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November 8, 2024

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PJM PC/TEAC Briefs: Feb. 7, 2023

Planning Committee

Update on 2022 Cost Allocation 

VALLEY FORGE, Pa. — An error in the power flow case for several generators caused minor impacts to the 2022 annual cost allocations and zonal charges for the units, according to a presentation PJM’s Grace Niu gave at the Feb. 7 Planning Committee meeting (ER22-702).

The error affected zonal allocations for 28 projects in 14 regions, with changes being below $1 million for all but three. Baltimore Gas and Electric saw its charges drop by $5.56 million, while APS increased by $1.66 million and Dominion went up by $2.62 million. Liu said the next steps are a FERC filing to make adjustments to the tariff to avoid similar incidents in the future.

Stakeholders Approve New TO/TOP Matrix

Stakeholders endorsed proposed revisions to the Transmission Owner/Transmission Operator (TO/TOP) Matrix, which defines the tasks TOs and PJM are accountable for to comply with NERC reliability standards. Gizella Mali, TO/TOP Matrix Subcommittee chair, said the changes do not add any new standards or remove any retired standards and contain only minor revisions identified in the subcommittee’s review.

The changes include updated document titles, versions and sections, as well as hyperlinks to reference tabs.

Transmission Expansion Advisory Committee

Dozens of Transmission Projects Canceled with Beaver Valley Extension

PJM’s Phil Yum reviewed the baseline impact of First Energy’s March 2020 announcement that it will no longer deactivate its Beaver Valley Nuclear Power Station, a two-unit 1,872-MW generator in Shippingport, Pa. (See Beaver Valley Nuclear Plant to Stay Open.)

Dozens of transmission upgrades had been identified in PJM’s Regional Transmission Expansion Plans (RTEP) since the company’s 2018 announcement that it intended to deactivate three of its nuclear facilities, including Beaver Valley. First Energy has also canceled the deactivation requests for the other two generators identified, Davis Besse and Perry Nuclear Generating Station.

The reinstatement of Beaver Valley has led PJM to cancel 22 baseline upgrades in the APS zone, four in the American Transmission Systems Inc. zone and five in the Penelec zone.

PJM Reviews Baseline Project Proposals

Dominion proposed two solutions totaling $17.8 million to address an overload identified at its 230/115-kV Bremo transformer in the 2027 RTEP light load case. PJM’s preferred solution is to rebuild the Bremo-Fork Union 230-kV line with double circuit structures, achieving a summer rating of 1,573 MVA and disconnecting the line between the Bear Garden substation and Bremo to extending the line 1.6 miles to instead terminate at the Fork Union. The $10.09 million proposal comes with a projected in-service date of Nov. 1, 2027.

The proposal includes the potential to retire the Bremo substation and reterminate all its lines at Fork Union if there is sufficient headroom in the future. Dominion’s second proposed solution would be to retire the Bremo substation now, relocate its lines to Fork Union and install three additional transformers at the substation at a $35.17 million cost.

Dominion also proposed a $7.71 million solution to a 300-MW load drop violation identified at its Evergreen Mills substation. The project would cut the Brambleton-to-Poland Road 230-kV line into two new lines that would run between the three substations, with Evergreen Mills in the middle. Approximately 0.59 miles of new line would be required to cut-in Evergreen Mills, with a total cost of $7.71 million. The project has an estimated in-service date of June 1, 2027.

Supplemental Projects

American Electric Power proposed a $154.53 million supplemental project to rebuild 46.1 miles of 345-kV line with deteriorating wood H-frame structures, some of which have broken in the past and caused conductors to fall to the ground. The faltering equipment is along AEP’s 51.1-mile Conesville-Bixby line in Ohio and is a major source of transmission into the greater Columbus area, making deactivation unviable.

Degrading of the laminated crossarms is a particular concern, with inspections showing decay and rot in the wood. AEP said there are few ways of identifying decay before it causes a loss of functionality and that, paired with the prevalence of delaminated crossarms on the line, many of the failures have “historically been catastrophic in nature.” The Conesville-Bixby line is the only in AEP’s eastern footprint that continues to rely on laminated wood.

Dominion presented two supplemental projects totaling $138 million to resolve two thermal violations at its Bristers substation in Virginia and on the line to the Nokesville substation. The first proposal would reconductor about 9.2 miles of the line between the two substations with higher capacity equipment to achieve a minimum normal summer conductor rating of 1,573 MVA at a $23 million cost, according to the company’s presentation to the TEAC.

The second half of their proposal is to install two 1,400-MVA 500/230-kV transformers and accompanying equipment at the Vint Hill substation and expand the site to the north to provide adequate space for the equipment. Dominion would also cut and loop Vint Hill into the 500-kV lines between the Loudoun substation and the Meadowbrook and Morrisville substations, as well as cut and loop the Rollins Ford-Remington CT 230-kV line to Vint Hill. The work comes with an estimated $115 million cost.

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Market Monitor Pans ERCOT Market Redesign

ERCOT’s Independent Market Monitor continues to criticize Texas regulators’ preferred market redesign, saying the proposal is a “less effective and efficient means” to manage the market’s generation fleet.

During a hearing before the state Senate’s Business and Commerce Committee Feb. 7, Potomac Economics’ Carrie Bivens said the IMM does not support the performance credit mechanism (PCM) that the Public Utility Commission agreed to last month. (See Texas PUC Submits Reliability Plan to Legislature.)

The PCM rewards generators in ERCOT’s energy-only market with credits based on their performance during a determined number of scarcity hours. Those credits must either be bought by load-serving entities or exchanged between them and generators in a voluntary forward market.

Bivens said the IMM believes that recent modifications to the ISO’s operating reserve demand curve after the deadly 2021 winter storm provide “more than sufficient price signals” to retain market resources. She told lawmakers the PCM is a “novel concept” that will likely result in unintended consequences because of its design “challenges.”

“Our evaluation of the concept is that it decreases the efficiency of the energy market,” Bivens said. “In our opinion, if it’s designed appropriately, the most likely result is that performance credits will clear at zero and not add any benefits, since we’re already meeting the reliability standard. Otherwise, it may disrupt and distort the market leading to inefficient outcomes at increased costs.”

Jose Menendez 2022-03-02 (RTO Insider LLC) FI.jpgSen. Jose Menendez | © RTO Insider LLC

Sen. Jose Menendez (D) asked Bivens who would bear the costs of implementing the market mechanism. Energy and Environmental Economics (E3), a consulting firm hired last year by the PUC to review various proposed market revisions, put the implementation cost at $460 million.

“It shifts the risks from generators on to the load, and so it most benefits generators,” said Bivens, who has said the $460 million would be a minimum estimate for incremental costs.

She said the IMM has not performed its own analysis of the PCM’s costs, saying there are still several outstanding factors that “frustrate the ability” to derive an accurate cost estimate.

“Most particular is how the demand curve is going to be formulated. That is going to be a huge contributor to how much these items are going to cost,” Bivens said. “The reason I say that’s the minimum is because a model such as E3’s is going to assume perfect decisions, perfect capacity, no overbuild, no underbuild, no market-power abuse. You know, perfect information by all the participants, and that doesn’t exist in the real world.”

E3 has said the credits could cost retailers $5.7 billion a year, but that could be “significantly” offset by an overall decrease in energy costs.

Bivens agreed with Menendez that it is inaccurate to say no new thermal generation has recently been built, as Sen. Robert Nichols (R) said during an opening history lesson on ERCOT’s market development.

“We’re continuing to lose dispatchable power,” Nichols said. “No one is building anything new.”

The IMM noted in comments to the PUC that since 2014 the market has added about 7 GW of thermal generation — all natural gas, just the fuel type lawmakers asked for with legislation after the winter storm.

Asked by Menendez about the possibility of self-dealing among the so-called gentailers (companies with both generation and retail affiliates), Bivens said the IMM will work with the PUC to address market-power concerns, should the credit mechanism move forward.

Price manipulation is a concern “in every market, such as this one, in which there’s a concentration of supply,” she said.

Bivens was part of a three-person panel that also included PUC Chair Peter Lake and E3’s Zach Ming. Lake and Ming spent much of their time defending the PCM as Bivens sat silently for more than four hours.

“I’ve been very impressed with just your steadfastness,” Sen. Phil King (R) told her.

Senators questioned Lake and Ming on how the PUC’s proposal would incent the dispatchable generation they and other lawmakers requested during the 2021 legislative session. As the committee’s own press release put it, the PCM “was met with skepticism by members.”

“This is the first of its kind. We’ve seen the first of its kind before. Sometimes it works; sometimes it doesn’t,” Sen. Lois Kolkhorst (R) said. “We cannot miss on this. It’s critical.”

“If this PCM plan is adopted, will these new plants ever come online?” Sen. Brian Birdwell (R) asked Lake.

“We know market forces work,” Lake responded.

ERCOT Dispatchable Generation (Potomac Economics) Alt FI.jpgERCOT has added about 7GW of dispatchable generation, all gas, since 2014. | Potomac Economics

 

Asked whether the PUC could promise more reliability, Lake said, “Our goal was to provide you all the broad definition of the best reliability service that we could identify as a result of our analysis, and we recognize that there are a lot of technical questions yet to be answered.”

Lake told the committee he would put further planning on hold while they think things over.

As the hearing ended, an anonymous market participant who goes by the Twitter handle “King of Power,” tweeted that the “least bad option politically” would be for Texas to subsidize loans to new gas generators. That would be just fine with Lt. Gov. Dan Patrick, who presides over the Senate. On Monday, Patrick listed “adding new natural gas plants” as one of his top priorities for the session; he has threatened special sessions if he doesn’t get his way.

The tweet continued: “Lt. Gov and company get new gas plants, PCM is killed, [energy-only] market is intact, and senators can say they leveled playing field vs [environmental, social, and governance investing].”

Sen. King conducted the hearing after the committee’s chair, Sen. Charles Schwertner (R), spent the previous night in the Travis County Jail after being arrested for driving while intoxicated.

“The chair, as you know, is not going to be able to be with us today,” King said as he opened the hearing.

In a statement, Patrick said he will wait on the final outcome of Schwertner’s legal case before making a further statement. However, some have speculated this could cost the senator his chairmanship. Schwertner has been a vocal critic of the PCM, calling it a “costly and complex proposal that is unlikely to deliver the dispatchable generation resources that Texas needs.”

It’s not the first time Schwertner has found himself in hot water. He was investigated in 2018 for sending sexually-explicit text messages to a University of Texas graduate student. The inquiry ended when it determined that it was “plausible” that a third party had sent the messages.

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West, Southeast Need Tx Planners, Report Says

The non-CAISO West and the Southeast U.S. need independent regional transmission planning entities even if the entities are not RTOs, a report released Thursday by Clean Energy Buyers Institute and Grid Strategies contends.  

In contrast to much of the nation, the regions are not part of RTOs or ISOs that perform transmission planning and depend largely on individual utilities to propose projects, the research group and consulting firm noted.  

“Customers in two-thirds of the country rely on independent, trusted, expert transmission planners to achieve greater reliability and cost-savings,” Grid Strategies President Rob Gramlich said in a news release accompanying the report. “Western and Southeastern customers deserve the same benefits.”

The report says RTOs would provide the greatest benefits but that other types of organizations could do important jobs.  

In the West, “little regional planning takes place” outside CAISO, it notes. “The FERC 1000 Regional Planning Entities are Northern Grid, WestConnect and CAISO. Northern Grid and WestConnect tend to simply roll up the plans submitted by each utility.”

One entity that could provide some RTO-like services is WECC, the reliability organization for the Western Interconnection, CEBI and Grid Strategies suggested.

“Currently, the Western Electric Coordinating Council does not manage transmission planning, but it is well positioned to play a greater role,” their report says. “The entity covers the whole Western region, plus western Canadian provinces and a small part of Mexico, and has some independence from the utilities. WECC or another regional planning entity could begin performing technical studies of transmission needs and options that would be valuable for stakeholders.”

In the Southeast, three entities — Southeast Regional Transmission Planning, South Carolina Regional Transmission Planning and Florida Reliability Coordinating Council — nominally are responsible for transmission planning, but “like the West, these entities simply aggregate the utilities’ individual plans and periodically brief stakeholders without seeking input or sharing sufficient data, methods or assumptions to enable an assessment of the projects,” it says.

The Eastern Interconnect Planning Collaborative, which “covers the entire Eastern Interconnect and can evaluate interregional as well as regional opportunities,” could take on additional responsibilities, CEBI and Grid Strategies said. “This process is broad and inclusive and strives to plan backbone transmission facilities that enable interconnection-wide energy outlet and bulk transfers of power.”

FERC has encouraged the formation of RTOs such as PJM, MISO and SPP. “However, none of the relevant FERC orders (2000, 890 and 1000) require that planning functions be performed by an RTO,” the report says.

Independent transmission monitors (ITMs) have been proposed as a means of increasing transparency and oversight in regional planning, it notes.

During an Oct. 6 FERC technical conference on transmission planning, state regulators and consumer advocates urged FERC to order the creation of ITMs and to take other measures to increase oversight of transmission owners’ planning and spending. Witnesses representing transmission owners strongly opposed the ITM concept. (See States Urge More Transparency on Tx Planning, Independent Monitors.)

“The ITM has not been formally proposed by FERC at this point, and there are different versions of what it would do,” the report notes. “At a minimum, an ITM could provide information to market participants about transmission needs and opportunities, while complying with [FERC] Critical Energy Infrastructure Information requirements.”

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NYISO Operating Committee Briefs: Feb. 13, 2023

January Operations Report

NYISO on Monday updated the Operating Committee on January operations performance and how the early-February cold snap event impacted the grid.

ISO Vice President of Operations Aaron Markham said peak load for the month occurred on Jan. 31, at 20,641 MW, lower than the 22,004-MW peak load for the winter and far below the record of 25,738 MW, set in January 2014.

The cold weather event, which occurred Feb. 3 to 4, did not drop temperatures as much as during the December winter storm, but it caused roughly 2,000 MW of day-ahead-committed generation to become unavailable in real time.

Markham told stakeholders that a full operations report on the February cold weather event would be shared in March.

Emergency Operations

Stakeholders approved manual updates for manual emergency operations.

The manual provides rules and regulations that NYISO and market participants must follow in the event of a power system disturbance to both prevent further disruption and restore normal operations as soon as possible. The revisions include removing references of shift supervisor throughout, updating indexed tables and clarifying contingencies for non-NYISO controlled facilities.

FERC Interconnection Waivers

NYISO attorney Sara Keegan told stakeholders that 22 generation projects requested interconnection waivers from FERC to participate in the forthcoming 2023 Class Year study, but only 13 waivers were granted.

FERC granted eight waivers on Thursday and five more on Friday. (See related story, FERC Grants Interconnection Waivers to 8 NY Renewable Projects.)

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NYISO’s Bouchez Begins New Job as Consumer Liaison

NYISO announced on Thursday that Nicole Bouchez had begun working in her new position as senior principal economist and consumer interest liaison for market structures.

The ISO first announced the promotion last month to the Business Issues Committee. (See “Bouchez Named Consumer Liaison,” NYISO Business Issues Committee Briefs: Jan. 18, 2023.)

Bouchez has been with NYISO since 2003 and served as principal economist since 2011. In her new role, she will inform the consumer sector about changes in the wholesale energy markets and their implications, as well as serve as a coordinator for the ISO’s consumer-related initiatives, such as analyzing market developments or design changes.

“I am looking forward to working with the end-use consumers to provide valuable insights and information about market design changes,” Bouchez said in a statement. “This is an exciting time of change in the electric industry, and providing timely information is an important part of a successful transition.”

In an email to RTO Insider, Bouchez said she is “most excited about providing useful information about changes in the wholesale markets.”

NYISO CEO Rich Dewey commended Bouchez in a statement, saying “the expertise and experience that Nicole provides to our market teams and stakeholders is second to none,” and that the ISO “will continue to rely upon Nicole’s knowledge and guidance on changes in the markets.”

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NEPOOL MC Gives OK to Inventoried Energy Program Tweaks

The NEPOOL Markets Committee last week signed off on changes to the Inventoried Energy Program that are intended to get the winter reliability program back in line with global energy markets.

If approved by the full Participants Committee at its next meeting, the changes will incorporate an indexed forward rate to automatically adjust to changes in gas market prices ahead of next winter.

The tariff changes also alter the program’s gas contracting eligibility provisions, an effort to help increase the amount of inventoried energy brought to the region for the next few winters.

In approving the changes, the committee also rejected an amendment from Generation Bridge, which owns four natural gas units in Connecticut. The company wanted ISO-NE to change the maximum amount of stored fuel to be counted in the program from 72 hours to 120 hours.

Changing to 120 hours, Generation Bridge argued, would increase incentives to fill large tanks or arrange for more LNG in preparation for extended cold snaps. And it would improve the likelihood that units with oil capability but no capacity supply obligation would be available in the coming winters, the company said.

The committee, however, ultimately rejected that proposal.

Drilling down on DAS

The MC also continued to discuss ISO-NE’s proposed framework for a day-ahead ancillary services (DAS) market, diving into eligibility for the “flexible response services” (FRS) and energy imbalance reserves (EIRs) that will make up the core of the market.

Energy sources eligible for FRS will have to be dispatchable and located physically within ISO-NE (so no imports or virtual resources would be eligible). They would have to be unconstrained by transmission, not part of first-contingency supply loss and sustainable for a minimum of an hour.

EIR resources would also have to be physical supply resources located within the bounds of ISO-NE and either committed in the energy market already or a fast-start resource.

The committee also discussed settlement rules for the DAS market, which would be “largely unchanged from those proposed during Energy Security Improvements discussions in 2019-2020.”

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Texas RE Board/MRC Briefs: Feb. 8, 2023

Is Cryptocurrency the Answer to ERCOT’s Market Volatility?

AUSTIN, Texas — An executive with the Texas Blockchain Council extolled the virtues of bitcoin mining as an answer to the ERCOT market’s volatility last week.

Steve Kinard, the council’s director of bitcoin mining analytics and president of the Bitcoin Mining Foundation, told the Texas Reliability Entity’s quarterly meeting of its Board of Directors on Wednesday that he has made more than a dozen visits to ERCOT’s nearby headquarters. That includes meetings of the grid operator’s Large Flexible Load Task Force, which is developing policies on how best to integrate the large loads into the market.

“We’ve been having a fruitful conversation there. … The desire there is really to have a discussion on how we can maximize the benefit for all Texans of having a flexible load that can respond to economic incentives and help balance the grid,” said Kinard, a self-described cryptocurrency skeptic turned advocate.

“This is both the traditional demand response, but we’ve also seen miners effectively provide frequency response that helps balance [the grid] in times of unexpected outages,” he said. “Those are two different avenues that we’ve explored in terms of ancillary services that the industry can use. We’re trying to bring more transparency around that, and I think a lot of progress is being made.”

Bitcoin miners have flocked to Texas to take advantage of ERCOT’s low energy prices and the state’s business-friendly environment. The miners rely on the energy to run the massive banks of computers that produce the cryptocurrency. The computers solve complicated math problems, which then get added to the open-source blockchain; the miner is awarded bitcoins.

The average financial exchange can use more than 1,700 kWh of electricity, which is almost twice the monthly amount used by the average American home.

Kinard said mining isn’t a technical term, but “something that kind of snuck into the vernacular over time.” He said a white paper’s author used an analogy to gold miners who “expend energy to mine the scarce gold resource.”

“The bitcoin miners have to expend energy to bring new bitcoin into circulation, which is also a scarce resource,” Kinard said.

ERCOT has welcomed the industry and its terms because wind energy’s penetration has created market volatility. The coincidence of negative prices and a $5,000/MWh cap creates opportunities and the need for flexible loads, Kinard said.

“As ERCOT has evolved over time, particularly with more and more wind, we see more volatility and regional differences of power,” he said. “A lot of miners are seeking out power at the lowest cost to generate these computations. As result of that sort of [wind] boom that you’ve seen in Texas … often on a windy day, the power prices there will be zero.”

How bitcoin mining works. (Texas Blockchain Council) Content.jpgTexas Blockchain Council

Kinard’s background is in oil and gas banking. It only took two years of due diligence for him to change his mind on cryptocurrency.

He went from “thinking bitcoin is a scam and ridiculous, as most traditional bankers and perhaps some of you in the room would understandably think,” he said, “and then 180-ing to really believing that this is a transformational opportunity for the industry and for the state of Texas.”

South Texas Transmission Project

Judith Talavera 2023-02-08 (RTO Insider LLC) FI.jpgAEP Texas CEO Judith Talavera address Texas RE’s Board of Directors. | © RTO Insider LLC

AEP Texas (NASDAQ:AEP) CEO Judith Talavera updated the board on the Lower Rio Grande Valley System Enhancement Project, a series of 345-kV lines and interconnections in South Texas, saying the project is expected to be in service by January 2027.

The Texas Public Utility Commission approved the $1.28 billion transmission project in September. It will add 351 miles of lines radiating from a new substation and another link into the Lower Rio Grande Valley. AEP, South Texas Electric Cooperative and Electric Transmission Texas are among those involved in the construction. (See Texas PUC Directs Tx Construction in Valley.)

The valley has long been a high-growth area in both population and industrial facilities, “as long as I can remember,” said Talavera, with 22 years at AEP. However, limited transmission capacity has trapped renewable resources’ output in the region and prevented additional energy from coming in.

“I don’t think I’m going to tell any of you in this room that we’re seeing a tremendous amount of change in our industry,” Talavera told the directors. “And with that change comes some risks, sometimes for a variety of reasons. …

“These projects will certainly help enhance the reliability and, most importantly, the resiliency of the system in that part of the state,” she said. “They’re also going to add more flexibility for how generation as assets can be dispatched or scheduled.”

Talavera said the project will also improve ERCOT’s ability to schedule transmission outages.

The project’s developers are currently conducting open houses and gathering feedback from landowners. They plan to file five certificates of convenience and necessity by September for various portions of the project, Talavera said. Construction is expected to begin late this year or early 2024, she said.

85 ‘System Events’ in 2022

Less than two years after collaborating on the joint NERC–FERC report on the deadly February 2021 winter storm, Texas RE staff will again engage with the organizations on a review of the December winter storm.

While the ERCOT region held together and met demand with plenty of supply to spare, it also saw fossil fuel outages exceed expectations and load forecasts underestimate projected loads. The grid operator sought federal permission to ignore air-quality limitations should it have to declare an energy emergency alert, a move that was never necessary. (See “DOE Grants ERCOT’s Emergency Request,” FERC, NERC Set Probe on Xmas Storm Blackouts.)

“We generally fared [well], but we are in the process of doing some follow-up on some of the things that occurred during [the storm], most notably with some concerns about how we can get our load forecasts analyzed or better … as well as, we had a number of units that had some issues,” said Mark Henry, Texas RE’s director of reliability services and registration.

He said staff “at least took a look” at 85 system events last year. Nearly half (41) involved loss of generation, while there were 16 physical security events. The most significant events were the December storm, the second Odessa disturbance in June, a loss of wind generation in the Panhandle in March, and a loss of generation and transmission in Texas City and its refineries and petrochemical-manufacturing facilities. (See NERC Repeats IBR Warnings After Second Odessa Event.)

Equipment failures accounted for 31% of the events analyzed, and weather was identified as the cause of 25%.

Texas RE added 27 registered entities during the year. The organization now has 310 such entities, the growth being driven by wind, solar and storage resources.

“They tend to want to be independent,” Henry said. “Each site wants to be registered as its own entity. That makes it hard on us.”

Regional Standards Process Approved

The board and Members Representative Committee both approved staff’s proposed Regional Standards Development Process (RSDP) document that will now be submitted to NERC for a 45-day public posting period. Assuming NERC’s approval, the document will then be filed with FERC.

The RSDP defines the open process for adoption, approval, revision, reaffirmation and retirement of Texas RE’s regional standard for ERCOT. The process also details how to obtain a Texas RE regional variance to a NERC reliability standard.

In other actions, the board approved nominations for several of its committees:

  • Suzanne Spaulding, Milton Lee, Curt Brockmann and alternate Jeff Corbett to the 2023-24 Hearing Body, a non-standing committee that only meets when a contested case hearing is requested;
  • Spaulding as chair, and Corbett, Brockmann, Daniela Hammons and Texas RE CEO Jim Albright to the Director Compensation Committee; and
  • Crystal Ashby, Corbett and Hammons to the Nominating Committee.
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FERC Grants Interconnection Waivers to 8 NY Renewable Projects

FERC on Thursday granted waivers to eight renewable generation projects, allowing them more time to have their interconnection studies approved by NYISO’s Operating Committee before entering the 2023 Class Year (CY23) study.

Current NYISO tariff procedures require projects participating in a class year study to have their system reliability impact study (SRIS) approved by the OC before entering the study, which begins Monday.

Invenergy, York Run, Boralex, Barrett Hempstead, ConnectGen, Gravel Road, Microgrid Networks and Thousand Island each asked the commission for its SRIS to have until the completion date of the Annual Transmission Baseline Assessment base cases for CY23 to be voted on by the OC (ER23-803, ER23-787, ER23-798, ER23-783, ER23-786, ER23-830, ER23-785, ER23-780).

The eight projects were unable to meet the Monday deadline. Their requests were supported by NYISO, other state agencies and the Alliance for Clean Energy New York (ACE NY).

The developers argued that they performed procedural due diligence, requested NYISO to expedite their SRISes and kept the ISO informed about their progress.

NYISO told FERC that study delays occurred from a variety of factors, including multiple revisions or material alterations. ACE NY and agencies including NYSERDA said further development delays could limit both health benefits to citizens and emissions reductions.

Each request also cited how FERC had granted similar waivers to the Clean Path New York transmission project.

FERC said it granted the waivers because the facility projects “acted in good faith,” made requests “limited in scope” that related to “a single timing requirement,” could experience significant delays in their development and because granting them would not have “undesirable effects” on other CY23 participants.

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Clements: States Should not Wait on FERC for Transmission Planning

WASHINGTON ― State energy offices have a key role to play in transmission planning, and they can and should take action even before FERC finalizes its rules on regional planning and cost allocation, Commissioner Allison Clements told a packed ballroom at the National Association of State Energy Officials’ (NASEO) Winter Policy Summit on Wednesday.

“There’s a feeling around Washington, perhaps, that FERC’s got this under control; we’re going through this transition,” Clements said, referring to the commission’s much-debated notice of proposed rulemaking on transmission planning issued last April. “FERC can cross every ‘t’ and dot every ‘i’ [for] the perfect transmission planning and cost allocation rule, but if the states [haven’t] bought in and if the rest of the pieces related to getting transmission done, from cost allocation to siting, aren’t considered together, we won’t get it done. …

“You have an opportunity to decide by being proactive in your state in these federal jurisdictional planning processes how you want this to play out,” she said.

State regulators and utilities are generally seen as having the primary power for transmission planning at the state level, but Clements and others at the conference argued that energy offices can act as hubs for bringing together public, private and community stakeholders, as well as fostering regional and cross-state collaborations. Such state-level efforts could include not only planning for new transmission, but also upgrading lines with grid-enhancing technologies (GETs).

“Transmission is the No. 1 solution to the reliability, costs and security of our system. That is the reality today,” Clements said. “The other reality is that money is going to be spent. … And the question is how are we going to direct that money? How can we make that money be spent well, so that customers 10 years from now, 15 years from now, 20 years from now are not left holding the bag on a system that is under-matched for the challenges at hand?”

The development of transmission for offshore wind is ripe for regional planning, Clements said, pointing to the efforts of five New England states to secure up to $250 million in federal funding from the Infrastructure Investment and Jobs Act. (See New England States Group up to Push for Federal Transmission Funding.)

“Current transmission system planning wasn’t designed to create a whole new grid, which is effectively what a regional offshore wind system is,” she said.

The first offshore wind projects now under development are being laid out with radial lines connecting them to onshore substations, which is “not the most cost-effective way to get significant capital transition investment done,” Clements said.

“If we start as a group of willing states, whether it be offshore or onshore in your region, and start talking about what a robust set of investments look like 10 years forward, you have the opportunity to not slow down the current procurements, which your states are very focused on, but to have a parallel track to be thinking forward about what you want that to look like,” she said.

Clements also encouraged state energy offices to actively promote the use of GETs — such as dynamic line ratings and advanced conductors — to increase the capacity of existing lines while saving millions for grid operators and customers.

Citing a 2021 report from the Brattle Group, for example, Clements said a combination of GETS could double the amount of renewable energy that could be interconnected on existing lines.

While some projects have been successfully completed, GETs are not being widely adopted, Clements said, first because of misaligned incentives. “Why would a transmission owner or a utility want to make an investment that would actually decrease its need to increase its rate base?” she said.

A bigger challenge, however, is the jurisdictional split between FERC and the states, and transmission and distribution, Clements said. “FERC usually focuses on the bigger transmission investments; states are usually focused on the distribution system,” she said. “We have to close that gap, and I think it is incumbent on all of us to talk to our regulators about the opportunity for grid-enhancing technologies; to ask our utilities about it; to put a little friendly pressure on; to say, ‘What are you doing on this?’”

Spurring Private Investment

Estimates vary of just how much new transmission the U.S. will need to achieve a carbon-free grid by 2035 and a net-zero economy by 2050. A much cited 2021 study from Princeton University called for a threefold increase in transmission capacity, while a recent study from the National Renewable Energy Laboratory said the amount of new transmission needed will depend on the generation mix, setting a range of 1.3 to 2.9 times current capacity.

Maria Robinson 2023-02-08 (RTO Insider LLC) FI.jpgMaria Robinson, DOE | © RTO Insider LLC

The IIJA includes $10.5 billion for a new Grid Resilience and Innovation Partnerships program, and Maria Robinson, director of the Department of Energy’s Grid Deployment Office, said the first round of funding for the program, totaling $3.8 billion, had drawn hundreds of concept papers.

“What excites me most about what’s going on here is that there are lots of really phenomenal ideas for rapid resilience … whether that is coming from utilities directly, or munis or co-ops, you have lots of terrific ideas on how they want to modernize,” Robinson said.

Echoing Clements, Robinson sees state energy offices as being able to extend the reach of federal funding to look “at how we continue to use this momentum to spur greater investments moving forward from the private sector as well … to ensure we’re getting the best bang for our buck.” Ongoing collaboration between DOE and state energy offices is an integral part of Robinson’s vision for “figuring out where the needs are.”

Robinson acknowledged some of the frustrations raised by the funding limitations, specifically that some of the IIJA funds for grid resilience cannot, at this time, be used to include generation from microgrid projects. “It’s just terrible,” she said. “We are working really hard to figure out if there are other places where we might be able to find that money” for microgrids to be included in grid resilience projects, she said.

Convening, Informing, Engaging

Karen Wayland, CEO of the GridWise Alliance, sees the blurring of lines between state and federal jurisdiction as a result of the higher profile states are taking in setting their own clean energy targets. As a result, she said, state energy offices need to be actively engaged with their governors, legislatures and grid operators.

According to the U.S. Energy Information Administration, 31 states and the District of Columbia have set renewable portfolio or clean energy standards. 

“We’re trying to design a system to meet state and federal goals, and so that means that the states have to be involved in the infrastructure that’s necessary to be that platform to meet their decarbonization and their security goals,” Wayland said in an interview with RTO Insider. “They have a really important role to play in convening the relevant stakeholders at the state and local level to kind of guide them to an understanding of the goals that that expanded transmission would address.”

State energy offices also “have a big role to play” in coordinating stakeholder discussions on high-voltage transmission lines being planned to connect nodes within their states, to help determine “whether and how and where a transmission line will be built.”

David Terry 2023-02-08 (RTO Insider LLC) FI.jpgDavid Terry, NASEO | © RTO Insider LLC

NASEO President David Terry sees state energy offices being able to take a broader view of energy market evolution than state regulators typically can because of the statutory limitations of their work.

State energy offices can “work with local communities on behalf of your governor, on behalf your legislature, to inform them of why the state is going in a certain direction with their energy activities,” Terry said. “Why a transmission line may be important; what’s the value to them … what’s the long-term benefit. For the average voter or consumer, this is not exactly top of mind.”

While “kind of soft and a little bit amorphous,” Terry said, the stakeholder engagement and public education roles of energy offices do have an impact on state-level decision making. They can “look across all of these new demand[-and-]supply issues … and they can take in some of those concerns that private sector industry has,” he said. “I think that informs the process. Nothing will make it easy, but it informs it so at least the best decisions can be made.”

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Counterflow: Holier Than Thou?

tesla powerwallSteve Huntoon | Steve Huntoon

The latest rage in green electricity procurement is hourly matching of carbon-free (green) supply with customer load.[1] The impetus is recognition that the standard practice of annual matching involves non-green generation to balance supply and load throughout the year. This seemingly simple “next frontier”[2] in procurement is anything but simple.

Some Background

By way of background, let’s recall that no consumer physically gets a given supply of electricity. The grid is akin to a giant swimming pool with thousands of hoses dumping water in (generation) and millions of hoses taking water out (consumers). The grid operator is charged with maintaining the water level (balancing). No one physically gets water from a specific water hose.

This is a crude analogy because, among other things, when it comes to electricity, no one gets anything physical at all (matter) — not even electrons, which don’t actually move.[3] Instead generators supply electric energy, and that’s what consumers use. With me so far?

So when a consumer buys green electricity, it’s basically getting a contract commitment of some form that X megawatt-hours of green electricity are generated by the seller, and the seller hasn’t sold these green attributes elsewhere.[4] 

With annual matching there is total annual green generation equal to total annual consumer load. But because of large differences between generation and load throughout the year, the grid operator has to procure and deliver other generation when that green consumer’s load exceeds the green generation. And when green generation exceeds the green consumer’s load, the excess is delivered to other consumers (or curtailed).

Now consider this situation with hourly matching instead of annual matching. Every green consumer has to pay the cost of covering its hourly load with green supply. Each hourly load has to be covered from some combination of green generation and storage. The extra green generation to cover peak hours will be under-utilized during other periods, and storage, especially long-duration storage, is hugely expensive, so the cost of this hourly matching is huge.[5]

Proponents of this “next frontier” of hourly matching vis-à-vis annual matching say that the former incents much more actual green generation because of the basic phenomenon described above. But there are multiple problems with this vision — as we shall see.

Hourly Matching Is an Irrational Way to Reduce Emissions

The incremental cost of hourly matching versus annual matching is many times greater than the incremental green generation from hourly matching versus annual matching. The modeling by the proponents of hourly matching shows this.

If you look at this emissions reduction chart for annual matching versus hourly matching, you’ll see that annual matching for the sample participation rate in California modeling yields 2.4 million tons/year, compared with 5.7 million tons/year for hourly matching, a ratio of 2.4 to 1.[6]

Annual matching in California (Jesse D Jenkins) Content.jpgJesse D. Jenkins

And now if you look at the cost premium chart for annual matching versus hourly matching, you’ll see that annual matching has a cost premium of $1.60/MWh, compared with a $19.90/MWh cost premium for hourly matching, a ratio of 12.4 to 1.[7]

Annual matching cost premium (Jesse D Jenkins) Content.jpgJesse D. Jenkins

So, instead of spending more for hourly matching, the green customer should use extra dollars for more annual green purchases.[8] The same dollar creates much more emissions reductions when spent on annual matching instead of hourly matching.

The Premises for Hourly Matching Are Wrong

Proponents of hourly matching presume that this consistently matches green generation with load. This is not the case for at least three reasons.

An hour is unpredictable, arbitrary and wrong. Proponents of hourly matching presume that within any given hour the green generation is matching the green consumer’s load. Of course a typical consumer’s load fluctuates widely; can a given consumer accurately forecast its load hour-by-hour and then communicate that to a generator such that the generator tracks that forecast with its output?

Wind power values (Pacific Northwest National Laboratory) Content.jpgWind power forecast and actual wind power values, for one day, in five-minute intervals | Pacific Northwest National Laboratory

And even where the consumer’s load tends to be flat (such as at a data center), green generation is not. This is illustrated by wind generation data for a typical balancing authority (region) for five-minute intervals.[9] You can see that wind generation varies greatly among 12 five-minute intervals comprising an hour.

If hourly matching is used, load will be matched to the average of the 12 five-minute intervals. During any given five-minute interval when load exceeds wind generation, other resources will be dispatched to cover the difference. And, similarly, when load is less than wind generation, the excess will be delivered to other consumers.

Just like annual matching!

Location, Location, Location

PJM Load-weighted Average LMP (Monitoring Analytics) FI.jpgPJM real-time load-weighted average LMP for 2021 | Monitoring Analytics

To further complicate matters there is the stumbling block of transmission constraints throughout the grid. In PJM for example, there are thousands of such constraints which, by definition, keep lower-cost energy from reaching load (aka “congestion”). This happens all the time all over PJM and is indicated by higher energy prices in constrained areas.[10] This map of varying energy prices in PJM illustrates the phenomenon.[11]

Now let’s consider a consumer inside a transmission-constrained area for a given hour. If the consumer’s green supply is on the other side of the constraint, then that green supply does not supply that consumer. Other generators, inside the transmission-constrained area, are being dispatched to supply that consumer (and other load within the constrained area).

The proponents of hourly matching say that generators and consumers will be grouped together by “the same electricity grid region,”[12] thus ignoring these transmission constraints.

Marginal Emissions

If things weren’t complicated enough, unless and until all non-green resources are eliminated from the grid, there is the nagging problem of marginal emissions. These come from the last (most expensive) resources dispatched to meet demand at any given point in time. And they typically would be fossil fuel resources because of their higher variable cost than green resources.

If we take a consumer that has an hourly matching supply arrangement, it can point to a matching green supply for its hourly load. But the sheer presence of its hourly load could cause the marginal resource to be fossil fuel instead of green. Now this consumer could argue that this is not the right “but for” test because without its load it wouldn’t be providing the green supply, and therefore the marginal fuel would be fossil fuel in any event.

But then again, once the green generation exists it would run regardless of whether it’s part of the supply committed to that consumer. So whether hourly matching always causes zero emissions (putting aside the arbitrary hour and transmission constraint issues discussed above) is somewhat of a metaphysical question.

Wrapping Up

Hourly matching is wasteful, and the premises for it are wrong. The climate challenge is tough enough without wasting money.

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.

[1] An entire conference was devoted to this and related subjects in December, http://www.raabassociates.org/main/roundtable.asp?sel=166. Only proponents — no skeptics — were on the panels. There is a federal executive order that requires 50% of federal electricity by 2030 to be “24/7 carbon pollution-free electricity,” https://www.whitehouse.gov/briefing-room/presidential-actions/2021/12/08/executive-order-on-catalyzing-clean-energy-industries-and-jobs-through-federal-sustainability/, section 102(i).

[3] “Energy is transmitted, not electrons. Energy transmission is accomplished through the propagation of an electromagnetic wave. The electrons merely oscillate in place, but the energy — the electromagnetic wave — moves at the speed of light. The energized electrons making the lightbulb in a house glow are not the same electrons that were induced to oscillate in the generator back at the power plant.” -Brief Amicus Curiae of Electrical Engineers, Energy Economists and Physicists, at 2, New York v. FERC, 535 U.S. 1 (2001), https://www.findlawimages.com/efile/supreme/briefs/00-568/00-568.mer.ami.engineers.pdf

[4] The green contract commitment can be in the form of Renewable Energy Certificates (RECs) or a power purchase agreement with a green generator. More here, https://www.ftc.gov/sites/default/files/attachments/press-releases/ftc-issues-revised-green-guides/greenguides.pdf, section 260.15.

[5] For example, RMI presents study data indicating that low hourly matching (0-10%) costs around $50/MWh while higher hourly matching (70-80%) costs more than $200/MWh — and that’s not close to full hourly matching. http://www.raabassociates.org/Articles/Final%20Dyson%20Presentation%2012.9.22.pdf, slide 10.

[6] Jenkins Presentation, slide 8, with annual matching and hourly matching under current technologies noted by arrows.

[7] Jenkins Presentation, slide 10, with annual matching and hourly matching under current technologies noted by arrows.

[8] This can be done by simply purchasing more RECs, or by over-procurement in a PPA with sale of the excess overload into the grid.

[10] For exhaustive detail on this phenomenon, please see the most recent State of the Market report here, https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2021/2021-som-pjm-sec11.pdf

[11] https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2021/2021-som-pjm-sec3.pdf, Figure 3-44 on page 174. A map showing zonal prices in real time is on the PJM home page.