The NEPOOL Markets Committee continued its discussion last week on Forward Capacity Market (FCM) parameters for the 2025/26 capacity commitment period.
Concentric Energy Advisors (CEA) and Mott MacDonald, two consulting firms hired by ISO-NE, presented updates to their analyses from the previous meeting on the net cost of new entry (CONE) and offer review trigger prices (ORTPs). ISO-NE also presented its input assumptions and updated values for CONE, OTRPs and the performance payment rate while proposing a smoothing mechanism for the peak load scarcity hour estimates used to calculate those values.
Expected capacity scarcity condition (CSC) hours are based on three sources: peak load scarcity hours, transient scarcity hours, and winter scarcity hours. ISO-NE updates the peak load scarcity hours estimate annually after its update to the installed capacity requirement.
ISO-NE said the estimated CSC hours for Forward Capacity Auctions 11 through 15 ranged from a low of 7.9 to a high of 14.1, with considerable volatility in recent year-over-year changes. The RTO said it wants to use a four-year moving average to establish the expected peak load scarcity hours for FCM parameters. It said four years aligns with the load forecast horizon and that the current four-year average (10.1 hours) differs little from the three- and five-year averages. In the net CONE calculation for FCA 16, total expected annual scarcity hours, including transient (0.8 hours) and winter (0.4 hours), becomes 11.3 hours with the smoothing mechanism, down from 15.3 hours.
ISO-NE also summarized its reasons for updates to the net CONE, performance payment rate (PPR) and ORTP proposed values. The RTO is also proposing changes to the PPR because of the revised peak load scarcity hours and reference technology assumptions.
Capacity values and energy and ancillary services revenues were adjusted to reflect degradation over the net CONE reference unit’s life in response to stakeholder feedback, affecting gross CONE, net CONE and PPR.
Operations and maintenance costs for net CONE reference technology were revised to reflect decreased dispatch activity consistent with the unit’s low heat value, and bonus depreciation was removed, impacting gross CONE and PPR.
The RTO also revised the site leasing rate for the battery technology that impacts only battery ORTP.
NEPGA Memo
The New England Power Generators Association (NEPGA) presented several amendments at the Markets Committee meeting Oct. 6-8. (See “NEPGA Proposes Amendments on Amortization Period, Owner’s Cost,” NEPOOL Debates Parameters for 2025/26.) In a memo to the committee for this meeting, NEPGA’s Bruce Anderson wrote that several NEPOOL stakeholders asked the group to estimate the impact each of its potential amendments would have on net CONE value.
NEPGA posted a modified version of the discounted cash flow model used by CEA in the current net CONE recalculation process to show the numerical inputs it proposes as amendments to the bonus depreciation line item. These inputs derive from analysis and conclusions drawn by Advantage for Analysts on behalf of NEPGA. Stakeholders cannot reproduce the calculation of the inputs, so NEPGA provided them and their impact on net CONE to stakeholders who want to reproduce any of its analyses.
Impact Assessment
ISO-NE said the interdependencies among the FCM parameters present unique challenges when calculating the combined effect of more than one amendment on CONE, net CONE, ORTP and PPR values, as many amendments will impact more than one parameter. For example, a change in gross CONE for the reference technology has downstream impacts on the PPR and all ORTP values, according to the RTO.
ISO-NE said it would attempt to validate the impact of individual amendments before next week’s committee meeting, but given “the numerous permutations required to assess all combinations, the ISO cannot determine the impact of hypothetical combinations of amendments ahead of the November MC meeting nor calculate results in real time at that meeting.”
If any amendments pass at the MC meeting, the RTO will calculate their combined impacts on CONE, net CONE, ORTP and PPR and publish them before the Participants Committee vote Dec. 3.
SPP’s Board of Directors last week approved 2021 operating and capital budgets that bend to the realities of COVID-19 and its potential economic impacts.
The budget includes $4 million in “controllable expenditures” that stakeholders recommended be eliminated to balance a net revenue requirement (NRR) they said was too high.
“Given this year and the unusual circumstances and what has happened to the markets, everyone is feeling the pain financially,” Director Susan Certoma, chair of the Finance Committee, told the board and Members Committee during their meeting Oct. 27. “The challenge was, could we also think about our controllable expenses and what we could do with those? There are not that many levers that can be used by SPP.”
SPP’s actual and budgeted/forecasted net revenue requirement for 2017-2023 | SPP
American Electric Power and Oklahoma Gas & Electric pressed the Finance Committee to keep the budget as flat as possible and said there should be a heightened focus on “controllable expenditures.” Those expenses include compensation, travel, meetings, consulting and maintenance, but Certoma said there is no “detailed plan” of which costs to cut.
“Staff will determine how they meet that challenge,” she said.
“The budget reflects the impacts and uncertainty of the pandemic, as well as our ongoing commitment to deliver high-quality services at the lowest possible cost,” CEO Barbara Sugg said.
The Members Committee, which advises the board, unanimously endorsed the budget recommendation.
The actions will result in an NRR of $155.3 million, with net favorable variances in revenues and operating expenses resulting in a projected over-recovery of $16.6 million. SPP is currently forecasting a $153 million NRR this year that will result in an $18.9 million administrative fee over-recovery. Meeting and travel restrictions are contributing to the variance.
The revisions also replace SPP’s administrative fee with a calculation that limits the annual budgeted NRR to a ratio not exceeding 0.43:1 of estimated annual transmission usage, expressed in megawatt-hours. This year’s administrative fee was set at 43 cents/MWh.
The NRR represents SPP’s funding necessary to provide services throughout its footprint. It comprises operating expenses (excluding depreciation and FERC assessment), principal payments on loans for capital expenditures and a capital reserve fund.
SPP’s gross revenue requirement of $188 million for 2021 is a $10 million increase over the 2020 forecast, stemming from an increase in scheduled principal payments on the RTO’s outstanding and new term debt, and lower 2020 operating expenses associated with the pandemic.
The RTO’s 2021 operating plan, with the strategic plan serving as the foundation, was used as a guide to develop the budget.
Directors Accept $532M Tx Plan
The board approved staff’s $532 million 2020 Integrated Transmission Plan and its 54 projects, overriding member concerns about transmission costs and the projected benefits. The plan, which includes 92 miles of 345-kV transmission lines and 141 miles of rebuilt high-voltage infrastructure, was developed over 27 months of collaboration between staff and stakeholders.
The 2020 ITP’s economic projects | SPP
SPP said the upgrades will solve 163 grid issues and should reduce wholesale energy congestion costs while providing estimated future net savings of up to 30 cents on the average monthly residential bill, thanks to a projected 4- to 5.2-to-1 benefit-to-cost ratio.
Golden Spread Electric Cooperative, Liberty Utilities, NorthWestern Energy, OG&E and Oklahoma Municipal Power Authority voted against the plan in the Members Committee.
“We feel we should be giving more credence to the lower-cost options out there,” said OG&E’s Greg McAuley, noting that a $30 million project the utility advocated for was passed over in favor of a $100 million project that had a better adjusted production cost (APC) but resolved less congestion.
Two of the project-cost hawks suggested they will take their concerns to the Strategic and Creative Re-engineering of Integrated Planning Team (SCRIPT), which is responsible for re-engineering SPP’s transmission planning processes. The SCRIPT plans to bring a final report to the board for its consideration and approval next October.
“We’re not real pleased with the cost-benefit calculations. We will be actively working with the SCRIPT to clarify how we calculate those benefits,” Golden Spread’s Michael Wise said. He said SPP’s calculation of benefits by extrapolating five- and 10-year APC out to 15 years and then using inflation or discount-rate measures to reach 40 years is a “leap of faith” when compared to more easily computed 40-year costs for completed transmission.
“We should ensure consumers they’re paying for 40-year projects that will really be beneficial,” Wise said.
“I look at the ITP proceedings, and I think the SCRIPT team is very timely,” Nebraska Public Power District’s Tom Kent said. “I’m growing very concerned about transmission costs. Now is the time to take a hard look at the metrics, especially when the footprint is so rich in generation. As we add more renewables, one has to wonder if we’re heading down the right path and what the reliability impacts are.”
The board also approved a nearly $91 million increase for NPPD’s 345-kV R-Project following the Members Committee’s unanimous endorsement. The approval raises the project’s price tag to $463.4 million.
McCauley, who was among those calling to suspend and re-evaluate the project during the Markets and Operations Policy Committee’s consideration two weeks prior, said he was changing his mind after talking to NPPD. (See “$91M Increase for NPPD’s R-Project,” SPP MOPC Briefs: Oct. 13-14, 2020.)
“Given the circumstance … I think NPPD has done what they can do,” he said. “In spite of that, this situation points out in stark clarity the risk association with building transmission. The fact that it happened to a project of this size and scope, it can happen anywhere. There are unforeseen circumstances that pop up and create risk.”
Arkansas COVID Cases in Wrong Direction
Sugg opened her president’s report by showing a slide “we’re not particularly proud of” — a chart of the increasing new COVID-19 cases in Arkansas.
SPP has based its return to the office and in-person meetings on a 14-day downward trend in cases. Arkansas, home to the RTO’s headquarters, has exceeded the peak of active cases it set in mid-August. The state reported a near record 1,316 new cases on Saturday and 25 deaths, raising the respective totals to 103,482 and 1,925.
COVID cases in Arkansas have been on an upward trajectory. | SPP
“Clearly, we’ve not met our criteria for returning to the office,” Sugg said. “The statistics will have to improve, or that return will be delayed further. It’s just not favorable for us.”
SPP will continue to hold virtual stakeholder meetings through the first quarter of 2021. Ironically, Sugg said the grid operator last year had contemplated increasing its use of virtual meetings to reduce travel costs and meeting expenses.
Sugg said staff are continuing to work through COVID-19’s effects, with the control centers yet to report a single infection. She did allow that she and other executives were conducting the board meeting from their corporate office, noting that “we have better Wi-Fi than at home.”
“The coordination between the two organizations has been outstanding,” Sugg said. “MISO has been absolutely challenged and appreciates the coordination with SPP. We’re very dependent on each other in that part of the country. I am very, very optimistic we’ll make progress working together.”
Con Ed Veteran Elected to Board
Members elected former Consolidated Edison General Counsel Elizabeth Moore to the board. Moore, who has 30 years of experience in the regulatory sector and energy industry, will serve the remainder of the late Bruce Scherr’s term and will begin a new three-year term in January. (See Former NERC Vice Chair Scherr Dies at 72.)
Moore served as counsel to New York Gov. Mario Cuomo and has been named as one of the “25 Influential Black Women in Business” by The Network Journal. She is currently director emeritus on the board of trustees at her alma mater, Cornell University.
Board Chair Larry Altenbaumer and Director Joshua W. Martin III were re-elected to three-year terms.
Members also elected Advanced Power Alliance’s Steve Gaw to fill the new Alternative Power/Public Interest sector’s seat on the committee and then to an additional three-year term in 2021.
Re-elected to three-year terms were Tri-State Generation and Transmission Association’s Joel Bladow (Cooperatives); Xcel Energy’s David Hudson (Investor-Owned Utilities); Omaha Public Power District’s Joe Lang (State); OG&E’s McAuley (IOUs); OMPA’s Dave Osburn (Municipals); and Google’s Jeff Riles (Large Retail Customer).
Board Approval for HITT Proposals
The board signed off on a revision request and several white papers stemming from the Holistic Integrated Tariff Team’s (HITT) recommendations, designed to help SPP successfully meet the ever evolving grid’s challenges.
The white papers were approved unanimously, but the HITT’s proposal that the RTO implement a new cost-sharing methodology for qualifying 100- to 300-kV transmission projects that primarily move power out of local transmission pricing zones met opposition from Southwestern Public Service, OG&E, Public Service Company of Oklahoma, Liberty Utilities and City Utilities of Springfield (Mo.).
The measure (RTWG RR422) would fully allocate those qualifying projects on a regional basis. Transmission owners have largely opposed the proposal, saying it would shift byway cost responsibility from wind-rich areas to others.
The Energy Resource Interconnection Service/Network Resource Interconnection Service (NRIS) Task Force brought forward a 72-page white paper that recommends replacing NRIS with a new capacity resource interconnection service (CRIS).
CRIS provides capacity deliverability from a single resource to any load within a control area, balancing authority or other designated region that contains more than a single load. NRIS provides a generator with a sufficient interconnection to allow it to qualify as a designated network resource on the transmission provider’s system without additional network upgrades.
The board also approved white papers on economic outage coordination, topology optimization and adding new load to the grid, all of which received unanimous approval from the Members Committee.
The first white paper recommends using existing transmission assets to increase grid flexibility and efficiency. The document says that while transmission elements are traditionally viewed as static elements, their topology reconfigurations may provide a means to reliably reroute power around congested facilities without causing additional burden on the system.
The economic outage coordination white paper evaluated other RTOs’ outage-coordination processes and criteria thresholds before concluding SPP will need to invest time and money fully integrating and streamlining the process to take full advantage of the economic benefits.
A Transmission Work Group’s paper documents proposed modifications to Tariff Attachment AQ that would limit its application to new load, revisions to loads and load retirements that need to be addressed outside of the ITP because of timing or some other “significant” reason.
CGC Fills Out Key Stakeholder Positions
Members and the board approved the consent agenda, which included:
the Corporate Governance Committee’s nominations of SPS’ Bill Grant, Evergy’s Kevin Noblet, EDP Renewables’ David Mindham and OMPA’s Melie Vincent to four-year terms on the Strategic Planning Committee. Arkansas Electric Cooperative’s Andrew Lachowsky was nominated to a vacant seat that expires in 2023.
the CGC’s nominations for Kansas Electric Power Cooperative’s Suzanne Lane to the Human Resources Committee and Lincoln Electric System’s Laura Kapustka to the Finance Committee, both for four-year terms.
the CGC’s recommended bylaw and membership agreement revisions clarifying that withdrawing members’ financial obligations are applicable to partial terminations when only some of their transmission facilities are pulled back from SPP. The committee also clarified that non-TOs become TOs upon transferring functional control of Tariff facilities to SPP.
the Supply Adequacy Working Group’s RR412 that allows both new and upgraded capacity from existing generators to be treated equally in qualifying as accredited capacity during the first peak season that each is available, thereby preserving the members’ expected generation investment value.
The consent agenda also included approval of a $14.67 million increase above the $32.46 million original estimate for Empire District Electric and Evergy Kansas Central’s 161-kV rebuild in eastern Kansas; an additional 161/69-kV transformer for Apex Clean Energy’s Jayhawk Wind project in eastern Kansas; modification of an East River Electric Power Cooperative 69-kV project; withdrawal of two notifications to construct; and the 2020 annual violation relaxation limits report.
FERC last week approved SPP’s compliance filing responding to orders calling for more transparency into how RTOs analyze each other’s systems during interconnection studies (ER20-943).
In a letter order Friday, FERC accepted revisions to the SPP-MISO joint operating agreement (JOA) that point to where interconnection customers can find the RTO’s modeling details used in affected-system studies; added details to the sink assumptions; provided for more frequent information exchange during SPP’s three-phase interconnection process; and corrected an administrative error.
SPP’s revisions provided a specific section number for its generator interconnection process and business practices guidelines within Attachment V of its Tariff, where energy resource interconnection service (ERIS) and network resource interconnection service (NRIS) modeling information is contained.
In a related order, the commission directed SPP to make a further compliance filing regarding affected-system coordination procedures (ER20-945).
FERC asked the RTO to explain why it proposed placing ERIS and NRIS modeling information in a particular section of the guidelines for the interconnection process and business practices, but not the section that provides the ERIS and NRIS modeling details the grid operator uses to study interconnection requests on its own system.
Commission Accepts FSR, Rate Schedule Changes
The commission last week accepted compliance filings in two other SPP dockets.
In a proposal to revise the grid operator’s fast-start pricing practices, SPP further revised its Tariff to provide that, for pricing purposes, fast-start resources’ (FSRs) composite offers will be calculated with commitment costs “in effect at the time of the commitment.”
The RTO also added language clarifying that an FSR’s commitment costs will be amortized over its maximum economic capacity operating limit and its minimum run time, and explaining how it calculates the commitment costs added to each breakpoint on the FSR’s energy offer curve (ER20-644).
FERC in July found that SPP’s original fast-start pricing revisions did not allow prices to reflect the marginal cost of serving load. (See “Directs Further Compliance Filing on Fast-start Resources,” FERC OKs 2 Changes from SPP’s HITT Work.)
The commission also accepted SPP’s Tariff revision clarifying the calculation of the transmission congestion rights (TCRs) administration service charge (ER20-2628).
FERC in February approved the RTO’s revisions to Schedule 1A of its Tariff that replace a broad rate schedule with four targeted ones, effective Jan. 1, 2021 (ER20-418). The new schedules take effect in January. (See “Board Approves Modernized Cost-recovery Structure,” SPP Board of Directors/Members Committee Briefs: Jan. 29, 2019.)
However, SPP discovered that the language mistakenly specified that the TCR service charge is calculated at the settlement location level. It added language that clarifies the charge type is calculated at the asset owner level and that two of the other new schedules are calculated at the settlement location level.
NIMECA, Corn Belt Finally Settle
Corn Belt’s headquarters building in Humboldt, Iowa | Corn Belt Power Cooperative
FERC on Oct. 26 approved an uncontested partial settlement and settlement agreement between North Iowa Municipal Electric Cooperative Association member cities and other parties over their annual transmission revenue requirement, formula rate templates and formula rate implementation protocols (ER15-2028).
The settlement resolved all issues set for hearing other than those related to Corn Belt Power Cooperative’s ratemaking treatment of its grandfathered agreements (GFAs), ATRR and formula rate template. The GFAs were a sticking point during hearing and settlement judge procedures that began in 2015.
Joining Corn Belt as intervenors were the Missouri Public Service Commission, Basin Electric Power Cooperative, MidAmerican Energy, Interstate Power and Light, and Missouri River Energy Services.
New England stakeholders frustrated by states’ inability to meet their clean energy goals within ISO-NE’s markets considered last week whether a forward clean energy market (FCEM) might provide a solution.
“I think it’s fair to say that the idea of a forward clean energy market … is one that seems to have great salience for the challenges we face here in the region,” Peter Fuller, principal and founder of Autumn Lane Energy Consulting, said during a Northeast Energy and Commerce Association webinar Wednesday. “It’s one that people have felt ought to be given serious consideration by the states, NEPOOL, the Federal Energy Regulatory Commission and all of the many stakeholders really interested in the success of that market.”
Brattle’s proposed forward clean energy market would be a centralized auction in which buyers and sellers could voluntarily exchange clean energy attribute credits (CEACs). | The Brattle Group
Fuller said it is “becoming increasingly clear that the wholesale market can and should be changed” to address states’ carbon-reduction goals.
In recent years, partly because the wholesale market was not delivering clean energy to the degree that several New England states wanted, they have utilized long-term contracting and procurements of solar energy and offshore wind.
“It may be that a more robust competition between resources that can deliver carbon-free energy [is] both more reliable and more cost-effective for ratepayers; that’s at least the hope related to the forward clean energy market,” Fuller said.
Federal-State Conflicts
He said the FCEM design would address the conflict between state and federal policymakers on issues such as the minimum offer price rule (MOPR) and Competitive Auctions with Sponsored Policy Resources (CASPR), a two-tiered capacity construct intended to prevent consumers from paying twice for the same capacity through both the Forward Capacity Market (FCM) and subsidies for state-mandated resources.
“We think FCEM can be a vehicle to address that conflict,” Fuller said.
Michelle Gardner, senior director of regulatory affairs in the Northeast for NextEra Energy Resources, added that “looking at the massive transition that we’re anticipating over the coming decades, to me this is really about harnessing the competition and the balance between both new and existing resources.” She said states could do solicitations for existing resources, “but for the most part, the existing resources in the market that do contribute to carbon abatement are not valued.”
Clockwise top from left: David O’Connor, ML Strategies; Greg Cunningham, Conservation Law Foundation; Peter Fuller, Autumn Lane Energy Consulting; Rebecca Tepper, Massachusetts Attorney General’s Office; and Michelle Gardner, NextEra | NECA
Rebecca Tepper, chief of the Massachusetts Attorney General’s Office Energy and Telecommunications Division, said that “markets are not going to bring us to or sustain a low-carbon future as they are currently designed.”
At a symposium the AG’s office held last year, two reasons were cited for why the markets were not working, Tepper said.
“One, it wasn’t bringing in the renewables, because of the MOPR, and that was resulting in double-counting,” Tepper said. “And two was resource adequacy. The forward clean energy market addresses No. 1, but it’s not designed to address No. 2.”
While the current system design is based on peak-hour demand, a transition to more clean energy will require availability at all hours of the day, Tepper said.
“We’re going to need to value other products like ramping and storage and others to incentivize them to address resource adequacy,” Tepper said.
Do the states have to control or have a more significant influence on an FCEM to work? Fuller said the market design “would be explicitly designed to create a high degree of control for the states.”
“I think who does the market administration is less important than making sure that it’s done in a way that passes muster in terms of nondiscriminatory competition among sources,” said Fuller, who added that the ultimate idea is to procure a generalized low-carbon product at the lowest possible cost.
Greg Cunningham, vice president and program director for clean energy and climate change at the Conservation Law Foundation, said existing programs such as state renewable portfolio standards could work with an FCEM.
“It’s conceivable that a form of RPS compliance could be participation in this market,” Cunningham said. “It obviously would have potentially negative implications for the REC market.”
Cunningham said he also appreciated Tepper’s concern about redundant costs.
“Striking the balance between the onset of a new [market] and moving away from the old one in a timely fashion so that we have the certainty that we as consumers in our homes and businesses and industries want from an electrical availability perspective but also from a cost perspective — that’s essential,” Cunningham said.
Could an FCEM address resource adequacy? There is “a lot of promise there to look at [the Forward Capacity Market and FCEM] in a combined fashion and a lot of efficiencies” Fuller said.
“Nothing that is going on with FCEM would alter or diminish the role of ISO[-NE]’s existing programs to maintain resource adequacy and reliability,” Fuller concluded. “The ISO’s capacity market might need to evolve in response to more clean energy with different attributes and characteristics than the fossil-fueled stuff that we’ve all become accustomed to, but those are going to happen whether we have an FCEM or contract-based system. We’re going to have to evolve to a bit of a different system. Nothing here would undermine resource adequacy, even though nothing in FCEM addresses resource adequacy directly.”
Although the coronavirus pandemic has sucked up most of the oxygen in this year’s presidential and congressional races, West Coast wildfires, record-breaking heat waves and more than two dozen tropical storms have also made climate change an issue impossible for voters to ignore.
A victory by former Vice President Joe Biden and a Democratic pickup of three Senate seats would reassert the U.S.’ commitment to the Paris Agreement on climate change and give the party a shot at enacting legislation to meet the agreement’s targets. President Trump’s re-election — even if he faces a hostile Senate — would likely mean four more years of climate denialism and regulatory rollbacks. The Washington Post reported last week that Trump had “weakened or wiped out more than 125 rules and policies aimed at protecting the nation’s air, water and land, with 40 more rollbacks underway.”
Regardless of what happens in D.C., however, state officials are likely to continue pursuing their own clean energy targets. In addition to races in 86 of the 99 state legislative chambers and 11 gubernatorial contests, state regulators are facing re-election from Georgia to Montana, with a climate-related measure on the ballot in Nevada.
Biden Plan
In July, Biden outlined a $2 trillion plan to eliminate power sector carbon emissions by 2035 and make the U.S. the leader in electric vehicle production, calling the climate change challenge a “once-in-a-lifetime opportunity to jolt new life into our economy, strengthen our global leadership [and] protect our planet for future generations.” (See Biden Offers $2 Trillion Climate Plan.)
Biden pledged to build on the billions in clean energy investments of the Obama administration and reverse the Trump administration’s environmental rollbacks. The Democratic candidate’s proposal was developed with input from former presidential candidates Sen. Bernie Sanders (I-Vt.) and Gov. Jay Inslee (D-Wash.) and is markedly more ambitious than the policies he backed during the primaries, when he called for spending $1.7 trillion over 10 years and eliminating CO2 emissions from power plants by 2050.
The shift reflects both his desire to motivate the liberal wing of the Democratic Party and to provide an economic stimulus to aid recovery from the pandemic. “We’re not just going to tinker around the edges,” he promised. “Science tells us we have nine years [to cut emissions] before the damage is irreversible, so my timetable [for] results is my first four years as president.”
The plan proposes funding to support EVs, improve energy efficiency and reduce the costs of clean energy technologies. Seeking to head off criticism that the plan will harm the economy, Biden framed his proposal as an economic development program, repeatedly referring to creation of “union” jobs.
Fracking an Issue in Pa.
During repeated campaign visits to the crucial state of Pennsylvania, Trump has warned that the former vice president will seek to eliminate fracking. Biden has denied the claim, saying only that he will end subsidies for fossil fuels and stop issuing new drilling permits on federal lands and waters.
ClearView Energy Partners calculated that the 10 counties responsible for 91% of Pennsylvania’s natural gas production had a significant role in Trump’s narrow 2016 win in the state. Except for Allegheny County, home to Pittsburgh, all of the top gas-producing counties voted for Trump, who added almost 31,000 votes to the total that GOP candidate Mitt Romney received in 2012. Trump won the state by less than 45,000 votes out of more than 6 million cast, a difference of 0.72%. Pennsylvania holds 20 of the 270 Electoral College votes needed to win the presidency.
Congress
Democrats are expected to hold or increase their current 232-197 edge in the House of Representatives. (There are also five vacancies and one Libertarian.) But approving legislation to implement Biden’s plans would likely require them to take control of the Senate, now held by Republicans 53-47, including two independents who caucus with the Democrats.
Polling indicates the Democrats will likely lose a seat in Alabama but gain one each in Colorado and Arizona. Democratic candidates also are within reach in toss-up races in Maine, North Carolina, Iowa, Georgia, South Carolina and Montana. A blue wave could also threaten Republican seats in Kansas, Texas, Alaska and Georgia’s second seat.
The commission is currently controlled 2-1 by Republicans. In July, Trump nominated Democrat Allison Clements, energy policy adviser for the Energy Foundation, and Republican Mark Christie, chair of the Virginia State Corporation Commission, to fill the two vacancies. (See FERC Nominees Bob and Weave Through Senate Hearing.)
Arizona Corporation Commission
In the West, Nevada voters will decide whether to require half the state’s electricity to come from clean energy resources by 2030, and voters in Arizona, Montana and New Mexico will vote for utility regulators in contentious races that could determine their states’ energy futures.
Renewable energy policy, via regulator elections and voter initiatives, is on the ballots of Western states Tuesday. | Bureau of Land Management
Three of the seats on the five-member Arizona Corporation Commission are up for grabs Tuesday, with only one incumbent on the ballot.
The commission, which regulates utilities and rates, voted Thursday to make the state the latest in the West to follow California’s lead and adopt a 100% clean energy mandate by mid-century. New Mexico and Washington have similar mandates approved by lawmakers.
The commission, which has four Republicans and one Democrat, voted 3-2. Chairman Bob Burns and Commissioner Boyd Dunn, neither of whom is seeking re-election, voted with Democrat Sandra Kennedy in support of the measure.
“The climate crisis is impacting Arizonans right now,” Kennedy said in a statement after the vote. “I am glad the commission was finally able to look past partisan politics to support science and economics-based policy that stakeholders, utilities and ratepayers could all agree upon and benefit from.”
The question of renewable energy and California’s influence on the more conservative Arizona has been a major source of contention in state politics and the utility industry.
Arizonans voted overwhelmingly in 2018 to reject Proposition 127, a measure that would have required the state’s power providers to generate at least half their annual sales of electricity from renewable resources by 2030. The race became a high-priced battle between California billionaire Tom Steyer, whose environmental advocacy group NextGen America backed the proposal, and Arizona Public Service (APS), which spent more than $50 million in the fight. (See High Failure Rate for Western Ballot Measures.)
Critics say APS has too much influence on commissioners, including through campaign contributions.
Six candidates are seeking the seats held by Burns, Dunn and Republican Lea Marquez Peterson — the only incumbent on the ballot.
The Washington Post reported Friday that billionaire and former New York City Mayor Michael Bloomberg, an advocate of carbon-free energy, had contributed $6.3 million to the three Democrats running: William “Bill” Mundell, Shea Stanfield and Anna Tovar. Two Republicans, Jim O’Connor and Eric Sloan, are also on the ballot.
The three leading vote-getters will join Kennedy and Justin Olson on the commission.
Arizona is one of 11 states where utility regulators are elected, not appointed by a governor or lawmakers. Also facing elections Tuesday, according to Ballotpedia, are regulatory commissioners in Alabama, Georgia, Louisiana, Montana, Nebraska, New Mexico, North Dakota, Oklahoma and South Dakota. (The 11th, Mississippi, elects its state officials in odd-numbered years, always in the year preceding the presidential election.)
The Montana race features Democrats running for two open seats on the all-Republican Public Service Commission, which has been plagued by infighting and scandal in recent years, the Montana Free Press reported. The commission’s support of coal power is out of sync with the growing progressive populations of cities such as Missoula and Bozeman, making change in the commission’s makeup and state energy policies a possibility this year.
New Mexico PRC
In New Mexico, lawmakers placed a constitutional amendment on the ballot that would shake up the state’s Public Regulation Commission by letting the governor appoint three at-large members in place of the five members now elected by geographic district. Both Republican and Democratic lawmakers overwhelmingly backed the ballot measure, and Gov. Michelle Lujan Grisham (D) supports it.
Many elected officials were angry with PRC commissioners for what they called an attempt to skirt the state’s landmark 2019 Energy Transition Act, signed by Lujan Grisham, which requires the state’s investor-owned utilities to get all their electricity from carbon-free sources by 2045. (See New Mexico Moves Toward Clean Energy, EIM Participation.)
Two current members of the PRC — Cynthia Hall and Stephen Fischmann — back the amendment, saying some of those elected to the PRC lack the backgrounds needed to understand complex regulatory issues.
Other members of the PRC argue that allowing the governor to appoint its members would deprive voters, especially those in rural disadvantaged communities, of the opportunity to influence ratemaking and policy decisions. (See Energy Amendments on NM, Nevada Ballots.)
Nevada Question 6
Nevada’s Question 6 asks voters for the second time in two years whether the state should make clean energy goals a part of its constitution.
A law signed by Gov. Steve Sisolak (D) in April 2019 requires the state to get half its electricity from non-carbon-emitting resources by 2030, but environmentalists worry it could be overturned by elected officials if the political winds shift.
Amendments to Nevada’s constitution must be approved in two consecutive elections, so the question faces a final vote this year after winning 59% support in 2018. That effort, like the current one, was bankrolled by Steyer.
The U.S. transmission system will require significant restructuring and greater alignment with public policy goals to meet the future needs of the electricity sector, according to industry insiders speaking at WIRES’ virtual fall member meeting last week.
The trade group promotes investment in transmission and progressive government policies to advance energy markets, economic efficiency, and consumer and environmental benefits through electric infrastructure development.
Here is some of what RTO Insider heard at the event.
Logjams, Dysfunction
During a panel on the integration of renewable energy and its impact on transmission, former FERC Chairman Joseph Kelliher said if he were an all-powerful king or wizard with a magic wand, he would change the structure of transmission ownership in the U.S.
Clockwise from top left: Joseph Kelliher, former FERC chairman; Rob Gramlich, Grid Strategies; Jasmin Melvin, S&P Global Platts; and Antoine Lucas, SPP | WIRES
“When I was at FERC, I was really stunned when National Grid testified at a FERC conference saying that the U.S. had at the time 492 different owners of the grid, and the government owns a third of the grid,” Kelliher said. “I think it would work better if you had a series of regional, national grids, something along the lines of our U.S. pipeline network. Pipelines are all corporate structured. They’re separated from production, dedicated completely to the business of moving other people’s gas. If you had regional, national grids whose only businesses were transmitting other people’s electricity, I think they’d be much more focused on quickly investing and anticipating the needs of the market.”
Kelliher added that the more realistic option is “effective, proactive regional transmission planning and execution of those plans.”
Grid Strategies President Rob Gramlich concurred and added that he does “a lot of work with renewable energy companies and associations, and what they see and feel right now is a symptom of a bigger disease.”
“What they see is interconnection queue logjams and dysfunction where you get to a certain number of projects in the queue, and suddenly the costs balloon, and then they jump out, and everybody else has to be restarted. It’s a total mess,” Gramlich said.
He said the interconnection queue problems could be “alleviated” by aligning transmission planning — and the cost allocation associated with it — with utility and state public policy goals.
Antoine Lucas, vice president of engineering for SPP, said he advocates for improved or increased alignment between the transmission planning processes and cost allocation.
“Any efforts that can create more alignment in that area, create more of a clear vision, will remove a lot of the hurdles that we see plague some of the transmission planning processes, including the generator interconnection process that Rob mentioned,” Lucas said. “We do have a lot of entities who are all working hard to try and serve the needs of their members or customers, but when you have so many different plans, different strategies, optimizing those is a significant challenge that if we could bring more alignment to it, I think we’d be able to see more get done at the national level.”
Kelliher said regional grid development currently relies “very heavily on network upgrades funded by generators,” which “is an inefficient way to build out the grid.”
“If you rely less on network upgrades and have more proactive regional planning, you have more clear cost allocation that’s as regional as possible,” Kelliher said. “You probably need to abandon the competitive provisions of [FERC] Order 1000, which I don’t take lightly. But I think the reason you have utilities deferring, going to great lengths to avoid regional cost allocation, is they don’t want competition for their projects.”
Gramlich said he would like to see much more hands-on leadership from FERC, “not just serving as sort of judges.” He cited current Commissioner Richard Glick and former Commissioner Cheryl LaFleur, now on the Board of Directors for ISO-NE, as positive examples of FERC working with governors and stakeholders on the interregional planning process.
Gramlich added there are “30 GW of offshore wind in the goals across the Northeast states [and] that it’s going to be much more efficient to proactively build transmission if those states get together and say, ‘OK, here’s what we’d like our RTOs and ISOs to do to proactively plan this.’ So, I think it will require both state and federal leadership outside of just the stakeholder processes.”
From the RTO perspective, interregional projects have two main challenges, Lucas said: cost allocation and siting. He said siting “seems to be an issue that creates a tremendous amount of friction, specifically when you’re talking about state authority versus federal authority.”
“I think any clarity on that would go a long way in helping to solve the problem, but I do recognize it’s a very challenging issue,” Lucas said. “If it were to be taken up again at FERC, I don’t know how successful it might be.”
‘No Silver Bullet’ for Energy Transition
In his keynote speech, Sen. Joe Manchin (D-W.Va.), ranking member on the Senate Energy and Natural Resources Committee, said the demand for clean energy is growing to address climate change. The challenge, however, is “maintaining affordable, reliable and dependable energy while also reducing emissions, and ensuring that hardworking families and communities that have powered our nation to greatness aren’t left behind in the transition.”
Sen. Joe Manchin (D-W.Va.) | WIRES
“There’s no silver bullet. We’re going to need a variety of solutions to ensure we can meet this challenge both at home and around the world, where fossil fuels are going to be used for decades to come,” Manchin said. “That’s why I say we need innovation, not elimination.”
Manchin said that his and Sen. Lisa Murkowski’s (R-Alaska) American Energy Innovation Act would invest $24 billion to advance critical technologies such as renewable energy, advanced nuclear, cybersecurity, energy storage, grid modernization, and carbon capture, removal, utilization and sequestration. It would also push technologies that can reduce emissions in four sectors of the economy that currently contribute about 90% of the nation’s overall greenhouse gas emissions.
“These varied solutions are necessary for us to reach any goal for reducing greenhouse gas emissions,” said Manchin, who hopes the bill comes to a vote during the lame-duck session following the elections. “They would also strengthen the United States’ position as an exporter of the technologies other countries will also need to tackle this global climate problem.”
Manchin added that the energy mix is changing with more renewables coming online and the retirements of older fossil-fuel units. That means “cost-effective energy storage is a critical technology to advance, and that’s also why a more flexible and modern electric grid is needed,” he said.
He said there is “a good argument for investment in grid infrastructure to help us meet our challenges.”
“We know that transmission is an essential component of a reliable and resilient grid because we know what happens when congestion disrupts the system,” Manchin said. “I expect transmission to get a good deal of attention next year. I know several bills seek to advance transmission by improving the interregional planning process at FERC or extending the investment tax credit to transmission.”
Manchin added that he hoped the “two very qualified nominees” for FERC — Allison Clements and Mark Christie — can be confirmed during the lame-duck session. (See FERC Nominees Bob and Weave Through Senate Hearing.) Clements, a Democrat and energy policy adviser for the Energy Foundation, and Christie, a Republican and chair of the Virginia State Corporation Commission, were nominated by President Trump in late July. Clements would fill the seat left open by the departure of LaFleur in August 2019. Christie would take the place of Bernard McNamee, who departed in September.
“I think we can all agree that the best FERC is a fully seated FERC,” Manchin said.
Xcel Energy on Thursday reported third-quarter earnings of $603 million ($1.14/share), beating Zacks Investment Research’s consensus expectation by 7 cents. A year ago, Xcel’s earnings were $527 million ($1.01/share).
The company narrowed its 2020 earnings guidance to $2.75 to $2.81/share and initiated its guidance for 2021 at $2.90 to $3/share.
The Minneapolis-based company said it intends to invest $22.6 billion in base capital, including an incremental $1.4 billion addressing COVID-19’s economic effects in Minnesota. Xcel has proposed spending money on the grid, solar facilities and repowering aging wind farms, which it said would create 5,000 jobs and add 5 GW to its renewable portfolio.
| Xcel Energy Center
Xcel also outlined a 10-year vision to power 1.5 million electric vehicles in its service territory by 2030. The company already installs home chargers for customers but wants to see fast-charging stations expanded along highways and other travel corridors.
“I’m particularly excited about EVs. … The variable cost of an EV is significantly below that of a gasoline[-fueled]” vehicle, CEO Ben Fowke told financial analysts, with the cost of EV charging equivalent to 60-cents/gallon gasoline. “So while EVs are expensive today, we think that cost comes down. The key to me is to get these stations built. … One of the biggest barriers to purchasing an EV is range anxiety.”
Xcel’s share price closed Friday at $70.03, having lost 23 cents after the earnings release.
ERCOT stakeholders last week approved the oldest protocol change on the grid operator’s books, shooting down a late request to table the measure in the process.
Luminant filed comments on the revision request the day before it would be considered by the Technical Advisory Committee and requested a delay so committee members could review the comments.
The Nodal Protocol revision request (NPRR945) is hardly controversial. It simply removes the “associated load” term that proponents say has been interpreted in some instances to restrict private-service arrangements otherwise authorized under state law and regulatory precedent.
“We filed the comments because we’ve heard from different groups that the NPRR didn’t change anything,” Luminant’s Ian Haley said during the TAC’s web meeting Wednesday. “We had concerns that TAC would be voting without understanding what it does. We wanted to ensure TAC is well aware of what we’re voting on today.”
Attorney Katie Coleman, representing Texas Industrial Energy Consumers and the measure’s sponsor, accused Luminant of “a little bit of sandbagging,” noting the revision dates back to May 2019 and that the company has had “ample opportunities to relay this concern.”
She reminded members that the issue has been discussed several times within the TAC’s Protocol Revision Subcommittee and that she conducted a workshop where she went through the NPRR’s effects and its history.
“This section of the protocols was meant to define the electric configurations that were eligible for net metering. It does not pertain to legal and regulatory requirements,” Coleman said. Referring to “associated load” as an “ambiguous term,” she said, “That term has been interpreted as load and generation to be owned by the same entity.
“That’s not what the language says, and I’m not sure it’s clear to market participants. It’s more restrictive than what the law allows in certain scenarios,” Coleman said. “We have [private-network] sites set up today, lawfully set up, and some reviewed by the [Public Utility Commission] in contested cases, where load and generation is not owned by same entity.”
Removing the term, Coleman said, will provide regulatory certainty for both existing and planned sites by deferring to legal and regulatory precedent and avoid potentially inconsistent interpretations of the protocols.
The NPRR adds language that “explicitly state[s]” that private-service arrangements must comply with PUC precedent and Texas’ Public Utility Regulatory Act. It also adds market transparency with a new reporting requirement that identifies all generation resources and settlement-only generators registered as part of behind-the-meter private-use networks (PUNs).
Luminant says NPRR945 provides clarity to those seeking to set up PUNs, but it raises “many additional and equally important policy questions, some of which cannot be addressed by ERCOT stakeholders.”
The generation company said PUNs are neither typical loads nor typical generation resources and are subject to nonmarket incentives that “warrant appropriate controls” to ensure their usage “balances risk and reward fairly across market sectors and customer classes.”
“In an energy-only market, this can actually harm resource adequacy objectives … by allowing a single entity to capture scarcity value that does not accrue to the rest of the market,” the company said in its comments. “Luminant supports correct pricing outcomes that utilize the demand of consumers in ERCOT and all generation bids needed to meet that demand. Unfortunately, [PUNs] bypass this needed aspect of price formation.”
“As Luminant is starting to understand, this has potential implications that are pretty serious,” said Golden Spread Electric Cooperative’s Michael Wise, saying he was concerned about cost shifts and their unintended consequences. “ERCOT’s interpretation of the protocols and the term ‘associated load’ has protected consumers very well. We believe it’s probably one of the most important issues brought forward to stakeholders and it merits this attention.”
Other TAC members weren’t so sure.
“With all due respect to Luminant and Golden Spread, these issues you’re raising are issues we’ve been discussing for months and months,” Demand Control’s Shannon McClendon said. “Katie has given detailed information. PUNs do not cause additional costs to the consumer. That’s a red herring Golden Spread is putting out there.”
Reliant Energy Retail Services’ Bill Barnes said that although he shared some of Luminant and Golden Spread’s concerns, he was “cautiously supportive” of NPRR945.
“I don’t think minds will change in one month. I don’t see the need to table,” he said.
The motion to table failed 8-22. The TAC then passed the measure by a 23-5 margin, with two members abstaining.
Staff, WMS to Address Market Delays
ERCOT staff will work with the TAC’s Wholesale Market Subcommittee to address what has literally become a growing problem.
At issue are the increased complexities of the day-ahead market (DAM), which has led to a steady increase in the market’s ability to publish its results on time. There have been 20 delays this year, the most since 42 in 2011, the first year of ERCOT’s nodal market.
ERCOT has seen increasing delays in its day-ahead market, driven in part by more granular point-to-point bids. | ERCOT
The grid operator allots three-and-a-half hours for the DAM’s execution, during which software must optimize its time, validate data inputs, execute the price-validation tool and post results, among other tasks. Input/output verifications and data errors can also lead to delays.
“There’s a lot of iteration in the DAM’s execution. Because of those iterations and other factors, we could have long run times to clear the DAM,” said Kenan Ögelman, ERCOT vice president of commercial operations. “If we get more than 170,000 [point-to-point (PTP) interval] submissions, we’ll pretty much have a DAM delay. An increase in settlement points can also lead to long run times.”
Ögelman said DAM participation has trended upward, with PTP bids largely contributing to the increased variables. Energy bids and energy-only bids have also grown, and binding constraints are on an upward path.
He said staff haven’t been “sitting on our hands,” but going after low-hanging fruit — “easy for us to do on our own,” Ögelman said — has resulted in staff falling further behind in solving the problem.
“We would like to engage stakeholders in an organized basis,” Ögelman said. “When I look at the solutions before us, they all have some drawbacks. I’m not seeing some perfect, low-cost solution without adverse effects.”
TAC Approves 7 Changes, Tables 8
The TAC’s unanimously approved consent agenda resulted in the approval of four NPRRs, a system change request and single revisions to the Planning Guide and Settlement Metering Operating Guide. Eight other change requests were tabled while they wait on their related NPRRs.
NPRR1028: requires qualified scheduling entities to notify ERCOT of physical limitations on their resources’ starting ability that are not modeled in the reliability unit commitment software and excuses compliance with parts of RUC dispatch instructions that violate a notified resource’s physical limitations. The NPRR also establishes a requirement that ERCOT extend a RUC commitment to honor a resource’s minimum run-time limitation when a physical limitation delays its ability to reach its low sustained limit.
NPRR1031: requires ERCOT to post operations messages informing market participants when load is curtailed because of a transmission problem.
NPRR1032: limits the DC tie schedules used in RUC optimization and settlements to the ties’ physical rating.
NPRR1041: adjusts the expiration of the protected information status of wholesale storage load data from 180 days to 60 days, aligning the disclosure of real power consumption and metered generation output to 60 days after each operating day.
PGRR023: adds a requirement that transmission service providers submit and annually review a list of contingencies for their portion of the system, ensuring that the appropriate contingencies are submitted for ERCOT and NERC planning criteria.
SCR812: creates an Intermittent Renewable Generation Integration report similar to wind and solar power production integration reports.
SMOGRR023: provides an option for a professional engineer’s nameplate certification of newly installed or replaced instrument transformers when nameplate photos cannot be physically accessed, and replaces a list of instrument transformer nameplate data requirements by referencing Institute of Electrical and Electronics Engineers standards.
Entergy held its third-quarter earnings call with financial analysts Wednesday as yet another hurricane, the fifth to hit Louisiana this season, bore down on the state.
“We’ve activated our storm response plan, and we are fully prepared and ready to respond,” Entergy CEO Leo Denault told analysts. “We’ve had a record-breaking storm season with back-to-back hurricanes hitting our service area. Yet no matter what 2020 threw at us, we remain steadfast in delivering on our commitments to our customers, our communities, our employees and our owners.”
Hurricane Zeta made landfall later that evening, ripping through Entergy’s New Orleans hometown with 110 mph winds. The most powerful hurricane to hit the U.S. this late in the year since 1899, Zeta knocked out power to more than 480,000 customers. By Friday morning, 327,000 were still without service, with some facing prospects of a full week without power.
Zeta followed Laura in August and Delta in October, both of which caused significant damage west of New Orleans. Aided by mutual assistance partners, Entergy deployed 12,000 workers after Delta to restore most of the nearly 500,000 outages in five days.
“We showed why we are best-in-class in storm response as we successfully managed to back-to-back major hurricanes all amid a global pandemic. That’s what we prepare for, and that’s what we do,” Denault said. “We can control what we can control. We can’t control the public health crisis, so we’re going to control what we can control.”
Entergy service trucks line up in preparation for restoration work. | Entergy
Entergy reported third-quarter earnings of $521 million ($2.59/share), as compared to 2019’s third quarter of $365 million ($1.82/share). That exceeded analysts’ expectations of $2.42/share, according to Zacks Information Research.
Denault said the results “amid these extraordinary times” demonstrated Entergy’s progress in building a “simpler, stronger and more resilient company.”
Entergy’s share price lost traction during the week, as did the rest of the broader market. Shares closed Friday at $101.22, down 5.8% following the earnings announcement.
FERC last week approved a settlement between SERC Reliability and Associated Electric Cooperative Inc. (AECI) for violations of NERC reliability standards. The ERO notified the commission of the settlement, which carries a penalty of $430,000, in a Notice of Penalty (NOP) on Sept. 30 (NP20-22); FERC indicated in a notice Friday it would not review the NOP, letting the agreement stand.
| SERC Reliability
The commission also accepted a settlement between an unnamed entity and its compliance enforcement authority for violations of NERC’s Critical Infrastructure Protection (CIP) standards. NERC’s NOP for the CIP violations, also filed Sept. 30 (NP20-23), follows the organization’s new policy of treating CIP noncompliance information as critical energy/electric infrastructure information (CEII) in its entirety. (See FERC, NERC to End CIP Violation Disclosures.)
Up to last month, NERC selectively redacted potential CEII from its filings to the commission. (See FERC Accepts WECC Violation Settlement.) In what is likely to be standard policy in such cases going forward, all information about the settlement — including the number, date and location of violations; the entities involved; mitigation actions; and penalties assessed — were included in a separate filing that is visible in the docket’s list but not accessible by the public.
Audit Uncovers Longstanding Issues
SERC’s settlement with AECI involves violations of a number of standards by the cooperative:
EOP-008-1 — Loss of control center functionality (two violations)
FAC-009-1 — Establish and communicate facility ratings
Per the terms of the agreement, AECI neither admitted nor denied the violations but did agree to the monetary penalty and additional mitigation and compliance activities.
The infringements of EOP-008-1 and FAC-009-1 were discovered during a compliance audit conducted from July to October 2016. However, the violations had been ongoing for several years at that point: since 2013 in the case of the EOP-008-1 violations, and 2007 for the FAC-009-01 issue.
AECI’s two infringements of EOP-008-1 concern requirements R1 — requiring reliability coordinators, balancing authorities and transmission operators (TOPs) to have a plan for meeting their obligations for reliable operation if their primary control centers are lost — and R4 — mandating BAs and TOPs have backup functionality for maintaining compliance with reliability standards during a loss of primary control center functionality. Both violations began on July 1, 2013, when the standard became enforceable.
As to the first requirement, SERC determined that the agreement between AECI and its six generation and transmission (G&T) cooperatives, which operate as regional dispatch centers (RDCs), did not require the creation of such a plan. The regional entity ruled the primary cause of the violation to be “management oversight” on the part of AECI leadership for “failing to ensure the implementation of an organizational model that reflected the [cooperatives’] role” in maintaining TOP functions.
A contributing cause was an “erroneous belief” by AECI’s management that backup plans were only required if all six G&Ts’ primary and backup control centers were lost. In reality, none of the G&Ts had a backup control center, meaning that a failure of even one primary center would put that cooperative out of action and potentially spark cascading failures. The lack of backup control centers was at the core of the R4 violation as well.
Both violations were found to pose a serious risk to the reliability of the bulk power system, as they could significantly lengthen response time in an emergency situation. AECI committed to a number of mitigating activities, primarily involving revisions to its rules for loss of RDC functions in the case of requirement R1 and requiring G&Ts to install backup facilities to fulfill requirement R4. The mitigation plans are expected to be fulfilled by the end of this year.
The FAC-009-1 violation was initially discovered at the same audit, when SERC determined that ratings for AECI’s solely and jointly owned facilities were not consistent with its stated facility ratings methodology (FRM). However, the full scope was not visible until SERC issued a request for information that required AECI to evaluate all transmission and generation facilities. At that point, the cooperative discovered that 101 of its 415 transmission facilities and eight of 25 generation facilities were incorrectly rated.
SERC assessed the violation as a moderate risk to the BPS; no harm is known to have occurred. In response to the violation, AECI rerated all transmission and generation facilities in accordance with its FRM, with all work completed by June 2019. Additional mitigation measures by the cooperative include revising its ratings application procedure, creating a new procedure for documenting asset database management processes and deploying new asset management software.
Relay Test Leads to Procedure Oversight
The remaining violations were submitted to SERC via self-report, with the TOP-004-2 infringement reported earliest of the three.
TOP-004-2 requires TOPs to “implement formal policies and procedures to provide for transmission reliability,” including switching transmission elements. AECI reported to SERC in March 2017 that one of its G&Ts had failed to follow the cooperative’s switching order procedure (SOP) following the inadvertent trip of a circuity breaker during relay testing at a substation. The operator at the G&T did not contact AECI prior to returning the breaker to service as required in the SOP.
SERC rated the violation as a moderate risk but noted that AECI had reported a similar incident of noncompliance with TOP-004-2 in 2015 (NP16-21). “The underlying cause of the prior noncompliance was similar, and the mitigation for the prior noncompliance should have prevented [this] noncompliance,” the RE said.
AECI’s mitigation plan, submitted Sept. 13, 2019, includes semiannual training for all G&T relay technicians on the SOP, along with modifying system control software to remind operators to contact AECI prior to operating BPS elements.
Training, Certification Round out Violations
AECI’s report of its PER-003-0 violation, submitted on July 24, 2019, saw the cooperative acknowledge that personnel working in the RDCs operated by its G&Ts had failed to obtain valid NERC certificates as required by the standard. SERC also attributed this shortcoming to management oversight on the part of AECI, alleging that the cooperative’s agreement with its G&Ts did not fully account for the functions they were expected to perform. As a result, AECI did not realize that the responsibilities of the affected positions required staff that were fully certified by NERC.
SERC determined that this violation posed a serious risk to the reliability of the BPS, as did the violation of PER-005-1, under which AECI reported that it did not have a systematic approach for training system operators employed by its G&Ts. The utility committed to mitigation activities for the PER-003-0 violation, including the creation of a NERC certification and training task force and a program to ensure management and implementation of the standard.
AECI’s proposed certification and training task force is a factor in planned mitigation measures for PER-005-1 as well. In addition, the entity is also developing a list of company-specific reliability tasks for all G&Ts along with programs to verify the capabilities of personnel assigned to perform those tasks. Mitigation for the PER-005-1 infringement was reported complete earlier this year, while the PER-003-0 mitigation is expected to be finished by next June.
