Page 1189 – RTO Insider

September 30, 2019October 21, 2025

Counterflow: New York’s Surreal New Deal

By Steve Huntoon

Heard much about New York’s Reforming the Energy Vision (REV) lately? No, I didn’t think so. Remember how REV was supposed to empower customers and reduce their costs with all kinds of innovations in the traditional utility model? It was the most hyped regulatory initiative since the California restructuring some 20 years ago.

But as I wrote back in 2016: “Acronyms and visions abound, but there is no clear roadmap or even a clear destination.”¹

How prophetic. Other than squandering customer dollars on a few uneconomic demonstration projects,² REV as a customer-empowerment revolution that reduces customer costs is dead. RIP REV.

REV Absorbed into NY’s Green New Deal

Instead, REV has essentially been absorbed into New York’s own Green New Deal. Its Green New Deal has nothing to do with customer empowerment, reducing customer costs or transforming the traditional utility model.

Instead of transforming the traditional utility model, that model will be the vehicle for imposing billions of dollars in costs on customers/taxpayers to pay for top-down, centrally planned projects.

NY’s Green New Deal is Surreal

Exhibit A is the planned enormous waste of customer/taxpayer dollars on offshore wind when the same subsidy dollars could procure many times that amount of onshore wind. I’ve written about that sad fact before.³

Exhibit B is the politically driven closure of the economic Indian Point nuclear plant and effective replacement of that emission-free generation with an equivalent amount of offshore wind (4,000 MW at about a 50% capacity factor) at a subsidy cost of about $830 million annually.⁴ In other words, replacing Indian Point with offshore wind will squander $830 million of New Yorkers’ money every year.

And when Indian Point is closed in 2020-21, with no telling when New York actually will have 4,000 MW of replacement offshore wind in service,⁵ we know that fossil generation will be replacing Indian Point generation, and New York’s carbon emissions will be going up, and even more so if New York succeeds in keeping new gas pipelines from supplanting coal generation. Don’t expect data and reporting on all this.

Exhibit C is the subsidizing of other nuclear plants in New York to stay open. Yes, it’s the theatre of the absurd when the economic nuclear plant is forced to close, with equivalent wind costing $830 million in subsidies and the allegedly uneconomic nuclear plants getting $500 million in subsidies to stay open.⁶ I think I know how Alice felt in Wonderland.

Exhibit D is the planned enormous waste of customer/taxpayer dollars on batteries. Yes, I’ve written about batteries several times.⁷

But, sorry, New York seems to have a particularly wasteful approach to subsidizing batteries: Simply subsidize batteries.

New York’s first battery project is the Key Capture Energy project, which New York claims “will help reduce greenhouse gas emissions. The 20-MW energy storage system supports Gov. Andrew M. Cuomo’s Green New Deal.” The state’s press release drones on with self-congratulatory quotes from just about everybody and lots of promotion of New York’s Green New Deal.⁸

Now here’s the thing: This battery project isn’t going to reduce carbon emissions one iota. This battery provides regulation service and moves off its set point at 50% of capacity only as signaled.⁹ The net effect on generation is trivial with no way of knowing whether carbon emissions are trivially increased or trivially decreased.

On to the much-ballyhooed 300-MW storage procurement by Consolidated Edison. The request for proposals is of course long and complex, but it asks nothing about actually reducing carbon emissions.¹⁰ It’s storage for the sake of storage.

On to the New York State Energy Research and Development Authority implementation plan for storage, with requirements and metrics for bulk storage, none of which involve actually reducing carbon emissions.¹¹ More storage for the sake of storage.

Last but not least is the idea of replacing peaker plants with batteries. It ought to be obvious that replacing seldom-run peaker plants with batteries won’t materially reduce carbon emissions because seldom-run peaker plants seldom produce carbon emissions. And even if they did run more it would beg the (unanswered) question of what would be used to charge the batteries.

And here’s a gut-check conclusion of New York Public Service Commission staff’s study of the subject that nobody seems to appreciate: six-hour batteries could provide equivalent generation for only 275 MW of the state’s existing peaker fleet of 4,500 MW.¹² Let’s think about this. The type of generation that batteries ought to be able to replace is peakers, but when operational analysis is done, it turns out that only 6% of existing peakers could be replaced by batteries.

So what’s the peaker replacement reality? Little carbon emission benefit and little operational feasibility.

Nota Bene

All this is fair warning to everyone everywhere when politicians pull numbers out of thin air — like New York’s 9,000 MW of offshore wind and 3,000 MW of storage — and tell the political appointees to just do it.

The politicians get the applause lines, and the customers get the shaft.

¹–http://energy-counsel.com/docs/You-Say-You-Want-a-REVolution-Fortnightly-February2016.pdf.

²-As I said about the utility residential solar programs: “REV demonstration projects at least demonstrate one thing: Utilities shouldn’t be running residential solar programs.”

³–http://energy-counsel.com/docs/Offshore-Wind-Edifice-Complex.pdf. By the way, there are more than 5,000 MW of onshore wind in NYISO’s interconnection queue, https://www.nyiso.com/documents/20142/1407078/NYISO-Interconnection-Queue.xlsx/c0fe9a9b-7011-ab05-0f51-fd4ad0ef33f0 (sorting on wind for total of 18,976 MW and subtracting 13,632 MW of offshore wind).

⁴-Indian Point’s 2,144 MW capacity times 90% capacity factor is 16.9 million MWh. https://www.eia.gov/todayinenergy/detail.php?id=29772. New York has not disclosed subsidy information, but if we use New Jersey’s $98.10/MWh price as a proxy (conservative given New York’s union labor requirement) https://www.scientificamerican.com/article/major-u-s-offshore-wind-projects-still-face-hurdles/, and subtract the $49/MWh energy price in the Long Island zone in 2018, https://www.nyiso.com/documents/20142/2223763/2018-State-of-the-Market-Report.pdf/b5bd2213-9fe2-b0e7-a422-d4071b3d014b (pdf page 8), then the annual subsidy cost is 16.9 million MWh times $49.10/MWh, which equals $830 million.

⁵-The first 1,700 MW have an (optimistic) in-service date in 2024. https://www.nationalfisherman.com/mid-atlantic/new-york-signs-1-7-gigawatt-deal-for-offshore-wind-energy/.

⁶–https://www.nytimes.com/2016/08/02/nyregion/new-york-state-aiding-nuclear-plants-with-millions-in-subsidies.html.

⁷–http://energy-counsel.com/docs/Cue-the-Pixie-Dust.pdf; http://energy-counsel.com/docs/Grid-Batteries-Kool-Aid-Once-More-with-Feeling-RTO-Insider-12-5-17.pdf; http://energy-counsel.com/docs/Battery-Storage-Drinking-the-Electric-Kool-Aid-Fortnightly-Janu ary-2016.pdf.

⁸–https://www.nyserda.ny.gov/About/Newsroom/2019-Announcements/2019-09-12-NYSERDA-Announces-Completion-of-Largest-Battery-Installation-in-the-State.

⁹–https://dailygazette.com/article/2018/07/05/20-megawatt-battery-facility-planned-in-stillwater. (“‘We’ll leave it probably half-charged,’ [Chief Development Officer Dan] Fitzgerald said, so that it can go either way.”).

¹⁰–https://www.coned.com/-/media/files/coned/documents/business-partners/business-opportunities/bulk-energy-storage/bulk-storage-request-for-proposals.pdf?la=en.

¹¹–http://documents.dps.ny.gov/public/MatterManagement/MatterFilingItem.aspx?FilingSeq=230734&MatterSeq=55960.

¹²– The PSC staff study is here, http://documents.dps.ny.gov/public/Common/ViewDoc.aspx?DocRefId={2F0A202D-CAB9-4961-96F3-56AEA67C6052} (pdf page 24). Four-hour batteries could replace 83 MW, and eight-hour batteries could replace 509 MW. Of course, eight-hour batteries cost twice as much as four-hour batteries. Adding solar to batteries could replace more megawatts, but of course that adds even more costs.

September 30, 2019

PJM MRC/MC Briefs: Sept. 26, 2019

CEO Search Continues

VALLEY FORGE, Pa. — Neil Smith, chairman of PJM’s search committee and a member of its Board of Managers, told the Markets and Reliability Committee on Thursday that he anticipates former CEO Andy Ott’s position will be filled by the end of fall.

“We are focused on speed but not at expense of quality,” he said. “When we can share, we will.”

Ott retired June 30 and board member Susan J. Riley stepped into his role temporarily while the organization searched for a replacement. (See PJM CEO Andy Ott to Retire.)

PJM’s Markets and Reliability Committee and Members Committee met Sept. 26 in Valley Forge, Pa. | © *RTO Insider*

Non-retail BTM Generation Rules Endorsed

Stakeholders unanimously endorsed revisions to Manuals 13 and 14D to clarify the reporting, netting and operational requirements of non-retail behind-the-meter generation (NRBTMG). In Manual 13, maximum generation emergency actions and deploy-all-resource actions are identified as triggers to load NRBTMG.

The endorsement follows a one-month deferral requested by Exelon in order to review applying the rules to community solar programs and aggregate net energy metering. Both PJM and Exelon told the Operating Committee on Sept. 10 that compromise language was close to being finalized, which excluded both types from reporting requirements. (See “Non-retail BTM Generation Update,” PJM OC Briefs: Sept. 10, 2019.)

PJM’s Terry Esterly said Thursday that staff added the revisions to Manual 14 Appendix D and Manual 28.

Stakeholders Urge Consensus on Load Management Testing Requirements

Stakeholders urged PJM and Enel X to reach a compromise on their dueling proposals to update load management testing requirements before a scheduled vote at the October MRC meeting.

“I would encourage both parties to find common ground and present one proposal,” said Adrien Ford of Old Dominion Electric Cooperative. “I think there’s been a lot of progress, and I’m just hoping we can see just a little more movement.”

The key differences between the two packages, endorsed at the Market Implementation Committee on Sept. 10, involve how much advance notice PJM provides to demand response resources before a test and procedures for retesting. (See PJM Stakeholders Support More Realistic DR Testing.) PJM wants testing procedures to more closely mimic reality and proposes a three-step notification system that gives resources first notice on the 21st of the month before, with additional alerts the day before and the morning before. Resources that fail would request a PJM-scheduled retest.

Enel X contends the month-ahead notification provides little useful information to resource owners who operate on a week-ahead timeline. It’s also uncertain how PJM will manage retests when new rules would test resources seasonally — an ambiguity the Enel X proposal attempts to clear up.

PJM — Brian Kauffman, Enel X | © *RTO Insider*

“If you want to do a retest, how will you have time in a season to do a retest?” said Brian Kauffman of Enel X. “Since that could really determine the compensation for resources in a year, it’s really important.”

Susan Bruce, of the PJM Industrial Customer Coalition, said the RTO’s proposal reads like a “gotcha test” to the companies she represents.

“We are not in a position to support PJM’s package,” she said, noting that consensus can still be reached. “I’m not looking to change testing for generators, but I note that there is an open-book test for generators, and there are many low-capacity-factor generators that similarly might not be operating a lot given our very healthy reserve margins.”

Pete Langbein, PJM’s manager of demand response operations, assured Bruce and others that that wasn’t staff’s intention.

“The idea was not to have a gotcha test,” he said. “We heard folks loud and clear, and what you have before you is dramatically different from what we started with. We agree it’s not fair” to test without advance notice.

Independent Market Monitor Joe Bowring said PJM’s package isn’t rigorous enough.

“It’s important to remember that demand response plays a critical role in PJM and a significant role in capacity markets. The PJM proposal is a very modest improvement, and of course you’d rather not have it because it imposes costs.

“While I appreciate your concerns, PJM’s proposal is at the extreme end of modes and should be a very basic requirement for ensuring that demand response is actually there when we need it,” he added.

If PJM and Enel X are unable to reach a compromise, the RTO’s package will be considered first by the MRC. Enel X’s proposal would only come to a vote if the PJM package fails to win approval.

Reserve Requirement Study Preliminary Results

PJM said preliminary results for its 2019 reserve requirement study lowered both the installed reserve margin (IRM) and forecast pool requirement (FPR), which will reset key parameters for the RTO’s upcoming capacity auctions.

Patricio Rocha Garrido, of PJM’s resource adequacy planning department, said the 2019 capacity model, the 2019 load model and the 2019 capacity benefit of ties (CBOT) drove the nearly 1% decrease in IRM, though the capacity model didn’t impact the lowered FPR.

The final report will be distributed Oct. 8 and include recommended IRM and FPR for delivery years 2020/21 through 2023/24.

Manual 34 Changes

The MRC and Members Committee also approved by acclimation changes to Manual 34: PJM Stakeholder Process addressing the prioritization of issues and creating an alternative path for critical, time-sensitive issues. The changes are also intended to ensure transparency throughout the process. (See New Rules to Give PJM Members More Time on Issues.)

The MRC also endorsed changes to the following manuals:

Manual 11: Energy & Ancillary Services. The revisions document the procedure for addressing missing historical performance scores in the regulation market and clarify that the reserve requirements used in the market clearing process are based on the largest single contingencies that are communicated by PJM Operations and modeled in the markets clearing software.
Manual 15: Cost Development Guidelines. To comply with FERC Order 841, changes were made to language on hydro resources and flywheels. Definitions were added for efficiency factor, fuel cost, variable operations and maintenance (VOM) and ancillary service costs. It was also approved by the Members Committee.
Manual 27: Open Access Transmission Tariff Accounting and Manual 28: Operating Agreement Accounting. The changes, required to comply with FERC Order 841, detail PJM settlement procedures for “charging energy,” which is purchased by energy storage resources for later resale. Charging energy is always billed at the applicable LMP, but different categories of charging energy are subject to different sets of charges. They include “direct charging energy” — power purchased by a storage resource from the PJM energy market for later resales to the market or is lost to conversion inefficiencies — and “load-serving charging energy,” which is purchased from the energy market and stored for later resale to end-use load.

– Christen Smith

September 30, 2019

ISO-NE IDs $8.7M Tx Fix for Boston Area

By Rich Heidorn Jr.

ISO-NE has identified a 160-MVAR reactor at National Grid’s Golden Hills 345-kV substation in Saugus, Mass., as a key part of its solution to Boston’s 2028 needs, the RTO’s Kaushal Kumar told the Planning Advisory Committee on Thursday. The reactor, at an estimated cost of $5.47 million, is intended to correct high-voltage violations found at minimum load levels.

Kumar, a senior transmission planning engineer, said the solution was chosen from four 115-kV and 345-kV alternatives in the RTO’s final review. All the finalists also require the installation of a 115-kV breaker in series with breaker 4 at Exelon’s Mystic generating plant to eliminate a breaker failure contingency, a project estimated at $3.25 million.

ISO-NE transmission planning includes the Mystic Generating Station — Mystic Generating Station

Together, the two solutions are estimated at $8.72 million (+50%/-25%).

Kumar said the cost estimate and expected in-service date were the most important factors in the RTO’s selection.

The winning project was the cheapest among the options that could be in service in 2021.

Because it is time-sensitive, it will be installed by National Grid. A need is considered time-sensitive — and excluded from competitive bidding — if the improvements are required within three years of a completed needs assessment.

ISO-NE transmission planning — ISO-NE selected a 160-MVAR reactor at the Golden Hills 345-kV substation as the cheapest solution to correct high-voltage violations expected at minimum load levels in the Boston area in 2028. | *ISO-NE*

Needs Update Reduces Thermal Violations

The RTO also briefed the PAC on its updated study of non-time-sensitive needs in the Boston study area, which will be the subject of a request for proposals in the fourth quarter. The update incorporates the Golden Hills reactor and system changes since the finalization of the Boston 2028 Needs Assessment in June.

The update made several changes to resource assumptions:

The New England Clean Energy Connect (NECEC) and Revolution Wind offshore wind projects were added to the model after providing approved contracts to the RTO. NECEC, a transmission line that would deliver Canadian hydropower to New England, was modeled as a 1,090-MW injection at the Larrabee Road 345-kV substation in Maine. Revolution Wind was modeled as a 120-MW injection at the Davisville 115-kV line in Rhode Island. Both were modeled at 20% of their nameplate capacity.
Resources that filed retirement and permanent delist bids for Forward Capacity Auction 14 were removed from dispatch assumptions.
The model uses FCA 13 active demand capacity resources (ADCRs), updated from FCA 12.
Resources outside Boston that filed retirement and permanent delist bids for FCA 13 have been removed from dispatch.
An “asset condition” project to refurbish the 110-510/511 cables in downtown Boston was added.

The needs assessment posted on June 10 identified one N-1 and six N-1-1 thermal violations under peak loads, all considered non-time-sensitive needs. The updated analysis eliminated three N-1-1 thermal violations: on the Woburn-Wakefield Junction 345-kV and Stoughton-to-K Street 345-kV circuits 1 and 2.

Four other thermal violations identified in the June 2019 Needs Assessment remain:

N-1 Thermal Overload: W. Amesbury–King St. 115-kV line;
N-1-1 Thermal Overload: circuits 1 and 2 of the Woburn-North Cambridge 345-kV lines; and
N-1-1 Thermal Overload: North Cambridge–Mystic 345-kV cable.

Mystic Reactor

ISO-NE’s Pradip Vijayan updated the PAC on revisions to the requirements for a 300-MVAR dynamic reactive device needed for system operations after the retirement of Mystic Units 8 and 9. Exelon announced last year that it would retire Mystic in 2022, but FERC approved a cost-of-service agreement between the company and ISO-NE to keep Units 8 and 9 operating through May 2024.

Since the Aug. 8 PAC meeting, RTO staff reduced the device’s requirement to provide full leading capability at 1.05 per unit voltage at the point of interconnection (POI), down from the original 1.1. The requirement to provide full lagging capability at 0.9 per unit voltage is unchanged.

Staff also amended some of the reactive power requirements for clarity, saying the device must provide continuous voltage control at the POI and must not stay in standby mode (providing no reactive power) under normal operating conditions.

The reactor is considered non-time-sensitive.

The RTO plans to finalize the Boston 2028 Solutions Study next month. Stakeholder feedback on the selection and the study report, which was posted Sept. 24, are due on Oct. 9. Comments should be sent to pacmatters@iso-ne.com.

“You can look for an RFP [on the non-time-sensitive needs] in December,” said the RTO’s Eva Mailhot. “That’s our Christmas present to you guys,” she joked.

Eastern Connecticut 2029 Needs Assessment

ISO-NE’s Jon Breard provided an update on the Eastern Connecticut (ECT) 2029 Needs Assessment, which was suspended in February because changes in the 2019 draft capacity, energy, loads and transmission (CELT) forecast indicated the net load figures in the ECT 2027 assessment were too high. The 2019 CELT shows changes in load, energy efficiency and solar PV from the 2017 CELT.

The revised ECT needs assessment considers future load forecasts, resource changes based on FCA 13 results, coordination with proposed Southeastern Massachusetts and Rhode Island (SEMA/RI) projects, and NERC, ISO-NE and Northeast Power Coordinating Council (NPCC) reliability standards.

Also included were NECEC and the Vineyard Wind and Revolution offshore wind farms.

ISO-NE transmission fix — Eastern Connecticut study area | *ISO-NE*

The CELT 2029 90/10 summer peak load forecast is 32,468 MW, an increase of 1,663 MW over the 2022 forecast. However, net load excluding station service decreased by 100 MW because of increased forecasts for energy efficiency and PV production.

The report concludes that non-transmission options were not able to correct the reliability violations in ECT.

All needs are time sensitive and located on the systems of Eversource Energy, National Grid and Connecticut Municipal Electric Energy Cooperative, the RTO said.

The RTO plans to post the draft ECT needs assessment next month, with the final report expected to be posted in the fourth quarter.

The study found no N-0 violations in ECT or neighboring areas and one N-1 low-voltage violation and no N-1 thermal violations in the ECT area. Steady-state peak load results identified seven N-1-1 violations.

The RTO plans to post the final needs assessment report in the fourth quarter.

Transmission Planning Technical Guide Short-circuit Requirements

The RTO’s Faheem Ibrahim briefed the committee on proposed assumptions for conducting short-circuit analyses using an ASPEN OneLiner.

Such analyses are used in generator interconnection studies, system impact studies, needs assessments, solution studies, and NERC and NPCC compliance studies.

Ibrahim said having a single set of study conditions and solution parameters in the Transmission Planning Technical Guide will ensure consistency across the different studies.

Comments on the revised guide are due to pacmatters@iso-ne.com by Tuesday.

September 30, 2019

CPUC Adds RAMP Costs to Rate Case for 1st Time

By Hudson Sangree

The California Public Utilities Commission authorized costs for a new safety program as part of a utility’s general rate case (GRC) for the first time Thursday, when it approved rate increases for San Diego Gas & Electric and Southern California Gas.

The unanimous approval of the utilities’ three-year general rate case included costs associated with the CPUC’s Risk Assessment Mitigation Phase (RAMP) program.

The “applicants are the first utilities to incorporate RAMP into their GRC filings, and these costs are being included in [their] respective revenue requirements for the first time in [test year] 2019,” the CPUC said in its decision.

Both companies are owned by Sempra Energy.

The RAMP program is part of the CPUC’s efforts to address disasters caused by the state’s three big investor-owned utilities, such as the San Bruno gas pipeline explosion and recent wildfires. The program, and the related Safety Model Assessment Proceeding (S-MAP), require the IOUs to examine the risks they face and propose strategies to mitigate those risks, which the CPUC must then approve.

CPUC RAMP — Part of the rate hike approved for San Diego Gas & Electric Thursday was for fire safety measures. | *SDG&E*

The utilities’ RAMP reports would eventually be integrated into their GRCs every three years, the CPUC decided. The SDG&E/SoCal Gas rate case was the first time that happened.

“The SDG&E and SoCalGas RAMP proceeding is an opportunity for large California investor-owned utilities to describe their proposed mitigations for safety risks associated with the operation of their assets,” the CPUC said on its website.

For SDG&E and SoCalGas, the rate-case decision filled nearly 800 pages, following a two-year review in which 20 parties intervened and 500 exhibits were entered into evidence, said Liane Randolph, the commissioner assigned to the rate case.

The result included a $1.99 billion revenue requirement for SDG&E’s combined operations and $2.77 billion for SoCalGas in 2019, with adjustments allowed in 2020 and 2021. A typical residential customer will see an increase of $1.01/month (0.7%) for electric service and $4.50 to $5 (about 14%) a month for gas service, Randolph said.

“However, a large part of the increases represents costs for incremental safety-related programs and activities that are being added to the GRC for the first time as a result of the … RAMP process,” Randolph told her colleagues at Thursday’s meeting. “The RAMP process requires SDG&E and SoCalGas to identify key safety risks and to propose programs that mitigate those risks.”

Programs being approved address wildfires caused by utility equipment and catastrophic damage from pipeline failures. Among SDG&E’s programs are 3D imaging that lets the utility assess the risk of pole failure because of winds and third-party attachments to poles, Randolph said. A gas leak survey process that uses electronic mapping is another example, she said.

RAMP costs are part of the PG&E’s next rate case, which the CPUC plans to decide in early 2020.

September 30, 2019March 13, 2025

Chatterjee Coal Country Forum to Consider ‘Energy Transition’

By Michael Brooks

FERC Chairman Neil Chatterjee on Thursday released an ambitious, star-studded agenda for the commission’s energy conference to be held Oct. 21 at the University of Kentucky in Lexington.

Dubbed the EnVision Forum, the daylong conference will feature 12 panels, three at a time, with some moderated by former FERC Commissioners Colette Honorable and Robert Powelson.

Panels will include “Transforming Transmission: Investing Today in Tomorrow’s Grid,” featuring former Commissioners Jon Wellinghoff and Phil Moeller, and “Emerging Issues in Organized Electricity Markets,” with ISO-NE CEO Gordon van Welie, MISO CEO John Bear and interim PJM CEO Susan Riley.

Giving keynote addresses will be Murray Energy CEO Robert Murray, American Electric Power CEO Nick Akins, Energy Storage Association CEO Kelly Speakes-Backman and Deputy Energy Secretary Dan Brouillette.

“Launching the EnVision Forum in my home state of Kentucky, where we are seeing a wave of societal challenges due to the closure of coal plants and mines, was the logical first step for us to take,” Chatterjee said in a statement.

“We want to start some new conversations with new voices and create relationships and understanding among the range of interests that are affected by this energy transition.”

There will also be panels on the intersections between energy and telecommunications, water and the opioid epidemic (“Pain, Pills, and Police: The intersection of the energy industry and the opioid epidemic”).

“The law enforcement community is grateful for Chairman Chatterjee’s out-of-the-box thinking in also focusing this conference on the intersection of the opiate epidemic and the coal industry at both ends of our commonwealth,” panel moderator Russell Coleman, U.S. attorney for the Western District of Kentucky, said in a statement.

Speaking to RTO Insider on Friday, Chatterjee said he has been “humbled and overwhelmed by how much interest there has been in this.” He estimates that, not including press and support staff, about 170 people have confirmed they will attend so far.

The event will be held “throughout” Kroger Field, the University of Kentucky’s 61,000-seat football stadium. Chatterjee said he has not yet done a site visit, but the stadium is home to the Woodford Reserve Club, used to host special events.

Chatterjee said the idea for the event took shape over the past six months. He said that as the industries that FERC regulates rapidly change, “the commission has clearly seen an increase in the visibility of its work,” but “a lot of people aren’t familiar with it.”

“It’s time people had a better idea of what FERC does,” he said. The forum will also give the commission the opportunity to hear discussions it wouldn’t normally be able to during its regular business hours, he said.

But Chatterjee also “liked the idea of getting out of Washington” and introducing stakeholders to Kentucky, a place that hasn’t felt the benefits of the energy transition as much as others, he said.

Prior to joining FERC, Chatterjee, a Lexington native, was an adviser on energy policy to Senate Majority Leader Mitch McConnell (R-Ky.). But energy wasn’t his first choice when coming to Capitol Hill: He originally wanted to work on health care policy, he said, as both his parents were professors and cancer researchers at UK. (He attended St. Lawrence University in upstate New York, as he couldn’t stand the idea of taking classes from his parents and their friends, he said.)

It was only when working on energy issues on behalf of McConnell that, he said, he fully realized the importance of coal to Kentucky. “Coal wasn’t just part of the economy; it’s part of the cultural lifeblood of the state.”

It’s also a central part of politics there. McConnell, who faces re-election in 2020, has been attacked by his Democratic challenger, Amy McGrath, for not supporting legislation to strengthen coal miners’ pensions or a fund that supports miners with black lung disease.

Just after he joined the commission in August 2017, Chatterjee said in FERC’s “Open Access” podcast that as a Kentucky native, “I’ve seen firsthand throughout my life how important a contribution coal makes to an affordable and reliable electric system. … As a nation, we need to ensure that coal, along with gas and renewables, continue to be a part of our diverse fuel mix.”

A year later, after FERC unanimously rejected the Department of Energy’s NOPR Notice of Proposed Rulemaking calling for price supports for coal and nuclear plants, Chatterjee talked about how former Chairman Kevin McIntyre had “helped me grow in my role as I made the transition from formerly partisan legislative aide to independent regulator.” (See Returning Chair Pledges to Protect FERC’s Independence.)

The inclusion of a panel on the opioid crisis had some FERC watchers scratching their heads.

“It appears from the content of this event that the chairman is [planning to run] for political office in Kentucky,” said one FERC observer who agreed that Chatterjee appears more animated by politics than by many of his FERC duties.

“This is a purely substantive event with serious and diverse technical content that is not political in any way whatsoever,” Chatterjee said Monday when asked if any political ambitions in the state.

It’s apparent at least that he did not shy away from the controversial. One panel is titled “All of the Above vs. Green New Deal: How States Balance Costs, Carbon and Communities” and will feature several state utility commissioners. Another is a “Conversation on Climate,” to be moderated by Rich Powell, executive director of ClearPath, an organization that supports “conservative policies that accelerate clean energy innovation.” Jason Bordoff, director of Columbia University’s Center on Global Energy Policy, will be a panelist.

Tyson Slocum, director of Public Citizen’s Energy Program, who has been highly critical of FERC, said he agreed to participate as a panelist on “Empowering 21st Century Energy Consumers with Technology” after receiving assurances he would be able to make his points that “FERC has to do a lot more to ensure the public and the public interest has a meaningful seat at the table” on commission issues and on RTO governance.

Public Citizen and other groups have been pushing since at least 2016 to have FERC provide public funding for interventions before the agency, as they say was required by the Public Utility Regulatory Policies Act. (See Citizens Groups Seek Public Funding for FERC Interventions.)

Rich Heidorn Jr. contributed to this report.

September 30, 2019

Texas PUC Briefs: Sept. 26, 2019

Texas regulators last week formally approved one of two transmission projects necessary to integrate much of the city of Lubbock’s load into ERCOT.

The Public Utility Commission signed off on a certificate of convenience and necessity (CCN) during its open meeting Thursday, granting Sharyland Utilities and Lubbock’s joint application for a 58-mile, $90 million 345-kV link between substations in Ogallala and Abernathy. Substation improvements will increase the total cost to nearly $100 million (48625).

The commission also heard oral arguments from two landowners opposing the path of the second 345-kV project, a 33-mile line from Abernathy to Wadsworth projected to cost about $74 million (48668).

The Texas PUC holds its open meeting Sept. 26.

The PUC will vote on the second CCN during its Oct. 11 open meeting. Chair DeAnn Walker suggested neither landowner — one of whom said he was a 101-year-old World War II veteran — needed to again make the long trip from Lubbock.

“My daughters went to [Texas] Tech [in Lubbock], so I know what that drive’s like,” Walker said.

The CCNs are needed to move 470 MW of the city of Lubbock’s load from SPP to ERCOT. (See “LP&L Lines for ERCOT Integration near Final Approval,” Texas PUC Briefs: Sept. 12, 2019.)

Oncor will be responsible for the projects’ construction before turning them over to Lubbock Power & Light, the city’s municipal utility. Both lines are scheduled to be energized by June 2021, meeting LP&L’s target date to join ERCOT.

Commission Approves Rate Recovery, $328K in Fees

In other business, the commission approved $110,600 in administrative penalties:

Retailer Quest Distributors was docked $20,000 for collecting deposits without informing the commission and without adequate customer protections (49576).
Utility AEP Texas settled for $69,000 (49725) and Entergy Texas settled for $21,600 (49829) in penalties regarding annual service quality.

The PUC approved El Paso Electric’s requests for a distribution cost recovery factor, based on an annual Texas retail revenue requirement of almost $7.8 million (49395), and to implement an interim fuel refund of almost $19.2 million (49482). It also agreed to requests by Southwestern Public Service (49495) and Oncor (49594) to adjust their energy efficiency cost recovery factors.

— Tom Kleckner

September 30, 2019

Key Details Change in MISO MEP Cost Allocation Plan

By Amanda Durish Cook

CARMEL, Ind. — Months after FERC rejected an earlier cost allocation plan, MISO is circulating a new draft proposal that would further lower voltage thresholds but raise cost minimums on economically beneficial transmission projects.

Under the new plan, MISO would lower the voltage requirements on market efficiency projects (MEPs) from 345 kV to 100 kV, compared with the 230-kV minimum in the first filing.

However, the cost threshold is set to rise from $5 million to $25 million for regional MEPs.

For interregional MEPs with either SPP or PJM, MISO will also seek a 100-kV voltage threshold but no cost threshold.

MISO MEP — Jesse Moser, MISO | © *RTO Insider*

“Perfection is not achievable, but we want to be as good as we can be,” Jesse Moser, MISO director of economic and policy planning, said during a meeting of the Regional Expansion Criteria and Benefits Working Group (RECBWG) on Thursday.

Moser said the cost requirement increase maintains a “demarcation of larger, regionally beneficial projects.” MISO’s $5 million threshold was approved by FERC in 2007.

The $25 million figure is not final and still open to suggestion, Moser said. He said a regional MEP cost threshold could also be designed to move with inflation. Going forward, MISO intends to review its MEP cost allocation method with stakeholders once every three years, he said.

“It was more about having a way to have some separation between local and regionally economic projects,” Moser said. “There’s not going to be an answer that doesn’t have some controversy and challenges.”

As in the first filing, the new plan would exempt from MISO’s competitive bidding process any MEPs needed within three years to mitigate reliability issues. The filing also preserves the elimination of a 20% postage stamp cost allocation. It additionally still seeks to add new benefit metrics for savings from the avoided costs for reliability projects and cost reductions related to the MISO-SPP transmission contract path.

But the new filing has abandoned a provision that would create a local economic project type.

FERC rejected the first cost allocation filing in June, finding it would have violated the principle of cost causation because projects proposed under the local economic transmission category would be required to demonstrate regional benefits while only being cost-shared on a local level.

The project type was meant for smaller, economically driven transmission projects between 100 and 230 kV, with 100% of costs to be allocated to the local transmission pricing zone containing the line. The projects would not only have to meet a local benefit-to-cost ratio of 1.25-to-1 or greater within their pricing zones but also be required to show the same minimum regional 1.25-to-1 ratio required of MEPs. (See MISO Mulling Next Steps on Cost Allocation Overhaul.)

“While FERC expressed appreciation for many aspects of the proposal, the commission had some concerns about the newly created local economic project category,” MISO CEO John Bear said at the RTO’s July Informational Forum.

Discord

MISO considered several possibilities before settling on the draft proposal, including lowering the voltage threshold to 100 kV for interregional MEPs only or placing projects lower than 230 kV back into the RTO’s existing “other” project category. Stakeholders have offered various opinions on the refiling, with some urging MISO to lower the interregional voltage threshold to 100 kV on both sides of the seam, and others advising that any 100-kV project be eligible for regional cost-sharing.

“This seems simpler than some of the earlier discussions,” Clean Grid Alliance’s Natalie McIntire said of the new version at the RECBWG meeting.

However, other stakeholders contended the MISO community was suffering from “cost allocation fatigue.” Some said it wasn’t clear why the RTO so dramatically altered its original proposal to include 100-kV projects instead of simply removing the lower-voltage project issues FERC raised.

Xcel Energy’s Susan Rossi characterized the proposal as a “drastic change at the last minute.”

But others said that if MISO failed to address the lower-voltage cost-sharing, it would be ignoring LS Power’s pending complaint that asks FERC to compel MISO to lower the threshold for competitively bid transmission projects from 345 kV to 100 kV. (See Complaint Seeks Bigger Role for Smaller MISO Projects.)

McIntire also said some stakeholders were forgetting that the original proposed 230-kV threshold was just the product of a compromise that several stakeholders still disagreed with because they felt it still represented too high a bar.

“I think MISO’s decision to move to 100 kV throws that compromise out the window, and that will be evident to FERC,” Entergy’s Matt Brown contended.

2020 Extension

The new MEP filing will still contain a cost allocation proposal for interregional projects with PJM, even though FERC’s rejection of MISO’s first allocation plan stood to complicate separate deadlines associated with compliance around the longstanding complaint by Northern Indiana Public Service Co. (See “Interregional Filings Also Rejected,” MISO Allocation Plan Fails on Local Project Treatment.)

FERC in mid-September granted an extension that will allow MISO to file its interregional allocation compliance by Jan. 2, 2020, instead of the original late September deadline (EL13-88). MISO was originally due to file its PJM interregional cost-sharing plan by Sept. 23, the date established in FERC orders stemming from NIPSCO’s 2013 complaint over the PJM-MISO seam that ultimately eliminated a cost minimum and lowered the voltage threshold for MISO-PJM interregional projects to 100 kV.

MISO said it needed the extra time for the MEP filing “to ensure proper coordination” with the compliance filing ordered in the NIPSCO complaint. The RTO also said that this is its first extension request since FERC rejected its proposed cost allocation changes to interregional and regional MEPs.

At a Sept. 17 meeting of the MISO board’s System Planning Committee, Director Nancy Lange urged stakeholders to keep working on a cost allocation refiling and remain undeterred by FERC’s rejection of the first proposal.

“I was happy that there was a consensus that could be filed with FERC,” Lange said of MISO’s first filing in late February.

Moser said MISO doesn’t envision using all the extension period granted in the NIPSCO complaint and hopes to make a revised cost allocation filing before Thanksgiving. MISO’s latest proposal is open to stakeholder comment through Oct. 10.

September 30, 2019

PUCO Delays Ruling on AEP Solar Projects

By Christen Smith

The Public Utilities Commission of Ohio last week delayed ruling on the need for two solar projects proposed by American Electric Power after the company asked for a “brief hold” to update its filings to reflect the impact of the recently approved Clean Air Act.

In its request filed Sept. 20, AEP said certain provisions of the new law — also known as House Bill 6 — convey potential benefits to the 300-MW Highland Solar and 100-MW Willowbrook facilities proposed in its long-term forecast report filed last year. The company offered very few details of how the legislation changes its proposal, citing confidentiality agreements, but did ask for a 60-day delay in proceedings.

“The new filing, if successful, would present the commission with additional options and flexibility as compared to the company’s existing proposal filed in these proceedings,” Steven Nourse, AEP’s attorney, wrote in the request. “Moreover, it is the company’s view that the new filing will ameliorate many of the concerns and objections raised by opponents in these proceedings. Such developments should be viewed as helpful regardless of whether the potential opinion and order scheduled for consideration on Wednesday would have initially rendered a positive finding or a negative finding on the need issues.”

The $170 million Clean Air Act, signed into law in July, curtails the state’s current renewable portfolio standards and tacks on monthly fees — ranging from 80 cents for residential customers to $2,400 for large industrial plants — to electricity bills, mostly for FirstEnergy Solutions’ Davis-Besse and Perry nuclear facilities. Some $20 million of the fees collected will support six solar power projects, including Highland Solar and Willowbrook, in rural areas of the state. (See Ohio Approves Nuke Subsidy.)

AEP submitted documents last year seeking cost recovery under the state’s renewable generation rider (RGR) for 500 MW of wind and the Highland and Willowbrook solar projects.

PUCO said last year that it would first determine the need for the projects before approving cost recovery mechanisms. On Sept. 19, the commission indicated it would announce a decision in the first half of the proceedings at its Thursday meeting; however, the agenda item was subsequently withdrawn. PUCO spokesperson Matt Schilling said the commission gave no reason for the change, telling RTO Insider that “it’s not uncommon to pull cases from the agenda to allow for more time to consider.”

Protesters — including the Ohio Consumers’ Counsel, Direct Energy, IGS and IGS Solar — urged the commission to rule in the case anyway, calling the bill irrelevant to “the statutory issue of whether Ohio utility consumers need electricity from the proposed solar plants.” Kroger and the Ohio Coal Association also opposed AEP’s request.

“HB 6 did not alter Ohio law that strictly limits a utility’s ability to seek PUCO approval of customer-funded subsidies for new generation plants that it proposes to own or operate,” the protesters wrote in a joint filing. “This separate funding for a monopoly utility generation project (including solar) can only be approved by the PUCO if the utility can show, among other things, that utility consumers need the electricity from the proposed power plants. As has been shown in this case, Ohio consumers don’t need electricity from AEP’s proposed plants, as the competitive market provides more than an adequate supply of power.”

The companies further allege that AEP doesn’t need a second revenue stream on top of the money afforded to the projects via HB 6.

“An outcome that could actually ‘ameliorate many of the concerns and objections raised by opponents in these proceedings,’ as AEP asserts, would be for AEP to withdraw its proposal and to develop the contested renewable projects through a separate affiliate,” the companies wrote. “Of course, AEP is free to undertake that endeavor outside this proceeding, without a delay in the PUCO’s decision.”

Scott Blake, an AEP spokesperson, told RTO Insider on Monday that concerns about the company collecting twice on the same projects presuppose the commission would accept the proposals as filed — an unlikely scenario given the impacts of HB 6 and the points raised by protesters within the proceeding.

“The HB 6 credit would also be factored in to any customer charge,” he said. “Under the proposal, we would purchase power at a fixed cost per megawatt-hour from the developer of the project. The credit from HB 6 would be included in the cost and used to calculate the customer portion.”

September 30, 2019

Stakeholder Soapbox: The Risky Case for Gas-fired Plants

By Mark Dyson, Chaz Teplin and Grant Glazer

Last week, RTO Insider published an op-ed from Steve Huntoon that challenged the approach and findings of the latest report from Rocky Mountain Institute (RMI) on “clean energy portfolios” (CEPs), defined as combinations of renewables, storage and demand-side management programs that, together, can provide the same energy and reliability services as a gas-fired power plant.

Our study, using detailed modeling approaches and robust, region-specific data, found that 90% of gas plants currently proposed for construction face significant risk of competition from CEPs, and associated stranded-cost risk within 10 to 15 years.

Gas-fired Plants — Historical and project evolution of CEP costs | *Rocky Mountain Institute*

The RMI team welcomes feedback and respectful discourse from all perspectives as it relates to our work and its implications, but Huntoon’s article misses the mark by misrepresenting our motivation, oversimplifying our approach, and downplaying the significance of key findings relevant to investors and other RTO market stakeholders. In dismissing our study as relying on “pixie dust,” Huntoon ignores evidence of the fundamental transition underway in the electricity industry and reflects a view of industry dynamics from a decade or more ago that is unsuited to today’s landscape.

An Evidence-based Study Focused on Financial Viability and Risks

RMI is an independent research and consulting firm focused on market-based, profit-motivated solutions for clean energy. Having observed the plight of the coal industry and its investors in recent years, we set out in our study to answer a simple question: Is gas-fired generation heading down the same pathway that has led coal plants into financial distress and early retirement?

There is evidence that this is already occurring. The Panda Temple project bankruptcy in 2017 was an early warning signal, and the planned closure of a 10 –year –old gas plant in California announced in June 2019 suggests a growing trend. Nationally, investors are taking notice, with final investment decisions in new gas capacity declining each year since 2014, and capacity factors for a growing share of new combined cycle gas projects already falling significantly below expectations.

With more than $100 billion in planned gas infrastructure investment through 2025, we set out to examine the risks to shareholders and ratepayers if those investments don’t pan out in today’s rapidly changing competitive environment.

A Transparent Approach with Conservative Assumptions

Huntoon’s first claim about our study is that “numbers are lacking: It’s not possible to validate the data and algorithms.” In fact, we clearly cite every source of data that we rely on, all of which are drawn from industry-standard sources (see pages 27-29 and the technical appendix). We also reference the full mathematical formulation of our model published in our initial, 2018 report (pages 29-37 of the appendix).

Huntoon then challenges our inclusion of energy efficiency and demand response in aggressive quantities. In fact, our estimates are consistent with definitive resource potential assessments from the Electric Power Research Institute, FERC and others, as well as recent evidence from leading utilities. To name just a few examples from the past year: Xcel Energy is including more than 800 MW of EE in its integrated resource plan in Minnesota; Portland General Electric is leaning heavily on demand flexibility in its 2019 IRP while building no new gas; and Glendale Water & Power ran a competitive, all-source procurement that resulted in new EE, DR and other customer-sited resources accounting for approximately 20% of new capacity needs.

Huntoon also argues that it is illogical for us to consider EE and DR only as part of CEPs, and not as complements to gas-fired generation. However, our optimization-based modeling approach shows directly how EE and DR are natural complements to zero-marginal-cost generation from wind and solar, with regionally distinct portfolios that leverage resource diversity and load profile characteristics across seasons and hours. More importantly, in making this argument that a combination of EE, DR and a small gas plant might be less costly than either a big gas plant or a CEP, Huntoon actually bolsters the case that EE and DR are a competitive threat to gas investments if planners do not account for them when sizing projects.

Finally, Huntoon takes issue with the possibility that batteries included in CEPs may be charged with “pixie dust” — or more accurately, energy from fossil-fired generation. To be clear: That is a feature of our analysis, not a bug. This assumption that batteries can be charged from the grid during off-peak hours is consistent with the reality of electricity markets, where off-peak capacity is readily available. Our model also carefully subtracts the energy required for battery storage when calculating the CEP’s net monthly energy generation.

A CEP shouldn’t be restricted from leveraging the current system any more than any other grid asset. Similarly, we would not argue that a new gas plant must keep the lights on without help from other, existing generators. Huntoon’s argument is irrelevant as it pertains to our central finding: that CEPs can compete and win on gas plants’ own turf.

Risks and Uncertainty in an Investment Case for New Gas Capacity

In short, the challenges made by Huntoon against our work are inaccurate, irrelevant or both. Our study finds clear evidence that the majority of proposed gas generation projects are uneconomic to begin with and, if built anyway, will likely lose money well ahead of their expected economic lifetimes. Far from relying on “pixie dust,” our analysis reflects the current state of the market and the inevitable outcomes of further innovation and cost declines in renewables and storage. Perhaps the “pixie dust” that Huntoon refers to is, instead, required to believe forecasts of new gas plant profitability even in light of current market trends and their clear implications.

September 29, 2019

RTOs Gather to Discuss Real-time Co-optimization

By Tom Kleckner

AUSTIN, Texas — Normally, Texas’ electricity industry points to ERCOT’s energy-only — and deregulated — market as a model for the rest of the country to follow.

Last week, however, ERCOT staffers and stakeholders gathered to hear advice from the RTOs that have already implemented real-time co-optimization (RTC) in their markets. MISO, PJM and SPP staff gave high-level overviews of their forward markets and lessons learned from their experience with the practice.

The Texas grid operator is just months into a multiyear effort to improve its market by adding RTC, a market tool that procures both energy and ancillary services (AS) every five minutes to find the most cost-effective solution for both requirements.

Gary Cate, SPP’s manager of market design, told members of the Real-Time Co-optimization Task Force gathered at ERCOT’s headquarters that his RTO’s implementation of RTC was “clean once we went there” with its integrated marketplace in 2014.

“[Our] real-time market doesn’t have performance issues,” Cate said, rapping the podium in front of him. “The day-ahead market did have commitment issues initially, with reg[ulation] up and reg down as separate products … but we didn’t have a lot of issues from a co-optimization perspective. We did co-optimization after multiple RTOs did it, so we kind of learned from their missteps.”

MISO added RTC to its market in 2009 at a cost of $75 million. Jeff Bladen, MISO’s executive director of digital strategy, said the tool provides an annual return of at least $60 million through a more efficient commitment and dispatch of energy and reserves.

“Our fundamental belief is co-optimization for all our products is necessary to be as efficient as our customers expect us to be. The market is now compensating for availability and flexibility, not just energy,” Bladen said. He noted the RTO plans to file a request with FERC to offer a short-term, 30-minute spinning reserve product.

MISO suggested ERCOT pay attention to ramp sharing, where energy and reserves share the same ramp capability. Bladen said the RTO observed frequent price spikes during parallel operations, which increased reliability risks because insufficient reserves were cleared. With ramp sharing, he said, reserve requirements are scaled up to account for the sharing.

ERCOT’s Matt Mereness, who chairs the RTCTF, said he found the information beneficial for the team’s current principle design phase, including the need to focus on “market education and technical details.”

MISO, PJM and SPP operate capacity markets, designed to ensure reliability by requiring suppliers to have enough resources to meet customer demand and a reserve amount. ERCOT’s energy-only market pays generators only when they provide power day-to-day, relying on scarcity pricing to incent additional generation.

‘Grappling’ with RTC

Reliant Energy’s Bill Barnes said RTC will work well in ERCOT’s market, pointing to the construction of demand curves as being the important difference.

“The energy-only market relies on the ASDC [ancillary services demand curve] to set scarcity prices to drive operational and investment decisions,” he told RTO Insider. “The must-offer requirement in the other markets is due to resource adequacy requirements that don’t exist in ERCOT.”

Resmi Surendran, senior director of regulatory policy for Shell Energy, agreed with Barnes. She said the AS demand curve’s design and the restrictions placed on AS offers could significantly affect the reserve margins the market can sustain.

Capacity markets expect must-offers from resources with capacity obligations, “which seems reasonable as they are paid to be available,” she said. She pointed out SPP and MISO were “very explicit” during their discussion that AS must-offers and near-zero offers for the services shouldn’t be expected if the RTO values the AS product.

“They don’t require resources that don’t have capacity obligations to offer into the AS market, and their offer caps for these AS products are high,” Surendran said. “AS markets are not a key revenue stream for the generators in those markets. In ERCOT, that is not the case. … How we design it could have an impact on the new type and amount of investments the market will attract.”

Shams Siddiqi, Crescent Power | © *RTO Insider*

Shams Siddiqi, who has been involved in much of ERCOT’s market design and is now president of consulting firm Crescent Power, has freely offered his expertise to the RTC task force. He said the tool will be more efficient in ERCOT’s nodal market, where all AS-capable resources are required to offer or let the system create proxy offers.

ERCOT’s must-offer requirement and reduced risk to selling AS under co-optimization will likely reduce AS prices, he said.

“Even if [ERCOT’s] proxy AS offers are set to [$0], when the resource does not submit an offer [under RTC], it’s unlikely that AS clearing prices will be $0, as AS clearing prices always take into account opportunity cost,” Siddiqi said. “Unlike what’s being proposed by ERCOT, other ISOs substitute higher-value AS capacity for lower-value AS capacity and maintain the substituted AS capacity as the higher-value service. This … results in higher level of reliability, making the ASDC continuous so that additional higher-value products always have value greater than or equal to lower-value AS service, and ensures higher or equal clearing price for higher-value AS compared to lower-value AS.”

Barnes said stakeholders are “grappling” with how to set AS proxy offers for RTC. “The pricing of AS in other markets with RTC helps inform our decision,” he said.

TAC Endorses 2 More Key Principles

The RTCTF also received endorsement last week of two additional key principles (KPs) from ERCOT’s Technical Advisory Committee. (See related story, ERCOT Technical Advisory Committee Briefs: Sept. 25, 2019.)

The latest KPs are:

KP 1.1: Replaces the operating reserve demand curve’s adders with ASDCs to determine market-clearing capacity prices for AS products, while continuing to adjust for ERCOT’s defined out-of-market actions to maintain reliability.
KP 1.2: Evaluates the values of and interaction between the systemwide offer cap, value of lost load and power balance penalty price as part of RTC’s implementation. The principle also sets parameters for the values.

The KPs will be sent to the ERCOT Board of Directors, which will now “consider,” rather than “approve,” the principles as a result of a tweak to the group’s scope. Following the KPs’ consideration, staff will draft and sponsor the necessary revision requests, according to the protocols.

The task force plans to consider 19 more KPs during its Oct. 9 meeting.

The TAC also reaffirmed Bryan Sams as the task force’s vice chair. Sams recently left Lone Star Transmission for a position with Calpine as director of government and regulatory affairs.