacy Analysis; 21: Rules and Procedures for Determination of Generating Capability; 21A: Determination of Accredited UCAP Using Effective Load Carrying Capability Analysis; and 21B: Rules and Procedures for Determination of Generating Capability drafted through the CIFP process and accepted by the commission in ER24-99. The new language details PJM’s new approach to risk modeling, how it simulates resource outputs and the definition of the capacity emergency transfer objective (CETO). (See “CIFP Manual Revisions Endorsed,” PJM PC/TEAC Briefs: June 4, 2024.)

Issue Tracking: CIFP Resource Adequacy 

Members Committee

Consent Agenda (1:50-1:55)

B. Endorse proposed tariff and Reliability Assurance Agreement (RAA) revisions addressing how capacity obligations arising from forecasted large load adjustments are assigned. (See “New Approach to Large Load Addition Capacity Assignments Endorsed,” PJM MRC Briefs: May 22, 2024.)

Issue Tracking: Capacity Obligations for Forecasted Large Load Adjustments 

Endorsements (1:55-2:05)

1. Nominating Committee Elections (1:55-2:05)

PJM Director of Stakeholder Affairs Dave Anders will review the sector nominees for the Nominating Committee’s 2024/25 term. 

The committee will be asked to elect the sector representatives upon first read. 

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MISO’s 2nd Long-range Tx Portfolio Jumps to About $25B

MISO’s second, mostly 765-kV long-range transmission plan could tip past $25 billion with the addition of more projects, stakeholders have learned. 

RTO staff said its “near-final” second long-range transmission plan (LRTP) stands between $23 billion and $27 billion, up from the original range of $17 billion to $23 billion. The grid operator plans to submit the portfolio to its Board of Directors for approval in early December. 

“That is currently where we’ll think we will land, including underbuilds,” Director of Economic and Policy Planning Christina Drake said of the cost during a teleconference June 21. The proposed portfolio will require “underbuilding,” or secondary, lower-voltage transmission upgrades to support a 765-kV network in the Midwest region. MISO is still finalizing its list of underbuild projects. It also has yet to translate its reliability and economic analyses into a business case for the second LRTP portfolio. 

MISO last month said it would add seven 765- or 345-kV projects in the Dakotas, Minnesota, Michigan, Indiana and Iowa and replace an original 765-kV project in Missouri and Iowa with segments of 345-kV line in the St. Louis metropolitan area. (See “MISO Undeterred, Plans More LRTP Projects,” MISO IMM Knocks LRTP Benefit Calculations; RTO Poised to Add More Projects.) 

“We’re in some of the final stages here of economic and reliability robustness testing,” Drake said. 

MISO’s analyses so far indicate that with the second, expanded portfolio, its Midwest region reduces curtailments by 8.5% annually — or by 20.4 million MWh — by 2042. Reductions in curtailments should assist fleet evolution, the RTO said. They should also reduce adjusted production costs by allowing the dispatch of the most economical units. 

RTO staff said the portfolio would allow more generation dispatch from its West region to flow east to population centers. MISO’s analyses showed the portfolio “enables and incentivizes” energy deliveries from renewable sources in Minnesota, the Dakotas and Wisconsin, which will cut down on price separation in the Midwest region. 

MISO said it expects LRTP II to overall reduce the cost to serve load in the Midwest by the early 2040s. While the Central region could save $2.20/MWh and the East region $.70/MWh, costs could rise at times in the West region, which will export more often. 

The RTO also said the portfolio would reduce congestion to improve existing transmission limits, especially in its Central and East planning regions. 

Some stakeholders said the savings seemed underwhelming for the scale of the proposed 765-kV network. 

MISO Senior Expansion Planning Engineer James Slegers cautioned stakeholders that when more generators can deliver output, the greater volumes will likely aggravate congestion on other flowgates. The RTO said it plans to address congestion shifts through the underbuild process or through its next LRTP portfolio.  

The RTO is planning to debut a second part of the portfolio that proposes more projects for MISO Midwest. 

Drake said MISO is aware that the $25 billion portfolio would not enable all new deliveries of generation the RTO expects in the next 20 years. 

“That’s why we’re taking this in two slices,” Drake said. She said the second part will be considered a separate portfolio and able to stand on its own merits. 

WEC Energy Group’s Chris Plante challenged MISO’s characterization of the second LRTP being a standalone portfolio. He likened the system to a car that needs major repairs in addition to several secondary issues. 

“We need to look at all the problems of the vehicle. I appreciate MISO saying that it’s standalone, but that’s a red herring. Just say what it is: It doesn’t address all of the constraints. Let’s be honest,” Plante said. 

MISO Executive Director of Transmission Planning Laura Rauch said that despite not proposing to solve all system issues with this portfolio, MISO is nonetheless demonstrating that it provides value and sustains reliability. 

Drake said that without the second LRTP, curtailments, overloads and price separation will proliferate, and new resources will be prevented from connecting to an already strapped system. 

The LRTP portfolio would resolve most impending thermal violations on 200-kV and above facilities in the Midwest, MISO said. But for facilities under 200 kV, it said, the second LRTP appears to solve thermal violations less consistently. Staff said some of the remaining violations are better addressed through MISO’s routine annual transmission planning or through network upgrades assigned to generators trying to complete the interconnection queue. 

MISO will host another LRTP workshop July 17. 

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NY Sets Strategy to Reach 6 GW of Energy Storage

New York has approved a framework to reach its 6-GW energy storage goal by 2030 and will take steps to ease factors that have limited its deployment to barely 400 MW of operational capacity so far (18-E-0130).

The Public Service Commission’s vote June 20 on a 6-GW roadmap is the culmination of a lengthy period of planning and review after Gov. Kathy Hochul doubled the goal from 3 GW.

If successfully executed as planned, the roadmap would create infrastructure that would reduce future investments needed in the grid, replace more of the high-emissions peaker plants and potentially meet at least 20% of the state’s peak load.

Storage is an indispensable part of the grid New York wants to build, in which intermittent wind and solar generation provide an increasingly large portion of the power portfolio. Department of Public Service staff estimate a need for 12 GW of storage by 2040, when the state reaches its statutory deadline for a zero-emissions grid, and the 2030 goal is seen as an important market signal needed to build momentum toward this.

The PSC order establishes an interim goal of 1.5 GW of storage by 2025.

Revenue uncertainty and rising costs have limited the storage buildout in the state. As of April 1, approximately 396 MW of storage was operational in New York; 581 MW was under contract; and 300 MW has been procured but not under contract.

The PSC’s order attempts to address this. Among the highlights of the roadmap:

    • 3 GW of new short-duration (up to four hours) bulk storage will be procured through a new competitive index storage credit mechanism.
    • 5 GW of new retail storage (up to four hours) and 200 MW of new residential storage (up to two hours) will be supported through expansion of existing regional incentive programs through the New York State Energy Research and Development Authority.
    • At least 35% of program funds will support projects that benefit disadvantaged communities by targeting fossil fuel peaker plant emissions reductions; there will be specific carve-outs for the New York City region because of the concentration of peaker plants and disadvantaged communities there.
    • Electric utilities must study the potential for storage projects to provide cost-effective transmission and distribution services not available through existing markets.
    • Investment will be prioritized in the development of reliable, long-duration storage technologies.
    • Prevailing wages will be a programmatic requirement for energy storage projects with a capacity of 1 MW or greater.
    • Contract duration will be a maximum of 15 years for bulk lithium-ion battery projects and 25 years for other technology.
    • A one-time inflation adjustment will be allowed.
    • Retail storage projects will be capped at 20 MWh.

The New York Battery and Energy Storage Technology Consortium (NY-BEST) welcomed the news.

“The roadmap represents the largest investment in energy storage in the nation, with proposed investments estimated between $1.2 billion and $1.9 billion, distributed across bulk, retail and residential programs,” Executive Director William Acker said.

The trade group Alliance for Clean Energy New York also celebrated the move.

“This is an important milestone in our clean energy progress,” Executive Director Marguerite Wells said. “Battery energy storage plays a pivotal role in improving grid reliability, stabilizing electricity prices, harnessing the full power of renewable energy, reducing New York’s reliance on fossil fuels and transitioning to a modernized electric grid, and is an important part of reaching our clean energy and climate goals.”

“Long-duration energy storage is a vital resource in meeting peak loads as traditional peaking plants retire due to the” Climate Leadership and Community Protection Act, the Independent Power Producers of New York said. “However, batteries, as load modifiers, and not generators themselves, are risky due to the need to decide when to charge and when to discharge into the system. However, we still need new dispatchable resources in the future, whatever qualifies as net zero under the CLCPA, to keep the grid running during events like the heat we have had this week.”

The PSC vote was not unanimous. Commissioner Denise Sheehan, who previously was associated with NY-BEST, recused herself, and Commissioner John Maggiore concurred rather than vote to approve.

“Advancing the energy storage sector through this program once again positions New York as a leader for others to follow. That said, I’m skeptical about how we’re funding this program,” Maggiore said.

He specifically faulted the roadmap for relying on funding through utility bills and for benefiting some disadvantaged communities at the expense of others through the downstate carveouts.

The analysis performed for the roadmap estimates the total cost of the incentive program at $1.29 billion to $2.01 billion, a very wide range because of the uncertainty of wholesale energy and capacity payments.

It estimates 6 GW of storage by 2030 would have a net value in averted grid expenditures of $1.94 billion in net present value through increased delivery of renewables and decreased reliance on more expensive firm capacity. It did not attempt to quantify further societal benefits such as improved air quality.

In 2030, when the program cost is expected to be highest, monthly bill impact of the retail/residential storage incentives is estimated to range from an average of $1.07 for residential ratepayers to $22.43 for commercial ratepayers to $2,307.50 for industrial high-load factor ratepayers.

On top of that would be the bulk storage program impacts: $1.05, $22.14 and $2,277.13 per month for the same three classes of customers, respectively.

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DOE Announces $900M to Kick-start Small Modular Nuclear Pipeline

Two weeks after visiting Georgia to celebrate the completion of two new reactors at the Vogtle nuclear power plant, Energy Secretary Jennifer Granholm was on stage at the American Nuclear Society (ANS) Conference in Las Vegas, announcing $900 million in federal funding to support the buildout of a pipeline of new, smaller-scale nuclear plants. 

The Westinghouse AP1000 reactors now producing power at Vogtle were the first new nuclear plants built in the U.S. since 2016 and came online seven years behind schedule and cost more than double the original estimate of $14 billion. The new federal funding, authorized in the Infrastructure Investment and Jobs Act, is aimed at building market confidence that the U.S. industry will be able to incorporate the lessons learned at Vogtle to deliver a new round of safer, more efficient small modular reactors (SMRs) on time and on budget. 

According to a notice of intent (NOI) the Department of Energy issued June 17 ― following Granholm’s announcement in Las Vegas ― the IIJA dollars will be split into two “tiers.” The First Mover Team Support tier will provide up to $800 million for two next-generation light-water SMRs, or GenIII+ SMRs, being developed by teams that include a utility, the reactor manufacturer, a construction company and end users or off-takers.  

The teams must have signed contracts in hand and must be committed “to deploying a first plant while at the same time facilitating a multireactor GenIII+ SMR orderbook,” the NOI says. 

The Fast Follower Deployment Support tier will split the remaining $100 million between three types of projects that together could help streamline and accelerate project development. The three “sub-tiers” include: 

    • siting initiatives that “lead to multireactor orderbooks of advanced SMRs” 
    • initiatives to support the buildout of a cost-competitive nuclear supply chain 
    • initiatives that help GenIII+ SMR projects set and meet their time and cost targets 

The NOI also sets out a tentative schedule, beginning with an informational “Industry Day” and meetings with prospective applicants this summer, followed by the opening of the application process. The deadline for applications could be by year’s end, and awards could be announced by summer 2025. 

The federal support is intended to “ensure nuclear power ― the nation’s largest source of carbon-free electricity ― continues to serve as a key pillar of our nation’s transition to a safe and secure clean energy future,” Granholm said in a DOE press release. The goal is to “support early movers in the nuclear sector as we seek to scale up nuclear power and reinforce America’s leadership in the nuclear industry.” 

But U.S. leadership in nuclear development ― at home and abroad ― has waned as the cost and time overruns of Vogtle have cast a pall over the market, creating a “commercial stalemate,” according to the NOI. “Utilities and end users/off-takers recognize the benefits of and need for nuclear power, but perceived risks of cost and timeline overruns and project abandonment have limited committed orders for new reactors.” 

Anticipated growth in power demand could help break that stalemate, said Patrick White, research director of the Nuclear Innovation Alliance.  

DOE’s efforts to build an SMR pipeline is “part of a larger conversation about how different energy end users are going to think about trying to meet their clean energy targets,” White said. “I think we’re seeing a lot of conversations about what does it take for a utility to reach net zero? What does it take for things like tech companies that have increasing energy requirements from data centers, from AI computing?” he said. 

“There are more and more conversations about how a Generation III+ SMR could help meet those energy needs. So, I think this is another piece of the puzzle of trying to align all the different stakeholders so we can have a reactor technology ready when a project developer, a constructor and an end user are ready to commit to a project and move forward.” 

State of the Stalemate

The new Vogtle reactors ― referred to as Units 3 and 4 ― are classified as GenIII+ reactors, which is industry shorthand for the generation of nuclear reactors developed since the mid-1990s, White said. The first generation of reactors was developed in the 1950s and ‘60s, and the second generation ― many of which still are online today ― in the ‘70s and ‘80s. 

But the 1,000-MW size of the AP1000 “might limit its application for some utilities … and that total cost of the project might be prohibitive for some smaller utilities,” he said. “And so there was a recognition by advanced reactor developers and by companies that there might be a niche here for using that Generation III+ technology, but on a smaller scale.”  

DOE has been funding other advanced SMRs through its Advanced Reactor Demonstration Program (ARDP), which has provided $2.5 billion in IIJA funds to two projects using new technologies. TerraPower’s 345-MW Natrium reactor is designed to be a sodium-cooled fast reactor. The Bill Gates-funded company broke ground on the project June 10 at a site in Wyoming, near a soon-to-retire coal plant owned by PacifiCorp, which is planned to be the primary off-taker for the Natrium plant. 

X-energy’s Xe-100 reactors are designed as high-temperature, gas-cooled generators. X-energy is working with Dow Chemical, which plans to install four of the reactors at its Seadrift plant in Texas. 

A key difference between the ARDP projects and the GenIII+ SMRs is the fuel they use. GenIII+ SMRs use the same low-enriched uranium (LEU) that powers existing reactors. But both Natrium and the Xe-100 are designed to use high-assay, low-enriched uranium (HALEU), which has a higher concentration of uranium-235, close to 20% versus 3% to 5% for the LEU that fuels most commercial reactors.  

Until recently, Russia was the only source of uranium for HALEU, but the war in Ukraine has spurred DOE efforts to develop domestic supplies. A demonstration plant was opened in Ohio in November of 2023, with the goal of eventually producing enough HALEU for both ARDP projects, which are not expected to come online until the end of the decade. 

The GenIII+ SMRs now available or in development in the U.S. are mostly sized at 300 MW: for example, the Westinghouse AP300, a smaller version of the AP1000, and GE Hitachi’s BWRX 300. Holtec also is developing a 300-MW GenIII+ SMR, with plans to deploy two of the reactors at its Palisades plant in Michigan, which is in the process of restarting. 

The Palisades restart received a conditional commitment for a $1.52 billion loan from DOE’s Loan Programs Office in March. (See LPO Announces $1.52B Loan to Restart Palisades Nuclear Plant.) 

But, as DOE notes, the pipeline of committed projects is thin. Billed as the first GenIII+ SMR deployment in North America, the Province of Ontario and Ontario Power Generation (OPG) plan to install four GE Hitachi BWRX 300s at an existing OPG nuclear plant.  

The Tennessee Valley Authority also says it wants to install a BWRX 300 at its Clinch River site. CEO Jeff Lyash has spoken about developing a fleet of up to 20 reactors by 2050. (See Making the Case for Nuclear at NARUC.) 

Nuclear Capacity Needed

In addition to Vogtle Units 3 and 4, the 93 nuclear reactors in operation across the U.S. provide close to 18% of the nation’s electricity and 45.5% of its carbon-free power, according to the Nuclear Energy Institute, an industry trade group.   

In its recent Pathways to Commercial Liftoff: Advanced Nuclear report, DOE estimated that to meet President Joe Biden’s goal of a net-zero economy by 2050, the U.S. will need 550 GW to 770 GW of clean, firm power by 2050. Advanced nuclear could provide 300 GW of that total if the industry can triple its fleet’s 100-GW capacity, the report says.  

While some environmental groups, such as the Sierra Club and Greenpeace, remain opposed to the development of any new reactors, nuclear energy has become a rare point of common ground for Democrats and Republicans in Congress. A new bill aimed at streamlining and accelerating nuclear permitting (S. 870) cleared the Senate by a vote of 88-2 on June 18 and is on the way to President Biden. The House passed the bill in May with a strong 393-13 vote.  

But will DOE’s $900 million be enough to provide the momentum needed to overcome the legacy of Vogtle and activate the pipeline of orders the NOI envisions? 

Again, drawing on the lessons of Vogtle, DOE will prioritize projects that are reliable, licensable and commercially viable, according to the NOI. Teams also must be able to show they’ve agreed on a “preferred reactor technology with a replicable design.” 

Catherine Prat, a nuclear engineer and member of ANS, cautioned: “I don’t know if anyone in the design phase of a mega-project would say that any finite amount of money is enough. It certainly helps offset some of the risks, but still requires significant investment from utilities and reactor vendors to develop and deploy the technology.  

“It is a significant step for DOE to recognize that some level of government support is necessary, and I think it’s fair to say the industry is appreciative of that,” Prat said in an email. “Let’s not let perfection (enough money) be the enemy of good (some money [and] movement in the right direction).” 

Getting a pipeline of projects over the post-Vogtle hump will require “really trying to align the business models and business requirements for all the different commercial players that are going to need to work together,” White said.  

DOE “is trying to help kind of create a framework or a way to have incentives for these different companies to come together and say, ‘What is a business model that makes sense for these first movers and for fast followers?’ Does providing this additional funding help them to retire risk related to design, related to siting, related to licensing, related to supply chain, or is it a way to just help maybe reach alignment faster? 

“How do you get to five reactors? How do you get to 10 reactors that really help lower the cost of all the technologies overall?” 

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NY Opens Land-based Renewable Energy Solicitation

New York launched its eighth large-scale renewable energy solicitation June 20, seeking proposals for land-based projects to help the state meet its emission-reduction goals.

The New York State Energy Research and Development Authority (NYSERDA) said eligibility applications are due July 15; bid proposals are due Aug. ; and initial award notifications are expected by Sept. 30.

The 2024 Renewable Energy Standard request for proposals — RESRFP24-1 — will result in NYSERDA procuring Tier 1 renewable energy certificates from renewables that enter commercial operation before Nov. 30, 2026, with a possible deadline extension to Nov. 30, 2029.

A productive RFP would help NYSERDA continue to refill the state’s renewable energy pipeline, which suffered a major setback in late 2023 as 81 projects canceled Tier 1 contracts totaling 7.5 GW of nameplate capacity because of rising costs that made it financially untenable to proceed to construction.

As the pipeline collapsed and chances of the state reaching its goal of 70% renewable energy by 2030 grew increasingly remote, NYSERDA launched RESRFP23-1 on Nov. 30, 2023.

On April 29, it announced the 2023 solicitation had yielded tentative contracts for 24 projects totaling 2.4 GW of capacity, all of them mature proposals and many of them party to previously canceled contracts.

For RESRFP24-1, NYSERDA is encouraging all project developers to submit proposals, including new market entrants. The solicitation includes the inflation-indexing provisions that have been included in other recent renewable solicitations in the era of spiraling costs.

It also includes requirements to ensure the state’s societal goals beyond climate protection are addressed, including labor provisions, stakeholder engagement requirements, disadvantaged community commitments and agricultural land preservation.

“Private renewable energy developers are ready and willing to invest billions of dollars into New York, providing jobs and tax revenue for our local municipalities,” Marguerite Wells, executive director of the Alliance for Clean Energy New York, said in the state’s announcement of RESRFP24-1. “We expect numerous quality responses to this RFP, and we look forward to NYSERDA awarding projects that will be built expeditiously to bring benefits to New Yorkers as soon as possible.”

NYSERDA has scheduled a webinar for prospective bidders on June 27.

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OMS-MISO RA Survey: Potential 14-GW Capacity Deficit by Summer 2029

[EDITOR’S NOTE: A previous version of this article used the wrong figure for the bottom of the range of expected resource adequacy in summer 2025 in the first sentence (“a potential 1-GW capacity deficit”); this error was also in the excerpt for the article. The survey found that MISO could be short by as much as 2.7 GW.]

A relatively low turnout of constructed capacity in recent years could continue and deepen a potential 2.7-GW capacity deficit in summer 2025 to more than 14 GW by summer 2029, MISO and the Organization of MISO States revealed in their five-year resource adequacy projection.

According to the pair’s 11th annual joint survey, the footprint could either enjoy a 1-GW capacity surplus or contend with a nearly 3-GW deficit by next summer. Much depends on how quickly developers can overcome obstacles to get new resources into commercial operation.

This year’s survey assumed MISO will realize only about 2.3 GW/year in accredited capacity from new builds and did not designate projects with signed generator interconnection agreements as a foregone conclusion in committed capacity totals. The survey also didn’t account for the size of MISO’s record-breaking 300-GW interconnection queue and used a 9.2 to 9.6% planning reserve margin requirement over the next five years.

At the 2.3-GW/year rate — which is the historical average of what developers were able to connect in the past three years — a 5-GW capacity shortfall in planning year 2026/27 widens to 7.4 GW by 2027/28 and nearly 12 GW by 2028/29. Last year’s survey anticipated a 9.5-GW shortfall by the 2028/29 planning year. (See OMS-MISO RA Survey Signals Potential for 9-GW Shortfall by 2028.)

This year’s lower rate of assumed capacity additions spurred debate between MISO staff and stakeholders about what developers realistically can accomplish. That stalled the announcement of the survey results by a week.

During a June 20 teleconference to discuss the results, David Schoon, MISO resource adequacy engineer, said the RTO reflected a “new paradigm” from its interconnection queue in the survey. He said MISO’s current 50-GW backlog of unfinished generation that’s been approved to connect to the system but still is waiting in the wings influenced the survey’s new method of evaluating capacity additions.

Schoon said MISO felt it needed to reflect the stubborn trends from the “COVID slowdown, such as continuing supply chain bottlenecks, commercial uncertainty and permitting and labor delays,” despite what interconnection customers claim will be brought online.

“We’ve got to get out of that guessing game,” Schoon said of the queue’s annual yields. He said it’s not realistic to assume developers can bring an “explosion” of resources online in a single year.

However, Schoon said MISO and OMS also contemplated that circumstances mend over time, and the footprint experiences an influx of skilled labor, a less fraught supply chain, expedited permitting and commercial viability of new technologies. In that alternative projection, MISO might connect more than double its three-year historical rate, at a little more than 6 GW annually.

At 6.1 GW/year, MISO could enjoy a 4.6-GW surplus by summer 2029.

However, MISO added a caveat that large, spot-load additions could balloon over the next five years and threaten a more than 30-GW shortfall under the 2.3-GW/year scenario and a nearly 10-GW shortfall even under the 6.1-GW/year rate.

“The situation is changing very rapidly around us,” said Senior Director of Resource Adequacy Durgesh Manjure, referring to generation retirements and a resurgence in load growth through new data centers.

“Immediate actions are needed to expedite the addition of new capacity, coordinate resources for new load additions and potentially moderate the pace of resource retirements,” Schoon said.

Josh Byrnes, OMS president and member of the Iowa Utilities Board, said RTO members’ actions over the next year will matter a great deal. “We need to quickly move to make sure that new load doesn’t outpace generation additions,” he said.

Byrnes said the RTO should focus on ushering new capacity through its interconnection queue expeditiously and “use the expansive MISO footprint to the fullest” through regional transfers.

In a press release accompanying survey results, Byrnes stressed that as the region faces “tightening capacity reserve margins compounded with rapid and large load additions, it is imperative for everyone from developers (new load and generation), economic development authorities, utilities, regulators, MISO and other stakeholders to work in close coordination.”

WEC Energy Group’s Chris Plante asked if MISO has considered that load-serving entities with planned data centers in their territories will take pains to ensure they can cover the large load additions with new capacity or purchases.

MISO’s Scott Wright said OMS and the RTO deliberated on the steps utilities and local governments will take to spur economic development.

“But we’ve also noted that laying it out this way highlights the fact that … a lot of these are un-resourced loads,” Wright said.

Michigan Public Power Agency’s Tom Weeks asked if MISO or its consultants mulled quantum computing emerging in time for the new decade, which could make data center energy consumption “plummet by orders of magnitude.”

Schoon said such breakthroughs weren’t included as possibilities in survey results.

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Group Claims Powerex Backing Markets+ to Benefit from Divided West

A new study commissioned by Renewable Northwest (RNW) adds a contentious new wrinkle to the debate about the potential impact of market seams if the West ends up divided between CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+.

The study, conducted by Grid Strategies, comes about five months after release of a report from the Western Power Trading Forum and Public Generating Pool that cautioned that seams between Western day-ahead markets would create a different set of challenges from those seen at the boundaries between the full RTOs in the Eastern Interconnection. (See Western Market Seams Issues to Differ from East, Study Finds.)

The Grid Strategies study partly expands on that theme, finding that effective “market configuration” — meaning a market based on the widest footprint possible — outweighs the importance of market design. It also warns that lessons from the Eastern Interconnection show that market seams there continue to be a “persistent drag on efficiency” despite the mechanisms MISO, PJM and SPP have implemented to mitigate their impact.

The study also delves into the specific challenges a two-market scenario could pose in the Pacific Northwest, where neighboring and closely interconnected balancing authority areas — such as those operated by the Bonneville Power Administration and PacifiCorp — fall into separate markets, creating a winding and complicated boundary.

BPA, which controls about 75% of transmission in the Northwest, has made it clear its decision on a day-ahead market will not be driven by concerns about seams and has argued such issues can be resolved by seams agreements. (See Seams Concerns Won’t Drive Day-ahead Market Decision, BPA Says.)

The Grid Strategies study finds that “while experience in other markets support BPA’s argument that a seams agreement is necessary, experience also shows that seams agreements do not reduce barriers to transacting across market seams and will not address the detrimental impact of market seams on consumers.”

‘Hard to Achieve’

But the most controversial aspect of the new study is the contention that Vancouver, British Columbia-based energy marketer Powerex has backed the development of Markets+ because it stands to make more money trading in a divided West than in a single market with no seams.

That’s an assertion other Western electricity sector stakeholders have shared with RTO Insider but have been reluctant to put on the record.

“Well, to the detriment of my dreams to retire in Canada, I decided to go on the record,” RNW Executive Director Nicole Hughes joked in an email to RTO Insider. RNW is a renewable energy trade group that long has advocated for the development of a single organized market in the West and is a key supporter of CAISO’s EDAM.

Hughes was referring to a June 14 opinion piece she wrote for the Seattle-based publication Clearing Up.

The op-ed draws on Chapter 9 of the Grid Strategies study, which is headed “Good Configuration is Hard to Achieve Because Some Parties Benefit from Bad Configuration and Inefficient Seams.”

The chapter explains that BPA and Powerex control the largest amount of power supply and transmission in the Pacific Northwest, the latter being “the exclusive marketer of BC Hydro capability in the U.S., holding substantial hydro generation, storage and transmission rights, and is a major energy supplier to the Northwest.”

Powerex’s “mission” in participating in the U.S. market is “to maximize profits” on behalf of British Columbia’s ratepayers, the study says.

“As the exclusive marketer for BC Hydro, Powerex reports that electricity ‘trade provides economic and environmental benefits for British Columbia. All income generated by Powerex is returned to BC Hydro, which helps the utility keep electricity rates amongst the lowest in North America,’” it says, citing Powerex’s description of itself in the “About Us” section of its corporate website.

Last year, the Western Markets Exploratory Group (WMEG) completed a series of studies, conducted by Energy+Environmental Economics (E3), to assess the benefits that would accrue to various electricity market participants in the West under a range of market footprint scenarios.

Grid Strategies cites wording in the WMEG study for Powerex, which found that in a scenario where Northwest utilities join EDAM, Powerex “expects that its most attractive market opportunities would be forward sales,” prompting the company to limit the hourly flexibility of its hydroelectric exports.

But in a situation where Northwest utilities join Markets+, E3 determined Powerex “expects that its most attractive market opportunities will be hourly optimized transactions” and that it would offer the market its full hourly flexibility.

“E3 estimates that the incremental regionwide cost increase attributable to Powerex’s withholding hourly flexibility in these scenarios is approximately $7 million,” Grid Strategies says. “This example shows how positional power and control of transmission can have significant financial consequences for consumers in the Northwest.”

As the competition between EDAM and Markets+ plays out, SPP has found its strongest support among some entities in the Northwest, including BPA and Powerex, and among Arizona utilities Arizona Public Service, Salt River Project and Tucson Electric Power. But other major players in the Northwest, including PacifiCorp, Portland General Electric and Idaho Power, have signaled their intent to join EDAM, with Seattle City Light likely to follow.

Transmission links between the Northwest and Southwest are limited, and the Grid Strategies study notes that “control of key transmission capacity rights connecting the Northwest to the Southwest is highly concentrated, with a meaningful portion controlled by Powerex, who as a power marketer has an objective of maximizing profits, rather than minimizing consumer costs as do load-serving transmission capacity owners.”

“A pivotal supplier exercising market power can manipulate prices, benefiting itself to the detriment of load-serving entities and consumers,” the study continues. “It is very difficult to mitigate this market power in a two-market setting with no centralized oversight of the broader region. If the seams were more efficiently managed internally within a single market, this would be less likely to occur.”

Powerex Points to Governance, Design

In her op-ed, Hughes points out Powerex controls about 20% of transmission capacity rights on the California-Oregon Intertie, a key link between the Northwest and CAISO. She says direct trade with the Desert Southwest would allow Powerex to avoid paying to wheel power through the CAISO system.

“Powerex states that the solution to congestion rents wheeling through CAISO is to build more transmission to the Desert Southwest,” Hughes wrote. “More interregional transmission connectivity between the two regions would definitely benefit customers West-wide. However, several utilities serving major load centers are committed to continuing to operate in CAISO’s WEIM [Western Energy Imbalance Market] and have committed to expanding their commitment by joining its Extended Day-Ahead Market, while BPA is leaning toward leaving the WEIM and joining Markets+.”

Hughes also asserts the WMEG study indicates BPA would benefit from increased transmission revenues in a divided day-ahead market scenario while the rest of the region would see rising transmission costs.

Reached for comment, BPA spokesperson Doug Johnson said the federal power marketing administration was unprepared to respond to the Grid Strategies study or Hughes’ op-ed.

In an email to RTO Insider, Jeff Spires, director of power at Powerex, said that while “attention to seams is important,” the intent of the study “appears to be to distract from the essential governance and market design elements that differentiate the two day-ahead market options.”

“Powerex is just one of numerous entities participating in the development of Markets+, who collectively seek an organized market that provides independent and inclusive governance, an impartial market operator and a market design that achieves competitive market outcomes while balancing the interests of a broad array of participants,” Spires wrote.

Takeaways

The Grid Strategies study concludes with a handful of “key takeaways.” Chief among them is the assumption FERC is “unlikely to mandate good configuration and does not have a template for effective, efficient and equitable seams coordination,” leaving it to Western utilities and regulators “to evaluate customer impacts and make the best decisions for ratepayers” when it comes to day-ahead market decisions.

Another point is that attempts to address market inefficiencies caused by seams in the East have been “largely unsuccessful.”

“Transactions between markets are far below efficient levels, resulting in higher consumer costs,” the study says.

Yet another takeaway has to do with the access issues that would stem from a two-market configuration in the Northwest because of the region’s “heavy reliance” on BPA’s transmission.

“If market seams are developed between the major load centers in the region and the generation and transmission needed to serve these load centers, costs to consumers will increase, and efforts to bring new clean energy generation to load will be hindered,” the report says. “Particular attention should be paid to avoiding development of these seams today, and ample opportunity currently exists to develop a market [that] will minimize negative impacts to customers.”