The Texas Public Utility Commission last week approved a new rule that allows utilities operating solely outside the ERCOT region to apply for a generation-cost recovery rider (GCRR) for capital investments in individual generation facilities (55031).
The rule applies primarily to El Paso Electric, Entergy Texas, Southwestern Electric Power Co. and Xcel Energy’s Southwestern Public Service. It stems from a bill passed (HB 1397) in last year’s state legislature.
PUC Chair DeAnn Walker, pointing to the abundance of renewable facilities already installed and coming online, modified the rule in a memo before the July 2 open meeting to clarify that a utility may include “more than one discrete generation facility” in the rider. Utilities will be allowed to amend their GCRRs to request inclusion of additional generators.
PUC Chair DeAnn Walker, the sole commissioner present, leads July 2’s open meeting.
“I feel like where we are with our future generation, most are going to be smaller projects, where you may need to have more than one included in the rider,” Walker told her fellow commissioners.
The commission agreed that if the rule is not working, they can always revisit the issue. Walker said the PUC’s earnings-monitoring process would allow them to determine whether any utilities were taking advantage of the rule.
Walker was the only commissioner present in the PUC’s meeting room. Commissioners Arthur D’Andrea and Shelly Botkin both called in from remote locations.
PUC Extends Customer Relief Program
The commissioners agreed to extend the state’s Electricity Relief Program from July 17 to Aug. 31, citing Gov. Greg Abbott’s decision to curtail certain economic activities in the face of rising coronavirus diagnoses and hospitalizations. An order will be drafted for the commission’s approval during its July 16 open meeting.
The PUC created the program in March to help retail providers’ unemployed customers by shielding them from disconnections for nonpayment and offering bill payment assistance.
“While we certainly wish we could snap our fingers and make this virus go away, it’s clearly with us for the long haul and we need to reflect that in our decisions,” Walker said.
The state reported a record 8,258 COVID-19 confirmed cases on July 4, bringing its total to 195,239. A record 8,181 Texans were hospitalized on Sunday. The state has reported 2,637 deaths.
The program is funded by a rider charge applied to customer bills within the ERCOT region.
Entergy, LCRA Get CCNs
In other actions, the PUC:
Granted Entergy Texas a certificate of convenience and necessity (CCN) to build, own and operate a 230-kV line and substation north of Houston that is needed to accommodate future load growth. Entergy has reached a settlement with all intervenors on a 9-mile route that is projected to cost $34.1 million. The substation is expected to cost an additional $23.3 million (49715).
Approved Lower Colorado River Authority’s request for a CCN for a new substation and a 138-kV line connecting the facility with the grid in the Texas Hill Country north of San Antonio. The 22.5-mile project, costing an estimated $64.3 million, is needed to address congestion and voltage issues, LCRA said (49523).
FERC last week ordered hearing and settlement judge procedures on American Transmission Systems Inc.’s (ATSI) request to recover deferred and ongoing legacy costs related to the company’s move from MISO to PJM in 2011 (ER20-1740).
ATSI’s proposed revisions to its transmission formula rate, filed by PJM in May, sought $154 million in additional rates, including legacy MISO Transmission Expansion Plan costs, costs of ATSI’s integration into PJM and deferred vegetation management costs.
In 2011, the commission rejected ATSI’s first request for recovery of PJM integration costs and MISO exit fees, saying the company had failed to “provide sufficient information or support that would enable the commission to find that it is just and reasonable for ATSI’s transmission customers to bear the costs arising from the decision to switch RTOs.”
FERC upheld the denial on rehearing in 2016. It said its ruling was without prejudice, allowing ATSI to file a new request that included a detailed cost-benefit analysis showing that the benefits to wholesale transmission customers exceed the costs of the switch to PJM. (See FERC Rejects ATSI Bid for Cost Recovery on Switch from MISO to PJM.)
American Transmission Systems Inc. is a unit of FirstEnergy. | FirstEnergy
In justifying its new rate request, ATSI, a unit of FirstEnergy, said its move to PJM has generated about $4 billion in benefits, dwarfing the $154 million it seeks to recover.
But American Municipal Power (AMP), Buckeye Power, Industrial Energy Users of Ohio (IEU) and the federal energy advocate for the Public Utilities Commission of Ohio protested the request.
AMP and Buckeye said the request should be rejected because of the four-year delay in refiling for the RTO transition costs since the commission’s 2016 rehearing order. AMP said utilities should not have unlimited discretion on how long it will carry deferred costs on its books. AMP, Buckeye and IEU also contended that ATSI’s cost-benefit analysis did not accurately calculate the impact on Ohio retail customers.
IEU and AMP also challenged ATSI’s request for $18.7 million in deferred vegetation management costs incurred from 2013 to 2016, saying the company failed to demonstrate that they were “enhanced” or prudently incurred.
Citing the disputes, the commission’s order accepted ATSI’s proposed Tariff revisions and suspended them for five months to become effective Dec. 1, subject to refund.
Stakeholders at a virtual public hearing on Thursday praised the Bureau of Ocean Energy Management for working through the pandemic and urged the agency to approve the 800-MW Vineyard Wind offshore wind project along with the 1-nautical-mile turbine spacing advocated by developers and recommended by the U.S. Coast Guard.
“I’d like to go on record in supporting the 1-mile distancing between towers,” said Brad Lima, recently retired as chief academic officer of the Massachusetts Maritime Academy. “There was one statement in the [May 14] Coast Guard report that stood out: ‘Anything that can be done to reduce traffic scenarios is a prudent decision.’ … It’s quite evident based on the number of companies which have won leases for the Atlantic Coast sites that offshore wind is where power generation wants to be.”
BOEM’s supplemental environmental impact statement (SEIS) for the Vineyard Wind project, released June 9, included a proposal by the Responsible Offshore Development Association (RODA), a fishing industry group, calling for six “transit lanes” at least 4 nautical miles wide for a projected 22 GW of projects from the coasts of New England to Virginia. (See BOEM Issues Revised EIS for Vineyard Wind.)
The proposed transit corridor would provide a path for vessels traveling from New Bedford, Mass., and other southern New England ports to fishing grounds in Georges Bank, east of Cape Cod. Only one of the lanes intersects the Vineyard Wind 1 wind development area in federal waters south of Massachusetts.
The report also reflects changes to the Vineyard project since the draft EIS: replacing 696-feet-tall, 10-MW turbines with 837-feet-tall, 14-MW turbines. The SEIS found that the cumulative effect of the 22 GW of projects could have major impacts on navigation and vessel traffic, commercial fisheries, and military and national security uses.
Cumulative Impacts
“Global climate change presents a serious threat to the commonwealth’s environment, residents, communities and economy,” said Lisa Engler, director of the Massachusetts Office of Coastal Zone Management (CZM). “Gov. [Charlie] Baker has expressed the need for action. The magnitude of the impacts from climate change requires all of us to put politics aside and act together quickly and decisively.
“We still have the ability to check the severity of future impacts by aggressively reducing greenhouse gas emissions and adapting to the changes,” Engler said. “The cumulative analysis included in the SEIS ensures that potential impacts beyond this individual project are evaluated.”
Engler said the state’s review, which included the Department of Environmental Protection, Energy Facilities Siting Board, Environmental Policy Act Office, Department of Public Utilities and the CZM, is complete.
The total project capacity still remains at 800 MW, and a change to the turbine capacity would not result in a change to the footprint or to the 8-MW minimum turbine capacity, said BOEM environmental coordinator Jennifer Bucatari, who presented the agency’s summary of the SEIS. The project will comprise up to 100 wind turbines.
Vineyard Wind also submitted changes expanding the onshore substation, with a total area of ground disturbance of 7.7 acres, which is 1.8 acres greater than the area analyzed in the draft EIS, she said.
As for the various transit lane proposals and the turbine locations they would displace, “under the current cumulative scenario, displacement of all these turbine locations is not feasible, and therefore the addition of all six transit lanes would lead to the elimination of some of the turbines that could have occurred within these lanes,” Bucatari said.
Competitor Concerns
David Hardy, COO of Ørsted North America Offshore, praised BOEM’s work on the supplemental EIS. “It is no small feat to forecast the myriad impacts the development of a new ocean-based resource will have on the human and natural environment, both positive and negative,” he said.
Ørsted has been awarded more than 2,900 MW of offtake rights, with the states of Connecticut, Maryland, New Jersey, New York, Rhode Island and Virginia having all awarded their first offshore projects to the company.
Hardy said Ørsted “strongly” supported the developers’ consensus proposal of 1-nautical-mile turbine spacing, with an east-west layout for simpler navigation.
He said RODA’s proposed 4-mile spacing “would result in the loss of over 50 wind turbine locations from our current three projects: South Fork, Revolution Wind and Sunrise Wind. … This equates to a nearly 25% loss in the total wind turbine locations for our state” power purchase agreements.
The SEIS should reflect a more favorable rating of offshore wind as a domestic economic development engine consistent with ongoing and planned investments, Hardy said, noting Ørsted is planning to spend $15 billion over the next decade in the U.S.
“For many of the cumulative impact parameters considered in the SEIS, BOEM chose not to incorporate widely accepted or legally mandated mitigation strategies; thus the bottom-line impact of the 22-GW buildout must be considered a worst-case scenario and not as representative of as-constructed impacts,” Hardy said.
Where BOEM comes out on the Vineyard project will likely determine the fate of offshore wind in the whole country, said Joe Martens, director of the New York Offshore Wind Alliance and former commissioner of the New York Department of Environmental Conservation.
“A plain reading of the SEIS could lead to the conclusion that if the Vineyard Wind project is not advanced, other projects in various stages in the pipeline inevitably will,” Martens said. “I don’t think this is the case. … The [Vineyard] developers have gone above and beyond the extensive federal, state and local requirements for offshore wind.”
The Vineyard project is in effect a “litmus test” for the industry, he said, urging its approval on both environmental and economic grounds. “All eyes are on this project.”
Communities Supportive
The project has been thoroughly vetted by all the “top notch” environmental groups and should be approved to provide more renewable energy for the state, said Eileen Mathieu, board member of Sustainable Marblehead, a volunteer community organization in the town of Marblehead, Mass.
“In Marblehead, our municipal light department … is eager to be able to purchase reasonably priced electricity from renewable sources,” Mathieu said. “However, local resources are very constrained, so that right now we only have 12% renewable energy in our portfolio and 26% nuclear.”
Marblehead buys its power through the Massachusetts Municipal Wholesale Electric Co., which “needs wind options to provide its 22 municipal light plant members, and currently it has none,” Mathieu said.
“We strongly support this project as the first large-scale OSW project in the region,” said Kai Salem, policy advocate for the Green Energy Consumers Alliance.
Fred Hopps of Beverly, Mass., founder of the town’s clean energy advisory committee — and a former resident of Copenhagen, Denmark — gave “a thousand thanks to the Danes for practically single-handedly keeping offshore wind energy alive.”
BOEM will hold two more web-based public hearings on the SEIS for Vineyard Wind, on July 7 and 9, with the public comment period open through July 27 on a dedicated website. The agency expects to publish its final EIS in November and to issue a final decision in December.
Vineyard Wind is a joint venture between Copenhagen Infrastructure Partners and Avangrid Renewables.
FERC has asked the D.C. Circuit Court of Appeals to give it 90 days to respond to the court’s June 30 order barring the commission’s use of tolling orders to delay judicial review of its rulings under the Natural Gas Act.
The commission’s motion Monday said the delay would give it time to respond to the order overturning “the commission’s decades-old, judicially sanctioned rehearing process” and consider whether to seek a review by the Supreme Court.
The court ordered its clerk to issue a mandate in the case on Tuesday, but the court had not filed the mandate nor responded to FERC’s motion as of late that afternoon. “We have nothing for you at this time,” commission spokeswoman Mary O’Driscoll said.
No More Stopping the Clock
The D.C. Circuit’s 10-1 ruling concluded that FERC’s use of tolling orders to stop the 30-day clock for acting on rehearing requests improperly prevents litigants from appealing commission rulings indefinitely even as it allows gas pipeline companies to seize property under eminent domain and begin construction (Allegheny Defense Project, et al. v. FERC, 17-1098). (See D.C. Circuit Rejects FERC on Tolling Orders.)
The court said it had erred since 1969 when it first ruled that issuing a tolling order meant that FERC had “acted upon” the request under the language of the NGA and that parties must wait until the commission’s review of the request is complete before seeking judicial relief.
E. Barrett Prettyman Federal Courthouse, home of the D.C. Circuit Court of Appeals | HSU Builders
FERC routinely issues tolling orders to buy itself more time to consider rehearing requests because both the NGA and the Federal Power Act deem such requests denied if it does not act on them within 30 days.
In the face of increased criticism of its use of tolling orders, FERC on June 9 issued a rulemaking saying it will no longer permit gas pipeline developers to begin construction until it acts on the merits of any rehearing requests (Order 871, RM20-15). (See FERC Revises Pipeline Policy on Landowner Concerns.)
The new rule followed Chairman Neil Chatterjee’s September 2019 pledge that FERC would seek to reduce tolling orders and act on landowner rehearing requests within 30 days. In February, the chairman announced the creation of a new rehearing section within the Office of the General Counsel to expedite action.
In its motion, however, FERC noted that the impact of the court’s June decision “extends well beyond landowner cases and affects all requests for rehearing under the Natural Gas Act and presumably those under the Federal Power Act as well.”
It said tolling orders “allow the commission to manage its large case load,” noting the commission averages more than 1,100 orders and 285 rehearing requests annually.
Circuit Split?
FERC said it needed time to analyze the court’s conclusion that while an order granting rehearing solely for the purpose of further consideration does not prevent a rehearing request from being deemed denied, the NGA does not require the commission to resolve the merits of rehearing requests within 30 days. The court wrote that the NGA’s reference to acting on a rehearing request requires “some substantive engagement with the application” but not necessarily a “deci[sion] [on] the rehearing application.”
The court declined, however, to address whether FERC could issue interim orders that grant rehearing for further consideration coupled with a request for supplemental briefing or further hearing processes.
“A stay of the court’s mandate would afford the commission time to consider how to revise its processes and allocate its resources so that it can fulfill its statutory role on rehearing in the absence of these interim orders,” FERC said.
The commission said the D.C. Circuit previously read the act as requiring it to actually decide the merits of rehearing requests within 30 days. “In addition, every other court of appeals to consider the issue has determined that the term ‘act’ encompasses tolling orders that grant rehearing for further consideration,” FERC said.
It noted Judge Karen LeCraft Henderson’s dissent, which said the decision “creates a circuit split that could force the Supreme Court to weigh in.
“Whether the court’s conclusion as to the plain language of Natural Gas Act Section 717r(a) warrants Supreme Court review is something that the commission and the solicitor general will need time to consider without the added burden of the court’s decision immediately taking effect,” FERC said.
A stay would not harm rehearing petitioners because of its commitment to bar construction during the rehearing process and because district courts can hold eminent domain proceedings in abeyance while rehearing is pending, it said.
In addition to filing the motion for more time, FERC also is seeking a legislative response to the order. On July 2, Chatterjee, a Republican, and Commissioner Richard Glick, a Democrat, issued a statement asking Congress “to consider providing FERC with a reasonable amount of additional time to act on rehearing requests involving orders under both the Natural Gas Act and the Federal Power Act.”
FERC has approved a set of amendments to SERC Reliability’s bylaws, jointly submitted by the regional entity and NERC last year, aimed at creating “a more strategic, efficient and effective governance body” (RR20-2).
The new bylaws, approved July 1, will take effect Jan. 1, 2021, and will implement a number of structural changes, including:
transitioning SERC’s Board of Directors to a hybrid board containing 15 sector representatives and at least three independent directors (with a maximum of five);
requiring that a majority of the board, as well as a majority of the independent directors, be present to have a quorum for meetings;
eliminating the use of alternates and proxies for directors and independent directors;
formalizing SERC’s membership body by transitioning the existing board structure into a members group, which will include a representative from each member company and meet at least annually to advise the board on the business plan and budget, elect independent directors and approve bylaw changes as needed;
changing the Board Compliance Committee into a Board Risk Committee; and
adding a Human Resources and Compensation Committee, Nominating and Governance Committee and Finance and Audit Committee.
NERC’s Board of Trustees approved the revised bylaws at its meeting last November. At the time, NERC Chair Roy Thilly called the changes “a very positive development,” and Trustee Fred Gorbet said they would “[move] SERC to the front of the pack in terms of good governance.” (See “SERC Bylaw Changes OK’d,” NERC Board of Trustees Briefs: Nov. 5, 2019.)
Consumer Group Demand Voice in SERC
The proposal by NERC and SERC did not go entirely unopposed. Earlier this year, consumer advocacy group Public Citizen filed a protest requesting further amendments to the planned changes.
Public Citizen supported the desire for greater board independence but felt the RE’s plan did not go far enough to ensure “effective reliability and cybersecurity governance” because the resulting board structure would still lack representation by consumer advocates. The group asked that FERC require SERC to reserve at least one seat on the board for such a representative, that the RE also be made to include household consumer advocates in its broader membership and that at least one advocate should serve on the new members group.
In their response to Public Citizen, NERC and SERC reminded the commission that in its Order 672, it had given REs “flexibility … to find a governance structure appropriate to their regions” and that it would not “prescribe limits on board composition [or] representation of industry segments.” The organizations noted that consumer advocates could join the members group and pointed out that they also “have numerous opportunities for involvement at SERC outside of the membership body.”
The commission sided with NERC and SERC, agreeing that Order 672 prohibits it from creating specific conditions for board composition and that consumer advocates can participate in SERC’s decision-making process without the RE being obligated to allow them on its board.
With the new bylaws accepted, SERC will now begin its search for qualified independent director candidates to fill the new board seats, along with beginning transition activities to implement the other governance changes. SERC’s goal is for all changes to be in place when the new Regional Delegation Agreement, approved by NERC’s board at its May meeting, takes effect. (See “Other Approvals,” NERC Board of Trustees/MRC Briefs: May 14, 2020.)
[UPDATED July 6 to reflect PJM’s comments detailing its objections to the proposal.]
PJM filed the joint stakeholders’ end-of-life (EOL) proposal with FERC on Thursday, turning aside the protests of most of its transmission owners, who claim moving EOL projects under the RTO’s planning authority violates their rights.
The 279-page filing notes that the Operating Agreement amendments, initiated by American Municipal Power (AMP) and Old Dominion Electric Cooperative (ODEC), were approved by 69% of the Members Committee on June 18 despite the RTO’s opposition (ER20-2308). (See PJM Stakeholders Endorse End-of-Life Proposal.)
“While PJM did not support these amendments in the stakeholder process, PJM submits them as the party assigned responsibility under the Operating Agreement to ‘administer and implement’ the Operating Agreement and to file changes to the Operating Agreement under [Federal Power Act] Section 205.”
The filing leaves FERC to decide between the stakeholders’ proposal and PJM’s plan, which was endorsed by the Transmission Owners Agreement-Administrative Committee (TOA-AC) in a June 12 filing proposing amendments to Tariff Attachment M-3 (ER20-2046). It would require TOs to have a formal program for EOL determinations and to identify potential EOL projects five years in advance. Projects that “overlap” with Regional Transmission Expansion Plan (RTEP) violations would be included in a competitive window seeking regional solutions. The RTO’s proposal failed to win consensus, with a sector-weighted vote of 36% at the May 28 Markets and Reliability Committee meeting.
ODEC and AMP have filed a motion to have the TOs’ filing dismissed on procedural grounds.
In filing the joint stakeholders’ proposal, PJM rebuffed the TOs, who argued in a June 26 letter that the proposal violates their rights under the Consolidated Transmission Owners Agreement. (See TOs Demand PJM Reject EOL Proposal.)
However, the RTO also filed comments detailing its objections to the joint stakeholders’ proposal.
The TOs and PJM contend the stakeholders’ proposal also violates FERC precedents and Order 890’s rules regarding transmission asset management. PJM has said decisions on when a facility is at the end of its useful life or otherwise needs to be replaced “are the sole responsibility of the transmission owner.”
PJM asked FERC to act within 61 days and proposed Jan. 1, 2021, as the effective date for the OA changes, if it accepts them. The RTO said the date would coincide with the beginning of the next cycle of the RTEP.
The joint stakeholders say their proposal complies with commission precedent by continuing to give TOs exclusive authority to determine whether a transmission asset has reached its EOL while making the replacement of such assets PJM’s responsibility through the RTEP.
The proposal would:
modify OA Schedule 6 to create a process for evaluating and replacing EOL assets under the RTEP, removing the planning from Attachment M-3 of the Tariff;
require TOs to develop an EOL program, including criteria, for facilities approaching their EOL and submit a binding notification to PJM of facilities that will reach their EOL within six years;
require TOs to provide PJM a 10-year, forward-looking list of facilities’ EOL conditions;
exclude the planning of EOL facilities from the RTEP reliability exemption for transmission facilities under 200 kV; and
amend the OA definitions and Schedule 6 to remove EOL assets from evaluation as supplemental projects under Attachment M-3 and evaluate all EOL facilities as a separate category under Schedule 6.
PJM told FERC the changes “should be implemented prospectively … as there are no transition provisions in the joint stakeholder proposal for current EOL determinations less than six years out.”
PJM Comments
In separate comments filed later Thursday afternoon, PJM said the joint stakeholders’ proposal violates its governing documents and commission precedent on the RTO’s and the TOs’ roles in the planning of supplemental projects, including EOL facilities, and the planning of asset-management projects.
It noted that the stakeholder process “was markedly dominated by legal debates, including debates as to the meaning of certain governing documents and the scope of authority ascribed to PJM and the PJM transmission owners under those documents.”
“These legal issues, as well as related policy issues, are not ones that necessarily lend themselves well to final resolution in a stakeholder process,” PJM continued. “It is for this reason that PJM is filing these comments and urges the commission to provide clear resolution on the legal and policy issues raised by the joint stakeholder proposal.”
The RTO said the proposal that the EOL notifications be binding on the TOs “unreasonably restrict transmission owners’ flexibility regarding their end-of-life decisions over their transmission assets. More specifically, this lack of flexibility potentially impedes a transmission owner’s ability to modify its end-of-life decisions due to changes to system conditions or unforeseen circumstances that can impact an asset’s life. Instead, the proposal assigns the responsibility to PJM to determine whether to escalate or delay replacement of the transmission owner’s asset.”
It said although the proposal says that “‘determination of EOL is still a TO determination,’ the proposed revisions specific to EOL conditions seem to effectively assign that responsibility to PJM.”
PJM also cited an apparent inconsistency between exempting from the competitive window process EOL notifications on substation equipment while exempting facilities below 200 kV.
Northwest Power Pool (NWPP) members last week discussed a proposed Western resource adequacy program that would create a “binding” capacity mechanism for summer and winter but be able to change course if peak loads shift to other seasons in the face of a changing resource mix.
NWPP formally kicked off the RA effort in April in response to mounting evidence that the West could face capacity deficits as early as this year, raising the risk that load-serving entities could inadvertently draw on the same resources for RA as fossil fuel generators retire and the region increasingly relies on intermittent renewables. (See NWPP Planning Western Resource Adequacy Program.)
While still in its early stages, the RA program is proceeding apace after the NWPP stakeholder group spearheading the effort outlined its initial concepts just two months ago. (See NWPP Details Proposed Reliability Program.) Eighteen NWPP members spanning nine U.S. states and one Canadian province have already signed on to the effort, with three additional entities expressing interest in joining, NWPP President Frank Afranji told ERO Insider.
Speaking during a webinar Thursday, Afranji said that NWPP’s RA group has already completed “Phase 2A” of the initiative — the preliminary design — and is now advancing to the detailed design work of “Phase 2B.”
NWPP says it’s now entering Phase 2B of it RA program development. | NWPP
Implementation of a “nonbinding” RA program (Stage 1 of Phase 3) is slated for next year, followed by the rollout of progressively comprehensive Stage 2 and 3 “binding” program — which would require participating LSEs to demonstrate RA in advance and enforce penalties for noncompliance — heading into 2024.
“The implementation phase begins in 2021; however, we have not put out specific dates for the different stages in this phase because the timeline for implementation is still preliminary at this point. I anticipate, as these dates become more certain, we’ll have more information to share at a future public webinar,” Lea Fisher, Public Generating Pool senior policy analyst, said in an email.
“Even when we move into the implementation phase, the program is going to be designed to be very dynamic,” RA group member Gregg Carrington, Chelan County (Wash.) Public Utility District’s managing director of energy resources, said during the webinar.
“We’re going to be able to learn as we go, and it’s going to be continuous improvement,” Carrington said. “To the extent that we discover things that work for us, we’ll keep them, and to the extent we find things that don’t work, we’ll make changes as we go.”
‘Refining as We Go’
NWPP’s current proposal envisions a Stage 1 nonbinding, no-penalty program that asks participants to offer “forward showings” of resource adequacy and availability from participants seven months in advance of the summer (June to September) and winter (November to March) seasons.
“This would be an opportunity to gain experience with the program administrator and submit data, [and] certify all the resources,” said RA group member Joel Cook, Bonneville Power Administration’s senior vice president of power services. “That data would be available to all the participants. We’d have a multilateral agreement between the program administrator and each of the participants to establish requirements.”
The absence of enforcement and penalties will likely exempt Stage 1 of the program from FERC oversight, Cook said.
Stage 2 would introduce a more stringent requirement in which participants must demonstrate to the RA program administrator that they have sufficient resources to meet required metrics for the binding season seven months ahead of the operational timeline.
“An inability to meet showing requirements would result in a penalty or other consequences, and enforceability of the provisions and penalties for noncompliance would likely make the program, at this point, FERC-jurisdictional,” Cook said.
NWPP is proposing an RA program with “binding” summer and winter seasons that would require participants to demonstrate their capacity showings seven months in advance. | NWPP
Stage 3 would extend the depth of the RA program by creating a pool of resources for participants to buy and sell for each season’s operational timeline, Cook said.
“The details would be developed with the [NWPP] program developer, so we have a lot of work still ahead of us,” he said. “This is intended to mitigate the risk for participants when the spot market is less liquid, and we have entities relying on that spot market to serve some of their resource adequacy needs.”
Alan Comnes, senior director at consulting firm Energy GPS, asked whether seasonal requirements would be broken down into individual months or consist of a single requirement.
“This is a design aspect that we’re going to be refining as we go,” Carrington replied. “SPP, for example, has a summer-binding season. People submit that six months in advance, but then people also submit information as they get closer and closer to the operational time period. Cal-ISO has an annual review of their capacity product, but then they do a true-up on a monthly basis. We have not made a determination whether or not we’d do a monthly true-up.”
Fred Heutte, Northwest Energy Coalition senior policy associate, asked whether NWPP would consider a monthly, rather than seasonal, RA showing.
“My concern is that system conditions vary a great deal within seasons, and a seasonal approach could lead to over-acquisition of RA resources. Also, the gap months between the seasons are a bit problematic. If RA is addressing both coincident peak demand and need for ramping [and] flexibility, then we will have RA needs in all months,” Heutte said.
“The program that we set up was designed to cover what we considered to be the coincidental peak demand,” Carrington responded. “What we did is we took a look at 10 years of records, and we determined exactly the number of peak-hour demands that occurred … and all of them fell within the time periods that we’ve designed right now. If that changes in the future … the program’s going to be set up to be dynamic, and we’ll be able to make adjustments as we move forward as well.”
RA group member Mark Holman, managing director with Powerex, said the group selected summer and winter as the program’s binding seasons because they contain the greatest risk of a capacity shortfall. Northern reaches of the footprint tend to peak in winter, while those farther to the south peak in summer.
“But that doesn’t mean that entities are not planning their systems in the April-May and the October time periods,” Holman said. “And, of course, if you meet your summer and winter season peaks, you’re often going to have resources available in those other periods. I think the thinking is that as we launch this program, we need to address the critical periods of greatest risk.”
But Holman also agreed with Carrington that if stakeholders identify the need for a spring- or fall-binding RA period, “we can certainly move to that in a future year.”
Stage 0
Portland General Electric Senior Director of Power Operations Cathy Kim reviewed how the program would treat resource eligibility, with resources likely required to undergo a registration and certification process.
Kim also noted that many resource-rich Northwest entities sell capacity out of their systems, requiring the future RA program administrator to validate the counting of capacity to prevent “overselling” as it is transferred from one system to another.
She also emphasized that the program would be “technology-agnostic” and consider all resources, including demand response and battery storage in addition to the region’s predominant thermal, hydro and pumped storage generation.
In reviewing the program’s import-export assumptions, Holman pointed out that modeling assumptions of future hourly imports into the NWPP footprint will have a “significant impact” on identifying the critical hours of RA need and the calculations of participants’ regional planning reserve.
He also delved into an important point for a region populated by entities with heavy surplus capacity, explaining that participants that export energy to other regions must demonstrate those exports are drawn from true surpluses and do not in any way contribute to regional planning reserve margins or lean on the RA program.
It is presumed that entities are making those exports from their surplus capability beyond what they are obligated to show as part of the showing component of the program,” he said.
NWPP is proposing that Stage 1 of the program be preceded by a Stage 0 “stopgap” solution in the event of a loss-of-load event before the RA program commences operation. This interim program would allow participants to give and receive RA assistance “on a voluntary basis during high grid stress periods” in summer and winter. “The intent is for the Stage 0 interim solution to be available this summer,” Fisher said.
Holman wrapped up Thursday’s webinar by applauding the level of stakeholder interest in the RA program.
“I’ll just say that it’s really good to see that people are engaged, and that they’re thinking about the same issues that we’re all thinking about, which is how to achieve a resource adequacy program that really achieves two core purposes: ensures reliability and unlocks investment savings through diversity — and we do that in a very efficient manner.”
FERC last week approved SPP’s second effort to eliminate revenue credits for sponsored transmission upgrades under Tariff Attachment Z2 and replace them with incremental long-term congestion rights (ILTCRs), effective July 1 (ER20-1687).
The commission in January rejected an earlier attempt to eliminate the revenue credits, giving SPP an opportunity to file a revised proposal that “does not impose a cap that limits the term and potential value of ILTCRs.” (See FERC Order Keeps Z2, Aids EDF’s Sponsored Project.)
The RTO responded in April with a filing that proposed to remove the cap on the amount recoverable through the candidate ILTCRs and revert back to current provisions allowing those ILTCRs a term of at least 10 years and up to 20 years.
The June 30 order was a defeat for renewable developers, who contended that SPP’s proposal would violate FERC’s cost allocation policies because upgrade sponsors — generally wind and solar facilities — would no longer receive direct payments from third parties who benefit from an upgrade. They argued SPP could not remove Z2 credits without trying to replace them with another mechanism “that considers whether others benefit from these directly assigned network upgrades.”
The commission disagreed, saying upgrade sponsors receive ILTCRs as a form of compensation for being directly assigned network upgrade costs. Third-party beneficiaries of incremental network upgrades “will continue to indirectly pay for such upgrades through congestion payments,” it wrote.
“To the extent that an upgrade is utilized at its full capacity in the day-ahead energy market and thus generates congestion rent … a load-serving entity whose power consumption contributes to congestion on the upgraded facility will fund ILTCRs associated with the upgraded facility through its congestion payments,” FERC said.
Z2 credits for transmission upgrades will soon be a thing of the past for SPP members. | Apex Clean Energy
Under Attachment Z2 of SPP’s Tariff, transmission customers that fund network upgrades can be reimbursed through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrade.
SPP has been trying to replace Z2 credits since 2016, when controversy arose after the grid operator identified eight years of retroactive credits and obligations that had to be resettled after staff failed to apply credits. (See SPP Invoices Lead to Confusion on Z2 Payments.)
In a separate proceeding related to the retroactive Z2 payments, FERC in February denied SPP’s request for a rehearing of a 2019 order that the RTO provide refunds of credit payment obligations (ER16-1341). (See FERC Denies Rehearing in Z2 Remand Order.) SPP and Oklahoma Gas & Electric have appealed the decision to the D.C. Circuit Court of Appeals, where the matter is expected to be set through a briefing process, according to the RTO.
FERC Accepts Generator-replacement Proposal
FERC on June 30 also accepted SPP Tariff revisions that create procedures for expedited replacement of existing generating facilities when the replacement is not a material modification, effective July 1 (ER20-1536).
The commission said SPP’s procedures will avoid duplicative study costs and operational costs that otherwise would occur when the replacement request must proceed through the interconnection study queue process, delaying the addition of more efficient and cost-effective resources. FERC said the proposal will prevent generator owners from losing their existing interconnection service and potentially incurring “significant costs” to obtain replacement service at the same location.
“We find that SPP’s proposal will allow for more efficient use of the transmission system by streamlining the current replacement process,” the commission said.
FERC found SPP’s proposed process complies with Order 2003, which requires public utilities that own or operate transmission to file generator interconnection procedures for facilities with capacity greater than 20 MW. The order provides for pro forma large generator interconnection procedures (LGIP) but allows for variations consistent with or superior to the standard LGIP.
In its April filing, SPP said its proposal will encourage owners of existing facilities to upgrade to newer, more efficient technology.
Multiday Minimum Run Time OK’d
FERC’s Office of Energy Market Regulation on June 30 issued a letter order accepting SPP’s Tariff revisions that allow market-committed resources with a minimum run time extending beyond initial reliability unit commitment or day-ahead commitment periods to be eligible for make-whole payments after their initial commitment period (ER20-1782).
The RTO’s stakeholders approved the change in January. It is intended to minimize potential gaming opportunities identified by the Market Monitoring Unit. (See “Members Pass 12 Revision Requests,” SPP MOPC Briefs: Jan. 14-15, 2020.)
FERC to Examine Roughrider’s Formula Rate
FERC on June 30 also accepted SPP’s Tariff revisions that add a formula rate template and implementation protocols allowing Roughrider Electric Cooperative to recover its annual transmission revenue requirement (ATRR) as a transmission-owning member of the RTO, effective July 1 (ER20-1750).
However, the commission said its preliminary analysis indicates the proposed revisions may be unjust and set them for hearing and settlement judge procedures. Missouri River Energy Services had protested the filing, arguing that it lacked adequate detail about the source of certain construction costs.
Roughrider, embedded in the Integrated System as a Basin Electric Power Cooperative member, joined SPP on April 30 and has been placed in the RTO’s Upper Missouri pricing zone. The North Dakota distribution cooperative serves more than 8,000 members in six counties. It purchases power through Montana’s Upper Missouri Generation & Transmission Cooperative and also sources energy from SPP members Basin Electric Power Cooperative and Western Area Power Administration.
FERC did not suspend and subject Roughrider’s ATRR to refund obligations because the co-op is not within the commission’s jurisdiction under Section 205 of the Federal Power Act. However, it noted that Roughrider voluntary agreed to issue refunds should it change under the hearing and settlement judge process.
Industry experts last week discussed the energy industry’s racial gaps and how to design more equitable energy policies that address the higher bills and bad air quality often faced by the poor.
Diana Hernandez, Columbia University assistant professor of Sociomedical Sciences at the Mailman School of Public Health, said one out of three U.S. households are “energy insecure” — paying a high proportion of their earnings on utility bills, facing disconnection notices or forced to keep their homes at unhealthy temperatures to cut costs.
African Americans and Latinos are most likely to face energy insecurity and often pay more for energy bills, Hernandez said during the June 30 panel discussion, held via Zoom and sponsored by Pecan Street, an Austin, Texas-based electricity data research organization.
Hernandez said “the legacy of segregation” means that marginalized populations live in older, less energy-efficient households and are generally not able to afford new efficient appliances, better insulation or new windows.
The University of California Berkeley’s Energy Institute at Haas in June found that Black households have higher residential energy expenditures than white households across the nation. Researchers said Black renters pay on average $273 more per year than their white counterparts, while Black homeowners pay about $408 more per year than white homeowners.
“They’re paying more, and they’re benefiting less from new energy technologies,” Hernandez said.
“People end up making trade-offs in quality of life for high-energy burdens,” said Dana Harmon, executive director of the Texas Energy Poverty Research Institute. She said that food and clothing are the most common concessions before covering high energy bills.
Hernandez used as an example Lisa Daniels, a 68-year-old Newark, N.J., resident who died in 2018 after Public Service Electric and Gas disconnected her power, leaving her without access to her oxygen mask. Her death prompted New Jersey Gov. Phil Murphy last year to sign a law that bars utilities from shutting off power for 90 days after nonpayment by customers who rely on electric medical devices to survive.
Pecan Street General Counsel and CFO Fisayo Fadelu said disadvantages for communities of color are evident in cities’ infrastructure investments.
“We need to acknowledge that the playing field is not even. Equal investment will not work,” she said.
Fadelu said that while communities of color might not recognize energy justice as a priority, energy efficiency lowers housing costs. The clean energy sector can provide much-needed well-paying jobs, she said, but cities must be willing to invest in those communities to correct racial burdens, she said.
Environmental Defense Fund Director of Regulatory and Legislative Affairs John Hall | Pecan Street
“Race has been and is the most dominant issue in American politics,” said John Hall, director of regulatory and legislative affairs for the Environmental Defense Fund. “Because racism is such a dominant force in our society, that gives rise to systemic racism. And systemic racism is in every sector and industry.”
Hall said the first step organizations usually take is enacting diversity equity and inclusion plans pertaining to hiring practices, then extending those principles to their contractors.
“Overall, the energy sector, as well as the fossil fuel industry and clean energy sector, have not enacted diversity, equity and inclusion plans,” Hall said. “And as a consequence, they have not afforded communities of color the opportunity to participate.”
Minority communities are more likely to be located near fossil fuel plants and bear the brunt of harmful emissions, Hall said. Employees of color are often barred from blue-collar jobs in energy production, he said, expressing concern the same trend is developing in the clean-energy sector.
“We need all Americans — not most — to make being anti-racist their business,” Hall said.
MISO is one organization that recently recommitted to diverse hiring practices during its June Board of Directors meeting. (See MISO Board Addresses Racism, Social Unrest.) A recent follow-up letter from Board Chair Phyllis Currie and MISO CEO John Bear acknowledged “recent events of horrific mistreatment of the African American community.”
“We view these events as indicative of even broader concerns over systemic racism that unfairly discriminates against human beings throughout this community and many other diverse communities,” Currie and Bear wrote.
“We stand with the African American community,” the letter continued. “It is a community in pain, and we know that to have real empathy, we must do more to listen and learn from their perspectives on systemic racism and long-term disparate treatment.”
Currie and Bear vowed MISO will recruit interns from historically Black and Hispanic colleges and universities.
Pecan Street said it plans to hold additional virtual panel discussions on the energy industry’s racial disparities.
Texas regulators Thursday rejected their ratepayers’ participation in an American Electric Power wind project for the second time in three years, denying a plan by subsidiary Southwestern Electric Power Co. (SWEPCO) to add 810 MW of wind energy (49737).
The Public Utility Commission’s denial will not affect AEP’s $2 billion North Central Wind Project, comprising three wind farms in Oklahoma that will provide 1,485 MW of capacity. Arkansas, Louisiana and Oklahoma regulators have already approved the project, as has AEP a Go with $2B North Central Wind Project.)
An estimated 464 MW of capacity will now be allocated to SWEPCO’s Louisiana customers and 268 MW to Arkansas customers. SWEPCO sister company Public Service Company of Oklahoma’s (PSO) share will remain at 675 MW. SWEPCO wholesale customers will receive an additional 78 MW.
Invenergy is building the three North Central wind farms. | Invenergy
SWEPCO President Malcolm Smoak reiterated that the PUC’s order does not affect North Central’s “full viability.”
“It is disappointing that our customers in East Texas and the Panhandle will not have access to this major wind project, missing the opportunity for long-term cost savings and making it more difficult for businesses, residents and communities to meet their renewable energy goals,” he said in a statement.
AEP says the North Central wind facilities will save its SWEPCO and PSO customers $3 billion over the next 30 years.
The Texas commission rejected that argument in approving administrative law judges’ proposed decision. The ALJs said the North Central wind facilities “will significantly increase SWEPCO’s rate base, with some of the financial risk placed on the customers rather than the shareholders.”
AEP’s North Central Wind Project will involve three wind farms in Oklahoma. | AEP
SWEPCO’s request was opposed by most intervening Texas consumer groups. They pointed out that the wind generation is not needed for SWEPCO’s capacity needs. PUC Chair DeAnn Walker agreed, noting the utility is projected to have excess capacity until 2026.
“How this has been laid out is not something that I can go with,” she said.
“There are features of the project that I really like, but if you bring us a project [that benefits consumers], yet all consumer groups are opposed,” Commissioner Arthur D’Andrea said, “it makes it difficult to grant that.”
“It seems like the quantification of benefits … did not become, to me, convincing,” added Commissioner Shelly Botkin.
Invenergy is developing the three wind farms. One is expected to be completed this year, the other two by the end of 2021. SWEPCO and PSO will acquire the facilities upon their completion.
In 2018, the PUC similarly denied SWEPCO’s attempt to acquire a 70% interest in AEP’s proposed $4.5 billion Wind Catcher Energy Connection. AEP canceled the project the day after the commission’s rejection. (See AEP Cancels Wind Catcher Following Texas Rejection.)
