The NEPOOL Reliability Committee last week recommended that the Participants Committee support revisions to ISO-NE’s Planning Procedures 5-5 (PP5-5), 5-1 and 5-0.
The proposed changes to PP5-5 would align the RTO’s planning procedures with upcoming changes in NERC requirements and terminology, including the shift from special protection systems to remedial action schemes (RASes). It will also align PP5-5 requirements with NERC standard PRC-012-2, effective Jan. 1, 2021, which requires submittal of information on new and functionally modified RASes.
Each entity with an RAS will be required to submit a completed Attachment 1 for each of its existing schemes within six months of the changes’ effective date for ISO-NE to populate an RAS database. This information will help the RTO appropriately evaluate the impacts of RASes on the grid, as required by NERC and Northeast Power Coordinating Council.
ISO-NE also provided some responses to feedback received on the proposed revisions during last month’s RC meeting. The RTO clarified the definition of an automatic control scheme (ACS). ISO-NE said automatic under-frequency load shedding, out-of-step tripping and power swing blocking schemes are not considered ACSes, though automatic sectionalization schemes, such as restoring load tapped from a faulted line by re-energizing the non-faulted section, are.
The RTO also answered a question about how the requirements of PP5-5 will apply to RASes located on or affecting non-bulk electric system and non-pool transmission facilities. It said language will be added to clarify that section I.3.9 requirements and schemes located on sub-69-kV facilities that could have a significant adverse impact on the transmission system or a market participant are subject to I.3.9 approval but not NPCC/NERC review.
The proposed changes to PP5-0 and PP5-1 are minor but required to conform with those to PP5-5. The PC will vote on all the revisions at its next meeting Jan. 7.
Stein Re-elected
The committee re-elected Robert Stein, a consultant for H.Q. Energy Services and principal for Signal Hill Consulting Group, as vice chair.
Texas regulators will begin the new year with a discussion of pricing issues within ERCOT following complaints from participants saying they were improperly charged for point-to-point (PTP) obligations in the day-ahead market (DAM).
The Public Utility Commission agreed during its open meeting Dec. 17 to pick up the conversation during one of its two meetings in January.
“I’m not saying I’m opposed to repricing, but I’d like to hear reasons we do it in some cases and a defense of it,” Commissioner Arthur D’Andrea said. “I worry about the day when we’re talking about really big numbers.”
DC Energy Texas and Monterey TX, both qualified scheduling entities (QSEs), complained that their PTP obligations in the DAM were improperly priced in excess of their not-to-exceed bid prices following a market software error in September 2019. ERCOT’s board approved price corrections for eight operating days affected by the error, along with 13 others. (See Directors Approve Price Corrections for 21 Operating Days,” ERCOT Board of Directors Briefs: Dec. 10, 2019.)
Staff’s Darryl Tietjen addresses the commission. | Texas PUC
The QSEs said the resettled prices left them $269,283.22 and $86,647.98, respectively, out of pocket, and took their complaints through ERCOT’s alternative dispute resolution process. The ISO determined in April that it had not violated any protocols in handling the resettlements and denied their requests.
The companies then filed complaints with the PUC in May. An administrative law judge in October found ERCOT had violated protocols when it issued the resettlement statements and said the QSEs were entitled to “a remedy that places them back in the position they would have been in had they never been awarded PTP obligations at prices more than $0.01/MWh above their not-to-exceed bid prices” (50871).
“I have a lot of sympathy with what the [judge’s decision] says,” D’Andrea said. “These [P2P obligations] are hedging instruments. Putting a price not to exceed is part of risk management, but to blow those up doesn’t feel right to me.”
D’Andrea said ERCOT runs an “incredibly complicated system” but added that “the protocols read like an owner’s manual for the atomic bomb.”
“One thing I’m convinced on, like previous cases, is that the Protocols could be clearer,” PUC Chair DeAnn Walker said, suggesting a rulemaking could be in order. “If everyone says this is an issue, but everyone says we can’t agree on what the solution is … that’s what we’re here for.”
In October, ERCOT’s Board of Directors approved two more sets of price corrections covering 25 operating days. Unaffiliated director Peter Cramton called for a strong policy on price corrections, while staff has responded by creating a monitoring group to review system design changes before they go live. (See “Board Approves 2 Sets of Price Corrections,” ERCOT Board of Directors Briefs: Oct. 13, 2020.)
PUC Rejects Rulemaking Petition
The PUC rejected energy storage developer Broad Reach Power’s petition for a rulemaking to clarify commission rules on how a transmission service provider’s (TSP) transmission tariff applies to wholesale storage entities. Staff said its rule is “clear and unambiguous” in that a TSP’s “tariff shall not apply to any entity engaging in wholesale storage” (51501).
PUC Chair DeAnn Walker kicks off the commission’s final meeting of 2021. | Texas PUC
Broad Reach filed the petition in November after Texas-New Mexico Power (TNMP) filed wholesale tariff revisions for transmission service that the energy storage developer said assessed distribution service charges to wholesale storage entities. Broad Reach said the changes were “inconsistent” with commission rules and applicable legal standards. (See “Commission Threatens TNMP with ‘Comprehensive’ Rate Case,” Texas PUC Briefs: Nov. 19, 2020.)
Gleeson Named Executive Director
The commissioners approved COO Thomas Gleeson as their new executive director. He replaces John Paul Urban, whose resignation was announced Dec. 9.
Gleeson joined the PUC in 2008. He previously was a legislative analyst for the Texas Senate and a budget analyst for the Legislative Budget Board.
Legislative Report Finalized
The PUC approved its biennial report to Texas lawmakers, who will begin their 87th legislative session on Jan. 12. The report includes a recommendation that the Legislature clarify that electric vehicle charging stations are not an electric utility or a retail electric provider and that use of such stations is not a transaction governed by existing retail electric policies.
“These changes will provide regulatory rightsizing and consistency across the state, in areas inside and outside competition, to facilitate deployment and competition of electric vehicle charging stations for customers,” the report says in edits offered by D’Andrea.
$307,500 in Administrative Penalties
The PUC hit three companies with a total of $307,500 in administrative penalties. The commission:
docked retailers Direct Energy, First Choice Power and Bounce Energy $250,000 for various infractions that involved enrolling customers in postpaid service plans without obtaining written and signed letters of authorization; distributing inaccurate lists of authorized pay stations and improper customer disconnections. Direct Energy and First Choice Power are affiliates within the same brand family, which purchased Bounce Energy and acquired its customers following the violations (51277).
agreed with TNMP on a $50,000 penalty for violating staff’s system average interruption duration index (SAIDI) standard of 54.77700 minutes (5% over the threshold) for the 2019 reporting year (51395).
assessed Twin Eagle Resource Management, a QSE, $7,500 for incorrectly opting out of a reliability unit commitment instruction (51154).
The PUC also approved rate case filing deadline extensions for Cross Texas Transmission (51534) and Electric Transmission Texas (51583).
NEPOOL members got a look last week at what will ultimately underpin a new study to better understand the impact of New England’s ambitious greenhouse gas goals on the operation of the ISO-NE grid.
An expected dramatic reduction in New England GHGs by 2050 will recast the ISO-NE energy mix to include significantly more carbon-free resources, while electrification of the building and transportation sectors will drastically alter load volumes, peaks and profiles.
NEPOOL is embarking on a reliability study to better understand the implications of those changes as part of New England’s Future Grid Initiative. The study will examine whether current market revenues are sufficient to attract and retain the new and existing resources necessary to reliably operate the system. It will also identify operational and reliability challenges and outline possible ways to address them.
Peter Flynn, the consultant hired by NEPOOL and the New England States Committee on Electricity (NESCOE) to serve as administrator of the Future Grid project, presented the study’s stakeholder-developed framework document to the joint meeting of the Markets and Reliability committees on Thursday.
Flynn, former deputy general counsel for National Grid, said the study will eventually consist of several analyses using different computer models because “no single model can address the range of issues that NEPOOL stakeholders desire to assess.”
ISO-NE control room | ISO-NE
The analyses will be staggered, and the results from one will inform decisions about what to model in others. Close collaboration will be required between ISO-NE and any consultants retained by NEPOOL, according to the framework.
NEPOOL approved the objective and scope of the study, which will assess and discuss the future of the regional power system through the prism of state energy and environmental laws. The study’s scope is to define and evaluate the future grid by identifying the resource mix in the coming years and resource, operational and reliability needs.
Additional assumptions and scenarios are being developed through the stakeholder process at joint meetings of NEPOOL’s Markets and Reliability committees. A gap analysis will determine whether the existing markets are equipped to maintain system reliability and identify any deficits to be addressed to assure operations meet NERC, Northeast Power Coordinating Council (NPCC) and ISO-NE standards.
The study will feature economic analysis that includes production cost and ancillary services simulations, while a revenue sufficiency analysis will determine whether forecasted market revenues will be sufficient to attract and retain necessary resources.
An engineering analysis will include energy and ancillary services (EAS) simulations and a resource adequacy screen, while an availability and security analysis will answer questions about the conditions most likely to pose operational or reliability challenges.
EAS Market Simulations
The EAS market simulations will consist of nine matrix scenarios and 18 alternative scenarios.
The “Near Future Scenario” from National Grid assumes compliance with state requirements for 2035. The resource mix comprises approximately equal 8,000 MW amounts each of offshore wind, utility-scale PV and behind-the-meter PV, and 2000 MW of electric storage. It assumes about 16,000 GWh of building and transportation load.
Eversource’s “Distributed Pathway Scenario” is modeled to 2040 and represents a path toward reducing emissions consistent with an 80% economy-wide emissions reduction by 2050. The resource mix consists of approximately 12,000 MW of behind-the-meter PV solar, 9,000 MW of utility-scale PV, 8,000 MW of OSW and 4,000 MW of electric storage. It assumes 25,000 GWh of building and transportation load weighted toward transportation.
NESCOE’s “Offshore Pathway Scenario” is also modeled to 2040 and assumes carbon reduction that would put New England on course to comply with state law requirements by 2050. The resource mix consists of approximately 16,500 MW of OSW, 15,000 MW of utility-scale PV, 12,500 MW of rooftop PV and undetermined power amounts from electric storage and energy efficiency. It assumes approximately 76,000 GWh of building and transportation load, weighted equally, and load shapes consistent with such a high electrification level.
Next Steps
NEPOOL has asked stakeholders to provide feedback on these materials and assumptions on alternative scenarios by Dec. 31 to incorporate those comments and additional data in time for the RC/MC meeting on Jan. 19, 2021.
The committee expects study assumptions for the first phase of the report to be finalized by March 1. The final production cost simulation is scheduled for September 2021 to March 2022, and the ancillary services simulation from September 2021 to January 2022. MARS analyses will occur between October 2021 and January 2022. A final report is expected by May 2022.
For the second phase, dates have not been determined for the revenue sufficiency analysis and system security analyses, but they will not start before September 2021.
PJM stakeholders at last week’s Markets and Reliability Committee meeting heard a first read of manual language advanced regarding a stability limits capacity constraint proposal that some members are still challenging.
PJM and the Independent Market Monitor put forward the capacity constraint proposal, which was endorsed at the Market Implementation Committee meeting on Dec. 2 with 64% support. The proposal addresses the allocation of limits to multiple units by stating that the limit will apply to the sum of the output of the affected units plus ancillary service megawatts. (See “Stability Limits Review,” PJM MIC Briefs: Dec. 2, 2020.)
Joseph Ciabattoni, manager of interregional market operations for PJM, reviewed the proposed capacity constraint solution package and corresponding Operating Agreement and Tariff revisions. Ciabattoni said the units would be dispatched in economic merit order up to the stated stability limitation.
The package was the result of several months of discussion at the MIC on potential changes to how PJM curtails generating output to maintain stability during maintenance outages. Generating units are sometimes reduced below their normal economic max limit if a planned or unplanned transmission outage presents stability problems that could damage the units. (See “Stability Limits in Markets and Operations,” PJM MIC Briefs: May 13, 2020.)
Current rules require the RTO to implement a thermal surrogate to reflect the stability constraint in the day-ahead and real-time markets and to bind the constraint, affecting the unit’s dispatch.
If a unit chooses not to remedy a stability limitation identified during the planning process, its operating restrictions — as documented in its interconnection service agreement — would be invoked prior to those for other units, Ciabattoni said.
Lost opportunity cost (LOC) credits would not be paid for any reduction required to honor the stability limit. Similarly, LOC is not paid for economic megawatts of a resource that cannot produce because of a ramp limitation.
Paul Sotkiewicz of E-Cubed Policy Associates reviewed a proposed opportunity cost solution package. The proposal, presented by J-POWER and endorsed with 58% support at the December MIC meeting, was fundamentally the same as the PJM-Monitor package except for providing compensation for LOCs.
Sotkiewicz said if a generator is requested to take an outage when it can still run, the unit is in essence being asked to “misrepresent their true capabilities.” He said generation owners are very sensitive to the outage issue and that is why they’re seeking compensation for LOCs.
Carl Johnson of the PJM Public Power Coalition said he’s been “struggling” with how PJM can hold generators responsible when a contingency event is imposed. Johnson said he’s been ruminating on whether it’s never or always right to pay LOC.
Johnson said he’s also not certain that all contingencies can be identified at the time of generator interconnection because “the topology of the system changes.”
Consultant Roy Shanker said the stability limits issue seems more like a “contract matter” best dealt with when an interconnection agreement is signed.
“A better interconnection agreement would resolve all this going forward,” Shanker said.
Market Monitor Joseph Bowring said generators are “not held harmless” from all instances of being backed down because it’s not explicitly stated in the interconnection agreement. He said if there were no consequences in the agreement, the interconnection “would have cost a great deal more than it did.”
Bowring also noted that “there are no opportunity costs because the unit cannot run at a higher output and therefore there is no lost opportunity.”
Stakeholders endorsed PJM’s package of updates to RTV that call for additional penalties for generation operators that abuse the rules. The MIC endorsed the RTO’s package with 73% support, and it received 55% support over maintaining the status quo in a nonbinding poll. (See “Real-time Value Market Rules Endorsed,” PJM MIC Briefs: Nov. 5, 2020.)
The issue charge and problem statement, originally endorsed last December at the MRC, said observations indicated RTVs were being used to consistently override unit-specific parameter limits or parameter-limited exceptions. (See “Real-time Values,” PJM MRC Briefs: Dec. 19, 2019.)
Walter said the original intent of RTVs was to provide a way for generation operators to communicate current operating capability to PJM if their resources could not meet their unit-specific parameter limits or exceptions. Generators opting to use RTVs forfeit operating reserve credits and make-whole payments.
The PJM package requires that market participants repeatedly failing to reflect actual operating conditions in their submitted operating parameters could be referred to FERC for enforcement. A market participant would be required to enter a forced outage ticket into PJM’s Generator Availability Data System (eGADS) for the period of increased notification, start-up time and/or minimum downtime.
For the timeline of an RTV submittal, Walter said, the package would require that the requested period not exceed one market day. She said that when an RTV is requested, it would be available for that one day, then the entire schedule would revert to the previous day’s values.
The package also calls for adding RTVs to the Tariff. Currently, RTVs are mentioned only in the manual, Walter said.
Siva Josyula of Monitoring Analytics said the Monitor is concerned that the changes proposed in the PJM package undermine the parameter-limited scheduling (PLS) rules used in RTVs. The PLS rules are part of the capacity performance rules requiring units to operate to defined parameters, he said.
“The proposal we see essentially allows generators to circumvent the requirements without any justification during most of the days,” Josyula said.
Calpine’s David “Scarp” Scarpignato said RTVs are important to have in place because PJM needs to know what the units can and can’t do in real-time.
Scarp said it seems like the Monitor wants to penalize units that get paid for capacity that provide more flexibility compared to intermittent resources. He said the generators that are flexible are being held to a higher standard than other capacity resources that are less flexible.
Jeff Bastian, senior consultant of market operations for PJM, provided an informational update regarding the capital recovery factor (CRF) for avoidable project investment rate (APIR) determinations from a statement PJM issued to stakeholders on Dec. 7.
PJM’s statement came in response to the Monitor’s letter Dec. 4 saying CRF values used by PJM do not reflect current federal tax law. The CRF is used to calculate the APIR as a component of the net avoidable cost rate (ACR) of a resource.
Bastian said the net ACR of a given resource sets the market seller offer cap and the minimum offer price rule (MOPR) floor offer price depending on which is applicable. Attachment DD of the Tariff includes tables of CRF values for resources to calculate the market seller offer cap or the MOPR floor offer price.
The Monitor said in its letter that the tables should have been updated in 2018 and need to be updated before the next capacity market auction takes place early next year.
“Correct CRFs will ensure that offer caps and offer floors in the capacity market are correct,” the letter said. “The required changes are clear and unambiguous.”
Bastian said PJM is officially introducing the table update issue at the January Markets Implementation Committee meeting and addressing the issue in a “quick fix process” with a same-day vote.
“We understand the IMM’s concern, but we also appreciate the need for stakeholder input before making any changes to the Tariff,” he said.
Sotkiewicz said he can envision a scenario in which a market seller decides to take the issue to FERC because of the changes to the Tariff. He said a challenge could potentially delay the capacity auction, which stakeholders want to avoid.
He then suggested taking the table update issue away from the 2022/23 capacity auction so it could operate normally and not face any challenges.
“We’ve had enough delays to last a lifetime already,” Sotkiewicz said.
Bowring said he has opposed further delaying the capacity auction and wants it completed as quickly as possible. He said the issue remains that the tables need to be updated and PJM does not have the authority to take the issue “off the table.”
“Our view is the table should be changed quickly so there’s no confusion, no uncertainty and no risk of litigation,” Bowring said. “It’s the low-risk path forward, and I’m not sure why anyone would oppose that.”
Members endorsed the motion to defer the revisions for a month with a sector-weighted vote of 3.67 (73.4%). The revisions were originally unanimously endorsed at the November Planning Committee meeting. (See “Manual 14C Endorsed,” PJM PC/TEAC Briefs: Nov. 4, 2020.)
Mark Sims, PJM’s manager of infrastructure coordination, said the committee proposed minor changes to Manual 14C, including an update of the latest Tariff provisions clarifying the filing process for title transfers and associated title documentation in Section 5. New sections on cost-tracking for baseline projects and another for supplemental cost-tracking were also proposed.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, made the request to delay the endorsement by one month to work with PJM on some language suggestions. Poulos expressed concern about some of the proposed manual language.
Poulos specifically referenced sections 6.1.2 and 6.2.1 dealing with tracking of supplemental projects. Both sections say, “PJM may request additional information regarding projects.”
“I know that I ‘may request’ things a lot, and it doesn’t mean I’m going to get it,” Poulos said. “I don’t necessarily understand where that fits into a manual. It feels like it’s weakening the standard.”
Jason Barker of Exelon said he was “a bit troubled” by the issue being brought to the MRC. Barker said the discussion over the language would have been more appropriate when it was first brought up at the PC.
Manual 28 Revisions Endorsed
Stakeholders unanimously endorsed proposed revisions to Manual 28: Operating Agreement Accounting to comply with FERC directives and address the allocation of real-time and day-ahead uplift to up-to-congestion (UTC) transactions. The revisions were originally endorsed at the December MIC meeting. (See “UTC Uplift Changes,” PJM MIC Briefs: Dec. 2, 2020.)
In its order issued in July, FERC determined that PJM’s current uplift allocation rules are unjust because they do not allocate uplift to UTCs (EL14-37). (See FERC Orders Uplift Charges on PJM UTCs.)
The commission directed PJM to submit a replacement rate that revises the RTO’s rules to allocate uplift to UTCs “in a manner that treats a UTC, for uplift allocation purposes, as if the UTC were equivalent to a [decrement bid] at the sink point of the UTC.”
Pete Langbein of PJM reviewed a proposed solution package addressing the disposition of price-responsive demand (PRD) credits during a first read of the issue. Members unanimously approved an issue charge to address a disconnect in PJM’s settlement rules regarding payment for PRD at the July MIC meeting. (See “PRD Credits Disposition,” PJM MIC Briefs: July 8, 2020.)
PJM’s settlement rules call for revenues associated with PRD to be credited to the load-serving entity for an area and do not address the roles of electric distribution companies (EDCs) or curtailment service providers (CSPs), meaning some LSEs are paid for PRD service supplied by EDCs and CSPs. PRD providers represent retail customers that have the capability to reduce load in response to prices.
Langbein said PJM has an increasing share of load that is responsive to changing wholesale prices because of the implementation of dynamic and time-differentiated retail rates and utility investment in advanced metering infrastructure. Several EDCs cleared PRD as a capacity resource for the first time for the 2020/21 delivery year.
He presented revisions to Manual 11, Manual 18 and the Tariff. Stakeholders will vote on the revisions at the MRC meeting on Jan. 27.
Members Committee
Committee Elections
PJM stakeholders elected new members of the 2020/21 Finance Committee and the 2021 Sector Whips, with Erik Heinle of the D.C. Office of the People’s Counsel selected as the vice chair of the Members Committee.
The Finance Committee members elected include: Adrien Ford of Old Dominion Electric Cooperative (Electric Distributors); Poulos of the Consumer Advocates of the PJM States (End-Use Customers); George Kogut of the New York Power Authority (Other Suppliers); and Jim Benchek of FirstEnergy (Transmission Owners).
The sector whips elected include: Steve Lieberman of American Municipal Power (Electric Distributors); Susan Bruce of the PJM Industrial Customer Coalition (End-Use Customers); Michael Borgatti of Gabel Associates (Generation Owners); Brian Kauffman of Enel North America (Other Suppliers); and Sharon Midgley of Exelon (Transmission Owners).
Risk Management Committee Charter
Members unanimously endorsed the charter for the Risk Management Committee originally voted on at the MRC meeting in August.
Jennifer Tribulski, senior director of member services for PJM, presented the charter establishing the Risk Management Committee (RMC) as a new standing committee. Though stakeholders unanimously endorsed the charter, PJM later determined the charter needed the MC’s approval to establish a new standing committee. (See “Risk Management Committee Charter,” PJM MRC Briefs: Aug. 20, 2020.)
The Risk Management Committee is set to meet for the first time on Jan. 26, taking the place of the Credit Subcommittee by expanding its scope to incorporate risk and changing its reporting structure. Under the revised charter, the subcommittee will report to the MRC rather than the MIC.
In her presentation, Tribulski said the Credit Subcommittee last met in March 2019 with much of the work around the RTO’s credit and risk rules accomplished through the Financial Risk Management Senior Task Force in the wake of the GreenHat Energy default.
She said the task force was established for the specific purpose of overhauling PJM’s rules for managing the credit risks of market participants and was not tasked with reviewing credit and risk management issues outside of its limited purposes. (See PJM Members OK Tighter Credit Rules.) She said PJM felt it was important to have a committee available to review and work on issues beyond those contemplated by the task force.
Lieberman, assistant vice president of transmission and PJM affairs for American Municipal Power (AMP), finished his last meeting as chairman of the MC. Katie Guerry, the current MC vice chair and head of regulatory affairs for Enel North America, will serve as the MC chairwoman for 2021.
Lieberman thanked the PJM Board and stakeholders for helping guide him through a year that saw major changes in operations with the onset of the COVID-19 pandemic, forcing discussions into a virtual setting. He said he had some “personal disappointment” that he was unable to chair the meetings in person.
“I hope I was still able to serve you in this role in a successful and professional way,” Lieberman said.
PJM CEO Manu Asthana thanked Lieberman for his service as chairman of the MC. Asthana said in working with him he came to find his “incredibly generous spirit” and an “amazing knowledge of the industry.”
Asthana said Lieberman played an important role in helping PJM navigate a “very difficult year.”
“We have been lucky to have you in the chair at the Members Committee,” Asthana said. “I know you didn’t get to govern in the personal manner to which you’re accustomed, but I know you have found a way to adapt and to project your character and personality through these phone calls.”
Following the awarding of its second competitive project in four years, SPP has begun gathering stakeholder feedback as staff works to again improve its project selection processes under FERC Order 1000.
“We’re trying to mirror this process similar to what we did in 2016,” General Counsel Paul Suskie said during a webinar with stakeholders Friday.
Now, as in 2016, staff will gather member suggestions to improve its Order 1000 processes and other written comments, with a Dec. 29 deadline. The Markets and Operations Policy and Strategic Plan committees will coordinate the information before the January governance meetings, with a task force likely to be formed to present final recommendations to the Board of Directors.
SPP created a similar task force to improve its competitive transmission practices after its first Order 1000 project was canceled because of falling load projections. The task force’s chief recommendation was to allow re-study requests before issuing a notification to construct (NTC), which would have identified the change in load sooner. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)
“We knew we had to re-study, but [following the Tariff] we had to wait until the NTC was filed,” said Ben Bright, SPP manager of regulatory processes. He said the task force helped implement about half the 56 suggested stakeholder changes before it was disbanded in 2018.
The Sooner-Wekiwa project, running west of Tulsa | SPP
The board in October approved an industry expert panel’s (IEP) recommendation to grant SPP’s second competitive project, the 75-mile, 345-kV Sooner-Wekiwa project in Oklahoma to Transource Missouri, the panel’s “designated transmission owner. (See Transource Tapped for SPP’s 2nd Competitive Tx Project.)
SPP selects a five-person IEP, based on its expertise in engineering design, project management construction, operations, rate analysis and finance, to evaluate project proposals in those categories. Developer proposals submitted as detailed project proposals under SPP’s transmission owner selection process qualify for incentive points during the scoring.
Five entities — Transource, Xcel Energy Southwest Transmission (the Sooner project’s alternate builder), Liberty Utilities, LS Power-Southwest Transmission, and City Utilities of Springfield (Mo.) — have already submitted 18 proposals and staff added 13 more.
LS Power’s Pat Hayes suggested that the process of granting incentive points is “broken,” given the staff burden to evaluate proposals that number in the hundreds. He called for Tariff revisions requiring the IEP to justify its recommendation according to the projects’ efficacy and costs.
“The goal of the TSOP should be to deliver more efficient and cost-effective projects,” he said. “If it’s causing excessive costs and inefficiencies on SPP staff in the initial stage, we need to do something different. We think the easiest alternative is to scrap the incentive points altogether. There has to be some way to reduce the number of solutions and ideas.”
Bright said that after discussions with engineering support staff, SPP would “probably” recommend the removal of incentive points.
“If there’s a way to improve and provide value, we certainly want to have those conversations,” he said.
Bright said staff is also interested in revising the templates used in project submissions. He said the granular nature of confidential information resulted in a lack of transparency.
“The public version of the reports showed there wasn’t much there [behind the redactions],” he said. “It would be nice to differentiate publicly one proposal from another.”
LS Power and Xcel Energy both proposed changes to the intricate scoring matrix, which resulted in Transource winning the Sooner bid despite turning in the three most expensive proposals. They called for RFP respondents to be provided with details on how the IEP will evaluate and score their submissions.
Other suggested improvements included adding a resiliency metric and offering unsuccessful bidders an opportunity to meet with staff and review the strengths and weaknesses of their proposals.
Affected Systems Issues
Staff also visited with the Seams Steering Committee (SSC) and the Generation Interconnection Users Forum during their meetings last week to gather feedback on SPP’s affected system studies.
Staffer Jon Langford told the SSC that SPP is experiencing a “couple of core issues” in the affected system studies it uses to determine the effects of non-jurisdictional and neighboring interconnection requests on its transmission system. He said neighboring entities, transmission owners and customers have expressed concerns over the RTO’s interconnection queue priorities and the transmission services it studies.
Affected system studies are currently performed when needed and separately from SPP’s GI requests. They account for interconnection requests on neighboring grids, including MISO, Associated Electric Cooperative Inc. (AECI), Minnkota Power Cooperative and Northwestern Energy.
Langford said neighboring transmission providers and planning coordinators typically agree on a defined queue priority in their joint agreements. As an example, he said SPP’s priority practices with AECI are not documented.
“The big questions are those affecting our ability to respond to affected system study requests in a timely manner,” said SPP’s David Kelley, director of seams and Tariff services. “That’s creating disputes and consternation, if you will, from customers on both sides of the equation.”
The committee agreed to revisit the subject at its meeting Jan. 7. Staff hope to have a recommendation to bring before MOPC later in January.
SPP Faced with 3 Planning Studies
Any work on coordinated system studies with MISO and AECI will have to wait, staff told the SSC on Wednesday, as SPP is working on three different transmission planning assessments.
SPP’s planning staff is busy with three different transmission studies. | SPP
“Obviously, there’s a very full workload amongst all of the planning staff. It’s going to be crucial we don’t duplicate work,” SPP’s Neil Robertson said.
Staff are well into work on the 2021 and 2022 studies and the 20-year assessment. The long-term assessment is scheduled to be completed in 2022.
CAISO’s Board of Governors voted Thursday to keep a small, older natural gas plant operating to maintain reliability and received a briefing on initiatives to revamp the ISO’s resource adequacy construct.
Both were part of CAISO’s push to prevent energy emergencies next summer like those that struck the state in August and September.
In an unusual request, management asked the board to approve a reliability-must-run (RMR) designation for two units at the Midway Sunset Cogeneration facility, a 250-MW plant built in the late 1980s in a Kern County oilfield.
The units were scheduled to retire at the end of this year. A third unit was already mothballed, but CAISO said the two remaining units may be necessary to help keep the lights on in the world’s fifth largest economy.
The plant can contribute to meeting demand in summer heat waves in the net-peak hours, when California’s solar resources ramp down but demand remains high in the evening. Rolling blackouts in mid-August and close calls over Labor Day weekend occurred during net-peak times. (See CAISO CEO Defends Blackouts Response.)
The Midway Sunset Cogeneration plant sits in a Kern County oilfield.
“The Midway Sunset Cogen is required for the ISO to meet the 2021 systemwide reliability needs due to capacity insufficiency at the net-peak hour during the months July-September 2021,” Neil Millar, vice president of infrastructure and operations planning, wrote in a memo to the board. “Accordingly, the ISO cannot allow the resource to retire or mothball because, absent these units, it faces an inability to meet reliability criteria during these months.”
Stakeholders, including Pacific Gas and Electric, protested the lack of process in the decision and the rush to designate the plant as an RMR resource. Board Chair Angelina Galiteva acknowledged their concerns but said “reliability trumps” all other considerations with just days before the plant’s scheduled shutdown.
Stakeholder Initiatives
On a larger scale, CAISO is prioritizing stakeholder initiatives to promote resource adequacy in 2021 and 2022.
“This is important to ensure we are ready for next summer’s heat events,” Anna McKenna, interim head of market policy and performance, told the board.
Changes in the annual update to the ISO’s three-year policy initiatives roadmap focus on the urgent need to “comprehensively reform resource adequacy requirements” in connection with the shift from fossil fuels to renewables and tightening supply across the West.
They include a redesign of the ISO’s resource adequacy construct, Greg Cook, executive director of market and infrastructure policy, said in his presentation.
The efforts will try to ensure there is sufficient supply to serve net-peak load in heat waves and provide an adequate planning reserve margin, which CAISO wants the California Public Utilities Commission to increase from 15% to 20%.
A new workshop will try to make sure exports do not occur during times of tight supply, as occurred during the August blackouts. And the ISO is seeking to bring new storage resources online by the summer and ensure that imports are backed by specific out-of-state resources.
Many of the issues addressed in CAISO’s slate of initiatives were identified in a preliminary root-cause analysis of the summer blackouts sent to Gov. Gavin Newsom in October. (See CAISO Says Constrained Tx Contributed to Blackouts.)
Oregon should recognize the capacity contributions of all resources including variable renewables, according to a new report commissioned by the state Public Utilities Commission.
The report from consulting firm Energy and Environmental Economics (E3) counsels the PUC to adopt a plan based on methods already familiar to market participants in Eastern RTOs. These include use of demand curves to adjust capacity prices and measuring the marginal capacity contributions from renewable resources based on effective load-carrying capability (ELCC).
The E3 report seeks to answer a key question the PUC posed in April 2019 when it initiated an investigation (UM 2011) into a “comprehensive approach” to recognizing the capacity contributions of the various resources in utility integrated resource plans (IRPs): How should capacity be valued?
“The capacity provided by a resource to the electric system plays a central role in determining that resource’s overall value and therefore informs fair compensation to that resource,” the PUC wrote then. The growing penetration of variable energy resources “requires an examination at how capacity from various resources should be valued.”
The PUC said its existing programs have dealt with capacity valuation on a “piecemeal” basis, using different methodologies to account for capacity from utility-scale generation, distributed resources, energy efficiency, storage and demand response. At the same time, variable resources were short-changed by receiving “little to no credit” for their contributions to peak needs.
“A holistic investigation into these issues related to capacity could lead to a harmonization of some of these disparate approaches,” the PUC said.
The regulator pointed out that capacity valuation can play a role in the implementation of time-of-use rates or in evaluating programs such as demand response that can avoid or postpone investments in new resources.
“Other program benefit evaluations where capacity value needs to be considered include transportation, electrification and energy storage,” the PUC said.
Marching Down the Decarbonization Curve
“I think we’ve all seen across the West what can happen when capacity planning doesn’t quite go to plan,” E3 Director Zachary Ming said during a PUC-hosted video call Thursday to explain the capacity valuation report. “I’m really happy to be part of this proceeding that’s happening in Oregon to try to make sure the state gets ahead — and stays ahead — of the curve on this capacity issue that’s becoming more and more important with every year as we march down the decarbonization curve.”
Ming offered a primer on concepts that might be unfamiliar to Westerners not steeped in the organized capacity markets prevailing in the East.
The study’s authors asked two questions in their effort to identify a capacity compensation scheme: How much capacity in megawatts can any one resource provide? And for any megawatt of capacity, what is the value of that capacity to the system?
“Once you answer those questions, then you can set a dollar value,” Ming said. Any compensation framework should “appropriately measure” the quantity and value of the capacity a resource is providing, he said.
Ming said ELCC is the “gold standard” for measuring a resource’s contribution to maintaining the one-day-in-10-years loss of load probability (LOLP) principle typically recognized as the basis for gauging system reliability. ELCC allows for a comparison between different types of resources and measures the “perfect capacity” from each that would provide equivalent system reliability. For example, based on operating characteristics, a 100 MW solar plant and 50 MW gas-fired plant would each be capable of providing 50 MW of capacity.
Measuring the ELCC of a resource such as solar can become particularly tricky, Ming said. Under the concept of “antagonistic pairings,” resources with similar limitations reduce each other’s ability to provide capacity, something that occurs when more solar plants are added to an already solar-heavy system. In contrast, the “synergistic” pairing of resources with different characteristics, such as solar and storage, improve each other’s ability to provide capacity.
Regulators might have reasons for applying ELCC in different ways, Ming said. To assess overall system reliability, a “portfolio ELCC” approach can be used to capture the combined capabilities of all resources on the system. A “last-in ELCC” approach can capture the marginal ELCC of the next unit of a variable or energy-limited resource, an important tool when trying to understand how a newly procured resource will contribute to system capacity needs.
The industry widely uses simplified “approximation metrics” to reduce the complexity of estimating ELCC, Ming said. Among the most common is use of hourly LOLP to gauge ELCC. Historically, LOLP hours have been almost “exactly correlated” with peak load hours, he said.
“Resource availability wasn’t really an issue [in the past]. All resources — you could turn them on and off; you could run them for as long as you wanted. The only issue of not being able to meet load is if load got too high, which happened in peak hours or during extreme weather years,” Ming said.
Increased adoption of renewables, especially solar, means that LOLP has shifted into the evening hours when load is actually falling but the volume of energy produced is also declining with the setting sun.
“In today’s system, you see this most notably in California, although Oregon is headed in this direction, the loss of load probability hours have shifted [to] both later in the day and later in the summer,” Ming said.
He said the monetary value of capacity should be rooted in the principle of avoided cost. “A resource should be provided no more compensation than the least-cost resource that can be procured by the utility that provides equivalent reliability.”
To keep costs in check, the report proposes that Oregon policymakers adjust capacity prices based on a sloped demand curve “similar” to those used in organized capacity markets. That would enable the regulator to increase the value of capacity as the system moves from periods of resource sufficiency to deficiency. During times of sufficiency, the capacity value might reflect only operations and maintenance costs. In periods of deficiency, the value might rise to the net resource cost (similar to net cost of new entry), which reflects the total cost of building, integrating and operating a resource minus the revenue it earns from energy and ancillary services.
Different Strokes
Acknowledging the difficulty of creating a single capacity compensation framework for all resource types, E3 instead recommended two broad approaches.
Dispatchable resources such as gas-fired plants would earn payments based on a fixed annual value determined by its MW capacity credit multiplied by the $/MW-year value of the capacity. Resources paid under this “fixed payment” scheme would be subject to penalties for lack of performance during critical periods.
A “pay-as-you-go” scheme would compensate variable renewables based on performance during peak demand or capacity scarcity hours. The plan could be structured to either pay resources dynamically during only periods of system stress, or it could “send a consistent pre-determined price signal for all hours that have a higher” LOLP, E3 said. The plan would avoid subjecting variable resources to an “undue performance requirement,” Ming noted.
Because of their dispatchability, storage resources would fall under the fixed payment scheme, with compensation based on the product of the “last-in” ELCC and the monetary value of capacity.
“Performance would be measured by having the utility send a signal to the storage resource based on its capabilities. If it responds, it won’t be assessed penalties,” Ming said. Using pay-as-you-go to compensate storage could be “potentially discriminatory” because it could require the resource to cycle every day to receive payment. It also avoids compensating a storage resource when it’s not actually needed for capacity.
Like storage, demand response resources would receive fixed annual payments. Because DR has more limitations than storage, performance requirements would be based on a resource’s “inherent capabilities, identical to what is used in its ELCC calculation.”
For hybrid resources, E3 proposed a “bifurcated” scheme in which the renewable portion of the resource would be compensated under pay-as-you-go while the storage portion receives a fixed payment. “We do not think that a fixed payment only is appropriate for hybrids for the same reason it’s not for renewables,” Ming said.
‘Deliberately Provocative’
Fred Heutte, senior policy associate with the Northwest Energy Coalition, asked what E3 meant by “dispatchable” resources. Heutte noted that E3 had performed a study for Tampa Electric showing that solar can be dispatchable in providing incremental and decremental energy, providing load-following capability.
“It’s not something commonly done right now, but it’s certainly possible. Is that what you mean by dispatchable or is there something else?” Heutte asked.
“I think for the purposes of providing non-capacity services to the system, dispatching solar can be useful, like providing ancillary services,” Ming responded. “From a capacity perspective, I don’t know that I’d consider solar dispatchable, but it’s a term of art; there’s a gray line, of course.”
Dispatchability is really a function of how a capacity resource responds within its compensation framework, Ming continued. Solar will provide as much energy as it can when it’s producing to meet capacity needs.
“Storage is going to provide energy when [the grid operator] sends a signal to dispatch, and to that extent the compensation framework impacts how storage is dispatched. The compensation framework does not impact how solar is dispatched,” Ming said.
Representing the Oregon Solar Energy Industries Association, Patrick McGuire asked how E3 saw the “last-in” ELCC being updated over time. “If it’s put into a contract, does it have to be leveled?”
“We would expect both the last-in ELCC and the table of loss of load probability hours is going to be different in each future year, and they’re going to be changing as the resource mix and the loads on the system change,” Ming said. “In particular, we would expect the last-in ELCC of solar to decline over time.”
Commissioner Letha Tawney asked whether the PUC should be concerned about whether LOLP data is sufficiently accounting for climate change.
“The West-wide heat storm this August was relatively unusual in the historical data, but over the multi-decadal timeframe of these contracts, [it] may not be such an outlier,” Tawney said.
“The answer to that question is quite simply an emphatic ‘yes,’” Ming said. “You do need to account for a changing climate. That is easier said than done. There are firms and researchers that are looking at how to do that. I would say the standard practice in the industry probably doesn’t do as good of a job accounting for climate as it should.”
Heutte posed a “deliberately provocative” question about the risks of introducing concepts from organized markets into Oregon’s IRP process, such as net cost of new entry (CONE) and sloped demand curves. He said for the past two decades he’s read prominent economists who claim capacity markets are the way forward for the electricity sector, but that recent talk from states such as Illinois, Maryland and New Jersey about pulling out of PJM’s capacity construct calls into question the concepts underpinning those markets.
“I’m wondering what can we learn from that. … How can we be assured going forward that those kinds of design elements will actually produce the kind of results we’re looking for?
Ming said E3 explicitly avoided using the term net CONE and instead used net resource cost, which is fundamental to ratemaking.
“Trying to isolate the portion of the resource that’s attributable to capacity and attributable to energy is something that’s done in ratemaking in every regulated jurisdiction across the country,” Ming said.
He said the reason states are looking to pull out of PJM is unrelated to the way the market sets net CONE or the demand curve.
“It’s related to the inability of renewables to bid into the capacity market. They’re forced to bid in prices that are higher than the clearing price and, ultimately, they don’t clear the market and they don’t get paid anything for capacity. So that minimum offer price rule implemented by FERC this year, that is what is driving the states to exit the capacity market,” he said.
Western utilities and their state regulators should increase their coordination and adopt dynamic planning reserve margins to help ensure the region’s grid is equipped with adequate resources as it takes on more variable generation, according to a new WECC report.
WECC’s report divided the Western Interconnection into five subregions based on load patterns and topology. | WECC
The recommendations come out of WECC’s first Western Assessment of Resource Adequacy Report, released last week. The report, the regional entity’s signature work for 2020, is the product of an internal effort to repurpose its mission by focusing on the growing challenges of resource adequacy in the Western Interconnection. (See WECC Seeks to ‘Invent’ Future with RA Forum.)
“We are really excited about this work,” Branden Sudduth, WECC vice president of reliability planning and performance analysis, said when staff provided a preview of the study at a meeting of the organization’s Board of Directors on Dec. 9.
The report is intended to supplement NERC’s 2020 Long-Term Reliability Assessment, published Dec. 15. (See NERC: Grid Operations ‘Fundamentally’ Changing.) Some Western stakeholders have complained that last year’s assessment failed to capture the risks that emerged this summer when a record-setting heat wave forced CAISO to initiate rolling blackouts for the first time in two decades while other balancing authorities prepared to take similar measures.
Both WECC and a joint root-cause analysis by California agencies have cited supply shortages as a key factor behind the energy emergencies, although WECC’s effort to address regional RA preceded the heat wave event. (See WECC Says Extreme Events Require Forecast, RA Changes.)
To account for the local and topological factors that contribute to interconnection-wide RA issues, the study divides the Western Interconnection into five subregions that align with the region’s three reserve sharing groups: CAISO, Southwest Reserve Sharing Group (SRSG) and Northwest Power Pool (NWPP).
Because of variations in peak seasons, the NWPP subregion is further divided into Northwest, Northeast and Central subsections. The report refers to CAISO as California-Mexico (CAMX) and the SRSG as the Desert Southwest (DSW).
Scenarios and Variations
WECC’s assessment applied two scenarios to each of the five subregions “to highlight a broad range of future resource possibilities, including known and expected resource retirements.” Scenario 1 assumes each subregion is required to meet its own demand, while Scenario 2 allows for imports.
The RE overlaid each scenario with three variations of resource availability. Variation 1 includes all resources currently in service and expected to run in future forecasts. Variation 2 includes existing resources and those under construction and expected to run in the forecast year (Tier 1 resources). Variation 3 includes existing and Tier 1 resources as well as those currently in licensing or siting phases but not yet under construction (Tier 2).
The reports points out that RA planning has typically relied on a “deterministic” — or static — approach that calculates needs by comparing the amount of available generation capacity, plus a planning reserve margin, to the highest demand of the year. If those resources cover the peak day, they are assumed to be sufficient for all other days of the year.
That planning approach is fraying at the edges with the increased adoption of variable renewables, prompting WECC to adopt a “probabilistic” approach that examines resource needs on an hourly basis over the next 10 years using supply and demand projections provided by Western balancing authorities. WECC ran the data through its Multi-Area Variable Resource Integration Convolution modeling tool, which matches generation to load for each hourly interval to determine if there is enough capacity to meet demand and to calculate a planning reserve margin.
This figure illustrates how WECC’s assessment examined subregional RA through two scenarios overlaid with three variations of RA variability. | WECC
“The model determines whether there are enough resources in the interconnection to meet expected demand while maintaining reserves to account for any variations from the expected forecasts or loss of generation. The results from this analysis are used to determine where resource shortfalls may occur in the system over any given study period,” the report said.
WECC’s analysis found that under Scenario 1, all subregions show some risk of loss of load, even with Tier 1 and 2 resources. All variations of that scenario contain hours with insufficient resources to serve load and maintain planning reserve margins.
The RE also found that most hours of unserved load can be solved under Scenario 2.
Still, the report notes that “under the most optimistic assumptions about future loads, resources and imports, there are still hours in which the interconnection does not meet” the one-day-in-10-years (ODITY) threshold for the 10 years studied. The DSW, NWPP Central and Southern California portion of CAMX were particularly vulnerable to loss of load, WECC found.
In what might be the most pressing finding, the analysis showed that even under the most optimistic assumptions under Variation 3 of Scenario 2, 2021 could see one to eight hours in which some subregions fail to meet the required planning reserve margins of the ODITY standard.
“The results worsen as the assumptions about resource construction and reliance on imports span to the more realistic, less optimistic end of the spectrum,” WECC said.
WECC also found that increased volumes of variable resources on the system compound the RA issues, making resource planning more challenging because more resources are not consistently available to meet demand. Additionally, demand is also becoming increasingly variable because of climate change, behind-the-meter generation and transportation electrification.
The report’s final finding: RA will suffer “significant degradation” if historical approaches to resource planning are left unchanged.
Getting There
WECC’s first recommendation is for resource planners and regulators to transition away from fixed planning reserve margins to dynamic margins aligned with hourly needs.
The second recommendation is for planning entities to not only consider how much additional capacity is needed to mitigate variability but also the expected availability of new resources. “Understanding the differences in resource type availability is crucial to performing resource adequacy studies,” WECC said.
The report’s final recommendation encourages balancing authorities to coordinate their planning activities each year to help prevent them from relying on the same resources. “This coordination will help subregions make assumptions about import availability in the context of the entire interconnection,” WECC said.
“I think we got the train on the track now and can understand how to manage this resource adequacy issue,” WECC Director Gary Leidich said during the Dec. 9 board meeting. “This information has to get in the hands of policymakers so they understand what’s going on.”
Director Richard Woodward said he liked the idea of a dynamic reserve margin but asked, “How do we get there?”
Matt Elkins, WECC manager of performance analysis, said he wants the RE to meet with planning entities to explain the range of resources they will need to meet reliability requirements. “We have to do it together.”
WECC’s Sudduth added that he was encouraged to see multiple states already working together to address RA issues.
Director James Avery said it will be necessary for every state in the West to count RA in the same way. “Otherwise, the work we do is going to be meaningless.”
WECC said it will release a more detailed analysis of subregional RA issues in the first quarter of 2021.
FERC last week authorized the installation of a new general partner and transfer of ownership interests in the privately held Infrastructure Investments Fund (IIF) that acquired El Paso Electric (EPE) earlier this year. (See IIF Closes El Paso Electric Purchase.)
The commission on Thursday accepted a request by IIF US Holding and IIF US Holding 2 (master partnerships operating under the IIF umbrella name) to transfer one individual’s 33.3% general partnership interest in the entities to Anne Cleary, another private individual (EC20-94).
In addition to EPE, IIF US Holding owns a string of public utilities authorized to sell wholesale electric energy, capacity and ancillary services at market-based rates.
| El Paso Electric
The commission said it found no evidence that the transaction would have an adverse effect on horizontal competition, rates or federal or state regulation, nor would it produce vertical market power concerns or result in the cross-subsidization of a non-utility associate company by a utility company.
IIF said that save for EPE’s transmission facilities and the “limited and discrete interconnection facilities associated with individual generation facilities,” it doesn’t operate or control any transmission in the U.S. FERC said IIF’s generation will continue to operate under existing market-based rate tariffs or cost-based rate schedules.
Public Citizen protested the transfer, criticizing Cleary’s installation and noting that she was president of a power company (Mirant California) that declared bankruptcy and was charged with market manipulation and other illegal conduct during California’s electricity deregulation crisis in 2000-2001.
The consumer advocacy group argued that IIF failed to represent all of Cleary’s energy-related affiliations as a former advisor of project managing service company Taffrail Group, a former principal with Modern Grid Solutions, and her link to a member of PJM’s Board of Managers through her board position with the Bermuda-based Ascendant utility. The group also argued that Cleary already serves on the board of directors at IIF subsidiary Southwest Generation Operating Co.
Public Citizen said IIF is a “lightly regulated, off-the-books series of private equity shell companies.” It said the three owners don’t function as owners but as a board of directors that simply delegates the day-to-day management of IIF to J.P. Morgan. It also said it’s “unclear what role J.P. Morgan played” in selecting Cleary for the Southwest Generation board seat.
Anne Cleary | Modern Grid Solutions
IIF said it is advised by J.P. Morgan and structured as a “limited partnership investment vehicle, the equity of which is held by passive limited partners.” The company disputed that J.P. Morgan directs IIF. It said its utilities handle their own “day-to-day management and activities.” It also said because Cleary is a private individual, “there are no common officers or directors of parties” to the ownership transfer and that her role at Southwest Generation isn’t relevant.
FERC said Cleary’s connections are not a concern because Public Citizen did not prove that the transaction would harm competition.
“Public Citizen has not argued, let alone demonstrated, that its allegations, if proved true, show that the proposed transaction will have an adverse effect on competition, rates, regulation or result in cross-subsidization,” the commission said.
FERC agreed with IIF that because Cleary and Dennis Clarke, the seller, are private individuals, there are no common officers or directors of parties to the transaction.
Norm Augustine, retired chairman and CEO of Lockheed Martin | Bipartisan Policy Center
A group of utility CEOs and other business leaders last week said the U.S. should triple federal funding for clean energy innovation to $25 billion annually over the next five years, calling it essential for addressing climate change and ensuring a leadership role for the U.S. in new technologies.
The American Energy Innovation Council, an 11-member group whose principals include the chairs of Southern Co., Dominion Energy, Xcel Energy and Royal Dutch Shell, said the increase should include a boost for the Advanced Research Projects Agency – Energy to $1 billion a year from the current $425 million.
Founded in 2010, the council is a project of the Bipartisan Policy Council, which presented a panel discussion Thursday on the group’s recommendations.
“There was a great deal of skepticism when we started as to whether [climate change] was really a problem. Today I think there are very few people who question whether or not we have a serious problem,” said Norm Augustine, retired chairman and CEO of Lockheed Martin. But he added: “We have a long way to go. Even today, about 88% of the world’s energy consumption use still comes from fossil fuels. That’s a number that’s declined by about 1% in the last quarter of a century.”
The American Energy Innovation Council said additional federal funding is needed to sustain innovations through the second “valley of death” between prototype and demonstration projects. | American Energy Innovation Council
A ‘Sputnik Moment’
The group cited research that 50 to 85% of annual GDP growth in the U.S. “can be traced to innovation.” In its first 11 years, ARPA-E provided $2.4 billion in funding for more than 950 projects, 166 of which have attracted more than $3.3 billion in private-sector follow-on funding, the group said. “Technology innovation improves productivity across industries and creates entirely new ones. Economists agree that innovation is the key engine of long-term economic growth and stability,” it said.
“Technology innovation requires expensive equipment, well trained scientists, multiyear time horizons and flexibility in allocating funds. This can be done most efficiently and effectively if the institutions engaged in innovation are located in close proximity to each other, share operational objectives and are accountable to each other for results,” it said. “Resources should not be spread thinly across many institutions working on the same problem.”
The group said it is alarmed that competing nations’ investments in science and technology are outpacing the U.S.
In fiscal year 2020, Congress appropriated about $9 billion for energy research, development and demonstration. But the U.S.’ “research intensity” — the ratio of R&D investments to GDP — has stagnated, while China’s tripled between 1995 and 2019, the group said.
“China’s recent announcement that it intends to completely decarbonize its economy by 2060 should be viewed as a new ‘Sputnik moment,’” they wrote, referring to the Russian satellite that prompted the U.S.-Soviet Union space race.
Valleys of Death
Although federal funding for early-stage R&D has increased in recent years, they said, “the later stages of demonstration and deployment continue to lag in resources and prioritization. Closing this gap is essential to successfully commercialize breakthrough technologies.”
Augustine said ARPA-E “does a fabulous job in dealing with that first ‘valley of death’” — the feasibility challenge between research and prototypes. But he said neither government nor industry has addressed the second gap between prototype and demonstration projects.
Former PG&E Corp. CEO Geisha Williams | Bipartisan Policy Center
The council recommended creation of a national, politically neutral “Energy Strategy Board” that would include experts in energy technology and markets, develop a long-term national energy plan and oversee a “New Energy Challenge Program” to build large-scale pilot projects.
“If you go from … research to prototype to demonstration it takes tremendous resolve, tremendous leadership and tremendous resources,” former PG&E Corp. CEO Geisha Williams said. “And I will tell you that no one company has the wherewithal to make it happen. It requires a very strong private and public partnership. And frankly, it’s going to require the type of funding that only the federal government can provide.”
“The U.S. government hasn’t had an energy plan for a long time,” Augustine added. “We don’t even have a capital budget for anything. … I know of no successful company that doesn’t have a capital budget.”
The American Energy Innovation Council said the U.S. should triple federal funding for clean energy innovation to $25 billion over the next five years. | American Energy Innovation Council
Augustine said such long-term planning is essential for a successful R&D program. “There will be failures; we’re talking about research and development,” he said. “My background is principally aerospace, and not every rocket works, I’ll guarantee you that. I’m afraid that’s true in the energy arena as well.”
Most Promising Technologies
Chad Holliday, chairman of Royal Dutch Shell | Bipartisan Policy Center
The group identified as the most promising technologies large-scale energy storage, advanced nuclear reactors, renewable and low-carbon hydrogen, and carbon capture and removal.
“If we try to focus on everything, it will be too much,” said Chad Holliday, chairman of Royal Dutch Shell. “But I think hydrogen is certainly one of the candidates for [research spending], and I believe carbon capture and storage is a second candidate for that.”
“There’s a lot of projections that suggest within 30 years, hydrogen in itself could be about 20% of the entire energy supply requirements [of] the entire world,” said Michael J. Graff, CEO of industrial gas manufacturer American Air Liquide Holdings.
Legislation
Speakers on Thursday expressed optimism that some of the priorities identified by the council will receive attention in an energy package as part of the year-end budget omnibus bill.
A discussion draft of the energy package includes a 75% increase in ARPA-E’s budget and funding for large-scale demonstrations of carbon capture utilization and storage technology, said Rep. Lizzie Fletcher (D-Texas), who also participated in the BPC forum.
ARPA-E’s budget would increase gradually, from $435 million for fiscal year 2021 to $761 million for fiscal 2025.
U.S. Rep. Lizzie Fletcher (D-Texas) | Bipartisan Policy Center
The Better Energy Storage Technology Act, which would reauthorize DOE’s grid-scale storage research, also is part of the package, said Fletcher, chair of the House Science, Space and Technology Subcommittee on Energy and a member of the House Transportation and Infrastructure Committee. At least one demonstration project would be due by September 2023.
Fletcher said House Democrats’ $1.5 trillion Moving Forward Act, which passed 233-188 in July, is not expected to clear this session, but it could be a “framework” for an infrastructure package in the next Congress. The bill, which received only three Republican votes, would allocate more than $70 billion to upgrade the electric grid to accommodate more renewables and electric vehicle charging and provide tax credits for EVs.
“A lot of people are talking about the challenges. We need a lot of people talking about the answers,” Fletcher said. “I think that it’s essential that this work centers on crafting ambitious but workable plans and depoliticizing this conversation. … That’s why … AEIC’s leadership and vision at this moment is so important.”
