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November 16, 2024

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ERCOT Evaluating RMR, MRA Options for CPS Plant

ERCOT has issued a request for proposal seeking alternatives to a reliability-must-run contract with CPS Energy, compensating for the utility’s planned retirement of a power plant. 

The ISO said in a July 25 market notice that CPS Energy’s decision to retire three aging coal-fired units, with a combined summer seasonal net maximum sustainable rating of 859 MW, would have a “material impact on identified ERCOT system performance deficiencies.” The grid operator’s staff has said the units’ retirement would load existing transmission facilities above their normal ratings under pre-contingency conditions.  

ERCOT’s determination triggered the grid operator’s obligation to issue an RFP for must-run alternatives (MRAs) and begin RMR negotiations with CPS Energy. The San Antonio utility has proposed suspending the three V.H. Braunig units after March 2025. (See CPS Energy Plans to Retire 859 MW of Gas Resources.) 

Qualified scheduling entities (QSEs) can submit proposals for one or more MRA resources to address system performance deficiencies more cost effectively than by committing one or more Braunig units through a more expensive RMR contract. QSEs can offer the resources for one or more seasons during April 1, 2025, through March 31, 2027. Eligible resources include types of generation, storage and demand response. 

RFP offers are due Sept. 9. ERCOT will host a workshop Aug. 15 to discuss the RFP and answer questions. After reviewing all proposals, staff will make a recommendation to the ISO’s board during its October meeting. 

An RMR contract would be ERCOT’s first since 2016. The grid operator entered into an agreement with NRG Texas Power over a previously mothballed gas unit near Houston. The RMR contract ended in 2017, thanks partly to transmission facilities that increased imports into the region. (See ERCOT Works to Address Loss of San Antonio Units.) 

$24.4B in Energy Fund Requests

The Public Utility Commission said July 29 it has received 72 applications for loans through the Texas Energy Fund’s in-ERCOT Generation Loan Program. The applications request $24.41 billion to finance 38.37 GW of proposed dispatchable, or thermal, power generation. 

Lawmakers have set aside $5 billion for this TEF program, one of four. 

“Texans have made it clear that they expect reliable electricity today and well into the future, and I am pleased to see industry leaders responding to that call and planning for major investments in dispatchable power for the state,” PUC Chair Thomas Gleeson said in a news release. 

Commission staff will evaluate the applications before the commission determines which projects will proceed to due diligence during the PUC’s Aug. 29 open meeting. The in-ERCOT program will provide low-interest loans to finance up to 60% of new construction or upgrades to existing dispatchable facilities. A proposed project must add at least 100 MW of new generation to the ERCOT grid to be eligible. Approved loans’ initial disbursements will be issued by Dec. 31, 2025.  

The in-ERCOT program and three other TEF programs were established in March because of state legislation passed last year. The PUC says the program can support up to 10 GW of new or upgraded generation capacity in ERCOT. (See Texas PUC Establishes $5B Energy Fund.) 

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Electric Sector Added just 55 Miles of New Transmission in 2023

The U.S. electricity industry added just 55 miles of new high-voltage transmission to the grid last year, despite estimates the system will need to expand rapidly in the near future, Americans for a Clean Energy Grid said in a report released July 30. 

“Fewer New Miles: The US Transmission Grid in the 2020s” was prepared by Grid Strategies with support from ACEG. 

“The findings of this report are a wakeup call. With only 55 new miles of transmission built in 2023, we are not keeping pace with the growing demand for power,” ACEG Executive Director Christina Hayes said in a statement. “The slowdown in new construction not only impacts our ability to meet future energy needs, but also risks increasing costs for consumers and reducing grid resilience. It is essential that we address these challenges to ensure a secure, reliable and affordable energy future for all Americans.” 

The U.S. Department of Energy’s Transmission Needs Study found the grid should expand by 57% by 2035, while Princeton University’s “Net-Zero America Study” found it would need to double or 80% of the potential greenhouse gas cuts from the Inflation Reduction Act would not be met, said the ACEG report. (See Will DOE’s Transmission Needs Study Spur New Regional, Interregional Lines?) 

While 2023 saw few miles of new lines built, the industry spent $25 billion on the grid (a record high), with 90% driven by reliability upgrades and the replacement of aging equipment. The decline has been felt for years, with the country building only 20% as much transmission so far this decade as it did in the early 2010s. 

“This trend began over a decade ago, when the average of 1,700 miles of new high-voltage transmission built per year from 2010 to 2014 dropped to only 925 miles from 2015 to 2019, and has fallen further to an average of 350 miles per year from 2020 to 2023,” the report said. 

So far this year up to May, the industry has completed one major transmission line, adding 125 new miles from completion of the 500-kV Delaney-Colorado Transmission Project that links Arizona and California. 

About 50% of recent spending is based on local planning criteria, which is usually below 345 kV and does not go through regional planning processes. Such lines focus only on reliability, ignoring maximized ratepayer benefits from multivalue projects, the report said. 

The 2010s saw massive greenfield projects, especially in Texas and the Midwest. Texas’ Competitive Renewable Energy Zone program saw $7.5 billion invested in ERCOT lines to bring wind power to population centers, cutting wind curtailment from 17 to 0.5% and leading to unexpected benefits like solar development in West Texas and electrification of oil and gas drilling in the regions. 

MISO’s Long Range Transmission Planning (LRTP) Tranche 1 Portfolio is another example, investing $10.3 billion to build out 2,000 miles of lines that offer at least 2.6:1 benefits to load. 

Recent federal action like FERC Order 1920 and DOE’s Transmission Facilitation Program to help finance new transmission lines should help, but the report said private capital needs to be invested to expand the grid. 

“Utilities are still currently incentivized to prioritize low- voltage upgrades focused on reliability and asset replacement,” the report said. “Both policymakers and regulators must capitalize on FERC’s issuance of Order No. 1920 to ensure the momentum brought about by federal action truly changes the incentives for transmission investment and helps spur a massive investment in the construction of new high-voltage transmission lines to ensure a reliable and affordable transition to a cleaner grid.” 

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PJM MRC Briefs: July 24, 2024

Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility

VALLEY FORGE, Pa. — PJM’s Markets and Reliability Committee endorsed one of two proposals to revise how PJM uses reserve resources, approving a deployment scheme where instructions are sent by basepoints, while rejecting a parallel proposal to grant operators the ability to dynamically increase market procurements. (See “First Read on 2 PJM Proposals to Revise Reserve Markets,” PJM MRC/MC Briefs: June 27, 2024.)  

PJM’s Emily Barrett said updating basepoints with reserve instructions provides more clarity around how resources are expected to respond and allows for units to be dispatched for less than their full reserve assignment. Resources being asked to respond at less than their assignment will be committed at the greater of their economic minimum parameter or the pro rata instruction. 

Stakeholders rejected a second proposal to determine the amount of 30-minute reserves PJM commits using a formula rather than the static 3,000-MW figure. The equation would select the greater of the load forecast error and forced outage rate together multiplied by the forecast peak load, the primary reserve requirement or the largest active gas contingency. 

The package also would have allowed operators to increase one of the three reserve categories without having to increase all three. Under the status quo language, any out-of-market increase in the 30-minute, primary or synchronized reserve requirement must be mirrored across all three. Barrett said the language tying the three reserve products together is viewed by staff as an oversight. 

Prior to the vote, PJM’s Executive Director of System Operations Dave Souder said the static reserve threshold is not sufficient and does not account for risks identified by dispatchers. The proposal would revert to the reserve procurement formula in place before the reserve price formation redesign. 

Paul Sotkiewicz, president of E-cubed Policy Associates, said outages experienced in Alberta, Canada, in April demonstrated the importance of having dispatchers able to match reserves with expected risk. 

“The Alberta outage a few months ago shows why this is needed. The renewable forecast was inaccurate, energy commitments were too low and firm load had to be shed. That provides a cautionary tale that lends support for the ability to commit more reserves available,” Sotkiewicz said. 

According to the PJM summarized voting report, the reserve procurement package had little support among electric distribution companies, which were 93.1% opposed, and end-use consumers, who voted 82.4% against. The Other Suppliers sector was split at 57.1% support, while generation and transmission owners were united in support. 

Responding to a stakeholder question about whether PJM would consider moving forward with the proposed tariff changes without stakeholder endorsement, PJM Vice President of Market Design and Economics Adam Keech said staff had not envisioned the vote failing and will have to consider next steps. 

Schedule Selection Formula Endorsed

Stakeholders endorsed a proposal to use a formula to sift through market sellers’ energy offers into the real-time market and select one schedule for each resource to be modeled in the market clearing engine (MCE). (See “Stakeholders Discuss Path Forward on Multi-Schedule Modeling,” PJM MIC Briefs: June 5, 2024.) 

PJM brought the issue before stakeholders as part of its effort to implement multi-schedule modeling in the real-time market, which staff have said would result in a significant increase in computation times, in part due to the number of configurations combined cycle units can operate under. The introduction of multi-schedule modeling is one part of a larger overhaul of the engine under PJM’s Next Generation Markets (nGEM) initiative. 

An earlier schedule selection proposal was endorsed by stakeholders but rejected by FERC in March. The commission cited a “crossing-offer-curves” scenario the Independent Market Monitor raised, under which PJM’s proposed formula would select market-based offers based on its dispatch cost at EcoMin even if it would be notably more expensive than a cost-based offer at higher outputs.  

The proposal endorsed July 24 is built around the same formula but aims to address the crossing curves issue by selecting price-based offers only when a resource passes the three pivotal suppliers (TPS) test and mitigating resources to their cost-based offers should they fail the TPS test. The tariff and operating agreement (OA) revisions are set to go before the Members Committee on Aug. 21 for an endorsement vote. 

The proposal was sponsored by PJM and the GT Power Group at the Market Implementation Committee and received the second-highest amount of support at the MRC in December. (See “Stakeholders Endorse Multi-schedule Modeling Solution,” PJM MRC/MC Briefs: Dec. 20, 2023.) 

Monitor Joe Bowring said the joint proposal would not resolve an issue with how dual-fuel units are committed. Since only one schedule is considered, the Monitor has argued that dual fuel units may be selected to run on a schedule using a fuel that is not economical for a portion of the day. 

Stakeholders had discussed waiving truncated voting rules and widening the vote to include a joint proposal from the Monitor and GT Power, which would allow generators to determine which of their offers would result in the lowest production cost and should be modeled in the MCE. 

Vote on Enhanced Know Your Customer Deferred

The committee delayed voting on a proposal to tighten PJM’s “know your customer” (KYC) requirements to require more due diligence checks on principals and key decision makers among member entities. (See “First Read on Expanded ‘Know Your Customer’ Rules,” PJM MRC/MC Briefs: June 27, 2024.)  

The proposal would require PJM background checks on beneficial owners, board of director members and principals of non-publicly traded members. Those entities would be responsible for providing a list of names for each of those categories and government-issued identifications, though the latter does not apply to boards unless requested by PJM. The proposal is aimed specifically at collecting more information on non-public members not required to report ownership information to the Securities and Exchange Commission. 

The beneficial owner definition is applicable to those who own, control or hold 10% or more voting power of an entity, either directly or with family. Since the June 27 first read, Assistant General Counsel Eric Scherling said the definition of family members was clarified to state that ownership split across spouses, domestic partners, parents, children or siblings counts toward triggering the requirement. 

The proposed definition of “principals” also was revised to add the phrase “corporate-level strategy” regarding the control individuals have over the member entity’s operations. Scherling said the change is meant to address feedback that the definition could be too broad and capture staff with day-to-day operational control over assets. 

Several stakeholders said they would need more time to review the changes and expressed continued concerns about the scope of the requested information. 

Sotkiewicz said the principal definition remains nebulous when considering parent corporations and subsidiaries with split ownership. He motioned to defer voting until the Aug. 21 MRC meeting to provide more time to review the revised language.

“This is an arduous process for people [who] happen to be partners but don’t necessarily have full decision-making authority. … This could turn into a paperwork nightmare and for what reason we’re not entirely sure” when the parent company is publicly traded and the ownership is clear, he said. 

John Horstmann, senior director of RTO affairs for Dayton Light and Power, said some members have widespread operations that go far beyond PJM markets and that principals managing activities unrelated to PJM could be captured in the KYC requirements. He gave the example of an international corporation that does business in the U.S. and overseas, questioning whether information about corporate staff overseeing activities in Bulgaria or Vietnam would be requested by PJM. 

Scherling said PJM’s focus is on its markets and intends to take a closer look at individuals who are high enough in the corporate structure they would have a hand in all operations, including PJM. 

PJM Chief Risk Officer Carl Coscia said the KYC structure is about following where PJM revenues are going, what they’re being used for and where investments are coming from, so it does need to go to the highest corporate-level strategy. 

“We want to make sure these markets are being used for good. That’s the good we’re talking about, not having money that shouldn’t be here,” he said. 

Scope for Deactivation Task Force Widened

Stakeholders endorsed a wider scope for the Deactivation Enhancement Senior Task Force (DESTF) to include proposals to establish cost-effective alternatives to reliability-must-run (RMR) agreements and technologies that could expedite resolution of transmission violations prompted by resource deactivations. The proposal passed with 89% support. (See “Consumer Advocates Seek Wider Scope for Deactivation Task Force,” PJM MRC/MC Briefs: June 27, 2024.)  

The revisions to the issue charge also include education on the alternatives to RMR contacts that other RTOs have developed to keep generators operating past their desired deactivation date and a follow-up to ongoing discussion on proposals to allow capacity interconnection rights (CIRs) to be transferred from deactivating generators to planned resources. The proposal is sponsored jointly by the Illinois Citizens Utility Board (CUB) and Maryland Office of People’s Counsel (OPC). 

The issue charge language includes education around using grid-enhancing technologies (GETs) and storage as a transmission asset (SATA) to expedite transmission upgrades necessary to allow a generator to retire. 

Souder said PJM is neutral toward the technology that resolves an identified violation and it’s up to project proposers to submit solutions, including GETs. 

Clara Summers, of CUB, said the proposed language was revised from the draft presented at the June 27 first read to allow partial solutions, with the goal of avoiding any interruption to the existing discussions on compensation and deactivation notification timelines. 

Vistra’s Erik Heinle said he is concerned about having too wide of a scope for the task force, stating that the wide-ranging issue charge governing the Resource Adequacy Senior Task Force (RASTF) caused the group to die under its own weight while the Reserve Certainty Senior Task Force (RCSTF) has benefited from a narrower scope. 

“I want to make sure these important issues get the consideration they deserve but don’t slow down the ongoing work,” he said. 

Bowring questioned whether the advocates believe the issue charge should be phased to focus on deactivation notification requirements and compensation first before initiating work on the newly added items. 

Phil Sussler, of the Maryland OPC, responded that stakeholders may be too optimistic that the deactivation notification changes will be approved in August and said the overall work areas of the DESTF may take longer than expected to complete. 

Reserve Requirement Study Updated with ELCC Accreditation Values

The committee voted by acclamation to endorse revised installed reserve margin (IRM) and forecast pool requirement (FPR) values for the 2023 Reserve Requirement Study (RRS) to reflect the implementation of PJM’s marginal effective load carrying capability (ELCC) approach to accrediting resources. The proposal also was endorsed by the Members Committee on July 24.  

The reanalysis recommended increasing the installed reserve margin (IRM), which sets the targeted capacity level above expected loads, to 18.6%, up from the 17.6% stakeholders endorsed last year for the 2023 RRS. The forecast pool requirement (FPR), which accounts for generator accreditation, would decrease from 11.65% to 9.37.  

The shift to marginal ELCC accreditation was part of a package of capacity market redesigns approved by FERC in January (ER24-99). The RRS figures are used to set the supply curve for the 2026/27 delivery year. (See PJM Presents Revised Reserve Requirement Study Values.) 

In addition to the ELCC accreditation values, the reanalysis updated the expected resource mix to include planned resources that submitted a notice of intent to offer into the 2026/27 Base Residual Auction. Gas generators that submitted dual fuel attestations were sorted into the corresponding ELCC classes, and resources that are scheduled to deactivate prior to the start of the delivery year were removed from the analysis. Generators expected to operate on reliability-must-run (RMR) contracts through the delivery year were included in the resource mix. 

Greg Carmean, executive director of the Organization of PJM States Inc. (OPSI), questioned how PJM would incorporate nuclear capacity being removed from the market to serve data center load, referring to a FERC filing from Talen Energy to reduce the amount of energy the Susquehanna nuclear plant sells into PJM. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.) 

PJM’s Andrew Gledhill said the megawatt value of that unit would be effectively derated to the new CIR amount. 

Bowring asked how PJM considers the reliability impact of amending interconnection service agreements (ISAs) with generators to reduce their maximum output and whether it considers not approving revisions if there are reliability impacts identified.  

PJM’s Pat Bruno said reliability analysis is conducted like generation deactivation studies. 

PJM Proposes Increased CONE Parameters

PJM’s Skyler Marzewski presented a first read on a proposal to revise two financial parameters used to calculate the cost of new entry (CONE) input to the 2027/28 Base Residual Auction (BRA). (See PJM MIC Briefs: July 10, 2024.) 

After consulting with The Brattle Group, PJM recommended increasing the after-tax weighted average cost of capital (ATWACC) from 8.85 to 10% and using a 0% bonus depreciation rate for the 2027/28 delivery year and beyond. The original quadrennial review included a 20% bonus depreciation value for the 2026/27 year. The proposed changes to the quadrennial review also would update the Bureau of Labor and Statistics (BLS) indices used in capital cost escalation rates. 

The changes increase values for all five CONE areas by an average of $79/MW-day, with CONE Area 5 seeing the largest increase at $90/MW-day and Area 4 increasing by $65/MW-day. 

The review was triggered by market participants reaching out to PJM regarding the impact of high interest rates since the quadrennial review was approved last year. (See FERC Approves PJM Quadrennial Review.) 

Greg Poulos, executive director of the Consumer Advocates of PJM States (CAPS), said some advocates are frustrated that components of the review are being cherry-picked in a manner that increases consumer costs, both in terms of the financial parameters and the creation of an additional CONE area for Illinois. (See PJM Stakeholders Approve New CONE Area for ComEd over Consumer Opposition.) 

Summers questioned how PJM determines when it is appropriate to make changes to CONE outside of the quadrennial review. 

Marzewski said PJM and Brattle opted to not include automatic adjustments to the quadrennial review financial parameters to account for changing market conditions, instead leaving that discussion for the next quadrennial review. 

Sotkiewicz said the adjusted figures would be a short-term fix, but major issues remain with the CONE inputs, namely the use of a combined cycle generator as the reference resource at a time when few such units are under construction within PJM and none have been financed in recent years. 

New Economic DR Parameters Discussed

PJM presented a proposal to add two new parameters for demand response resources offering into the energy market, allowing providers to set a maximum dispatch period and a minimum interval before they can be committed again after being released from a previous dispatch. The Market Implementation Committee endorsed the proposal last month. (See “Additional Parameters for Demand Response Endorsed,” PJM MIC Briefs: June 5, 2024.) 

PJM’s Pete Langbein said the proposal would allow DR providers to enroll consumers that are only economic for set periods of time and need a recharge before being committed again. While some of that capability exists under the existing market structure using hourly updates, it is administratively difficult. 

Bowring questioned whether a DR resource could submit an offer into the capacity market even if it can operate only according to the proposed parameters. Langbein said such a resource would be subject to capacity performance (CP) penalties if it did not deliver during a performance assessment interval (PAI). 

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Maryland PSC Opens Debate on Future of Gas

Maryland wants to cut its greenhouse gas emissions by 60% by 2031 and have a carbon-free electricity system by 2035, which means the use of natural gas, and the need for ongoing investments in pipelines and other gas infrastructure, also should wind down, according to a People’s Counsel petition to the Public Service Commission.

Filed in February 2023, the petition asked the PSC to open a docket on the future of gas in the state, and whether gas utilities should be allowed to continue such rate-based infrastructure investments. The commission has yet to act on the petition, but on July 25, it held a daylong public hearing on whether it should open such a docket. A second session is scheduled for July 31.

Electric heat pumps, more efficient than gas furnaces, already are eating into the gas utilities’ market, according to People’s Counsel David S. Lapp. Yet utility spending on replacing and updating existing infrastructure could total more than $700 million this year, which pencils out to close to $2 million in utility spending per day ― and rising gas utility bills.

“There’s a massive disconnect between the technology, climate policy and what’s actually going on with the state’s gas utilities,” Lapp said. Even so, investors are willing to provide capital for gas infrastructure because the commission continues to approve the utility investments and rate increases.

“We would argue that is a state subsidy to the gas utilities funded by utility customers who have no choice but to pay those rates or get off the gas system,” Lapp said. “So, in that sense, regulation is failing customers today.”

The OPC petition also raises the possibility of a gas utility “death spiral” as customers electrify their homes and drop off the system, leaving a diminishing base of customers, many of them low-income, to cover system costs through higher rates.

“As customers leave the system, rates will go up further, and then more customers will leave the system,” Lapp said. “So, this is not an economically sustainable path.”

However, Lapp stressed that the petition does not seek to shut down gas utilities; rather, it calls on the commission to open a proceeding that would consider a “wide spectrum” of pathways for these companies to plan for substantially downsized demand and capital spending.

Following Lapp’s presentation, a panel of gas company executives mostly stayed away from the topic of rate increases, arguing instead that maintaining and investing in their pipelines and other infrastructure could be critical for ensuring grid reliability even if natural gas demand does decrease.

Demand reduction “doesn’t necessarily mean there would be a proportionate reduction in gas infrastructure,” said Lauren Urbanek, senior manager of decarbonization strategy at Baltimore Gas and Electric. “That’s really dependent on the geographic nature of where customers may choose to electrify and whether they would choose to electrify completely or partially, potentially maintaining gas as a backup for some of the winter peaking days.”

Upgrading gas systems also can cut down on leaks, Urbanek said, noting that BGE has cut gas leaks on its system 25% since 2015. She also stressed BGE’s support for electrification, such as a planned study on “targeted electrification.”

“This is going to help us better assess what the potential is on the BGE system of geographically targeting heat pumps, network geothermal [or] other technologies in the BGE service territory,” Urbanek said. Potential savings “could either be used to support building electrification … or be returned to gas ratepayers as well.”

Ted Gallagher, general counsel for Columbia Gas of Maryland, similarly countered that his company has increased the number of customers it serves in Western Maryland — up 9.7% since 2005 — but has cut its emissions 5.7%.

He also urged the PSC to expand any potential docket to a more holistic examination of the future of energy in the state.

“The proper scope of [any] commission proceeding … should address Maryland’s whole energy future and not just focus on the future of natural gas,” Gallagher said. “The focus should not be based upon a foregone and unsupported conclusion that natural gas should be or will be phased out in order for Maryland to achieve its GHG emission-reduction goals.”

The STRIDE Act

The debate over gas utility spending in Maryland ― and the OPC’s petition ― trace their roots to a 2013 law called the Strategic Infrastructure Development and Enhancement (STRIDE) Act (S.B. 8/H.B. 89).

Passed in the wake of the deadly 2010 explosion of a Pacific Gas and Electric natural gas pipeline in San Bruno, Calif., the bill was intended to encourage Maryland utilities to upgrade and improve the safety of their pipelines by allowing them accelerated recovery of their infrastructure investments.

Specifically, customers have for the past 10 years paid an extra surcharge on their bills so gas utilities could start to recover their infrastructure investments while improvements and upgrades were being made. The law also requires the utilities to submit STRIDE plans to the PSC every five years, as well as yearly reports on current investments.

While the law does not set any safety standards or require long-term planning, its impact on rates has been dramatic, according to the OPC. BGE’s distribution fees for natural gas went from 26 cents/therm in 2010 to 85 cents in 2024, with another jump to 96 cents in 2026 already approved by the PSC.

Distribution fees at Columbia Gas jumped more than threefold, from 30 cents/therm in 2010 to $1 in 2024, or more than three times the rate of inflation, the OPC said.

The STRIDE program is set to continue through 2043, by which time total utility spending under the program could hit $9.5 billion, in addition to another $12 billion in system investments outside STRIDE, according to a 2023 OPC report.

A bill to require utilities to use modern leak detection technology and repair pipes before replacing them (S.B. 548/H.B. 731) was introduced in the General Assembly earlier this year but did not make it out of committee in either house.

Maryland’s ambitious climate goals could result in less demand for gas, yet gas utilities in the state continue to increase spending on pipelines and other infrastructure and raise their rates. | Maryland Office of People’s Counsel

In light of the bill’s failure, views differed on whether the legislature or the PSC has the authority to make any changes to the program. Urbanek said BGE would be “supportive of some kind of working group or other forward-looking proceeding that really does relate to the future of gas. … But really, the decision is still to be made by the General Assembly about the exact pathway to follow.”

Lapp argued that the PSC has the authority, as regulators, to require the gas utilities to provide the commission with long-term plans on their infrastructure investments based on the expected decline in gas demand, and that the need to act is urgent.

“The idea that the commission has to wait for somebody else to set the policy, for the General Assembly to set the policy, ignores the critical point that right now there is a policy, and that policy is one of accelerated spending,” he said. “It is leading to massive rate increases; it is leading to investments that are highly likely to be stranded and to result in a lot of litigation going forward. That is the policy, and waiting means the inertia will just keep that going.”

‘Stop Digging’

The PSC also heard a wide range of views from environmental advocates, union representatives, county officials and Maryland residents and utility customers.

Emily Scarr, director of the consumer advocacy nonprofit Maryland PIRG Foundation, supported the OPC’s call for a docket on the future of gas, pointing to the increases in BGE and Columbia Gas distribution fees.

“When you find yourself in a hole, stop digging,” Scarr said. “We’re asking you to put the shovel down and exercise your authority to require utilities to serve the public interest by providing safe, reliable and affordable energy. We can only achieve that goal with proper planning and data-driven decisions. The cost of inaction is clear. … You can direct investments wisely in the projects that will lower energy bills.”

Clara Vondrich, senior policy counsel at Public Citizen, said Maryland’s “energy policy as manifested through the proceedings and decisions of this honorable commission, as well as through legislation like the STRIDE Act, are incompatible with the state’s climate goals and in fact may make them impossible to meet.”

Vondrich told the commission she lives with her 85-year-old mother, who has become a little forgetful and has lost her sense of smell. Recently, Vondrich woke up to find her mother had left the gas on overnight and had not smelled the methane.

“We’re no longer in an era where we need to take those kinds of risks,” she said.

Brian Terwilliger, a business manager for the International Brotherhood of Electrical Workers Local 410, raised the concerns of the BGE workers his union represents. BGE’s gas system is one of the oldest in the country, which makes STRIDE upgrades essential, he said.

“Just a few months ago, we dug up a wooden main just down the road here, about 20 feet of it,” he said. “Our infrastructure has generational gaps; so, we have from wood to the most up-to-date stuff for our pipes.”

But Terwilliger warned that downsizing the gas system could trigger a mass exodus of skilled workers.

“They’re thinking about where they’re going to go, how this transition is going to work, and it’s going to be extremely difficult for Baltimore Gas and Electric to retain employees,” he said. “Our ask today … is really to look at the workers at the companies and think about how we’re going to continue to keep those employees employed.”

A transition period “needs to be at the forefront of this conversation,” he said.

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NYISO Stakeholders Continue Debate over Battery as Proxy Unit

NYISO analysts continue to recommend a two-hour battery electric storage system (BESS) resource as the proxy unit for the ISO’s capacity market demand curve.

“Based upon our review of the comments and the results developed to date, we continue to recommend the two-hour battery storage system as the peaking plant technology,” Paul Hibbard, vice president of Analysis Group, told the Installed Capacity Working Group on July 23.

This was the second-to-last working group meeting focused on its quadrennial demand curve reset for 2025-2029, and the first since stakeholders submitted comments on the recommendation earlier this month. (See Stakeholders Battle over Battery as Proxy in NYISO Demand Curve Reset.)

“There are no established minimum thresholds regarding the quantity or duration of energy a peaking plant must be capable of producing during peak periods to be considered a viable technology option for the purposes of the demand curve reset,” said Hibbard, responding directly to comments in opposition to the recommendation.

When asked if Analysis Group had done any reliability analysis to determine whether a two-hour duration was sufficient for maintaining reliability, Hibbard said that his group did not do reliability modeling.

“We’re not trying to model a system that’s operating entirely on two-hour batteries; the two-hour batteries are the peaking technology for the purpose of setting the demand curve,” Hibbard said.

“Another risk of the two-hour BESS is that it is very heavily reliant on reserve revenues, and it’s a reserve provider for 95% of the intervals,” said Mark Younger, of Hudson Energy Economics. “Did you at all consider if there is a risk, say, if the reserve price dropped in half, or if the reserve price dropped by three-quarters?”

“We haven’t tried to forecast reserve prices,” answered Todd Schatzki, principal of Analysis Group. “Ultimately that gets reflected in the net EAS [energy and ancillary services offset] calculation over time.”

One stakeholder noted that commenters had expressed concern with a battery’s capacity accreditation factors (CAFS) diminishing very rapidly.

“We don’t really feel we have a sufficient quantitative basis to assume the CAFs will decline over time,” Schatzki said. “We recognize that a lot of commenters believe that is going to be the case.”

Schatzki said that there were a lot of uncertainties with respect to calculating future CAFs for any technology and that final financial parameters had not yet been set.

1898 and Co., a consulting and analysis firm brought in by Analysis Group, presented some modifications to their calculations for capital and equipment costs for two-hour batteries. Based on feedback from stakeholders, real estate and land-lease costs in New York City were adjusted upward.

Discussion of how 1898 had calculated the costs of battery construction dominated the second presentation.

“Essentially it’s the supply and demand of electric vehicles that drives what happens in the lithium carbonate market,” said Kieran McInerney, a consultant with 1898. “If you look at the numbers for stationary storage verses EV demand for the raw material, it’s like 95% to 5%.”

McInerney said that currently the lithium carbonate market is relatively stable and that the numbers had returned to pre-COVID pandemic prices.

“I do not intend to predict the future; anything could change at any time,” he said. “But we do think that the costs that we are going to include in the final report are indicative of where the market is right now. … There’s a decent amount of stability in the raw material price.”

There was some discussion of how to properly account for inflation, which one stakeholder said is “crushing everything.” McInerney said that he wanted the inflation indices to reliably track costs.

“We believe it’s settling. It’s been a crazy last nine months, [or] year, with the reductions,” he said. “There’s cost increases and reductions that are due to materials; there’s technology changing. I can’t sit here today and tell you anything. Four years ago, we all thought the price was going to be lower today.”

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Prelim NYISO Analysis: 1-GW Shortfall by 2034

New York will be short 1 GW of resources by 2034, driven by increased demand, large load growth and lack of natural gas, according to the preliminary results of NYISO’s biennial Reliability Needs Assessment.

“Preliminary results show criteria violations that will result in reliability needs,” Ross Altman, senior manager of reliability planning for NYISO, told the Electric System Planning Working Group and Transmission Planning Advisory Subcommittee on July 25. “However, we are not defining those needs today. These are still preliminary results.”

New York City will experience a security margin baseline deficiency beginning as early as 2031, driven by the retirement of the New York Power Authority’s small gas plants. Altman said this could be expected to grow to 275 MW by 2034 because of demand growth.

“This is driven both by New York City load growth and also the assumption of the retirement of several small gas plants that NYPA is required by law to retire or replace,” Altman said.

Altman said that the final results of the RNA, to be presented in August, would identify some needs but that there would be more detail in the solicitations for next year.

Assumptions

The preliminary RNA assumes that many large generation projects will be online and contributing to the grid, including both the Empire Wind 1 and Sunrise Wind 2 offshore wind projects.

“This is a fairly small list, but we are tracking a much wider pool of projects,” said Altman. “This is a fairly conservative assumption. These are only the projects that we have high confidence on because they’ve met their milestones.”

NYISO

Approximately 6,400 MW of generation fueled by non-firm gas was modeled as unavailable. Altman said this modeling change was consistent with recently adopted changes to New York State Reliability Council rules. Dual-fuel sources with non-firm gas were modeled running on their alternate fuels.

“We wanted to highlight dual-fuel units that have non-firm gas contracts; we do not assume those out,” said Altman. “We just model what their capability is when they’re operating on their alternate fuel source.”

Additionally, roughly 2,100 MW of additional large loads were added to the system. Electrical imports from Chateauguay, Quebec, were set to 0 MW during winter months.

“We are setting those imports to zero in winter peak months consistent with our coordination with Hydro-Quebec and what we’re seeing in operations,” said Altman.

Preliminary Results

Ten years from now, NYISO estimates a loss-of-load expectation as high as 0.283.

“We need resources at that point to bring the LOLE to 0.1,” said Laura Popa, a manager of resource planning for NYISO.

NYISO

Popa walked stakeholders through alternate 2034 scenarios in which additional risk factors and potential solutions were modeled, including the inclusion of 9,000 MW of offshore wind, construction delays on the Champlain Hudson Power Express transmission project and the removal of certain large loads. Delaying the CHPE project would significantly impact the LOLE, bumping it up to 0.327 by 2034. Adding extra wind power or removing 1,900 MW of large load would bring the state below the 0.1 LOLE threshold.

Most questions from stakeholders centered on the math and assumptions of the model. Some wondered whether gas was being appropriately modeled as unavailable. Altman pointed out that New England was particularly dependent on natural gas and that it would continue to be used for heat, even if new construction was electrified.

“I don’t think anyone should take these results as ‘the sky is falling,’” Altman said. NYISO would prefer market-based solutions to the problem and believes it could identify an appropriate solution if it went through a solicitation process, he said.

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Counterflow: Hydrogen Flub

Last November, I wrote about the insanity of green hydrogen electricity. And I’ll return to that below.

But I’d like to start with green hydrogen generally, focusing on the first of DOE’s funded “hydrogen hubs” located in — where else? California!

From the PR materials, we can piece together a somber tale. Let’s start.

When is a Hub not a Hub?

Steve Huntoon

The term “hub” is a misnomer. There will be 10 or more hydrogen production sites (at renewable energy facilities), with hydrogen transported to four ports, 60 truck/bus fueling stations, two power plants, etc. There does not appear to be a central location that would receive and store hydrogen for transshipment to end-use locations.

The funding statute, the Bipartisan Infrastructure Law, defines a hydrogen hub as a network of hydrogen producers and hydrogen consumers “located in close proximity.”  Instead, with this “hub,” hydrogen production sites span most of the state, and hydrogen consumers in San Diego and Lodi are 473 miles apart.

So much for Congress’ “close proximity” requirement.

Making Global Warming Worse

This hydrogen “hub” is going to make global warming worse. Here’s why.

This project is going to use electricity from 10 or more renewable production sites across California to make hydrogen, and then store and transport the hydrogen to, among other consumers, two or more power plants. In my prior column, I showed how the losses in converting renewable energy to hydrogen, storing and transporting the hydrogen, and then converting the stored medium back into electricity, would take 7 MWh of green electricity at the source to end up with 1 MWh of green electricity delivered to end-use consumers.

And that’s what will happen here. Every 7 MWh of renewable generation at production sites that otherwise would have been delivered directly to the grid, displacing natural gas generation, instead will be diverted to this hydrogen “hub,” ultimately becoming 1 MWh of renewable generation delivered to the grid. So, every metric ton of carbon emissions avoided at the point of consumption will result in 7 metric tons of incremental carbon emissions from non-displaced natural gas generation.

Does that make any sense to anybody?

Cost of Carbon Emission Reduction

This hydrogen “hub” is a $12.6 billion project. Let’s ballpark a 10% annual revenue requirement for return of (depreciation) and return on capital, so $1.26 billion annually. DOE says this hydrogen hub will reduce carbon emissions by “2 million metric tons per year.”

That can’t be so for the reason given in the prior section, but giving DOE the benefit of the doubt, if we do the math, that’s a cost of $630 per ton of carbon emission reduction.

That cost is a multiple of the per ton cost of dozens of other carbon mitigation options, including 10 in the energy sector alone, as this IPCC table (see page 1,254, Table 12.3, Energy Sector portion) shows. All listed options are $200/ton cost or less.

Detailed overview of global net GHG emissions reduction potentials (GtCO2-eq) in the various cost categories for the year 2030. | IPCC

Which begs the question, why spend many billions on a hydrogen “hub” that, even assuming DOE’s figures, still costs more than a multiple of myriad other carbon mitigation options?

Job Creation

DOE claims this hydrogen hub will create 90,000 permanent jobs. This appears to be typical sleight of hand that ignores the fact that what taxpayers must pay for this program will reduce their disposable income, thereby reducing their spending and thereby reducing the jobs their spending would otherwise support. And those would be jobs providing products and services that people actually choose to pay for, instead of jobs artificially created by government agencies using taxpayer money.

Let’s take an example: DOE says the hub will fund 5,000 hydrogen trucks and 1,000 hydrogen buses. But the truck drivers and bus drivers driving new hydrogen trucks and buses instead would have kept driving diesel/gas trucks and buses. No new jobs.

Water

Have I mentioned all the water that will be needed for the electrolysis to produce hydrogen (9 kg of ultrapure water for every 1 kg of hydrogen)? This in a state not known for having a lot of spare water. Just sayin’.

Backup for Well Water Pump

Speaking of water, DOE says it “will use hydrogen to provide backup power to community well water pumps to ensure clean drinking water during power outages.”

This use of taxpayer dollars is wrong for at least three reasons. First, the recipient, the Rincon Band of Luiseno Indians, is a small tribe (about 500 members) that owns Harrah’s Resort Southern California — an enormous hotel/casino/events center. This tribe does not need subsidies from the rest of us.

Second, the tribe’s water well pump already has backup generation in the form of a 130-kW diesel generator. DOE’s implication that the tribe would get backup generation it doesn’t already have is wrong.

Third, the tribe already is using taxpayer funds for a new solar/battery system. Is the plan to substitute some sort of hydrogen system for this solar/battery system? Or perhaps have three systems (in addition to the grid): the diesel generator, the solar/battery system and the hydrogen system? Yikes.

OK I’ll stop the hydrogen rant here.

P.S. Re. last column’s P.P.S. about “(What’s So Funny ‘Bout) Peace, Love, and Understanding,” I came across this live Elvis Costello cover where the Bangles show up. It seems like it’s over at four minutes but somehow rocks on. And oh yeah, the Boss with Bon Jovi. And Sheryl Crow covers it not too shabby. And Bob Geldof — thank you for Live Aid! — gives a reading that explains it before killing it. Thank you again Bob Geldof!

Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.

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Environmental Review of Maryland OSW Plan Completed

Federal regulators have completed their environmental review of a wind energy proposal off the Maryland coast, putting the US Wind project in line to be the 10th approved in U.S. waters. 

The U.S. Bureau of Ocean Energy Management said July 29 that the plan could yield up to 2.2 GW of emissions-free electricity if built as proposed. 

BOEM said it will post a notice of availability of the final Environmental Impact Statement on Aug. 2, triggering a waiting period of at least 30 days before it can issue a Record of Decision on the construction and operations plan submitted by US Wind. 

All nine of the records of decision issued so far have been approvals. 

US Wind is proposing a wind energy facility of up to 114 wind turbine generators rated at 14 MW to 18 MW each, up to four offshore substations and a meteorological tower on OCS-A 0490, an 80,000-acre lease area 10.1 miles off the northern Maryland coast. Seven of the original 121 turbine positions were deleted to create greater separation from Delaware Bay marine traffic. 

The nameplate capacity would be as much as 2.2 GW, and that electricity would be exported to three substations to be built in Delaware. 

The project includes MarWin, a 300-MW wind farm, and Momentum Wind, rated at 808 MW. Both hold offshore renewable energy credit (OREC) agreements with the state of Maryland. The remainder of the lease area would be built out in a third phase as additional demand arose. 

BOEM made the environmental impact statement (EIS) public in draft form in October 2023 and received 1,833 comments in response. 

The Maryland offshore wind final EIS follows a format similar to those issued for other projects, presenting a range of possible effects that construction and operation of the wind farms would have in a series of categories — sometimes positive, sometimes negative, sometimes both or neither. 

For example, birds could have increased foraging opportunities once wind turbines were installed and they could be killed by spinning blades. Jobs might be lost in the recreation and tourism sectors and jobs would be created in the wind sector. Environmental justice populations would suffer some disruption and could benefit from new employment and economic activity. 

The cumulative environmental impact with ongoing and future activities (including other offshore wind activities) also is predicted, and in some cases is more beneficial or more detrimental than the individual impact of one project. 

The EIS also looks at the future result of the status quo — of not building wind farms in OCS-A 490 — and finds that in some categories, continuation of present environmental trends might be as detrimental in their own way as would be building wind farms intended to counter those trends by reducing greenhouse gas emissions. 

The critically endangered North Atlantic right whale — poster cetacean for offshore wind opponents — is one such example.

The EIS estimates the project by itself would have minor negative impact on the whale but a major impact if considered in combination with existing baseline factors and environmental trends that would continue without construction of the facility. 

As with the reports prepared for other projects, the Maryland offshore wind EIS foresees potential major impacts for commercial fisheries; scientific research and surveys; and visual resources. 

MarWin and Momentum Wind are important pieces of Maryland’s strategy to reach its target of 8.5 GW offshore wind by 2031. Right now, they are the only pieces — Ørsted canceled the Maryland OREC contract for its two-phase 966-MW Skipjack project amid industrywide financial struggles. (See Ørsted Cancels Skipjack Wind Agreement with Maryland.) 

In May, the state allowed US Wind to request contract revisions and higher compensation in an attempt to keep those two projects in the portfolio. (See Maryland Offers OSW Developer More Lucrative Terms.) 

The Biden administration’s push for offshore wind development continues. BOEM has scheduled an auction Aug. 14 for wind lease areas off the Delaware, Maryland and Virginia coastline estimated to hold the potential for up to 6.3 GW of electric generation. 

US Wind said July 29 that the EIS is a major milestone for its three-phase project, and said it expects BOEM to issue the record of decision in September. 

CEO Jeff Grybowski said in a news release: “We are well on our way to putting Maryland’s offshore wind goals that much closer to reality. We applaud BOEM for the comprehensive and thorough review of our federal permit application. We are now one step closer to securing all of our federal permits by the end of this year, and look forward to the day we can get steel in the water.” 

Italy’s Renexia SpA, a subsidiary of Toto Holding SpA, is majority owner of US Wind. 

Trade association Oceantic Network said the pipeline of approved U.S. offshore wind proposals will exceed 15 GW once US Wind gets its record of decision, and it noted that more than 5 GW already is under construction. 

CEO Liz Burdock highlighted the local and national relevance of US Wind in a news release: 

“Maryland has long seen offshore wind power as a key part of its energy and economic future, investing in a local offshore wind supply chain and the development of robust clean energy targets that have been driving the industry forward since its early stages. Today, the state has a commercial scale project nearing full construction approval and is poised to become a regional hub for offshore wind manufacturing and steel fabrication. Along with US Wind’s direct investment in Sparrows Point Steel, this offshore wind project will contribute to new, well-paying jobs across Maryland and throughout the supply chain.” 

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FERC Grants PG&E Incentives for 4 Transmission Projects

FERC on July 25 approved two incentives Pacific Gas and Electric requested to support work it will undertake with LS Power Grid California for four transmission projects included in CAISO’s 2021/22 transmission plan (EL24-107). 

In an order issued at its monthly open meeting, the commission found the projects satisfy the Order 679 requirements for incentive rate treatment because they will improve reliability and reduce congestion. Commissioner Mark Christie dissented in the 2-1 vote.   

FERC approved use of the Construction Work in Progress (CWIP) and the abandoned plant incentives for PG&E’s supporting work to interconnect and integrate the Collinsville, Manning, Newark and Metcalf projects into CAISO’s grid, which will help offset associated costs and address long lead times.  

After becoming sponsor, LS Power also was awarded transmission rate incentives for the projects in March 2023.  

The Collinsville Project consists of a new 500/230-kV substation, two new 230-kV transmission lines to the Pittsburg substation, looping in the Vaca Dixon/Tesla 500-kV line into the Collinsville substation and adding a series capacitor to the Collinsville/Tesla line.  

The project, which is estimated to cost between $475 million and $675 million, will mitigate a constraint on the Cayetano-North Dublin 230-kV line, increasing reliability and facilitating renewable generation in the northern Bay Area, according to PG&E. It’s estimated to cost PG&E $197.9 million to complete several updates, including constructing several lattice structures, new bays and line swapping, decreasing existing series capacitor banks, adding a telecommunications path and adding breakers.  

The Manning project will consist of a new 500/230-kV substation and two new 230-kV transmission lines to the Tranquility substation, looping the PG&E Panoche-Tranquility transmission lines and the Los Banos-Midway and Los Banos-Gates 500-kV lines into the Manning substation. It’s estimated to cost $325 million to $485 million and will mitigate the constraint on the Borden-Storey 230-kV transmission line, allowing for the advancement of renewable generation in the Westlands or San Joaquin areas, the order says. PG&E’s work supporting the project will cost an estimated $423.9 million for looping lines into the new substation, building new transmission lines, installing relays and switches on the Los Banos-Midway line and more.

The Newark project includes a new 500-MW HVDC line between two new LS Power convertor station facilities at an estimated cost of $325 million to $510 million. According to PG&E, the Newark project addresses CAISO’s forecast of significant load increases in the Silicon Valley area that will result in overloads in the San Jose 115-kV system. PG&E’s work supporting the project will cost another estimated $16.3 million and include installing a new substation bay at Newark substation, upgrading the Newark station ground grid and grading, constructing a 230-kV line with new insulators and hardware and implementing new telecommunications equipment.  

Finally, the Metcalf project will consist of a new 500-MW HVDC line between the two new LS Power converting station facilities and is estimated to cost $525 million to $615 million. PG&E’s work supporting the project is significant, costing $266.6 million and including constructing a 500-kV line, installing a 115-kV underground cable and expanding a portion of the Metcalf substation.  

‘Check-the-box’

PG&E argued that the CWIP incentive will help support the significant cost of the projects, which are projected at $904.7 million between 2024 and 2028 — a “significant portion of PG&E’s planned $9.1 billion in overall transmission spending during that period,” the order reads.  

The incentive also would help address the long lead time between 2024 and 2027/28, which is the earliest the projects are expected to go into service.  

“PG&E contends that requiring investors to wait a minimum of four years before receiving a return on their investments would diminish the attractiveness of these investments relative to other PG&E investments that have shorter lead times. Further, PG&E argues that allowing CWIP recovery will lower financing costs, which will decrease the total revenues paid by consumers over the life of the projects,” the order reads.  

CWIP recovery also would reduce the “rate shock” that could occur if the cost of the projects were accounted for only in the 2028/29 rate case.

But in a protest submitted to FERC, the California Public Utilities Commission argued that the CWIP incentive is harmful to California ratepayers by requiring “premature and excessive rate recovery.” When projects have longer lead times and higher costs than when forecasted at the time the incentive was granted, the incentives cost consumers more and provide a one-sided benefit, the CPUC said.  

If FERC granted the incentives, it should put up “guard rails,” the CPUC argued, including capping CWIP eligibility at the cost of the project and rescinding CWIP recovery as soon as CAISO’s original in-service date passes.  

Maintaining course with past dissent, Commissioner Christie also argued PG&E should not be awarded the CWIP and Abandoned Plant incentives.  

“The CWIP and Abandoned Plant incentives are nothing more than a transfer of wealth from consumers to transmission developers and risk from developers to consumers,” Christie said in his dissent. “It is long past time for the commission to revisit its ‘check-the-box’ practice of granting transmission incentives, including as set forth in Order No. 679. The longer the commission does nothing to address these unfair transfers of wealth and risk, the more consumers are exploited.” 

But FERC sided with PG&E in granting both incentives for all four projects without ‘guard rails.’  

“We find that PG&E has demonstrated that each of the requested incentives, and the package as a whole, address its risks and challenges for the support work that it will undertake in conjunction with the projects,” the order said.

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Texas Commission Rejects ECRS Rule Change

Texas regulators have rejected an ERCOT protocol change that took months of sometimes-contentious negotiations before the grid operator’s staff and stakeholders could reach a compromise that earned board approval. 

In taking up the rule change (NPRR 1224) that modified the ISO’s new ERCOT contingency reserve service (ECRS) product, the Public Utility Commission removed a proposed $750/MWh pricing floor. It also asked ERCOT to separately implement the revision’s trigger mechanism for the service (54445). 

The commission sided with staff’s determination that the operating reserve demand curve (ORDC), which uses scarcity pricing to value operating reserves, should be relied upon to generate “economically appropriate market pricing.” Staff said the offer floor “inappropriately supplants the role of the ORDC in pricing scarcity risk” and said the demand curve should remain the vehicle to price ECRS capacity and deployment risk until real-time co-optimization can be deployed. 

The ISO plans to add co-optimization of energy and ancillary services in real time in 2026. 

ERCOT COO Woody Rickerson said NPRR 1224 was originally drafted without an offer floor. It was expected, he said, “but we wanted to get market participant feedback on what the offer floor would be … the NPRR was written so that that offer floor can be filled in after market participant input.” 

“I thought you all were completely agnostic to that, to be honest,” PUC Chair Thomas Gleeson said. “Is it still fair to say that the part of this revision that is most important to ERCOT is the trigger?” 

“Yes,” Rickerson responded. “ECRS is a high-need reliability tool.” 

The trigger mechanism takes effect when there is a 40-MW power balance violation for at least 10 minutes. 

The rule change was approved by ERCOT’s Board of Directors in June and included the offer floor and trigger mechanism for the ancillary service product. ECRS procures capacity resources that can be brought online within 10 minutes and sustained at a specified level for two consecutive hours. (See “Contentious NPRR Revising ECRS Passes over Monitor’s Objections,” ERCOT Board of Directors Briefs: June 17-18, 2024.) 

ERCOT’s Independent Market Monitor has opposed ECRS after it first was deployed in June 2023. It says the grid operator’s first new ancillary service in 20 years created artificial supply shortages that produced “massive” inefficient market costs totaling more than $12 billion in 2023. (See ERCOT Board of Directors Briefs: Dec. 19, 2023.) 

Potomac Economics’ David Patton, whose firm serves as ERCOT’s IMM, again pressed his case against the protocol change. He made his third business trip to Texas in eight months to argue against the NPRR. 

“The market performance that was impacted by the deployment of ECRS in 2023 was calamitous. I’ve never seen something as bad as what happened,” Patton told the PUC. “The priority has to be to fix ECRS, not just iterate and improve and make it a little bit better. We know how to fix this. What the NPRR would do is institutionalize a fairly large share of the dysfunction that we saw in 2023.” 

Patton told RTO Insider the PUC’s decision was a “partial victory.” 

“The trigger mechanism, while it may be used in the near term, can be changed and improved by ERCOT if I can convince them that it is having unintended consequences. If the protocol revision had passed, we would be stuck with it,” he said in an email. “Ultimately, that decision had huge cost implications over the next two years.” 

Attorney Katie Coleman, who represents the Texas Industrial Energy Consumers lobbying group, agreed with the commission’s decision to remove the offer floor and allow ERCOT to address the deployment trigger. She called for a $100 floor during the board’s discussion. 

Coleman also agreed with Gleeson’s complaint that ERCOT’s board process “did not work” for him. Gleeson said he and Commissioner Lori Cobos, who both sit on the grid operator’s board, did not comment during the directors’ consideration of NPRR 1224 because they did not have all the information they needed. 

“I would argue that some of the most pertinent information I heard came in post-board decision. … I need to have all the information that I can have at the board because I think it is important for me to be able to tell the board what I think so that if they pass something, they know perhaps it may get rejected at the PUC. For me, that does a disservice to the board process,” he said. 

“Unfortunately, there was urgency to move something through the stakeholder process to try to get it implemented this summer, and as a result, some of the issues and analyses were not fully fleshed out before the board,” Coleman told RTO Insider. “We agree with [Chair] Gleeson that improvements are needed to make sure the board has all the information needed to make the right decision.” 

SPS Capacity Needs Partly Approved

The commission partly granted Southwestern Public Service’s request for additional capacity to meet SPP’s planning reserve requirement (PRM), approving three solar farms but rejecting a battery storage facility (55255). 

An administrative law judge in May approved SPS’s application for three solar facilities at existing plant sites in Texas and New Mexico offering 418 MW of nameplate capacity. However, the ALJ rejected a request for a 36-MW battery facility in New Mexico, saying SPS has failed to prove the facility is an economical solution to its capacity needs because it would add only an incremental amount of capacity relative to its $66 million cost. 

Gleeson filed a memo agreeing with much of the ALJ’s decision. He found fault with the conclusions that SPS “adequately considered” alternatives to the solar facilities and that its request-for-proposals process was conducted reasonably. Gleeson recommended adding a cost cap to the solar facilities, currently projected at just over $700 million, and agreed with the ALJ’s recommendation for a third-party review if the construction costs are 10% greater than projections. 

The PUC chair wrote that SPS’s “questionable” resource planning decisions placed the commission in a “difficult position.” 

“I believe a cost cap may be appropriate in this case because of SPS’s failure to adequately consider alternatives, which led them to the selection of a capital-intensive, non-dispatchable resource to satisfy their capacity needs,” Gleeson said. 

SPS filed in July 2023 to increase its capacity needs following SPP’s three-point increase in the summer PRM to 15%. The utility said the additional capacity would be needed as early as 2024 due to the retirement of aging natural gas facilities, the expiration of power purchase agreements, and projected customer load growth. (See SPP Board, Regulators Side with Staff over Reserve Margin.) 

The commissioners agreed SPS should ensure customers receive 100% of the solar facilities’ production tax credits as they are earned. 

Staff Begins Beryl Investigation

PUC staff has filed a memo outlining a proposed scope and approach to the commission’s investigation of Houston utilities’ response to Hurricane Beryl (56822). 

Staff is planning to send requests for information to electric and water service providers in the Greater Houston area and to invite generation companies, retail electric providers and communications service providers to submit the effects to their services and their response to the May derecho event and Beryl.  

They also are analyzing utilities’ emergency operations plans, vegetation management plans, infrastructure and storm hardening plans, after-action reports, and customer complaints. Their investigation will include reviews of storm preparedness and response best practices from infrastructure experts.  

A draft report is scheduled to be presented to the commission for its consideration during the Nov. 21 open meeting. A final report will be delivered to Texas Gov. Greg Abbott (R) and the state Legislature by Dec. 1.