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November 30, 2024

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MISO Predicts Painless Fall Despite Missouri Capacity Shortfall

MISO doesn’t believe autumn will prove much trouble for it to tackle, though it faces a capacity shortfall in Missouri.

According to its seasonal outlook, the grid operator likely will come the closest to calling on its load-modifying resources in September, when it predicts a 115.6-GW systemwide peak. Over the fall, MISO will have 115.8 GW of cleared capacity on hand. MISO noted that 124 GW was offered but didn’t clear the fall capacity auction.

Subsequent fall months don’t seem any cause for concern. MISO predicts a 95-GW peak in October and a nearly 94-GW peak in November, which should be handled easily by cleared capacity totals.

The systemwide numbers are despite a projected capacity shortfall in portions of Missouri for the season.

Per MISO’s capacity auction held in spring, Zone 5 — which contains local balancing authorities Ameren Missouri and the city of Columbia, Mo.’s Water and Light Department — should experience an 872-MW capacity deficit over the next few months. The zone came up short on its local clearing requirements in the auction and cleared at the $719.81/MW-day cost of new entry for generation in the fall and upcoming spring.

Ameren leadership has said the effects of the scarcity likely will go unnoticed, not impacting reliability nor customers’ bills. (See Ameren: MISO Missouri Capacity Shortfall Likely Inconsequential.)

July Peak Prediction Unfulfilled

Meanwhile, MISO reported its operators contended with a 118-GW peak in July, lower than the 123-GW peak it anticipated before the start of the season.

MISO’s peak occurred July 15, while MISO Midwest was under conservative operations as hot and stormy weather passed through. July’s peak registered lower than the 121-GW peak in July 2023. Load averaged about 86 GW per day in July, in line with last July’s average load. Real-time prices also closely tracked last year, coming in at $30/MWh compared to last July’s $31/MWh. Gas and coal prices were identical year-over-year in MISO, holding at $2/MMBtu apiece.

MISO said average generation outages in July totaled 31 GW per day, a 2-GW improvement over last year.

MISO leadership and stakeholders are set to review summertime performance during a quarterly MISO Board Week meetup in mid-September in Indianapolis.

Ramp Deficit Triggers VOLL

MISO and stakeholders dissected a mid-June price spike due to inadequate ramping at an Aug. 22 Market Subcommittee meeting.

MISO’s system-wide energy price shot up to $3,500/MWh for two intervals on June 16 after several units powered down around 9 p.m. MISO said the ramping ability available on its remaining dispatchable resources “was insufficient to meet emerging risks.”

Stakeholders asked how MISO didn’t see the ramp needs coming when the units’ exit that night was planned. They also questioned how prices could soar to the $3,500/MWh value of lost load briefly then almost instantaneously settle back to the usual, approximately $25/MWh.

“We’ve seen a number of these real-time price spikes related to operating reserves and not having enough ramp,” Market Evaluation Manager Dustin Grethen said. “We ended up in a situation where available dispatchable generation was insufficient.”

Grethen said the value of lost load was necessary because ramping capability went into a deficit and demand couldn’t be met systemwide.

Grethen said multiple times this summer, MISO has been “trying to run lean” and use reserves. However, he said in this instance MISO experienced an under-forecast in wind output paired with some uninstructed deviation on the part of other generators.

“Things are tighter than they used to be. Some of these risks that before went under the boat are now bumping the bottom,” Grethen said.

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CPUC Approves Plan to Procure 10.6 GW of Clean Resources

California regulators have approved a plan for the state to buy up to 10.6 GW of long-lead time clean energy resources, including 7.6 GW of offshore wind along with geothermal energy and long-duration energy storage.

The California Public Utilities Commission voted Aug. 22 to approve the central procurement plan. It is seen as a way of transforming the market for emerging technologies that will help the state meet its greenhouse gas reduction goals.

“With this new tool, California has the opportunity to jumpstart clean energy technologies and bring them to scale,” CPUC President Alice Reynolds said in a statement after the vote.

The CPUC will ask the state’s Department of Water Resources (DWR), through its Statewide Energy Office, to buy up to 10.6 GW of nameplate capacity including:

    • 6 GW of offshore wind.
    • 1 GW of geothermal generation.
    • 1 GW of multi-day energy storage.
    • 1 GW of energy storage with a discharge period of at least 12 hours.

The plan excludes long-duration storage that uses lithium-ion batteries. Pumped storage hydroelectric projects will be eligible only if they’re 500 MW or less and received state funding before 2023. The geothermal generation may be of any type.

The procurement will be on behalf of all energy providers within the CPUC’s jurisdiction, including investor-owned utilities, community choice aggregators and direct access providers. The benefits and costs will be split up among energy providers.

Solicitations will start in 2026 for long-duration storage and in 2027 for offshore wind and geothermal resources, with the resources coming online by 2037.

The resource quantities in the procurement are “up to” amounts. DWR or CPUC could decide to not buy the resources if they cost too much. The CPUC is expecting multiple rounds of solicitations in which costs would fall over time.

Assessing Need

The centralized procurement strategy is a component of Assembly Bill 1373 of 2023. Under AB 1373, resources eligible to be included in the strategy are those that don’t use fossil fuels or combustion to generate electricity and that have a lead time of at least five years for development and construction. (See New California Law to Give State Power to Procure Renewable Energy.)

The bill set a Sept. 1, 2024, deadline for the CPUC to determine if there’s a need for centralized procurement. To make that assessment, the CPUC evaluated utilities’ integrated resource plans and looked for gaps in certain resource types.

The CPUC saw a need for geothermal generation and long-duration storage but plans to ask DWR to solicit only about half the projected amount needed to meet renewable and zero-carbon energy targets.

This will “facilitate a down payment” on the technologies, “while still leaving room for LSEs to procure the technologies individually, after costs are reduced and market transformation is underway,” the agency said in its decision.

For offshore wind, the CPUC said 7.6 GW is enough to signal “a strong interest in developing the resource,” while going beyond that amount might be riskier for ratepayers.

The California Energy Commission in 2022 adopted the nation’s most ambitious long-term offshore wind goals, targeting a buildout of up to 5 GW by 2030 and 25 GW by 2045. (See California Adopts Country’s Most Ambitious OSW Targets.)

Utility Cost-sharing

The benefits and costs of centrally procured geothermal and offshore wind energy will be divided among energy providers within CPUC jurisdiction based on their annual load share. For long-duration storage, benefits and cost shares will be based on 12-month coincident peak demand.

More details of cost and benefit sharing will be worked out before any contracts are signed.

Although publicly owned utilities aren’t within CPUC jurisdiction, the agency recommended that DWR ask those utilities if they want to voluntarily participate in the centralized procurement.

The CPUC will reevaluate the need for additional centralized procurement of long-lead time resources in future IRP cycles. Previous need determinations won’t be reduced in that process, according to the CPUC decision.

CPUC Commissioner John Reynolds said approval of the procurement strategy “issues a challenge to the industry.”

“We want to see developers deliver on the immense potential of these technologies to deliver tangible ratepayer benefits and cost efficiencies with the economies of scale we are enabling here,” he said in a statement.

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BPA to Delay Day-ahead Market Decision, Sources Say

The Bonneville Power Administration will delay its Western day-ahead market choice beyond a scheduled Aug. 29 announcement date and likely will extend the decision-making process into 2025, multiple sources told RTO Insider.

The sources, who are not authorized to speak on behalf of their organizations, shared those details a week after BPA Administrator John Hairston said he was “evaluating” the timeline for choosing between SPP’s Markets+ or CAISO’s Extended Day-Ahead Market (EDAM).

“There’s a lot of factors at play. There’s more to come in the next week or two,” one source said.

Speaking during the agency’s Aug. 15 Quarterly Business Review, Hairston said the agency was “balancing the need for a deliberate, transparent process with the urgency created by the decisions of our neighbors.”

Two of those neighbors, the six-state utility PacifiCorp and Oregon’s Portland General Electric, have signed implementation agreements with EDAM, while the Balancing Authority of Northern California, Idaho Power, the Los Angeles Department of Water and Power, and NV Energy have signaled their intent to join the CAISO-run market.

BPA staff in April issued a “leaning” recommending the agency choose Markets+ over EDAM, citing the SPP market’s independent governance and overall design as primary factors in the opinion. (See BPA Staff Recommends Markets+ over EDAM.)

The agency previously cited Aug. 29 as the date it would issue a “draft letter to the region” on a decision whether to join a day-ahead market and which market it would select, followed by a “final” letter in November. Two sources said a decision now could be delayed by as much as six months.

BPA spokesperson Doug Johnson told RTO Insider the agency still is evaluating the timeline and expects to provide more information the week of Aug. 26.

During the Aug. 15 call, Hairston acknowledged the progress the West-Wide Governance Pathways Initiative has made in “improving” CAISO’s state-run market governance without the need for legislative changes, but he also pointed to the legislative changes still needed to bring greater independence to the ISO’s EDAM and Western Energy Imbalance Market (WEIM), in which BPA is a participant. (See CAISO, WEM Boards Approve Pathways ‘Step 1’ Plan.)

“As I’ve said from the outset, BPA seeks to participate in a market that has a durable, effective and independent governance structure [that] provides fair representation to all market participants and stakeholders,” Hairston said. “I fully appreciate the magnitude of such a decision, and you have my commitment to continuing our deliberate, transparent process, with the aim of making a decision that is right for our customers and the region.”

Hairston and his agency face pressure on multiple fronts over the day-ahead market decision. Environmental and industry groups that favor development of a single West-wide market that expressly includes California, such as the Northwest Energy Coalition, have urged BPA to join EDAM to help maximize the “diversity benefit” of the West’s geographically distributed emissions-free resources through a market with the largest possible footprint.

Northwest utility regulators, who have no oversight authority over BPA, also signaled their preference for a single market based on EDAM when they helped launch the Pathways Initiative last summer. In separate letters earlier this year, Washington Gov. Jay Inslee cited the importance of a single West-wide market that includes California to meet state targets for emissions reductions, while Oregon Gov. Tina Kotek warned that “fragmentation will drive unnecessary costs, create new reliability risks and prevent fully utilizing the resources that customers across the region have paid for.”

The most significant political pressure materialized in a July 25 letter addressed to Hairston from the four U.S. Democratic senators representing Oregon and Washington.

In the letter, the senators urged the agency to delay its decision until more developments play out around Markets+ and EDAM and made clear they think the Northwest would see more benefit from one organized electricity market than two. They also directed BPA to answer 14 detailed questions about its “leaning” by Aug. 25 — a Sunday. (See NW Senators Urge BPA to Delay Day-ahead Market Decision.)

Further complicating matters for BPA: A week after the arrival of the senators’ letter, FERC issued SPP a deficiency notice covering multiple sections of the Markets+ tariff that the RTO filed in March, a concern cited by the senators. (See FERC Finds SPP Markets+ Tariff ‘Deficient’ in Several Areas.)

‘Lasting Consequences’

BPA also faces pressure in the other direction from many — although not all — of the publicly owned utilities that constitute its base of “preference” customers, who have advocated firmly for the agency to join Markets+. (See Northwest Public Power Group Endorses Markets+ over EDAM.)

On Aug. 21, a sizable cohort from that group sent their own response to the Northwestern U.S. senators, asking them to consider the impact of BPA’s day-ahead market decision on the region’s consumer- and tribal-owned utilities. Among the 47 signatories were Tacoma Power, Clark Public Utilities and the Snohomish, Chelan, Douglas and Grant county public utility districts in Washington; and Salem Electric, Umatilla Electric Cooperative and the Clatskanie, Emerald and Northern Wasco County people’s utility districts in Oregon.

“BPA’s decision will have lasting consequences for our ratepayers and your constituents,” the utilities wrote. “Although we support West-wide collaboration, the fiduciary obligation to our ratepayers drives our evaluation of day-ahead market options — as it should BPA’s decision.”

The letter reiterated BPA’s oft stated concern about EDAM’s California-run governance, saying “governance drives major policy outcomes and, therefore, the allocation of economic outcomes among the communities served through the market,” echoing a point made in a recent “issue alert” released by a group of entities that helped fund the “Phase 1” tariff development stage of Markets+. (See Governance is ‘Key Consideration’ for West, Markets+ Backers Say.)

While the utilities contend it was competition from Markets+ that motivated the effort to address CAISO’s market governance, they also doubt the Pathways Initiative can achieve “meaningful change” to California law because previous efforts “have always failed.” The utilities also argue EDAM was designed and approved under CAISO’s current “flawed governance,” and that it would take years to “unwind” the impact of that on a market design that disfavors Northwestern interests.

“Forcing BPA to delay participation in Markets+ and forgo a market with superior governance and market design frameworks on account of hopes that the West-Wide Governance Pathways Initiative may succeed would be irresponsible and harmful to our ratepayers,” they wrote.

But the utilities’ most notable concern is that pressure from the senators could delay BPA’s decision to help fund the “Phase 2” implementation stage of Markets+, which, they contend, would take pressure off the efforts to alter the WEIM/EDAM governance structure.

“BPA’s ongoing funding commitment to Markets+ is essential to the continued development of a day-ahead market that respects the policy, economic and regulatory interests of our ratepayers,” they wrote.

The Portland, Ore.-based Public Power Council (PPC) made a similar point in an Aug. 15 letter addressed to Hairston, which encouraged BPA to commit to funding Phase 2 of Markets+ to ensure the market “remains a viable option for BPA and other stakeholders in the West.

“This commitment should be formalized in a letter to the region, capturing the agency’s evaluation of market options to date,” the PPC wrote. “We acknowledge that this may result in a timing difference between BPA’s decision to fund the next phase in Markets+ and BPA’s overall decision on day-ahead market participation.”

Such a commitment would represent a significant financial investment for BPA. The cost for Phase 2 implementation —scheduled for 2025 through the first quarter of 2027— will run to about $150 million, SPP told RTO Insider. Whatever the actual figure, BPA will be on the hook to cover 17.4% of the funding costs, second only to Powerex’s 23.2% share, according to an SPP document.

BPA’s original share for funding Phase 1 was 15.2%, but all Phase 2 funders will face higher shares now that NV Energy, Western Area Power Administration’s Desert Southwest Region, Liberty Utilities and Arizona Electric Power Cooperative have pulled their support from Markets+.

During an Aug. 13 Markets+ Participants Executive Committee meeting, SPP staff told stakeholders they have SPP board approval to engage with lenders over Phase 2 funding agreements, which will be extended to participants by the end of the year. (See SPP Dispels Concerns over Markets+ Deficiency Letter.)

SPP expects its administrative costs to operate Markets+ to range between $65 million and $70 million annually.

 

 

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Analysis Group: No Changes to NYISO CONE Method Needed

The Analysis Group told NYISO stakeholders Aug. 22 that it did not recommend any major changes to the annual process for updating the ISO’s gross cost of new entry for generators, saying it did not find any other, more accurate source of data on component costs.

NYISO increases its CONE every year between its quadrennial demand curve resets (DCRs) to account for inflation. It uses data from inflation indices for four major components of engineering, procurement and construction costs: generating equipment, labor, materials and other miscellaneous costs.

Stakeholders have raised concerns that the Analysis Group’s recommendation of a two-hour lithium ion battery storage system as the peaker plant for the 2025-29 DCR — a change from GE Vernova’s 7HA.02 gas turbine — leads to higher CONE values.

But the consultancy said the increase is attributed to factors that are not taken into account in the annual update — and they should not be.

“In our view, annual updates are not designed to replicate a full demand curve reset,” Daniel Stuart, a manager and public policy expert for Analysis Group, told the Installed Capacity Working Group. “They just can’t consider policy changes in market factors, [such as] federal policy that provides a new tax credit for battery storage technology that will never be picked up on an inflation index.”

The consultancy did, however, change an index it had recommended to estimate the generating equipment component for battery storage systems to one that that excludes lead acid batteries.

“That seems like a helpful improvement to exclude a kind of battery that is quite different from lithium ion batteries,” said Stuart. “But beyond that, we have not found any other indices that more accurately reflect the changes and the four cost components defined in the tariff.”

Howard Fromer, director of regulatory affairs for Bayonne Energy Center, expressed concern that utility-scale batteries would not be accurately represented by the new index because they represent a small minority of the batteries included.

“It’s going to get watered down by including a lot of stuff [that] aren’t even subject to tariffs,” Fromer said. “We’re going to miss a huge potential component going forward.”

Stuart asked what other index should be used. Fromer suggested adjusting the index; Doreen Saia, chair of the Albany office of energy and natural resources practice for Greenberg Traurig, said the risk factor could be adjusted.

“Throwing up our hands and saying, ‘We just can’t get there,’ doesn’t ignore the fact that an investor will just throw up his hands,” Saia said.

Amanda De Vito Trinsey, a lawyer with Couch White representing New York City and Multiple Intervenors (MI) — a group of large industrial, commercial and institutional energy consumers — stepped in.

“I hear what everyone’s saying, and I understand the concern,” Trinsey said. “We don’t know what will happen, and so I think we’re doing the best with what we have in place. The city and MI support the process that you have here, and we don’t see any reason to depart. … What we have now captures that risk adequately.”

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NERC Following ‘Very Ambitious Timeline’ for IBR Conference

Plans are advancing rapidly for a technical conference to resolve an impasse on a proposed reliability standard, NERC staff told members of the organization’s Standards Committee during its monthly conference call this week.

The technical conference, scheduled for Sept. 4-5 at a still-to-be-announced location near NERC’s Washington, D.C., office, is intended to address FERC’s directive in 2023 — part of Order 901 — to submit reliability standards by Nov. 4 addressing IBR performance requirements, disturbance monitoring data-sharing and post-event performance validation. 

NERC has produced five draft standards relating to FERC’s order, four of which have met the two-thirds weighted stakeholder approval needed for submission to the commission. However, the last standard, PRC-029-1 (Frequency and voltage ride-through requirements for inverter-based resources), failed to receive approval in its most recent formal ballot round that ended Aug. 12. 

The failure of PRC-029-1 to win industry approval and the impending FERC deadline prompted NERC’s Board of Trustees to take unprecedented action to break the impasse. Invoking its authority under Section 321 of NERC’s Rules of Procedure, the board directed the Standards Committee to convene a technical conference to gather input from industry, which it will use to revise the proposed standard. (See “Board Invokes Standards Authority to Meet IBR Deadline,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.) 

NERC will submit the revised standard for stakeholder ballot; if it receives at least a two-thirds weighted stakeholder approval, it will be considered approved. 

NERC Manager of Standards Development Jamie Calderon acknowledged the board’s directive established “a very ambitious timeline” for the entire process, which must be finished by the end of September. 

“We have 45 days to plan the conference, implement the conference, take the results of the conference, revise the standard … ballot the standard, and close that ballot. All within a 45-day window,” Calderon said. “It’s absolutely going to be crucial that we are working in concert with the SC throughout.” 

Calderon said the planning has been especially challenging because until Aug. 12, NERC did not know which of the proposed standards, if any, would fail the ballot and what the board’s decision would be for those that did. ERO staff knew there was a possibility they would have to organize a technical conference on short notice, so they “have been working diligently [with SC leadership] to make sure [they] can hit the ground running.” 

While NERC announced following its board meeting the technical conference would take place in its D.C. office, Calderon said interest has grown so rapidly the ERO no longer believes its office will have sufficient space for all attendees. Even capacity at the backup offsite location soon may be reached, she said. To allow as many interested parties to participate as possible, NERC has implemented a virtual attendance option for the conference as well.  

The board has scheduled a special conference call Oct. 9 to discuss the stakeholder vote on the revised standard. A vote of less than two-thirds will not necessarily mean the standard is rejected. According to Section 321, the board has the option of accepting the standard if it receives at least 60% weighted approval. 

Soo Jin Kim, NERC’s vice president of engineering and standards, reminded attendees the technical conference is just one option for getting the IBR ride-through standard over the finish line. Section 321 also allows the board to direct the SC or NERC management to develop a draft standard without stakeholder input and submit it to FERC directly after posting it for a 45-day comment period.

The board previously threatened to invoke this authority in 2023 to pass NERC’s draft cold weather standard, but the measure ultimately was unnecessary after industry approved EOP-012-2 in its final formal comment and ballot period. (See Industry Approves New Cold Weather Standard in Final Vote.) 

“If this fails to get to 60%, we would have to go back to the board to adopt that procedure with a very, very compressed time frame, because we would still need to meet the Nov. 4 deadline,” Kim said. “That does not require a technical conference, [and] it does not require another ballot. So I just want to remind everyone that that path is a little bit more aggressive with regards to drafting and language.” 

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CAISO Kicks Off New Initiative to Streamline Bilateral Trading

A new initiative to streamline and expand bilateral trading in the Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM) was launched Aug. 20, marking another important step toward EDAM implementation.

The initiative centers on inter-scheduling coordinator (inter-SC) trades, an optional market feature facilitating settlement of bilateral contracts between scheduling coordinators (SCs).

“As we’ve been going through implementation activities, we’ve seen some requests where there may be potential value in inter-SC trade functionality,” said Milos Bosanac, regional markets section manager at CAISO. “The lift to implement this functionality is not extensive, and it’s something that could be included, if approved, within the broader implementation activity of the EDAM effort for May of 2026.”

According to the straw proposal, SCs in the ISO market can submit an inter-SC trade, which is a settlement service for parties of bilateral contracts to offset ISO settlement charges against bilateral contractual payment responsibilities. Inter-SC trades don’t have an impact on market optimization, schedules or dispatch, and currently are supported in the ISO balancing area, but not in the wider WEIM or future EDAM footprint.

There are three types of inter-SC trades involving energy, ancillary services and the integrated forward market (IFM) load uplift obligation. Trades of energy can facilitate settlement of bilateral power purchases or trades of energy between SCs in the day-ahead or real-time markets and can be made at physical generator locations (PNodes) or at aggregate pricing nodes (APNs).

Ancillary services trades can facilitate bilateral arrangements of regulation-up, regulation-down, spinning and non-spinning reserve ancillary services obligations. These are financial-only trades that are not at defined locations in the real-time market. In the WEIM and EDAM markets, ancillary services are not optimized or settled through the market, and therefore, the ISO isn’t proposing to extend this type of trade to the broader markets.

IFM load uplift obligation trades can facilitate transfer of bid cost recovery obligations between parties based on bilateral contract arrangements. Like ancillary service trades, they do not occur at defined locations and operate only in the real-time market, and aren’t being considered for extension, either.

“We’re also not proposing, at this stage, to extend this type of inter-SC trade to EIM and EDAM areas for a couple of different reasons, primarily that this is really a feature of participation in the day-ahead market so it wouldn’t necessarily be applicable in the EIM,” Bosanac said. “The current structure of settlement of the IFM load uplift obligation in the EDAM is with the balancing area, not necessarily with the discrete loads within that balancing area. So, there might not be much value to this type of inter-SC trade.”

For trades at physical locations, settlements occur based on the locational marginal price at the location, and there is no limit to the number of trades that can occur. But at APNs, only one trade can occur per scheduling coordinator each hour. Some stakeholders took issue with the limit on trades.

“This will not meet WAPA’s requirements,” said Tong Wu, representing the Western Area Power Administration. “We need to be able to have multiple trades because we have multiple customers … so although from WAPA’s side there’s only one SC, on the customer side, there will be multiple SCs that we need to trade with.”

Dan Williams, principal advisor of Western markets at The Energy Authority, shared Wu’s concern.

“WAPA has really defined the need statement very well within its resource portfolio for why this needs to exist and how it can be used,” Williams said. “There’s probably still a little more work.”

The initiative received overall support and is expected to be presented to the ISO Board of Governors and Western Energy Markets Governing Body in early November.

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DOE Wind Power Reports Show Mixed Results in 2023

The 2024 editions of the U.S. Department of Energy’s wind energy market reports show growth amid challenges. 

Utility-scale onshore wind capacity increased by 6.5 GW in 2023. While that represented a $10.8 billion capital investment, it was the third consecutive annual decline, and the smallest capacity addition since 2014. 

The emerging U.S. offshore wind industry ran into serious problems in 2023, and by May 2024, there still was only 174 MW operational in U.S. waters. But three projects totaling 4,097 MW were under construction, and four other projects totaling 3,378 MW had been permitted. 

Distributed wind capacity nationwide reached 1,110 MW with the addition of 1,999 new turbines in 16 states in 2023. This was more turbines than were added in 2022 or 2021, but the cost and the capacity of those additions was greater than in 2023. 

The difference in 2022 and 2023 average wind speeds is shown across the 48 contiguous states. | Pacific Northwest National Laboratory

DOE’s Wind Energy Technologies Office funded the reports, which were compiled by three DOE national laboratories. 

The office said in a news release that the policies of the Biden administration and funding from the Inflation Reduction Act have accelerated the wind energy sector to the point that it accounted for more than 10% of electricity generated and 12% of capacity added in the United States in 2023. 

It said the U.S. project pipeline is 53% larger than a year ago and projected that annual capacity additions would exceed 15 GW by 2026 and be nearly 20 GW by 2030. 

Onshore Wind

The Land-Based Wind Market Report was prepared by Lawrence Berkeley National Laboratory. 

Highlights include:  

    • Installed capacity surpassed 150 GW in 42 states, with Texas leading in nameplate capacity (41,594 MW) and Iowa leading in percentage of in-state electricity generation (59.2%). 
    • General Electric built the majority of wind turbines installed in the U.S. in 2023 — 58%. Vestas was a distant second at 30%. Nordex and Siemens-Gamesa Renewable Energy accounted for 9 and 4%, respectively. 
    • The U.S. wind industry continues to rely on imports, although the IRA has created renewed optimism about domestic supply chain expansion; annual U.S. production capacity at the end of 2023 stood at 15 GW for nacelle assembly, 12 GW for tower manufacturing and 4 GW for blade manufacturing. 
    • Independent power producers own over 90% of the new wind capacity installed in 2023. 
    • Direct retail purchases of wind power, including corporate offtakers, led the market for new wind energy capacity for a second year in a row, buying electricity from at least 48% of the new facilities; electric utilities were a distant second at 29%. 

Offshore Wind

The Offshore Wind Market Report was prepared by the National Renewable Energy Laboratory (NREL). 

Highlights include: 

    • Using the broadest definition, including the maximum potential capacity of lease areas that are newly designated but not yet sold, the U.S. offshore wind pipeline grew 53% to 80,523 MW as of the end of May. 
    • Just over 25,000 MW of that pipeline calls for floating wind turbines, which still are in the development stage and are not expected to be installed in U.S. waters at commercial scale anytime soon. 
    • Estimated investment in the U.S. offshore wind supply chain has reached $10 billion since President Biden took office; NREL has estimated the need to be at least $22 billion. 
    • State-level policies continue to drive offshore wind development; as of May 31, mandates in eight states total 45,703 MW and non-binding planning targets in five states total 69,427 MW. 
    • Fifteen contracts to purchase 12,378 MW from offshore wind farms have been signed. 
    • The report tallied 68,258 MW installed capacity worldwide as of December 2023, less than 100 MW of it in the United States. 

Distributed Wind

The Distributed Wind Market Report was prepared by the Pacific Northwest National Laboratory. 

The North Atlantic region off the New York-New England coast has the most advanced portfolio in the U.S. offshore wind industry. | Lawrence Berkeley National Laboratory

Highlights include: 

    • Ohio, Illinois and Alaska accounted for 78% of the distributed wind capacity added in 2023. 
    • Large turbines (larger than 1 MW) accounted for 69.5% of capacity added; midsize turbines (101 kW to 1 MW) accounted for 8.6%; small turbines accounted for 21.9%. 
    • The major distributed projects in 2023 were a 4.5-MW facility for a lime manufacturing plant in Ohio, a 2.8-MW facility to support an EV maker’s plant in Illinois and a 0.9-MW facility to serve communities in Alaska. 
    • Only 11% of distributed wind installed in 2023 feeds into the grid for local use, while 89% was installed to supply an on-site use; this was an aberration caused by two particularly large projects at industrial sites. 
    • Significant activity and investment in the small wind market in 2023 suggests development might increase in coming years. 
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Exec Details MISO’s Tight Spot Between Load Growth, Retirements, Unwieldy Queue

INDIANAPOLIS — Senior Vice President Todd Hillman encapsulated MISO’s current pressure cooker environment of escalating data center demand, a precarious reliability situation and an overwhelmingly large interconnection queue at Infocast’s inaugural Midcontinent Clean Energy Summit Aug. 20.

Hillman said the days of 0.6 to 1% “anemic” load growth MISO-wide are in the rearview. He said MISO is bracing for 10% load growth in the next few years, driven by 14 to 16 GW of new facility demand.

But he added a caveat that MISO has poor visibility into the magnitude and entrances of large loads. Complicating matters, MISO is scraping its reserves as generation retirements continue.

“In the Midwest, we are at our reserve margins,” Hillman said. “We’ve already been driving to this reserve margin without any load growth.”

MISO expects 80-plus GW of retirements in its dispatchable fleet by 2042, Hillman said.

“We’re all waiting for that next thing: ‘Is it small nuclear reactors, is it long-duration storage, is it, is it, is it?’ My question is when will these technologies become commercially viable? Because we need them now,” he said.

For its part, MISO is trying to craft markets that place reliability front and center, Hillman said, invoking MISO’s proposed availability-based capacity accreditation for all resources, efforts to beef up scarcity pricing and exploring a possible new resource adequacy standard to replace the loss of load expectation.

Hillman said the MISO community should take notice of PJM’s capacity auction, where Dominion Energy’s entrance caused its zonal price to skyrocket to more than $440/MW-day. He said the unofficial data center capital of Arlington, Va., contained in the zone provides a cautionary tale for MISO. He said PJM and MISO, which can rely on one another in times of need, cannot count on the other’s imports when both regions are maxed out before emergency conditions descend.

“You can’t have two drunks leaning on each other. One of them is going to fall down. Now I’m not saying MISO is the drunk. I’m not saying that,” Hillman joked to audience laughter.

Hillman said the typical data center can be built in a matter of months. Generation, on the other hand, takes about six years to build, factoring in queue wait times and construction obstacles.

He said the situation is becoming desperate enough that Holtec International will attempt a restart of Palisades’ 800 MW reactor in Michigan after three years of retirement “to the low, low, low introductory price of $2.5 billion.”

Hillman also touched on the double-edged sword nature of MISO’s very active interconnection queue, which potentially could grow to 350 GW if MISO certifies all 123 GW of its 2022 queue submittals.

“The good news is that we have a very robust queue. The bad news is that we have a very robust queue,” Hillman said.

He said MISO’s active queue is so large engineers deem it “technically infeasible” to study potential interconnections.

Hillman reflected on how far MISO has come in two decades. He pointed out that the conference’s location, the Mariott Indianapolis North, was the site of MISO’s first annual meeting in 2005.

Back then, MISO was in the thick of what would become known as “Peakerfest,” Hillman said, where control room operators would over-commit peaking resources out of an abundance of caution. He also said MISO’s then approximately 5 GW wind fleet now stands at 35 GW.

“We’ve basically had three generation renaissances in the last 50 years,” Hillman said of the energy industry. He noted that from about 1969 to 1986 the nation built about 200 GW of coal power, which was followed by approximately 200 GW of new natural gas generation in the 1990s and the early 2000s surge in wind farms.

“Now we’re in the fourth renaissance, and that’s a load renaissance,” Hilman said. He called for a “higher level of debate” on the clean energy transition.

“We have always seen our industry come through,” he said. “It’s going to be quite the ride. It’s going to be quite the adventure.”

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CAISO Adjusts Timeline for Storage Bid Cost Recovery Initiative

Responding to significant stakeholder pushback, CAISO has extended the timeline of its Storage Bid Cost Recovery and Default Energy Bids Enhancements initiative to allow more discussion of alternative solutions to refine BCR provisions for storage resources. (See CAISO Proposal Seeks to Refine Storage Bid Cost Recovery.) 

CAISO staff discussed the changes in an Aug. 19 meeting originally intended to review the revised straw proposal slated to be released Aug. 14. But after stakeholders consistently asked for a more holistic initiative, the meeting was spent considering alternative proposals to the first one presented by the ISO.  

“This is a change that we think will support stakeholders to collaborate with us to develop those ideas so that we can continue comparing them to other proposals and determine what is the best path forward given the challenges that we’re trying to solve,” said Sergio Dueñas Melendez, storage sector manager at CAISO. “I want to note that this revised schedule does not change the importance and the sense of urgency that we have in addressing this issue.”  

In 2022, the ISO identified that bid cost recovery (BCR) provisions for energy storage didn’t align with the intent of BCR, resulting in unusually high payments to storage resources. (See CAISO Kicks Off Storage Bid Cost Recovery Stakeholder Initiative.)  

The problem materialized because CAISO’s BCR construct doesn’t adequately consider state of charge (SOC), Dueñas Melendez said, which is necessary for an energy storage resource to support its awards and schedules. It led to two main concerns: that storage assets are not exposed to real-time prices for deviating from day-ahead schedules and that they may have an incentive to bid strategically to maximize the combined BCR and market payments.  

In response, the ISO presented a proposed solution that would redefine dispatch that is unavailable due to SOC constraints in the binding interval as “non-optimal energy,” which would be ineligible for BCR. If a storage resource’s SOC at the start of the binding interval was equal to its minimum or maximum value, the market would rerate or derate the Pmax or PMin to zero in order to capture that the asset is completely full or empty, the proposal says.  

Alternative Proposals

Some stakeholders supported the proposal, including the California Public Utilities Commission’s Public Advocates Office, which described it as “a measured and sufficiently well-targeted approach to ensure that storage resources are not incentivized to deviate from day-ahead schedules to achieve excess BCR payments,” Dueñas Melendez’s presentation said.

Others, such as the California Energy Storage Alliance (CESA), suggested implementing an alternative solution in the interim that would address concerns related to strategic bidding. CESA proposed modifying the formula used to calculate BCR from real-time dispatch minus day-ahead schedule to day-ahead locational marginal price (LMP) minus real-time LMP. This calculation would eliminate the impact of a resource’s bid on BCR payments, according to CESA.  

“Stakeholders have argued for this solution for a couple of reasons: first, because it would eliminate the impact of that resource’s bid on BCR payments, so that way it’s no longer something that they can strategically use,” Dueñas Melendez said. He added that other stakeholders favored the solution because the software they use for automatic bidding uses -$150/MWh bids in the hours representing their day-ahead schedules to firm up those bids or schedules.  

While stakeholders supporting the proposal acknowledged the solution wouldn’t address the concern that storage assets are not exposed to real-time prices for deviating from day-ahead schedules, they argued it would allow for more time to develop a more “holistic” solution.  

Dueñas Melendez highlighted other potential drawbacks of the proposal, including that it would not eliminate buy- and sell-back BCR and that it would pay BCR to resources that are not available in real time. The ISO also questioned how the proposal would be implemented for storage assets in the Western Energy Imbalance Market (WEIM) outside CAISO’s footprint, considering that there is no day-ahead LMP for WEIM storage resources.  

CAISO further questioned CESA’s proposal, stating that the modified calculation could lead to revenue credit in intervals where the resource wasn’t dispatched due to a high offer, as well as unwarranted BCR when the day-ahead LMP is greater than the real-time LMP.  

Don Tretheway, director of markets and regulatory policy at GDS Associates and representing CESA, responded: “The intent of what CESA put out there was really to address instances where there was inflated BCR, so putting out an example that says the CESA proposal results in higher BCR payments … we would never have put that out as an approach, and we did recognize that there would be the need for some additional logic.” 

The intent of the approach, he said, was to show that not using real-time bid prices could help “unwind the inflated BCR payments,” giving the ISO more time to “come up with a holistic solution about what BCR should mean for storage” and what market design enhancements CAISO should pursue.  

CAISO’s Department of Market Monitoring disagreed with the suggestion to develop an interim solution, saying that addressing all issues in track 1 is a better approach than implementing an interim change and then tackling bidding incentive issues — which DMM believes to be the core issue — in a later process.  

The revised straw proposal is now scheduled for release Sept. 3, with the final proposal expected Sept. 30, a month later than the initial timeline. The joint ISO Board of Governors and Western Energy Markets Governing Body will vote on the proposal Nov. 7 instead of Sept. 26. 

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SDT Recommendations Spark Debate at Standards Committee

Members of NERC’s Standards Committee again debated qualifications for standard drafting team participation at their monthly conference call Aug. 21, with the discussion extending the meeting more than a half-hour over its planned end time.

The committee was considering two proposals submitted by NERC staff to approve members of new standard drafting teams (SDT), along with a proposal to add supplemental members to an already existing team. The new teams were for Project 2024-01 (Rules of Procedure definitions alignment — generator owner and generator operator) and Project 2024-03 (Revisions to EOP-012-2), while the existing team to be augmented was for Project 2022-02 (Uniform modeling framework for inverter-based resources).

Project 2022-02 came first on the agenda. NERC Manager of Standards Development Jamie Calderon explained that NERC recently assigned the project a new standard authorization request (SAR) in response to FERC Order 901, which requires the ERO to submit standards concerning data sharing and model validation for inverter-based resources (IBRs) by November 2025. (See NERC Standards Committee Moves Forward on IBR Projects.)

Because of the scope of the new SAR, Calderon said, the existing SDT members wished to bring in new participants with “additional skill sets [such as] inclusion, performance data and other aspects of modeling.” Industry stakeholders nominated six new members, of which NERC staff recommended five for addition to the team.

The exclusion of the sixth member, who like other nominees was only identified by number during the meeting, sparked questions from Robert Blohm of Keen Resources. Reading off background information provided to committee members, Blohm noted that the candidate was not recommended because their organization “did not support the candidacy [because] it didn’t have the resources … to allocate his time.” Blohm asked if the nominee could still participate in the SDT “if he’s willing to volunteer his own time and put in the effort,” perhaps as an observer.

Committee Chair Todd Bennett, of Associated Electric Cooperative Inc., said that while “each committee member [could] decide on their own” whether they agreed with Blohm, he would look at the employer’s feedback as “a non-supportive recommendation” if he were not an officer and had the ability to vote. Steve Rueckert, director of standards at WECC, said he understood Blohm’s reasoning, but he expected that NERC would already have asked the candidate for their willingness to participate and factored that into their recommendation.

Following his feedback, Rueckert moved for the committee to accept the original slate of five suggested by NERC. The motion passed unanimously.

Next on the agenda was Project 2024-01, which is intended to “address the definitions for generator owners and generator operators within the NERC Glossary of Terms to ensure the inclusion of [IBRs]” that meet recently approved registration criteria. (See FERC Accepts NERC ROP Changes, Drops Assessment Proposal.) Members were asked to approve a chair, vice chair and eight additional members to the SDT for the project.

Rueckert noted that NERC had received 11 nominees for the team and asked why only 10 were recommended. Calderon replied that two of the nominees were members of the same “representative body” and NERC felt that if both were included, it would reduce the diversity of the team.

Blohm argued for including the 11th candidate, observing that “only two candidates among the 10 recommended … have drafting team experience.” He suggested that the candidate, who has previously served as an SDT chair, would add valuable perspective to the team. He moved to amend the proposal to allow all the nominees to serve.

Members largely supported Blohm’s motion, which passed with no objections. Maggy Powell of Amazon Web Services was the sole abstention, saying she was “not particularly comfortable” with the idea of adding people to the team that were not recommended because it “discounts … the work that NERC has done to … vet these participants and [their] qualifications.”

The final project voted on at the meeting was Project 2024-03, which is working on the most recent changes ordered by FERC to NERC’s cold weather standards. NERC recommended a chair, vice chair and 11 members from the 18 candidates nominated by industry stakeholders.

Blohm again warned that the nominees seemed to lack experience serving on SDTs. He observed that of two candidates from the same company, NERC staff had recommended one with no drafting team experience over another who had previously served on SDTs. He suggested switching the two candidates and also adding another two industry nominees, which he said would “make a team of 14, eight members of which — in other words, a majority … would have drafting team experience.”

Members were receptive to Blohm’s suggestion, though there was considerable disagreement about the best parliamentary approach to handling the amendments. Rueckert reiterated Powell’s objection to “discounting NERC’s work based on a short [biography] that we’re seeing presented to us.” He also reminded members that inexperienced candidates could only gain experience by serving on SDTs.

The committee eventually compromised on switching out the two candidates from the same organization, while adding just one of the non-recommended nominees, resulting in a team of 13 total.