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November 8, 2024

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PJM PC/TEAC Briefs: Oct. 5, 2021

Transmission Expansion Advisory Committee

NJ OSW Proposals

PJM received 79 proposals addressing both the onshore and offshore demands of New Jersey’s ambitious offshore wind program as part of the RTO’s “state agreement approach” under FERC Order 1000.

Aaron Berner, senior manager in PJM’s transmission planning department, presented the results of the competitive solicitation process at last week’s Transmission Expansion Advisory Committee meeting. The submission window was open from April 15 to Sept. 17.

Berner said proposals were received from both transmission owners and merchant developers and included 57 projects that featured cost commitment provisions to cap costs. He said through “multiple combinations” of different proposals, even more potential solutions are available beyond the initial 79 proposals.

Specific details of the proposals were not provided.

The four project categories included:

  • Option 1a: onshore upgrades on existing facilities, with 45 proposals submitted;
  • Option 1b: onshore new transmission connection facilities, with 22 proposals submitted;
  • Option 2: offshore new transmission connection facilities, with 26 proposals submitted, and;
  • Option 3: offshore network with eight proposals submitted.

“We’re characterizing this as a very robust response,” Berner said. “We have a number of different types of proposals that have been received for all of the options.”

Berner said PJM is “moving forward” to begin evaluating some of the issues around reinforcing networks and preparing reviews of the offshore elements of the proposals. He said PJM is collaborating with consultants with offshore wind expertise to “better evaluate” the projects.

Staff from PJM and the New Jersey Board of Public Utilities provided details last month to stakeholders during a special meeting of the Planning Committee, advising them on how the winning proposal would link to the new offshore wind projects New Jersey is soliciting. (See PJM, NJ Staff Brief Stakeholders on State Agreement Approach.)

NJ-OSW-Project-Solicitation-(PJM)-Alt-FI.jpgPJM gave an example of how proposals to New Jersey’s solicitation for offshore wind transmission projects may look. | PJM

 

The BPU has already awarded three offshore wind projects in two solicitations: the 1,100-MW Ocean Wind 1 and 1,148-MW Ocean Wind 2 projects, both developed by Ørsted, and the 1,510-MW Atlantic Shores project, a joint venture between EDF Renewables North America and Shell New Energies US. The BPU is planning to hold three more solicitations over the next five years to help the state reach its goal of supplying 7,500 MW of offshore wind by 2035. (See: NJ Awards Two Offshore Wind Projects.)

Berner said the BPU has issued a guidance document indicating certain processes to be employed going forward during the project evaluations. New Jersey retains the right to elect to move ahead with any of the projects and is targeting the end of 2022 to make final decisions.

Transource Update

Berner provided an update on the Independence Energy Connection (IEC) East and West transmission project in Maryland and Pennsylvania and its impact on the 2021 RTEP.

The Pennsylvania Public Utility Commission voted 4-0 in May to reject a series of related applications and petitions filed by Transource Energy for the siting and construction of high-voltage electric transmission lines in Franklin and York counties. The PUC denied the project based on concerns about whether the need established in the PJM planning process met the requirement for needs specific to Pennsylvania. (See Transource Tx Project Rejected by Pa. PUC.)

Transource’s plan for the eastern section of the project originally proposed extending 15.8 miles of transmission lines from a new Furnace Run substation in York County, Pa., to the Conastone substation in Harford County, Md. An updated configuration released in October 2019 increased the size of the new substation in Pennsylvania and added four miles of lines connecting to an existing right of way that would feed into two upgraded Baltimore Gas and Electric substations.

The western segment of the IEC project called for a 230-kV double circuit transmission line running 28.8 miles from Franklin County, Pa., into Washington County, Md.

Berner said PJM performed a sensitivity study to determine any reliability impacts associated with the removal of the IEC project from the RTEP. He said PJM found “a number” of thermal issues, but none of the issues needed immediate addressing.

“The magnitude of these violations is not significant at this point, so we’re not concerned about moving forward quickly with a reliability reinforcement,” Berner said.

The PJM Board of Managers endorsed the RTO’s recommendation to suspend the IEC project at its Sept. 22 meeting because of the “permitting risks” and to remove it from the pending RTEP models, Berner said. He said PJM has yet to do a benefit-to-cost ratio recalculation associated with the project.

PJM will begin to review any impacts to the interconnection queue following the determination of reinforcements for the baseline RTEP reliability, Berner said, and will include the update in future market efficiency studies.

Berner said PJM is not cancelling the IEC project at this time and will allow it to play out in the courts. Transource officially appealed the PUC decision in June, filing cases in the U.S. District Court for the Middle District of Pennsylvania and another in the Commonwealth Court of Pennsylvania. (See Transource Challenges Pa. PUC Decision in Court.)

“We’re going to let this continue to work its way through the various processes,” Berner said. “But we felt it was prudent to move forward with suspending the project.”

Planning Committee

Reserve Requirement Study Results Endorsed

Stakeholders at last week’s Planning Committee meeting unanimously endorsed an installed reserve margin (IRM) of 14.7%, up slightly from the 14.4% required in 2020.

Patricio Rocha Garrido of PJM’s resource adequacy department reviewed the 2021 reserve requirement study (RRS) results, which determine the RTO’s IRM and forecast pool requirement (FPR) for 2022/23 through 2024/25 and establish the initial IRM and FPR for 2025/26. The results are based on the 2021 capacity model, load model and capacity benefit of ties (CBOT).

2021-reserve-requirement-study-(PJM)-Content.jpgThe 2021 reserve requirement study (RRS) results versus the 2020 RRS results | PJM

 

Rocha Garrido said the results differed slightly from the numbers presented at the August PC meeting. (See “2021 IRM Results,” PJM PC/TEAC Briefs: Aug. 31, 2021.) In the process of reviewing the preliminary results, PJM discovered that some of the generating units were duplicated and had to be removed from the study, he said.

The calculated IRM moved from 14.64% to 14.66%, Rocha Garrido said, and the recommended IRM was bumped up from 14.6% to 14.7%. The recommended FPR also went from 1.0887 to 1.0894.

Adrien Ford of Old Dominion Electric Cooperative asked if the removal of the generators impacted previous years of the RRS or if it was just this year.

Rocha Garrido said the units were introduced erroneously this year, so the error only applied to the 2021 study.

He said the recommended FPR of 1.0894 was a modest increase from 1.0865 for 2020. The FPR is the most important parameter of the study because it is used in the reliability requirement calculation for Reliability Pricing Model auctions.

The 2021 capacity model is driving the increase in both the FPR and the IRM, Rocha Garrido said, with the average effective equivalent demand forced outage rate (EEFORd) of 5.8%, compared to 5.78% in the 2020 RRS. The higher average EEFORd was caused by the increase in the average unit size, going to 175 MW in the 2021 RRS compared to 159 MW in 2020 because of the removal of effective load-carrying capability (ELCC) resources from the model.

“Having more smaller units is better for reliability than having larger units,” Rocha Garrido said.

The CBOT — the help PJM can expect from imports during peak loads — is also estimated to increase pressure on the FPR and IRM. Rocha Garrido said imports from neighboring grid operators as a share of all generation decreased from 1.54% in 2020 to 1.47% in 2021.

A review and vote on FPR and IRM will take place at the November Members Committee meeting with final approval at the December PJM board meeting.

Manuals 14A and 14B Updates

Jonathan Kern of PJM’s transmission planning department provided an update to Manual 14A: New Services Request Process and Manual 14B: PJM Region Transmission Planning Updates reflecting proposed changes to the generator deliverability test and related procedures. Kern presented the initial draft of the proposed changes at the August 10 PC meeting. (See “Winter/Light-Load Generator Deliverability Update,” PJM PC/TEAC Briefs: Aug. 10, 2021.)

The purpose of the changes is to consider the “evolving resource mix” in PJM’s planning process, Kern said, and is relevant to the interconnection queue studies and the RTEP baseline studies.

Proposed-default-deliverability-requirements-(PJM)-Content.jpgThe proposed default deliverability requirements for wind and solar under PJM’s proposal for generator deliverability test modifications of light-load, summer and winter periods  | PJM

 

Kern said PJM intended to provide a first read of the manual updates at the PC meeting, but the RTO is still in the process of “fine-tuning the procedure to ensure repeatability” and that the results “make sense.” He said PJM is also examining the impacts to the interconnection queue.

Most of the analysis is expected to be completed by November, Kern said.

“Since there are a lot of changes, this extra time will allow stakeholders some time to digest the proposed changes,” he said. PJM has added proposed changes to the summer period to go along with the winter and light-load periods since the information was first presented in August to “harmonize” the three tests, Kern said. He added that the ramping limits for wind and solar were also refined for the three periods using ELCC studies.

Manual First Reads

Several manual updates resulting from cover-to-cover reviews received first reads:

  • Michael Herman of PJM’s transmission planning department provided a first read of Manual 14B: PJM Region Transmission Planning Process Update. Herman said one of the most significant changes came with the addition of a new section adding detail around the incorporation of end-of-life (EOL) needs in the RTEP, which were part of the tariff attachment M-3 discussions. In December, FERC rejected a stakeholder proposal to move EOL projects under the RTO’s planning authority, siding with transmission owners who argued that it would violate their rights. (See FERC Rejects PJM Stakeholder EOL Proposal.) The commission also accepted the TO sector’s own tariff amendments concerning EOL projects in August 2020, rejecting arguments in rehearing requests by more than a dozen load-side stakeholders. (See FERC Accepts PJM TOs’ End-of-life Revisions.)
  • John Reynolds of PJM’s resource adequacy planning department provided a first read of Manual 19: Load Forecasting and Analysis Update. Reynolds said the most significant change was adding battery storage to the list of forecasted items in the load forecast model overview in Section 3.1.
  • Joseph Hay of PJM’s infrastructure coordination department provided a first read of Manual 14F: Competitive Planning Process Update changes to the proposal fee structure to conform to the PJM Operating Agreement. Hay said the language in Manual 14F was not in agreement with the latest changes to the OA, which states, “All proposals in any RTEP window are subject to a non-refundable deposit of $5,000, except for project proposals submitted with cost estimates of $5 million or less. In addition to the $5,000 non-refundable deposit, the proposing entity must pay all actual costs incurred by PJM to evaluate the submitted project proposal.”

The committee will be asked to vote on the manual changes at next month’s meeting.

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PJM Operating Committee Briefs: Oct. 7, 2021

Synchronous Reserve Deployment Initiative

PJM stakeholders will vote next month at the Operating Committee on two different proposals seeking to improve the deployment of synchronized reserves during a spin event.

Ilyana Dropkin, an engineer in PJM’s performance compliance department, provided a summary of the initiative, developed in the Synchronized Reserve Deployment Task Force (SRDTF), at last week’s OC meeting. The task force was endorsed at the March OC meeting, and stakeholders received education around synchronized reserves and created a matrix to develop proposals. (See PJM OC Endorses Synchronized Reserve Discussion.)

Synchronized reserve events are emergency procedures triggered by PJM to maintain grid reliability in accordance with NERC’s Resource and Demand Balancing (BAL) standards. The RTO invokes those procedures under conditions such as the loss of multiple generating units at the same time or a sudden influx of load.

The task force examined ways to secure controlled deployment of synchronized reserves throughout emergency events by using tools like real-time security-constrained economic dispatch (RT SCED) to have consistent pricing and dispatch signals. The goal was to ensure BAL compliance during the recovery and maintain a reliable transition in and out of emergency events and to also define clear rules and expectations that address how PJM operators approve RT SCED cases around a synchronized reserve event.

Dropkin said the task force developed two different proposals: PJM’s intelligent reserve deployment (IRD) proposal, and a separate one by the Independent Market Monitor. In a nonbinding poll taken by stakeholders, PJM’s proposal received 75% support, while the IMM’s received 9% support. Sixteen percent of stakeholders preferred the status quo.

Michael Zhang, senior lead engineer in PJM’s markets coordination department, provided a first read of the PJM proposal. He said IRD is a SCED case that simulates the loss of the largest generation contingency on the system and for which the approval of the case will trigger a spin event.

The proposal calls for taking the megawatts of the largest generation contingency and adding them to the RTO forecast to simulate the unit loss, Zhang said. PJM would then be allowed to flip condensers and other inflexible synchronized resources cleared for reserves to energy megawatts and procure additional reserves to meet the next largest contingency.

Zhang said some of the significant changes over the status quo include updating the economic basepoints to replace all-call instructions and having active constraints controlled by IRD so that deployed resources don’t have negative impacts on the constraints.

Siva Josyula, Monitoring Analytics | © RTO Insider LLC

“IRD is an out-of-the-box solution,” Zhang said. “It’s fully optimized to deploy reserves and optimize economic solutions.”

Siva Josyula of Monitoring Analytics provided a first read of the IMM proposal. Josyula said the concept is to make sure reserves are deployed in proportion to the cause of the spin event and the resources that are deployed during a spin event are those that clear and are being compensated for providing synchronized reserves.

The proposal calls for using a reserve deployment tool that generates new dispatch signals, Josyula said. The total megawatts to deploy is equal to those lost or required for area control error recovery.

Manual 1 Changes Endorsed

Stakeholders unanimously endorsed manual changes to enshrine emergency protocols created in the wake of the onset of the COVID-19 pandemic at last week’s Operating Committee meeting.

Chris Moran, senior lead analyst with PJM’s NERC compliance team, reviewed the updates to Manual 1, Attachment F: Control Center and Data Exchange Requirements, which details how the RTO’s market operation control centers conduct remote operations in emergency situations. Moran first presented the manual changes at the September OC meeting. (See “Manual 01 Changes,” PJM Operating Committee Briefs: Sept. 10, 2021.)

The attachment was originally developed and implemented at the start of the pandemic to provide guidance for remote operations in case of control center staff illnesses. The temporary attachment, which took effect in April 2020, was set to expire Dec. 31.

As the pandemic progressed, Moran said, it became evident to PJM staff that the attachment needed to become a permanent part of the manual and to apply more broadly than just COVID-19. He said the language changes include replacing COVID-19 with “exceptional circumstances,” which PJM defines as “an event or effect that can be neither anticipated nor controlled, including, but not limited to, any act of a public enemy, war, insurrection, riot, fire, severe weather, natural disaster, flood, civil unrest, explosion, pandemic or other public health emergency.”

Moran said the RTO had made one change to the proposed definition after the September OC meeting, removing language that said an emergency was valid if “reasonably determined by PJM.” Moran said existing manual language puts the decision to implement remote operations “solely on the market operation centers.”

“The market operation centers are the ones who have to make the call whether or not they need to conduct remote operations,” Moran said. “This is a last-resort option.”

The attachment changes also include updating NERC contact information for PJM.

Adrien Ford of Old Dominion Electric Cooperative thanked PJM for bringing the issue forward to the committee and making changes to “appropriately focus that the [control centers] would be making the decision” on remote operations.

Winter Weekly Reserve Target Update

Patricio Rocha Garrido of PJM’s resource adequacy planning department reviewed the results of the 2021/22 winter weekly reserve target analysis, saying the numbers differed slightly from 2020/21. PJM’s estimated 2021/22 winter weekly reserve targets | PJM

The targets for December, January and February are 24%, 27% and 21% respectively, compared to 23%, 27% and 23% last year.

The December value is slightly higher because PJM is “seeing a little bit more load uncertainty” in the month, Rocha Garrido said, while February is seeing a “little less load uncertainty.”

Patricio Rocha Garrido, PJM | © RTO Insider LLC

Rocha Garrido said the targets are part of the reserve requirement study and help PJM staff to coordinate planned generator maintenance scheduling over the winter months. The objective is to “cover against uncertainties” related to load and forced outages by ensuring that the loss-of-load expectation (LOLE) for winter is “practically at zero,” he said.

The winter weekly reserve target for each month is the highest weekly reserve percentage, rounded up to the next integer value. Rocha Garrido said the targets are only recommendations to PJM’s Operations Department.

Rocha Garrido also presented the target numbers in a separate presentation at the Oct. 5 Planning Committee meeting. The OC and the PC will be asked to endorse the results at their November meetings.

Day-ahead Schedule Reserve (DASR)

David Kimmel, senior engineer in PJM’s Performance Compliance Department, reviewed preliminary proposed changes to the 2022 day-ahead scheduling reserve (DASR) requirement.

The DASR is the sum of the requirements for all zones within PJM and any additional reserves scheduled in response to a weather alert or other conservative operations. It is the sum of the three-year averages of both the under-forecasted load forecast error (LFE) and eDART forced outage rate component. PJM’s 2022 day-ahead scheduling reserve requirement (DASR) components | PJM

Kimmel said the final 2022 DASR requirement is 4.43%, slightly lower than the 2021 requirement of 4.78%. He said the number comes from the LFE component of 2.04%, which is down 0.14% from last year, and the forced outage component of 2.39%, down 0.21% from last year.

The value will be incorporated into Manual 13 changes and be effective through April 30, after which it will be replaced with the day-ahead secondary reserves. Kimmel said the change is dependent on FERC’s review and action on reserve price formation and PJM’s operating reserve demand curve (ORDC).

The OC will be asked to endorse the changes at its November meeting.

Manual Updates

Several manuals were reviewed in first reads as part of a periodic review:

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Stakeholder Soapbox: Transmission Planning Needs to be Improved — And We Already Know How to Do It

Johannes-P-Pfeifenberger-(The-Brattle-Group)-Content.jpgJohannes P. Pfeifenberger | The Brattle Group

Both reliability and clean energy related public policies are increasing the need for and benefits of large-scale regional and interregional transmission to avoid increased total electricity costs. Most studies of decarbonization find that a cost-effective end result requires at least a doubling of the delivery capacity of the U.S. transmission network.

Proven industry practices show that the industry already knows how to put together transmission plans based on co-optimizing generation and transmission to reliably and cost-effectively link anticipated future generation with anticipated future load. Any reasonable estimate of future generation reveals that each region will have a generation mix that is very different from today’s. But as FERC said in its recent Advanced Notice of Proposed Rulemaking, “transmission planning processes generally do not plan for the needs of anticipated future generation.”

In a new report, analysts from the Brattle Group and Grid Strategies offer some solutions that need to become standard practice, based on some proven examples of forward-looking, multi-benefit planning by some RTOs/ISOs and other grid planners in the U.S. and abroad. (See related story, New Tx Study Calls for Holistic Planning Across Regions.)

Rob-Gramlich-(Grid-Strategies)-Content.jpgRob Gramlich | Grid Strategies

The U.S. has been investing between $20 billion and $25 billion annually in improving the nation’s transmission grid. Over 90% of these investments are justified based on: (1) the local reliability criteria of transmission owners, including the replacement of the many aging transmission facilities built before the 1970s; (2) the local and regional reliability upgrades triggered by generation interconnection requests, which are now dominated by renewable generation and storage resources in many regions; and (3) the reliability criteria associated with regional planning processes conducted by grid operators. To date, only a small portion of transmission spending is justified on economic criteria and full analysis of broader regional and interregional benefits and costs.

The prevalent approach to transmission planning can be described as inefficiently reactive and incremental. It fails to take account of the large economies of scale and scope that exist in more holistic forward-looking plans. It fails to capture the co-benefits that exist in “reliability,” “economic,” and “public policy” based transmission facilities. Improved practices will significantly reduce electricity costs relative to status quo planning.

Costs associated with the prevalent planning approaches can be shown to be excessive when comparing studies under the current approach versus a holistic plan. For example, our report compares the results of a recent “regional” offshore wind analysis with the results of PJM’s generation interconnection studies. PJM’s study shows that the current generation interconnection study process (evaluating one interconnection cluster at a time) approximately doubles the transmission-related costs of integrating offshore wind generation compared to a more proactive, regional study process.

Improve Planning Processes

The planning processes can be improved by taking advantage of the last decade’s proven industry experience. MISO’s Multi-Value Project planning effort was a great example. It was proactive by incorporating anticipated future generation and load. It was multi-value, considering reliability, public policy, production costs and other benefits. It was scenario-based, finding a “least regrets” set of lines that were valuable under multiple potential future states. And it was portfolio-based, finding efficiencies and a less contentious cost allocation approach compared to considering projects individually.

MISO’s MVP plan is only one example. SPP’s Integrated Transmission Planning, numerous CAISO economic planning efforts, New York’s public policy transmission planning, and ERCOT’s CREZ and long-term system assessment approaches are all great examples of what can and should be done routinely.

These examples of successful, effective and proactive transmission planning demonstrate that we have proven and workable planning methodologies that can be employed. RTOs, their stakeholders and members, states, and FERC should see to it that these methods become the rule, not the exception. Thus far we do not have any good examples of joint interregional planning efforts that could lead to efficient interregional transmission infrastructure, but we’ll need to have that as well to achieve an efficient, reliable and resilient network.

The Planning Imperative

It will be critical to improve the existing processes for transmission planning and generation interconnection with proactive approaches that employ the above methodologies. Without such improved planning, we will not be able to build the more cost-effective, more flexible electricity grid necessary to meet reliability, economic and public policy needs at lower overall costs. In fact, without improved planning processes we may not even be able to bring online the clean-energy resources necessary to achieve the public policy mandates in place today.

Johannes P. Pfeifenberger, The Brattle Group’s practice leader for electricity wholesale markets and planning, is an economist with a background in electrical engineering and over 25 years of experience in electricity markets, regulation and finance.

Rob Gramlich is founder and president of Grid Strategies LLC, which provides economic policy analysis for clients on electric transmission and power markets in pursuit of low-cost decarbonization. He serves as executive director of Americans for a Clean Energy Grid and the WATT Coalition.

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Regulators Debate Competition in Entergy’s Texas Footprint

Texas regulators last week discussed the lack of competition in Entergy Texas’ (NYSE:ETR) footprint in the state’s southeastern portion, questioning whether the costs that previous commissions have allowed the utility to recover have benefited ratepayers.

At issue is a transmission-to-competition rider the Public Utility Commission approved in 2006, allowing Entergy to recover $14.5 million annually over a 15-year period for expenses incurred in 1999 through 2005, plus carrying costs, a figure that amounted to $207 million. The order was a result of 2005 legislation (House Bill 1567), which allowed an investor-owned utility to recoup spending more for capacity under power purchase agreements than were included in its last rate case (31544).

“It troubles me that ratepayers in the southeast spent [$200 million] on the transition to competition, and they have nothing to show for it,” Commissioner Jimmy Glotfelty said during the PUC’s open meeting Thursday.

The order stipulated three true-up periods every five years, with the last occurring this year. Entergy’s final true-up, approved by the PUC on Thursday, reflected a cumulative overcollection of $3.1 million (51806).

Entergy-Texas-Region-Map-(Entergy)-Content.jpgThe Entergy Texas footprint creeps close to Houston. | EntergyThe utility, then known as Entergy Gulf States, opted out of ERCOT’s competitive market, eventually joining MISO in 2013.

“It seems to me competition has been good for the rest of the state,” Glotfelty said. “If this moves us toward a competitive market in that area, I think that would be prudent. Stakeholders need to tell us is it’s time to move forward with competitive choices in the southeast region.”

Commissioner Will McAdams echoed Glotfelty’s comments, saying expanding competition into the southeast has been “heavily debated” within the state legislature, where he once worked. He also noted opinions over whether Entergy Texas should join ERCOT’s competitive market have gone back and forth.

The February winter storm “has made people evaluate that maybe [competition] is not such a good thing,” McAdams said. “If consumers and ratepayers want to see any type of competitive benefit in the future, we should provide them a venue at the PUC during the interludes between legislative sessions, where they can speak in front of their elected representatives.”

Commissioner Lori Cobos reminded her peers that one of the reasons Entergy joined MISO was that it wanted to “garner some of the benefits of being in an actual RTO or ISO.”

“As a commission, we should continue to review whether that is producing the benefits that were proffered to us as joining MISO. This merits a lot deeper consideration,” Cobos said.

After listening to the debate, PUC Chair Peter Lake offered his opinion on what Entergy’s customers can do.

“If they want to have that conversation, they should let us know,” he said.

ERCOT to Continue Conservative Ops

ERCOT staff told the commission that they will continue with their conservative operations approach through the winter and into next summer because of maintenance outages during the shoulder months.

After assuring the commission they would recall or deny thermal maintenance outages should unseasonably warm or cold weather create tight conditions, staff did just that on Friday, issuing an advanced action notice for Monday. The grid operator said it expects to withdraw or delay approved or accepted outages from 3 to 9 p.m. to scrounge up 94 MW of capacity to meet expected demand.

According to the notice, ERCOT expects wind and solar contributions to amount to about 6 GW from 6 to 7 p.m.

Dan Woodfin, senior director of system operations, told the PUC the amount of thermal capacity taken offline for maintenance outages has increased this fall to 18 GW, up from 10 GW a year ago.

Woodfin and Kenan Ögelman, vice president of commercial operations, also briefed the PUC on the recently completed summer season that they summarized as cooler than normal, wetter than normal, less windy than normal and conservative.


ERCOTs-ancillary-services-expenditures-(ERCOT)-Content.jpgWith the exception of August 2019, ERCOT’s ancillary services expenditures this summer exceeded the previous two. | ERCOT

Average daily temperatures were 1 to 2 degrees cooler than normal, without the widespread temperatures across the state that generally mark Texas summers. ERCOT did set new monthly peaks for June (70.2 GW) and September (72.2), but the summer peak of 73.5 GW on Aug. 31 was far short of the projected 77.2 GW.

Additional solar resources led to higher solar generation June through August, peaking at a record 7.04 GW on Aug. 31. Wind energy also set a new demand peak, hitting 23.6 GW on June 25.

Ögelman said prices were relatively low during the summer, with few spikes. ERCOT committed more resources through reliability unit commitments than it has in previous summers — for more than 2,000 effective hours, compared to about 200 in 2020 — and spent more than $50 million each month during the summer procuring non-spin reserves and other ancillary services.

ERCOT has drafted a nodal protocol revision request (NPRR) that will allow non-controllable load resources to participate in non-spin reserves, Ögelman said. The measure has cleared the Technical Advisory Committee and goes before the Board of Directors next. (See ERCOT Technical Advisory Committee Briefs: Sept. 29, 2021.)

“There’s no good reason not to allow load to participate,” Ögelman said when asked the reason for the change. “You want all the resources that can provide value to that space providing value to that space. Secondarily, this adds more liquidity to that market.”

When Ögelman told the commissioners the NPRR may not be implemented until the middle of next summer, Lake said softly, “We can work on that.”

PUC Clarifies Securitization Order

Staff have filed draft orders codifying the commission’s response to ERCOT’s requests for debt-obligation orders that would allow the grid operator to securitize $2.9 billion in market debt as a result of high charges incurred during February’s storm (52321, 52322). (See Texas PUC Finances Market Debt over Lt. Gov.’s Objections.)

The commissioners agreed that companies that opt-out of ERCOT’s proposal to finance $2.1 billion in debt would have to form a new entity if they want to start serving unaffiliated customers. Upon re-entering the market, the entities would be assessed uplift charges.

An NPRR wending its way through the ERCOT stakeholder process would strengthen the grid operator’s market-entry qualification and continued participation requirements. The commissioners decided to wait on the NPRR, rather than direct ERCOT to develop and implement it.

In another storm-related docket, the commission agave staff the go-ahead to publish a rulemaking for public comment that cuts the high systemwide offer cap (HCAP) from $9,000/MWh to $4,500/MWh. It will become effective Jan. 1 (52631).

The HCAP is currently set by rule at $2,000 after it was stuck at $9,000 for too many consecutive hours during the storm but was to revert back to $9,000 on Jan. 1. The cap was designed to incent generation to come online during tight conditions. (See “Offer Cap Could be Halved,” Texas PUC Directs Tx Construction in Valley.)

“By no means will this be the only action we take on the ERCOT market design structure,” Lake promised.

Status Reports for Valley Project

Following the PUC’s directive last month to three utilities that they add a second 345-kV circuit to an existing transmission line in the Rio Grande Valley, Cobos requested quarterly updates on the project (52682).

Cobos asked that effective Nov. 1, AEP Texas, Sharyland Utilities and South Texas Electric Cooperative file progress reports detailing tasks, time estimates, coordination with ERCOT, delays, and reliability and safety measures necessary to complete construction.

In other actions, the PUC:

  • rejected Entergy Texas’ application to acquire a proposed 100-MW solar facility in southeast Texas, agreeing with an administrative law judge that the utility did not prove the acquisition was a cost-effective way to provide consumer benefits when compared to alternatives (51215);
  • signed off on a unanimous settlement agreement between AEP Texas, staff and other parties under which the utility will refund $23.4 million to ratepayers for transition bonds issued by its AEP-Central Division (51484);
  • granted requests by Southwestern Public Service (52072) and Texas-New Mexico Power (52153) to adjust their energy-efficiency cost recovery factors for the 2022 program year by $6.3 million and $7.2 million, respectively; and
  • assessed a $56,000 administrative fee against AEP Texas for exceeding SAIDI and SAIFI standards by more than 5% during its 2019 reporting year (52034).
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MISO Market Subcommittee Briefs: Oct. 7, 2021

An emerging underfunding trend has led to some early concerns for MISO’s congestion-hedging market.

MISO says there’s a burgeoning mismatch between awarded auction revenue rights (ARRs) and actual congestion patterns in the footprint. As a result, load-serving entities hold a historically smaller share of financial transmission rights (FTRs) and the congestion value associated with ARRs is falling, the RTO said.

Staff’s John Harmon said during a Thursday Market Subcommittee teleconference that the trend began in December 2019.

The grid operator said while it won’t propose FTR market changes for the 2022-23 planning year, it said “substantial foundational rule changes” could be on the horizon to better line up ARR awards and congestion patterns. The RTO has hired an outside consultant to investigate its FTR-ARR auction structure.

ARRs and FTRs in MISO are issued based on transmission capacity and used by LSEs and other market participants as financial hedges against congestion charges in the day-ahead market. The grid operator funds FTRs through day-ahead congestion costs. An ARR is the LSE’s entitlement to a share of revenue from FTR auctions because of their historical use and investment in the transmission system.

MISO Independent Market Monitor David Patton observed that FTR obligations in 2020 exceeded congestion revenues by $74.6 million, a 4.1% shortfall.

MISO said increasing wind generation has reduced the volume of ARRs. Wind generation ARRs tend be about one-third of those associated with retiring baseload generation.

“Even though wind can produce up to 20 to 25% of energy, it has a smaller share of auction revenue rights,” Harmon said.

MISO said its FTR-ARR market was developed to “protect long-term rights with provisions for very limited, incremental portfolio change.”

Harmon said the recent move to lower generation shift factor cutoffs from 1.5% to 0.5% in the day-ahead market should better line up congestion with FTR rights. MISO will monitor the change’s effects before proposing any changes to its FTR market structure, he said. A lower generation shift factor allows staff to redispatch generators to improve transmission constraints.

Bill Booth, consultant to the Mississippi Public Service Commission, suggested MISO restrict participation in the FTR auctions to LSEs and those with long-term power contracts. WEC Energy Group’s Chris Plante has said it doesn’t seem fair that “a significant amount of day-ahead congestion revenue is allocated to entities that are not allocated any of the transmission system cost.”

Stakeholders have also recommended MISO revive its dormant FTR working group to examine potential changes to FTR and ARR mechanisms.

Harmon said MISO isn’t supportive of eliminating FTRs altogether, as some have suggested. “That would be a substantial overhaul of how we allocate congestion in our day-ahead market,” he said.

MISO Encourages Accurate Renewable Forecasts

MISO is proposing that its tariff contain direction on member-derived forecasts for dispatchable intermittent resources.

The RTO has said for months that its output forecasts for intermittent resources are consistently more accurate than those created by its members.

“As we get high wind and solar penetration, accuracy of forecasts is going to important for reliable operations and market efficiency,” Congcong Wang said of MISO’s day-ahead market and reliability commitment division.

The grid operator is proposing tariff language that members’ maximum forecast limits “reflect the most likely forecast outcome, and be directly derived from an accurate, and statistically unbiased forecast, using the most current forecast data available for the specific dispatch interval.”

The RTO also said that the forecast should be “directly derived” from a resource’s capabilities, actual generation data and weather predictions “relevant as of the time of submission.” It plans to file with FERC by December.

Staff will also periodically check its market participants’ forecasts to see if they continue to be less accurate than MISO’s. Wang said staff will reach out to market participants with chronically inaccurate forecasts before forcing them to use MISO’s forecasts. After that, a market participant can submit evidence to regain control of its forecasting.

More than 95% of MISO’s nearly 270 intermittent resources already use the grid operator’s renewable output forecasts. The RTO estimates that its footprint will contain more than 30 GW of wind and about 11 GW of solar in the next few years.

Some stakeholders have asked whether MISO couldn’t simply dictate that holdouts use MISO’s forecasts instead of making their own.

Wang said the language represents a “first big step” from the tariff being silent on forecast accuracy to prescribing careful forecasting. She said MISO doesn’t want to be too prescriptive in members’ forecasting.

Tx Customers Ask for Additional Load-forecasting Data

MISO transmission customers are asking for more insight into staff’s weekly load forecasts.

McNees Wallace and Nurick attorney Ken Stark, appearing on behalf of the Coalition of MISO Transmission Customers, said MISO is an outlier among RTOs because it doesn’t make its load forecasting data over the next week available to customers.

“MISO provides a day-ahead forecast by local balancing authority; however, that forecast is much less valuable than a current day plus six-day forward-looking forecast,” he said.

Stark said if large transmission customers had access to more specific load data, they might have been able to prepare and assist during Tuesday’s maximum generation alert and conservative operations declaration for the Midwest region. The event was unexpected because of mild weather and systemwide load of 72 GW.

He asked that customers have access to seven-day load forecasting data on the local balancing authority or local resource zone level. Stark also said MISO could make the data available to customers via a secure portal if the RTO is worried about revealing nonpublic data.

IMM: June 10 Emergency Unnecessary 

MISO’s Independent Market Monitor has concluded that the RTO did not need to escalate a maximum generation alert to a maximum emergency on June 10.

The brief emergency resulted in a surfeit of load-modifying resource (LMR) response and non-firm imports. (See “MISO Defends June Emergency Declaration,” MISO Market Subcommittee Briefs: July 8, 2021.) Ultimately, the event generated $2 million in day-ahead margin assistance payments to resources “that had to be held down to make room for the additional supply,” the IMM’s David Patton said.

“The combination of commitments, LMRs and higher imports led to a surplus in the Midwest exceeding 10 GW for most of the event,” he said.

Patton called for a more “surgical” method for deploying LMRs so that MISO is more precise in ordering curtailments. The grid operator has about 11.5 GW in LMRs participating as capacity, split 60-40 between demand response and behind-the-meter generation.

“We’re a unique RTO that … has 16, 17 GW import capability,” he said.  

Patton suggested MISO attempt modeling that contemplates non-firm imports when it is struggling and its neighbors aren’t.

He said suggested the grid operator delay making real-time commitments until control room operators are certain they’re necessary.

In this year’s State of the Market report, Patton asked the RTO to create an “uncertainty product” from fast-start resources to replace the expensive, out-of-market commitments that control room operators make. He said the system’s rising numbers of intermittent generators necessitates another class of energy reserves.

VoLL Pricing at Dead Buses Questioned 

The subcommittee meeting contained another disagreement over MISO’s policy of pricing dead buses at their $3,500/MWh value of lost load (VoLL).

Some stakeholders question how MISO can price dead buses at the VoLL when generators are unable to deliver power to customers.

Kevin Vannoy, MISO’s director of market design, said it’s an incorrect assumption that all dead buses can be traced to a catastrophic event. He said that sometimes, it’s as simple as a generator being offline.

“The value of energy is the value of energy whether it’s theoretical or possible,” Vannoy said.

“It’s a theory that cost $90 million,” Booth said, referencing VoLL pricing during Hurricane Laura.

The RTO originally said force majeure events that lead to dead buses should not be priced using VoLL. (See MISO to Outline New Pricing Plan for Hurricanes.) It said VoLL is appropriate to price capacity emergencies, even when they’re caused by force majeure, but that local and systemwide transmission emergencies should be shielded from the pricing.

“The procedures don’t speak to the cause of the emergency; they give us the tools to manage the emergency,” Vannoy told stakeholders during July’s subcommittee meeting.

Patton said February’s arctic event was a “garden variety” combination of transmission and capacity emergencies. He said it becomes difficult after emergencies to separate those caused by unavailable transmission or inadequate capacity.

“The distinction is really, I think, harmful,” Patton said in July.

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MISO Draws on Storage Model for DER Aggregations

MISO said last week it will pivot to its existing electric storage resource participation model in allowing distributed resource aggregations into its markets under FERC Order 2222.

The announcement scraps MISO’s original plan to use a modified version of dispatchable intermittent resource participation model for DER aggregations. (See MISO Assembling Order 2222 Compliance Plan.)

“We’re creating an entirely new model that largely leverages our [electric storage resource] model,” Market Design Adviser Michaela Flagg said during a Tuesday Distributed Energy Resources Task Force teleconference.

Under the new plan, all aggregations will be responsible for self-committing in the markets, instead of just those 1 MW in size or smaller. MISO will recommend that aggregators perform DER forecasting and reflect it in offers. The RTO also said it won’t dictate state-of-charge parameters, leaving those to aggregators.

The new DER aggregation model will use all eight of the operating modes in MISO’s electric storage model, with commitment statuses including:

  • injecting,
  • emergency injecting,
  • withdrawing,
  • emergency withdrawing,
  • continuous, or the ability to move between injecting and withdrawing,
  • available,
  • not participating or  
  • outage.

MISO expects the injecting, withdrawing and continuous modes will be most popular with aggregations.

The grid operator will likely require aggregators enrolling DERs to choose between demand response, distributed storage or distributed generation. Some stakeholders said having DERs declare just one registration type ignores DER’s other uses. One stakeholder likened it to a “choose-your-own adventure” book that disadvantages participating aggregators.

MISO’s response is that aggregators will be responsible for understanding DERs’ capabilities in their aggregations and should tailor the offers accordingly.

Kristin Swanson, the RTO’s DER program director, said it’s up to aggregation management to choose whether a DER will generate, inject or conserve energy. She said the market cannot currently choose between two separate bids from the same resource and the RTO’s real-time modeling cannot accommodate two resource types from a single resource.

“That’s not something we’re capable of doing right now,” Swenson said.

MISO won’t finalize a registration process until February.

Staff still plans to limit DER aggregations to a single pricing node they say will keep pricing simple and ensure that aggregations don’t aggravate transmission constraints.

Swenson has said Order 2222’s instruction that MISO cross the “distribution barrier is going to be a new experience.” She also called the 100-kW minimum size threshold “pretty tiny.”

“MISO’s not the only party that has to be ready in order for this to work,” she said during a Sept. 30 Reliability Subcommittee meeting.

Some stakeholders have asked MISO to keep cybersecurity at top of mind when designing communication modes with distribution operators.

Swenson has said she expects MISO’s first tariff filing, should FERC accept it, will require adjustments over time.

“We know we’re not going to have a perfect, comprehensive tariff filing in April, and we’ll never have to touch it again. We’re very aware that this is an emerging class of grid services,” she said.

Swenson also said MISO will maintain a “parking lot” list of DER ideas beyond Order 2222 compliance that it can’t currently accommodate because of current system limitations.

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MISO, SPP: Economics Secondary in Joint IC Planning

MISO and SPP said on Friday that a weak economic showing isn’t necessarily a dealbreaker in building transmission projects to accommodate generation from the RTOs’ overflowing interconnection queues.

Staffs told stakeholders Friday that their joint targeted interconnection queue (JTIQ) project has identified 11 projects in the upper Midwest that relieve most MISO-SPP constraints, but with a 0.33:1 combined benefit-to-cost ratio. The projects, tested with five other combinations of effective projects, are valued at $2.445 billion.

The grid operators also continue to consider a $424 million package that incorporates a long-distance, 345-kV line from Big Stone, S.D., to Alexandria, Minn.; a 345-kV line on the northeast side of Kansas City; and a transmission facility on the west side of Minneapolis. The multi-pronged project shows a combined 2.08:1 B/C ratio, but SPP experiences a negative 0.06:1 economic benefit ratio because of downstream impacts on other transmission lines.

If a project shows a negative B/C ratio to one RTO, it won’t automatically quash its chances of being approved, staff said.

MISO and SPP’s second round of evaluations tested 28 RTO-originated and stakeholder-submitted transmission solutions using their respective reliability and economic models. Eight solutions failed to relieve any transmission constraints, staff said.

The RTOs identified several projects crisscrossing South Dakota, Minnesota and Missouri during a first round of research under their joint targeted interconnection queue study. (See MISO, SPP Name Projects to Help Queue Troubles.)

Kelsey Allen, SPP’s lead engineer of transmission planning, said the JTIQ work began primarily as a reliability study, and the RTOs don’t intend to switch up projects now to chase higher adjusted production cost (APC) benefits.

The RTOs said they will have a final study report ready in December. Multiple stakeholders asked for an additional call to discuss project evaluation and selection before staff issues the final report.

MISO and SPP might use each footprint’s APC metric to determine cost allocation, increased transfer capability and real-time congestion reductions. The two could also assign some project costs to individual interconnecting generators based on avoided network upgrades.

SPP senior engineer Neil Robertson said the RTOs continue to collaborate on a final cost-allocation approach. He said it’s not easy to boil projects down to benefit dollars, so staffs may develop a rubric to divide costs that uses a scoring system for benefits like APC savings and new megawatts from the interconnection queues.

“I think anyone would want to see a simple benefit sheet in dollars,” he said. “You’re taking very different perspectives and traditional planning calculations and trying to compare them to one another. It’s apples to oranges.”

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Texas Senators Call for New RRC Weatherization Rules

Saying the Texas Railroad Commission’s (RRC) proposed weatherization rules for natural gas facilities don’t align with the state legislature’s intent, a Senate committee has sent a letter to the agency urging it to revise its rulemaking.

“It has become abundantly clear that failure to properly identify and weatherize critical natural gas infrastructure contributed to widespread power outages across the state,” the letter says. “The commission’s proposed rules contemplate designating all natural gas infrastructure assets as critical without regard to whether these assets directly support critical generation.”

During a Sept. 28 hearing before the Senate Business and Commerce Committee involving the RRC, which regulates the state’s oil and natural gas industries, the senators learned that under the commission’s proposed weatherization requirement, facilities can avoid the rule by not declaring themselves as critical infrastructure and paying a $150 opt-out fee. A Federal Reserve Bank of Dallas report said it can cost between $20,000 and $50,000 to weatherize new and existing wellheads. (See “State Senate Grills Gas Regulator,” Texas PUC Finances Market Debt over Lt. Gov.’s Objections.)

The letter, signed by all nine members of the committee, said rather than designate all facilities as critical, the RRC should start with gas-fired units and work backward through the supply chain to prioritize those elements “most directly essential to electric generation.”

“We sent this letter to the RRC to provide guidance as they proceed in their rulemaking process,” committee Chair Charles Schwertner (R) tweeted. “I will continue to hold these agencies accountable.”

Separately, Rep. Jon Rosenthal (D) filed a bill last week to close the loophole. “It is vital that we fix this oversight, so that Texans may finally have a reliable power grid,” Rosenthal tweeted.

The RRC on Thursday requested the state’s natural gas operators to “take all necessary action” to prepare for winter weather, according to the Houston Chronicle.

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New Tx Study Calls for Holistic Planning Across Regions

A new study on regional and interregional transmission planning pinpoints inefficiencies that hinder the integration of new renewable resources and recommends solutions to save the industry time and money and keep customer rates down.

The Brattle Group and Grid Strategies released their report Thursday ahead of this Tuesday’s deadline for submitting comments on FERC’s Advance Notice of Proposed Rulemaking (ANOPR) (RM21-17). The commission is looking at potential changes to improve electric regional transmission planning, cost allocation and generator interconnection processes.

The report finds systemic under-planning and under-investment in transmission. It recommends “incorporating realistic projections of the anticipated generation mix, public policy mandates, load levels and load profiles over the lifespan of the transmission investment,” rather than planning piecemeal on a case-by-case basis.

Transmission costs may grow as a percentage of total electricity costs but are still small relative to generation and present a more cost-effective solution that reduces systemwide costs and mitigates electricity rate increases, the report said.

“I think it’s hard to even say that we’re doing transmission planning, except for limited instances … like in the New York public policy work … and MISO MVPs [Multi-Value Projects],” Grid Strategies CEO Rob Gramlich told RTO Insider. “But just to comply with NERC regulations each year and make some upgrades here and there … is hard to call planning.”

Questions for the Future

The commission in its ANOPR gave several examples of questions it wants to address, starting with whether the existing regional planning processes appropriately consider the transmission needs of anticipated future generation, and whether reliability, economic considerations and public policy requirements are inappropriately siloed from one another.

“The geographic scope of regional and interregional RTO planning processes tends to be narrowly focused in its consideration of the transmission-related benefits’ geographic scope, typically quantifying only a subset of transmission-related economic and public policy benefits,” the planning report said.

FERC also posed the question of how to appropriately identify and allocate the costs of new transmission infrastructure in a manner that satisfies the commission’s cost-causation principle: that costs are allocated to beneficiaries in a manner that is at least roughly commensurate with estimated benefits.

Planners now consider only benefits that accrue to their own region without considering the broader set of interregional benefits, the report said.

“Projects near the regional boundaries, such as an upgrade to a shared flowgate, can address the needs of neighboring regions and need to be considered if the goal is to determine the infrastructure that most lowers cost,” the report said.

Without considering interregional needs, quantified benefits will be understated, and even “regional” projects near RTO seams could fail to meet applicable benefit-cost thresholds for regional market-efficiency and public policy needs simply because the planning process ignores the benefits that accrue on the other side of the seam, the report said.

A key driver of MISO’s MVP cost allocation process was state representatives requesting the RTO to evaluate cost-effective transmission solutions that could meet the region’s combined state-level renewable portfolio standards.

MISO-MVP-benefits-by-zone-(The-Brattle-Group)-Content.jpgMISO’s $6.6 billion worth of MVP projects approved in 2011 are now estimated to provide economic net benefits of $7.3 billion to $39 billion over the next 20 to 40 years. | The Brattle Group

“A high-level outlook of how states wish to pursue meeting their goals, or a more detailed set of scenarios, would greatly improve the ability of RTOs to plan their future system without having to develop a specific portfolio of resources to do so,” the report said. (See Tensions Boil over MISO South Attitudes on Long-range Transmission Planning.)

“The findings reinforce that there are many ways FERC can improve the current planning processes, particularly by ensuring that well known and previously tested transmission benefits are fully quantified,” said Barbara Tyran, director of the American Council on Renewable Energy’s Macro Grid Initiative, which supported the planning study.

New public policies and regulatory guidance is needed to implement improved planning processes that can achieve more efficient results, the report said.

FERC also asked whether and how to better coordinate between regional and local transmission planning processes to identify more efficient or cost-effective solutions; and whether it is necessary, and how, to more clearly identify the lines of regulatory authority and oversight between states and federal authorities.

Grid operators and planners need to be part of the policymaking process to ensure efficient and reliable integration of renewables, the Eastern Interconnection Planning Collaborative said in a white paper Wednesday. (See related story, Grid Operators Seek Policy Role, Reliability ‘Safety Valve’.)

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Oregon Group Contemplates RTO for a ‘Decarbonized World’

A Western RTO would likely take shape for reasons much different from those that motivated the creation of organized markets in other parts of the U.S.

That view was widely shared among members of Oregon’s RTO Advisory Committee last Wednesday, when it met for a second time to hammer out the contents of a study on the benefits and risks of RTO membership, due to the legislature by the end of the year.

During the committee’s first meeting in September, Adam Schultz, the Oregon Department of Energy’s Electricity and Markets Policy Group lead, promised that the second gathering would address a key question: What problem is the state attempting to solve by joining an RTO?

The answers for other organized markets usually centered on the anticipated cost savings to utilities — and their ratepayers — from the centralized dispatch of generation and regional transmission planning.

But the views expressed Wednesday pointed to a different factor driving the need for a Western RTO: namely, its potential role in decarbonization.

‘Feeling of Desperation’

What’s changed?

“I’d say it’s the conversation around our state’s mandates on procuring more clean energy, but also around the impacts and effects of climate change is having on our system,” said Nicole Hughes, executive director of advocacy group Renewable Northwest.

“Ten years ago, we weren’t seeing the radical climate [and] weather impacts; we weren’t dealing with the wildfire situation that we are today,” Hughes said. “So I think for some people involved in this conversation, there’s a feeling of desperation that if we aren’t doing everything that we could possibly do, to continue to live the lifestyles that we are hoping to live, then we’re not doing enough.”

For Renewable Northwest members, an RTO would be “one of the solutions” to decarbonizing the electricity sector, Hughes said.

Speaking from the virtual audience, Michael Jung, vice president of government affairs at generation and transmission cooperative PNGC Power, said his group’s members are committed to achieving carbon neutrality by 2033. Jung said PNGC’s membership of publicly owned utilities has in the past relied on the vast and “cheap” hydroelectric system managed by the Bonneville Power Administration to serve their customers “and never really had to think very hard about what to do to shape the future.”

But BPA’s “preference” customers confront a future in which the Federal Columbia River Power System will no longer be able to fully meet their needs. “The easy way out is no longer going to be an option,” Jung said.

“In the context of our carbon commitment, we really do believe that a Northwest RTO is going to be an essential ingredient towards giving us options that go beyond just the BPA preference power portfolio, and giving us a market that we can turn to to meet our needs, particularly in clean power, as well as facilitating the delivery across the transmission network, which may or may not be BPA[-operated],” he said.

Sarah Edmonds, director of transmission services at Portland General Electric, said an RTO is “unique” in offering the “integrated solution” needed to facilitate “deep decarbonization and clean energy integration” through better utilization of “resource solutions that don’t look like our traditional set of generation resources” on the grid.

“And when I say ‘integrated,’ I’m emphasizing the fact that the RTO brings all of the inputs and outputs from the market optimization part of the RTO, the transmission planning and the resource adequacy piece — potentially. And because those pieces are under one roof, they’re able to leverage each other, and the data that’s produced from these different functions and mechanisms can be integrated to provide that solution where all the pieces are coming together,” Edmonds said.

Mary Wiencke, vice president of market, regulation and transmission policy at PacifiCorp, cautioned that an RTO by itself will not reduce carbon emissions.

“I think the idea is to operate the system more effectively and enable that decarbonization to happen more efficiently, more cost effectively,” she said.

But Wiencke said any RTO dispatch model would need to consider state policies, such as California’s carbon pricing, a policy soon to be adopted by Washington state as well. “Those state policies will need to be reflected in the market rules in some fashion,” she said.

“I think one thing for you all to consider is that all seven RTOs/ISOs that have been formed were formed in a carbon environment. This is an opportunity for the region to consider what an RTO would look like in a decarbonized world,” said Ravi Aggarwal, a BPA manager and ex officio member of the RTO Advisory Committee.

‘Art of the Possible’

During the committee’s first meeting in September, it was Aggarwal who posed the idea that the Pacific Northwest consider an “incremental” approach to developing an RTO. (See Oregon RTO Committee Ponders Paths to Regionalization.) On Wednesday, he clarified that he wasn’t advocating for foregoing the pursuit of an RTO with the looser arrangements that exist in the region today.

But Aggarwal pointed out that the Northwest is unique in that it contains BPA, a non-FERC jurisdictional entity that controls about 70% of the region’s transmission and faces possible statutory limitations related to how it can participate in an RTO.

“If you look at the history, it took us about four years just to form a regional planning organization — Northern Grid — and that’s just one functionality of many that an RTO serves,” Aggarwal said, recounting other incremental developments such as the expansion of the Western Energy Imbalance Market (WEIM) (which BPA will joint next year) and the creation of the Western Resource Adequacy Program by the Northwest Power Pool. (See RA Program Will Require Restructuring of NWPP.)

“All those are incremental steps that move us probably closer to an RTO construct. It doesn’t take us directly to an RTO, but it builds a pathway to maybe eventually get to an RTO,” whether within an area like the NWPP footprint or West-wide, he said.

Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition, said his organization has supported the incremental steps the region has taken so far but thinks those efforts might be reaching the limits of their effectiveness.

“I think we’re going to get up to the edge of not being able to do much more, to evolve our grid to deal with emerging issues like the commitment of Washington and Oregon to 100% clean grids. We’re not to that edge yet; I think perhaps the [WEIM] day-ahead market possibly will be the edge of that functionality that can be bolted on to our existing grid without a more fundamental shift, which an RTO represents,” Gray said.

Wiencke said the need to decarbonize might outpace the timeline for creating an RTO.

“The conversation, I think, is really about urgency, and really about accelerating the decarbonization process, and I think there’s a lot of things that are needed to achieve that, including potentially an RTO,” Wiencke said. “However, I think there’s real tension there, because an RTO is going to take a long time to put together and to put in place, and I don’t know how to advise on sort of accelerating the development of an RTO.”

Oregon Public Utility Commissioner Letha Tawney pointed to other “constraints” beyond BPA’s jurisdictional status that have consigned the Northwest’s electricity sector to a policy of incrementalism — both rooted in California.

The first is CAISO’s state-run governance model, which Tawney believes California lawmakers would be willing to amend.

More intransigent though is the state’s resource adequacy model — overseen by the California Energy Commission rather than CAISO — which Tawney thinks the legislature is less likely to change.

“To incorporate [California] in the [RTO] dispatch, to take advantage of all the solar that they want to send out on a daily basis, and all of the investment they’re making in batteries, we will face a real challenge if we try to bring both the RA construct and a market construct together,” Tawney said. A governance change for RA program “isn’t even on the table right now.”

“There isn’t that sort of perfect RTO that we’re comparing to; we’re comparing to the art of the possible, given the existing landscape we’re operating in,” she said.