FERC on Thursday approved a CAISO plan meant to allow co-located resources, such as solar arrays with battery storage, to connect to the grid more quickly and seamlessly in the coming months (ER20-2890).
CAISO had asked FERC to speed approval of the measure to head off projected resource shortfalls next summer like those that plagued California in August and September, when the state ran short of electricity during Western heat waves as solar and wind dropped offline at night.
California had insufficient storage of renewable resources to cover the shortfalls, but CAISO has about 20 GW of storage in its interconnection queue and wants to bring part of it online before the next hot spell.
“The proposed Tariff revisions are initial steps toward developing more robust rules and models to integrate co-located resources and hybrid resources and optimize their performance,” FERC said in its decision.
| 174 Power Global
The co-located resource proposal is part of CAISO’s hybrid resources stakeholder initiative, which includes a second phase dealing with hybrid resources. The ISO’s Board of Governors adopted the second phase Thursday. (See related story, CAISO Governors Honor Olsen.)
The co-located plan governs generation and storage resources that share a single point of interconnection but have separate IDs, allowing CAISO to dispatch the resources individually. The rule changes take effect in December.
The second-phase proposal would dispatch solar or wind plus storage as a single unit. It is scheduled for implementation in October 2021. CAISO management decided to implement the co-located plan first because it involves relatively familiar procedures. The ISO said the hybrid resources plan is more complex and requires additional time for planning. (See CAISO Adopts Co-located Resources Plan.)
Among the changes FERC approved Thursday are market rules to ensure resources that share the same interconnection point do not exceed its limits. The Tariff changes also require wind and solar resources paired with storage to provide CAISO with data that allow for better generation forecasting based on weather.
A special public meeting of the Oregon Public Utility Commission last week illustrated the complexity of issues and interests at play for utility regulators charged with putting a state decarbonization plan into practice.
The PUC convened an online meeting Thursday to hear stakeholder comments on a raft of draft work plans to implement portions of Executive Order 20-04, which Gov. Kate Brown issued in March to direct state agencies to take measures to reduce and regulate Oregon’s greenhouse gas emissions.
Brown’s order aligns with an Oregon law that requires the state to reduce GHG emissions to 45% below the 1990 level by 2035 and at least 80% by 2045.
More than 120 people tuned into Thursday’s meeting, including representatives of electric and natural gas utilities, renewable and environmental advocacy groups, labor organizations and Native American tribes. “You may notice from the number of participants in this webinar that this is a topic that a lot of people care about,” PUC Chair Megan Decker said in opening the meeting.
Oregon PUC Chair Megan Decker | Oregon PUC
The draft work plans, developed by PUC staff and still subject to commission approval, cover three broad themes.
The first theme, “GHG Reduction Activities,” is broken down into three subsets: Utility Planning, Utility Services and Activities, and Transportation Electrification. The objective of the Utility Planning work plan, according to a PUC document, is “to identify, prioritize and deploy strategies to enhance and refine our existing least-cost, least-risk framework to ensure energy utilities are focusing their systemwide resource strategies on making rapid, large-scale and sustained progress to meet GHG reduction goals.”
The Utility Planning work plan, slated for adoption in the second quarter of 2021, contains a number of ambitious first-year priorities, including:
Updating utility integrated resource plan guidelines to include GHG costs and risks. Existing guidelines state that IRPs “must be consistent with the long-run public interest as expressed in Oregon and federal energy policies.” The changes would include having IRPs reflect utilities’ risks and costs of missing EO 20-24 targets and requiring IRPs to comprehensively assess the use of carbon-free resources — including on the distribution grid — in portfolio analysis.
Incorporating the social cost of carbon (SCC) into future IRPs.
Identifying and exploring approaches to carbon pricing.
Incorporating the SCC — or a carbon price — into utility avoided-cost filings, including those regarding energy efficiency and Public Utility Regulatory Policies Act resources.
Considering GHG-related risks in the utility procurement process.
Evaluating the effectiveness of a current voluntary program, established under a 2013 state law, to reduce GHG emissions from natural gas utilities. No projects have been developed under the program.
‘New Area for the PUC’
The Utility Services and Activities work plan seeks to “prioritize actions that streamline and modernize safe, reliable methods to connect clean resources — from renewables to demand-side management, to the electric and natural gas systems — and appropriately value their system contributions, especially when deployed to support low- to moderate-income customers.”
The plan also promotes the use of community-wide “green tariffs” to assist communities in their efforts to exceed the state’s renewable portfolio standard and use 100% renewable energy.
The Transportation Electrification (TE) work plan establishes near-term objectives for conducting research and enacting policies to underpin a new investment framework for utilities and other stakeholders.
The plan seeks to:
prioritize TE investments within distribution planning;
collaborate on new rate schedules and tariffs that encourage TE and efficient charging of electrical vehicles, and that benefit all ratepayers, including “impacted” communities;
engage stakeholders to improve the PUC’s TE planning guidelines to streamline utility processes and clarify cost-recovery standards; and
commence “a new robust data collection process into market transformation indicators to be tracked by the utilities and shared annually with the OPUC.”
“This plan really emphasizes consistent development of an investment approach,” Sarah Hall, the PUC’s resource and programs development manager, said during Thursday’s meeting.
“Just as an overall philosophy, this is a new area for the PUC, and we have to be open to a lot of learning and flexibility around new ideas,” Chair Decker said.
‘All About Inclusiveness’
The second theme, “Impacted Communities,” looks to address the “disproportionate effect” of climate change on communities that have been historically underrepresented in public processes. The objective of the work plan is to go beyond protecting those communities and ensure they are engaged in measures to reduce GHGs — and actually derive benefit from those measures.
PUC Director of Policy Robin Freeman said a “major component” of the work plan is the hiring of a new diversity, equity and inclusion (DEI) program director to give the PUC a point of contact with those communities. The commission expects to fill the position in December.
The position is part of the work plan’s broader objective to transform the PUC’s structure and operations, including expansion of a recently formed “low-income roundtable” to help increase staff awareness of issues affecting vulnerable ratepayers. The plan would also see the PUC create new tools to quantify the energy burden of Oregon residents and improve utility reporting of disconnections. It will additionally strive to fulfill Gov. Brown’s objective to engage electricity customers and communities to ensure that GHG reduction goals provide widespread benefits.
“I’m starting to see that equity is part of everything that we’re doing,” Decker said.
In its current iteration, the Wildfire Prevention and Mitigation work plan — which falls under the third theme — is less detailed than the other plans. Lori Koho, the PUC’s utility safety, reliability and security division administrator, said that in light of the wildfires that ravaged Oregon in early September, staff wanted to defer rulemaking until it could engage the broader community.
“We wanted that process to be open, and so, that’s a key part of what we’ve tried to put in our work plan — is to make sure there are steps all along the way for different parties to provide input and be a part of this because communication is so key,” Koho said.
The work plan envisions the PUC holding a series of workshops and town hall meetings to discuss requirements for utility wildfire mitigation plans. It also foresees further development of the Oregon Wildfire and Electric Collaborative to share best practices on mitigation.
“It’s all about inclusiveness,” Koho said.
‘Elephant in the Room’
Bob Jenks, Oregon Citizens’ Utility Board | Oregon PUC
Stakeholders speaking at Thursday’s meeting praised PUC staff for the level of detail in the draft work plans. But a number of them pointed to what they called one shortcoming: an unclear picture of the future of natural gas use in Oregon — despite the inclusion in the work plan of a fact-finding effort related to decarbonization of the gas sector.
Bob Jenks, executive director of the Oregon Citizens’ Utility Board (CUB) said that under EO 20-24’s cap-and-reduce program, natural gas emissions must decline by about 50% from 2017 levels by 2035. Instead, they are currently rising.
“I sort of look at the gap between the growing line of emissions we’re on right now and the declining line that we need to be on as a financial risk to customers,” Jenks said.
Meredith Connolly, Climate Solutions | Oregon PUC
“I think the elephant in the room is the future role of natural gas — which is more accurately known as fossil gas — in our electricity grid and in the direct use of our homes,” said Meredith Connolly, Oregon director with Climate Solutions.
Connolly noted that a recent biennial report from the Oregon Department of Energy showed that combined natural gas use in electricity generation and buildings is now the second biggest source of the state’s GHG emissions behind transportation fuels.
Max Greene, Renewable Northwest | Oregon PUC
“We see these rapidly accelerating building electrification trends in California and Washington and Vancouver, B.C. — those are coming to Oregon, and they’re going to happen very quickly here, and that’s a good thing for our health and climate and people’s pocketbooks,” Connolly said.
Max Greene, regulatory and policy director at Renewable Northwest, also encouraged the PUC to look at the costs and risks of using natural gas for electricity generation and home use.
Zachary Kravitz, director of rates and regulatory affairs at NW Natural, Oregon’s largest gas utility, said that while his company understands the PUC’s desire for the fact-finding mission around gas, “we support a data-driven effort that considers costs, resource adequacy and customer choice in that fact-finding.”
Zachary Kravitz, NW Natural | Oregon PUC
Kravitz also said that direct use of natural gas accounts for about 6% of Oregon’s total GHG emissions. Normalized for weather, those emissions have grown less than 1% per year on average over the last 20 years, while use per customer has “fallen significantly,” he said.
“And now that we’re moving forward under [Oregon Senate Bill] 98 to secure renewable natural gas and hopefully hydrogen, we expect our emissions to start decreasing, and this is before considering the impacts of this executive order,” Kravitz said. (See Initiative Seeks to Fuel Use of Green Hydrogen in West.)
Oregon PUC Commissioner Letha Tawney | Oregon PUC
Commissioner Letha Tawney said the comments about natural gas made her think about the course the commission previously charted around the risks related to utility ownership of coal-fired generation.
“I think CUB in many ways started us down that path, and we see them again raising the important question, echoed by many other stakeholders, around long-term risk, and I hear the tension you’re articulating, and I would encourage us not to discount what happens when you begin to really engage around those risks,” Tawney said.
Workforce Impact
Two commenters pointed to the deep implications of decarbonization for sections of the state’s workforce. Chris Hewitt, political director with the Oregon and Southern Idaho District Council of Laborers, spoke on behalf of the group’s 4,000 members who perform skilled work throughout the construction industry, including working for contractors on “traditional” energy projects such as gas pipeline construction and transmission upgrades.
“Our members live in the communities where they work, and they reflect the increasing diversity of our region, and for decades Oregon has relied on laborers and other trades workers to perform high-quality, safe work on projects that provide vital family-wage jobs,” many of which are located in rural areas, Hewitt said.
Chris Hewitt, Oregon and Southern Idaho District Council of Laborers | Oregon PUC
Many of those jobs enjoy negotiated wage packages that exceed $45/hour, Hewitt said. “By contrast, when we look at construction labor wage rates we’ve seen advertised for renewable projects today, those are commonly advertised between $12 and $18/hour, which is a significant difference.”
Hewitt said his group appreciates the ongoing efforts to mitigate climate effects, but “a rapid energy transition has really too often left workers behind and resulted in economic dislocation” without providing workforce transition plans or “explicit standards” for jobs in the expanding renewables sector.
“Unfortunately, it doesn’t seem that this work plan today as drafted includes much reference to that, and we hope that there’s room for that in the conversation. We also hope that this process can recognize workers who build and maintain our energy sector as an impacted community and as a stakeholder moving forward.”
Ranfis Villatoro, Oregon state policy coordinator with the Blue-Green Alliance, agreed that workers should be considered “impacted communities” under the work plans and emphasized the importance of aligning work standards with climate goals.
Villatoro said that on the path to decarbonization, “there’s always the potential for workers to be displaced and with a lack of clarity of how workers are retrained or transitioned into new workspaces, but it doesn’t have to be that way.”
“I think there’s more work for us to think about in the labor questions,” Tawney said.
Utility Response
Oregon’s two investor-owned electric utilities threw their support behind the work plans.
Karla Wenzel, PGE | Oregon PUC
“We think the plans and the work ahead of us fits well with our corporate strategy to accelerate decarbonization in our own operations and in our role offering customers products and services that help attain the state’s goals and assist customers in achieving theirs for transportation electrification and clean, green energy to power their homes and businesses,” said Karla Wenzel, manager of regulatory policy and strategy at Portland General Electric.
Wenzel said PGE looks forward to “working with and learning from” the PUC’s new DEI program director “as we support more inclusive engagement and more intentionality in including impacted communities.”
She cautioned that the work plans “are ambitious and a heavy lift,” with “aggressive” schedules that warrant flexibility, “given limited resources and the need to balance existing and growing regulatory work.”
Etta Lockey, PacifiCorp | Oregon PUC
“We appreciate the fact that these are not detailed plans and will require refinement of the actions and activities and potentially resetting of priorities,” Wenzel said.
Etta Lockey, vice president of regulation at PacifiCorp, agreed that work plans are “a lot to tackle” but appreciated that the plans acknowledged the potential need to refine processes “as we go.”
“Oregon is not alone in grappling with many of these issues,” Lockey said. “PacifiCorp is having similar conversations in many of its jurisdictions, particularly around issues of impacted and underserved communities. We’re very interested in how this discussion plays out in Oregon, and we’re very encouraged by the commission’s pursuit of somebody dedicated within the commission to work on these issues, and we look forward to engaging with that new role and the workstreams associated with it.”
Mark Petrie, Confederated Tribes of the Coos, Lower Umpqua and Siuslaw Indians | Oregon PUC
Mark Petrie, vice chair of the Confederated Tribes of the Coos, Lower Umpqua and Siuslaw Indians, spoke on behalf of Oregon’s most historically underserved communities. He noted that he had recently worked with the tribe to pass a resolution supporting research into offshore wind energy.
“I just wanted to highlight two goals we have with that resolution and to emphasize that it’s essential that this new use of ocean energy be developed in such a way as to minimize any potential effects on cultural and natural resources to the tribe ocean environment and its other responsible ocean users,” Petrie said. “The tribe wishes to ensure that offshore wind projects and benefits thereof are coordinated with tribal, state and local leadership and priorities to maximize the benefits from this sector.”
Oregon PUC Commissioner Mark Thompson | Oregon PUC
Wrapping up the meeting, Commissioner Mark Thompson expressed excitement at the number of new people he has not worked with previously as a member of the PUC.
“Sometimes we can probably kid ourselves and say our work is so complex that you have to be almost an expert to be able to engage in it and be understood. But I think some of the comments today — well, all of them — really prove that’s not the case,” Thompson said.
Transmission owners will continue to receive a 10.02% return on equity, FERC said last week, rejecting several complaints from consumer organizations and one of its own commissioners.
The commission adopted the figure in May, determining it through a discounted cash flow model (DCFM), capital asset pricing model and risk premium model (RPM). (See FERC Ups MISO TO ROE, Reverses Stance on Models.)
With the exception of correcting typographical errors on inputs to the RPM, FERC said in an order Thursday that it stands by the ROE it established under a longstanding MISO docket (EL14-12-015, EL15-45-014).
The commission said it will move ahead with dividing the overall zone of reasonableness into equal thirds instead of using a quartile approach. Several industrial customers, cooperatives, public service commissions and consumer advocates said the framework creates an overly broad zone of reasonableness. The Louisiana Public Service Commission said it leaves “very little space between ROEs that are presumptively just and reasonable and ROEs that are excluded as low-end outliers.”
FERC said the zone of reasonableness’ bottom eighth and top eighth are nevertheless “potentially lawful ROEs.”
The groups also said FERC’s use of an 80% weighting of the short-term growth rate and a 20% weighting on the long-term growth rate under the DCFM was arbitrary and unexplained. But the commission responded that it has “broad discretion in its weighting choice.”
FERC also brushed off the Louisiana PSC, which lambasted the RPM as a model that “would not be relied on by an investor to determine the cost of equity, does not use a long time period [and] involves numerous judgement calls, and the output of the method does not produce a range of just and reasonable ROEs.”
“The risk premium model has a strong theoretical basis. We continue to find that the defects of the risk premium model do not outweigh the benefits of model diversity and reduced volatility resulting from the averaging of more models,” FERC said.
| MISO
The commission said it will continue to use a test that regards a company as a high-end outlier if its estimated equity cost is more than 200% of the median of the zone of reasonableness. The PSC contended that FERC raised the threshold so high that it rendered the high-end outlier test “essentially useless.” The commission originally set the high-end outlier at 150% of the median.
“The high-end outlier test is an objective test to identify proxy group ROEs that are irrationally or anomalously high because, for example, they are the result of atypical circumstances that are unrepresentative of the subject utility’s risk profile or are otherwise likely to be in error,” FERC wrote. “We again note that the high-end outlier test is the first, but not the only, method for screening a high-end result from the proxy group.”
FirstEnergy and the Edison Electric Institute tried for a broad rehearing of the order, but FERC said the two lacked standing because they were not parties to the proceedings. It also said the order was only regarding the changes it made to the ROE methodology since prescribing a 9.88% ROE in late 2019. (See TOs Challenge New MISO ROE Rules.)
EEI argued it “actively participated” in the commission’s Notice of Inquiry proceeding regarding its base ROE policy, but that “it was not reasonably foreseeable that the commission would establish a new methodology for analyzing base ROEs” under a seven-year old MISO docket. Based on the commission’s reasoning, EEI said it would have to “intervene in all company-specific rate filings” to make sure it is able to participate in orders in the event that FERC “unexpectedly” uses a company-specific order to make policy for all jurisdictional public utilities.
Several TOs were also perturbed last year that the commission would use a MISO proceeding from 2013 as a platform to set policy when it had already collected opinions on adjusting ROE through an NOI.
MISO has had a chameleon-like ROE since 2013, when industrial customers argued that the 12.38% rate that TOs were collecting was too high. In 2016, FERC lowered the rate to 10.32% after its remanded ruling in an ISO-NE case set the zone of reasonableness at 7.03 to 11.74%.
The PSC pointed out that FERC contradicted itself in its reasoning when it switched from a 9.88% ROE and two financial models in late 2019 to a 10.02% ROE and three models in May.
Glick Chides Again
FERC Commissioner Richard Glick also condemned the commission’s longstanding indecision on a just and reasonable ROE and its framing of the issue as more science than art. He again partially dissented on the latest ROE order.
“For more than a decade now, the commission has struggled with the fact that its longstanding ROE methodology produces cost-of-equity estimates well below the ROEs it permitted public utilities to collect in the years before the Great Recession,” he said.
While he agreed that a 10.02% ROE is just and reasonable, Glick said FERC was not being open and transparent about what guides its decisions.
“The experience of the last decade has made it hard to believe that the commission’s history of fiddling with its ROE models is a purely technocratic exercise in financial modeling rather than a concern about the output of those models, i.e., the ROE itself,” he said. “If the commission has concerns about the ROE produced by the various models on which it relies, we ought to come right out and say so rather than papering those concerns over with hundreds of pages worth of discussion about dividend yields, growth rates, proxy groups and the like.”
Glick added that FERC’s “about-face” on using the RPM was indefensible and admitted he wasn’t sold on its use. He said that no court or commission precedent “has endorsed the proposition that every point within the zone of reasonableness established by the commission’s financial models must be presumptively just and reasonable.”
He said again that the commission should order refunds to all ratepayers who paid the 12.38% ROE rate that it later deemed excessive. By granting refunds for a period from November 2013 to February 2015, but not from February 2015 to May 2016, Glick said FERC was relying on a “bizarre and overly complex interpretation” of an “otherwise straightforward statute.” (See “Sharp Rebuke from Glick,” FERC Ups MISO TO ROE, Reverses Stance on Models.)
Glick said, however, he would back the ROE result to bring badly needed constancy to transmission-investment decisions.
“ROE is an area where stability is paramount and, in an effort to bring stability to what has been a particularly turbulent aspect of the commission’s authority, I can support an outcome that is just and reasonable even if it might not be the most just and reasonable,” he said. “All approaches to setting ROEs have their shortcomings, but the worst outcome by far is to continually fiddle with those approaches, undermining the certainty and predictability that help transmission owners make long-term investments.
“If the commission is going to purport to rely entirely on financial models to evaluate and set ROEs, it has to take those models at face value without second-guessing them when it does not like the results,” Glick said. “Otherwise, we’re going to end up promoting full employment for energy lawyers rather than a stable investment climate for transmission owners.”
FERC said last week that MISO does not need a waiver of its Tariff requirements in order to provide Entergy Texas with make-whole payments.
The commission decided MISO is free to determine whether to give Entergy about $4,000 in make-whole payments for a late 2018 manual redispatch of its Sabine 5 natural gas plant without FERC approval. The commission dismissed the waiver request as unnecessary (ER20-1901).
The Sabine facility initially had a day-ahead volume award of 450 MW with a ramp rate of 3 MW/minute. According to MISO, its system dispatched the unit below its day-ahead volume to only 191 MW at 6 p.m. A few minutes later, the grid operator manually redispatched Sabine 5 to return to its day-ahead schedule volume, which took the plant three five-minute intervals to reach. MISO then denied Entergy day-ahead margin assurance payments for the three intervals while the plant was ramping.
MISO’s Carmel, Ind., headquarters | MISO
The RTO said its system is currently incapable of taking a resource’s offered ramp rate into consideration during a manual redispatch setpoint directive. It also said its rules don’t allow it to pay out day-ahead margin assurance compensation based on after-the-fact adjustments to manual redispatch setpoint instructions.
Entergy sought informal alternative dispute resolution over the partially paid ramping intervals. MISO concluded it should reimburse the utility $4,064.74, the amount it would have received had it been allowed day-ahead margin assurance payments for the three intervals in question.
The RTO said Entergy “should not be harmed for following MISO’s instructions” but that it needed to seek a Tariff waiver in order to issue the payment.
The commission disagreed, saying MISO is authorized to make the payment without a waiver.
“After reviewing MISO’s filing and Tariff, we find that it is not necessary to revise, alter or waive any provision of the Tariff to implement the ADR determination. Instead, consistent with the ADR determination, MISO can update the manual redispatch setpoint … instructions to take into account a resource’s offered ramp rate for resettlement purposes,” FERC said.
The CAISO Board of Governors praised the work of retiring colleague David Olsen on Wednesday and adopted the second part of a plan to speed the interconnection of storage resources to avoid future blackouts.
The governors and new CEO Elliot Mainzer recognized former Chair Olsen for his efforts to bring renewable power into the mainstream over the past four decades, including nearly nine years on the CAISO board.
“You are truly a titan in the energy field,” Chair Angelina Galiteva said. “Your wisdom, dedication and commitment to the decarbonization of the grid … especially to elevating the ISO to an international and global leader in the field of integrating renewables … is greatly appreciated and cherished.”
Mainzer read a resolution from the governors honoring Olsen and presented him, in an online meeting, with a commemorative plaque. The resolution recognized Olsen’s many achievements, including ushering in an era of corporate sustainability as president of Patagonia in the late-1990s. He led the outdoor-gear company’s carbon-reduction efforts, making it the first U.S. corporation to get its electricity from wind and solar power. (See Ex-CAISO Board Chair to Retire.)
Olsen, 74, served as CAISO board chair from February 2018 to Oct. 1. Earlier this month, he announced he would retire Nov. 30 with more than a year left in his term.
“I’ll be 75 years old soon and have been on the CAISO board for almost nine years,” Olsen said in an email. “That’s long enough on both fronts.”
David Olsen’s colleagues on the CAISO Board of Governors presented him with this plaque at his last meeting before retirement. | CAISO
Hybrid Resources Initiative
The board unanimously approved the second phase of CAISO’s hybrid resources initiative, letting co-located storage and generation resources operate under a single resource ID.
“The hybrid model allows for the underlying resources to be managed by the resource operator as opposed to the ISO,” CAISO COO Mark Rothleder said in a memo to the board. New provisions would allow hybrid resources to provide energy and ancillary services, he said.
“The proposal also includes a dynamic limit tool that will enable the resource operators to communicate their maximum and minimum operating limits to the ISO in real time,” Rothleder wrote. “This tool will help the ISO ensure it is issuing feasible dispatches to hybrid resources participating in the market.”
The board approved the first phase of the hybrid resources initiative in July. It laid out new rules for co-located resources that operate under separate resource IDs for dispatch purposes. FERC approved those Tariff changes Thursday, allowing them to take effect in December. (See related story, FERC Accepts CAISO Co-Located Resources Plan.) The ISO’s second-phase proposal also requires FERC approval.
Both phases are intended to better integrate storage coupled with solar and wind generation. CAISO needs thousands of megawatts of storage to transition to 100% clean energy by 2045, as state law requires. It has about 200 MW of storage now.
In the near term, the ISO is urgently trying to interconnect more storage before summer 2021. Resource shortfalls next summer are forecasted to exceed those in August and September, when CAISO declared energy emergencies, including rolling blackouts, in mid-August.
FERC on Thursday rejected challenges to its July order revising how it enforces the Public Utility Regulatory Policies Act but granted clarification on several points (RM19-15-001, AD16-16-001).
Order 872 allowed state regulatory commissions more flexibility in how they establish avoided-cost rates for qualifying facilities and said they could require the rates to vary over the span of a QF’s contract. It also modified the “1-mile rule” and reduced the rebuttable presumption for nondiscriminatory access to power markets, from 20 MW to 5 MW, for small power production, but not cogeneration, facilities. (See FERC Issues Final Rule to ‘Modernize’ PURPA.)
Numerous stakeholders requested rehearing on Aug. 17, including California’s three investor-owned utilities, the Electric Power Supply Association, the Northwest and Intermountain Independent Power Producers Association, the Sierra Club, the Sustainable FERC Project and the Solar Energy Industries Association.
The requests were automatically denied when the commission failed to act within 30 days. In Thursday’s order, FERC explained why the challengers were wrong while also offering some clarifications. The order was supported by Chair James Danly and Commissioner Neil Chatterjee, both Republicans, but opposed by Commissioner Richard Glick, a Democrat, who had dissented in July.
‘Tiered’ Pricing, Variable Energy Rates
The commission rejected a request by Pacific Gas and Electric, San Diego Gas & Electric and Southern California Edison to clarify that it is no longer commission policy to permit states to subsidize QFs by the use of “tiered” avoided costs — the costs of a subset of facilities from which a state has mandated purchases or facilities that meet state requirements such as use of renewable fuel.
“PURPA neither requires nor prohibits states from establishing tiered procurement (and thus tiered pricing), such as California does,” the commission said.
FERC granted SEIA’s request for clarification that a state may only use variable rates to set avoided energy costs if the utility has fulfilled its obligations to disclose avoided-cost data as required under PURPA regulations.
FERC ruled in 2016 that Entergy did not have to purchase power from Occidental Chemical’s Taft plant in Louisiana because the PURPA generator had unconstrained transmission access and could sell its output in the MISO wholesale market. | Occidental Chemical
“We do not find the disclosure of such information unreasonable as the commission’s PURPA regulations already require its disclosure,” FERC said. “In addition, although electric utilities are required to disclose this data generally, it is especially important when a state has selected the fixed capacity/variable energy rate construct to ensure that QFs have this data from the purchasing electric utility to provide transparency with regard to a utility’s avoided costs.”
Competitive Solicitations
The commission also clarified the rules regarding the use of competitive solicitations to set QF rates.
“If a competitive solicitation is not conducted in accordance with the requirements of the final rule guidelines, then an aggrieved entity may challenge the competitive solicitation before the commission or in the appropriate fora,” FERC said.
Order 872 allows competitive solicitations as long as they are the result of a transparent process open to all sources, conducted at regular intervals and overseen by an independent administrator.
Rebuttable Presumption of Separate Sites
The commission offered clarification on several aspects of its requirement that the capacity of all small power production facilities “located at the same site” not exceed 80 MW.
“If a hydroelectric generating facility is more than a mile apart (but less than 10 miles apart) from an affiliated facility, yet on the same impoundment, the rebuttable presumption would be that they are at separate sites. We further clarify that, although the second sentence of footnote 769 [in Order 872] suggested that a hydroelectric generating facility in this circumstance was free to seek waiver (most likely in order to eliminate any uncertainty as to its status), it would be unlikely that any such a facility would, in practice, need to request such waiver.”
It also clarified that “the factors that may be used by an applicant to pre-emptively defend against rebuttal include the example factors identified in … paragraph 509 of the final rule.”
Paragraph 509 cited “physical characteristics, including such common characteristics as: infrastructure, property ownership, property leases, control facilities” and “whether the facilities in question are: owned or controlled by the same person(s) or affiliated persons(s), operated and maintained by the same or affiliated entity(ies).”
Rebuttable Presumption of Nondiscriminatory Access to Markets
FERC declined to rule on the argument by wind developer One Energy Enterprises that a behind-the-meter distributed energy resource’s primary purpose is to generate electricity for its host and any potential sale is secondary like cogeneration facilities.
But it clarified that behind-the-meter DERs such as municipal solid waste facilities and biogas facilities may argue that having “‘a predominant purpose other than selling electricity which would warrant the small power QF being treated similarly to cogenerators’ … supports their argument that they lack nondiscriminatory access to markets.”
“We will rule on any such arguments on a case-by-case basis taking into account the specific facts of the DER making the argument,” the commission said.
It also granted a request for clarification “that the list of factors in section 18 CFR 292.309(c) that small power production facilities between 5 and 20 MW can point to in seeking to rebut the presumption that they have nondiscriminatory access was not — but should be — added to 18 CFR 292.309(e) that applies to QFs in ISO-NE, MISO, NYISO and PJM, and also to 18 CFR 292.309(f) that applies to QFs in ERCOT. In order to avoid confusion, we hereby incorporate the factors listed in 18 CFR 292.309(c) into both (e) and (f).”
Glick’s Dissent
Commissioner Glick opposed Thursday’s ruling, saying during the monthly open meeting that the commission’s record was “insufficient to support several of the key changes” in Order 872. Glick said he requested a technical conference to create such a record but was denied by former Chair Chatterjee.
Glick said the commission “is administratively gutting PURPA” in response to utilities and others who had been unsuccessful in getting Congress to revise the law, which was last amended in 2005.
“It doesn’t matter whether you believe PURPA offers substantial benefits or whether you think it’s bad public policy,” he said. “The fact is these are matters for our elected representatives in Congress to decide. We should not be using our regulatory authority just because some might be frustrated by Congress’ inaction.”
The rulemaking eliminates QFs’ guarantee of obtaining a fixed-term, fixed-rate contract, undermining their ability to obtain financing, Glick said. “At the same time, utilities in vertically integrated states can depend on the guarantee that their ratepayers will pay for a generating plant over the life of the facility,” he said. “How is that not discrimination?”
Danly and Chatterjee, however, said claims that the rulemaking discriminates against QFs are “based on the incorrect assumption that electric utilities have not been required to lower their energy rates as prices have declined. The commission found, to the contrary, that utilities typically charge their customers cost-based rates, and, as their fuel and purchased power costs have declined, they typically have been required to provide corresponding reductions in the energy portion of their rates to their customers. …
“Requiring QF avoided-cost energy rates to likewise change as purchasing electric utilities’ avoided energy costs change does not create a discriminatory difference, but rather puts QF rates on par with utility rates,” they added.
Glick also criticized the commission for presumptively authorizing states to use LMPs to set avoided costs, “even though LMP may not fully represent the utility’s avoided costs. This leaves utility generation with a distinct advantage — exactly the opposite of the role Congress intended PURPA to play.”
Danly and Chatterjee rejected arguments that precedent prohibits establishing a rebuttable presumption that LMP reflects avoided costs for as-available energy.
“Because LMP is likely to reflect the true marginal cost of energy in the vast majority of cases … it is ‘so probable that it is sensible and timesaving to assume’ that LMP for a particular utility is an appropriate measure of the utility’s avoided costs for as-available energy, unless disproven in a particular case,” they said. “We leave open for specific cases to determine the appropriateness of using a particular LMP such that a QF could rebut the presumption that LMP is appropriate.”
Four-star Gen. Wesley Clark retired from the Army after a 38-year career that saw him wounded as an infantry commander in Vietnam and rise to become commander of the U.S. Southern Command and the U.S. European Command. He helped write the U.S. National Military Strategy and Joint Vision 2010 for maintaining “full-spectrum” dominance.
The National Commission on Grid Resilience recommended establishment of an independent National Resilient Grid Authority to develop an experimentation program that identifies emerging threats and vulnerabilities. | National Commission on Grid Resilience
“The grid is the fundamental infrastructure for the U.S. It’s more important than pipelines, transportation or anything else because everything depends on the grid,” he said Wednesday at the American Council on Renewable Energy’s Grid Forum. “If it ever goes down, we’re in enormous difficulty.”
Although the terrorist attacks of Sept. 11, 2001, and Russia’s attacks on the Ukrainian grid have increased vigilance in the U.S., Clark said, the nation lacks a way to coordinate its response or measure its success.
“Lots of different groups have made recommendations, and many of their recommendations have been adopted. But there’s no clearinghouse; there’s no report card; there’s no way of knowing how well we’re doing” in responding to cyberthreats, he said.
“We need to be more open … about what the threats are,” he said in an interview with ACORE CEO Gregory Wetstone. “It’s really hard to find out whether we’re in danger or not if you’re just a citizen or on a public utilities commission setting a rate. You don’t really understand the threat. We know our enemies understand the threat. The question is: Can we do a better job of conveying this to the American public?”
Centralize Oversight
Clark also called on the U.S. to centralize its oversight responsibility. “Someone on the National Security Council staff should be tasked with looking at grid resilience. They aren’t. There should be a congressional caucus that meets to look at resilience issues. There isn’t.”
Retired Gen. Wesley Clark | ACORE
The U.S. also should develop a “test bed” where contractors, technologists and utilities can “try their hand against the latest threat,” he said. “That’s the way we did it in the Army to develop new technology.”
Clark also called for an expanded transformer reserve and development of microgrids, starting with ones on military bases. “In the event of a major grid crash caused by, let’s say, hostile action or environmental conditions, we have isolated islands that are self-powered and have enough [power] to be able to spread to the local communities.”
Wetstone raised President Trump’s May 1 Executive Order 13920 banning certain grid components from foreign adversaries, complaining that it was too vague.
“We never knew what was banned. It just created a lot of uncertainty,” Wetstone said. “Guidance was promised by mid-September; then it was reframed that we would see a Notice of Proposed Rulemaking by the end of the year. So, obviously, all this is being punted to the Biden administration.”
“This is an example of how difficult it is to move forward in the grid resilience area,” Clark said. “If we were China, we’d have a central data repository, and we would know everything that’s ever been bought from any foreign supplier and it would be controlled. But we don’t have the inventory. We don’t actually know what’s out there. We do know the threat because it’s been detected. But we don’t know where the threat is.
“It’s one of the first issues that I hope the Biden administration will be able to get a grip on. It is an urgent problem,” he continued. “The executive order was a great first step. But it wasn’t executable.”
NERC responded to the executive order in July with a Level 2 alert seeking data on the presence of foreign-provided equipment in the bulk electric system, and the Department of Energy issued a request for information on utilities’ practices for identifying and mitigating supply chain vulnerabilities. In September, FERC Opens Supply Chain Cyber Risk Inquiry.)
Clark said the commission will “continue to push this and keep this issue alive because otherwise, everybody sort of nods sagely when you say these things: Yes, it’s complicated; yes, it’s a risk. And then it’s business as usual until there’s a catastrophe. If you think COVID and the lockdowns are difficult … it really doesn’t compare to what could happen with a significant grid problem.”
Commission Recommendations
Members of the National Commission on Grid Resilience, which made nine recommendations in a report in August. | National Commission on Grid Resilience
The National Commission on Grid Resilience issued a report in August that made nine recommendations:
Congress should direct DOE, the Department of Homeland Security and the Director of National Intelligence to establish a central clearinghouse and decisional node for communicating full and accurate threat information to BES operators and electric utilities.
Congress should establish a National Resilient Grid Authority, an independent agency staffed by rotating appointments of the country’s most highly qualified energy, cybersecurity and national defense experts from both the government and private sectors.
Congress should direct the Department of Defense and DOE to establish a nationwide advanced resilience technology (ART) test bed network of long-duration, blackout-survivable microgrids on military bases and other critical federally owned facilities that are predetermined to be safely sited on stable lands free from flooding, wildfires and other high-impact disasters for the foreseeable future. These should be devoted to both immediate defensive capabilities and rapid development of advanced grid resilience technologies.
FERC — in consultation with appropriate expertise at DOE and the Department of Interior, states actively procuring offshore wind energy resources and the relevant ISOs/RTOs responsible for the management of the onshore grid in their jurisdictions — should reform and strengthen interregional transmission planning, cost allocation and competitive bidding processes to better address the characteristics of widely dispersed renewable energy generation.
Congress should direct DOE and DHS to create a voluntary central repository of information regarding security and resilience investments in the electric power system.
Congress should pass a Resilience Investment Tax Credit that incentivizes investments in cyber and physical security transmission components and equipment that are American-manufactured, as well as electromagnetic pulse security measures at both the distribution utility and BES levels. It should also direct federal spending toward resilience and security investments in federally owned electric utilities and end-use federal facility energy applications such as grid-connected devices, electric vehicle fleets and charging infrastructure, and distributed energy resources.
Congress should establish a bipartisan caucus on grid security that meets regularly to consider issues impacting the security and resilience of the U.S. electric grid. The National Security Council should lead a complementary interagency committee on grid security that acts as a liaison with the caucus.
The White House and Congress should establish a secure ongoing domestic supply chain, manufacturing capability and labor skills sets for all critical components and whole equipment essential to the operational security of the bulk electric grid, particularly prioritizing the largest and longest lead time transformers. Further, Congress should make annual updates to the DOE’s “Large Power Transformers and the U.S. Electric Grid (2012)” and “Strategic Transformer Reserve Report (2017)” reports and deliver briefings on them to the NSC and Congress.
The president should order climate impact modeling of a range of future scenarios to identify where it will be safe to site new and upgraded bulk electric transmission. These planning scenarios should take into account sites critical to national infrastructure, areas threatened by environmental impacts (including sea-level rise, extreme heat and climate-driven population migration), impacts to the national economy and enhancements that could be made by public-private partnerships.
In an effort to improve the accuracy of U.S. transmission transfer capability, FERC on Thursday issued a proposal to require all transmission providers to implement seasonal and ambient-adjusted ratings (AAR) on their lines (RM20-16).
Such ratings are based on the predicted seasonal or forecasted air temperatures, allowing for more electricity to flow when the temperature is lower and, thus, reducing congestion and its costs.
Most transmission providers use static ratings that are only updated after equipment is upgraded. Static ratings tend to be very conservative and based on worst-case-scenario temperatures, often restricting power flow unnecessarily. Using ratings that vary by season is more accurate, but they still do not account for unexpected temperature fluctuations.
“Because ambient air temperatures are typically less extreme than worst-case assumptions, seasonal and static transmission line ratings typically indicate that there is less transmission system transfer capability available than the transmission system can actually provide,” FERC staff told commissioners in a presentation during their monthly open meeting. “This increases congestion costs.”
AARs’ updates can vary in frequency from daily to every 15 minutes. According to FERC, AARs are already widely used in PJM and ERCOT; elsewhere in the U.S., static and seasonal ratings are the norm.
The commission’s Notice of Proposed Rulemaking would require transmission owners to implement both seasonal ratings and AARs, with the former being used to evaluate long-term transmission service requests and the latter for near-term.
It would also require RTOs and ISOs to allow TOs to update their line ratings at least hourly to allow them to use a method more accurate than AARs: dynamic line ratings (DLRs). These take into account many other factors in addition to temperature, such as wind speed, precipitation, humidity, cloud cover and solar intensity, allowing for a much more accurate rating.
FERC staff said that it did not seek to require the use of DLR devices because of the challenges and costs of installing them. But they also said the provision in the NOPR may encourage TOs to begin testing their use. “This proposed requirement seeks to remove this barrier to adoption of these more accurate line ratings.”
The proposal comes nearly a year after a staff-led technical conference on the use of AARs and DLRs. Many transmission company representatives who spoke there recommended against such a proposal, saying that a one-size-fits-all approach was inappropriate. (See FERC Considering Tx Line Rating Rules.)
But it seems FERC was convinced by the testimony of, among others, PJM Independent Market Monitor Joe Bowring and Michael Chiasson of Potomac Economics, the Monitor for ERCOT, ISO-NE, MISO and NYISO. They lambasted TOs for having such inaccurate ratings and their lack of transparency around how they determine them.
To address their latter criticism, FERC proposed requiring TOs to share their ratings and methodologies with RTO/ISO market monitors. “Such information sharing would increase situational awareness and improve the ability to verify the accuracy of transmission line ratings,” staff said.
Comments on the NOPR are due 60 days after its publication in the Federal Register. If approved, TOs would be required to prioritize implementing AARs on historically congested lines, defined as lines that have been congested in the last five years. Those lines would need to have their AARs in place within a year; all other lines would be given two years.
Commissioners Neil Chatterjee and Richard Glick were enthusiastic about the proposal.
“If finalized today’s proposed rulemaking will produce substantial benefits to consumers by simply ensuring line ratings are more accurate,” said Chatterjee, who as chair had initiated the proceeding that led to the NOPR.
“Most people will tell you we need a substantial amount of new transmission capacity, and I definitely agree,” Glick said. “But we should also strive to operate the current grid more efficiently to ensure that we squeeze more out of current assets while, of course, not impairing grid reliability. The NOPR would take us a substantial step in the right direction.”
Even Chairman James Danly — who rarely makes any comments at all and did not make an opening statement during his first open meeting as chair — chimed in, though he did not indicate how he felt about the proposal itself. “I have no questions [for staff]. I’ll just say that I think this is a very important issue, and I encourage everybody to comment and file so that we get the most robust record we can.”
As part of the NOPR, the commission is also seeking comment on whether it should require transmission providers to use unique emergency ratings.
A San Francisco-based renewable developer will get more time to prove it has secured enough land for its proposed wind farm in MISO East because of emergency conditions created by the COVID-19 pandemic, FERC ruled Thursday.
The commission granted Pattern Energy Wind Development’s waiver request of MISO generation interconnection procedures on the grounds that the ongoing pandemic hampered property plans for the Uplands Wind Project, a 600-MW wind farm in southern Wisconsin. The waiver will buy Pattern an extension on MISO’s current Nov. 27 deadline to prove site control and the Jan. 25 deadline for the grid operator to review site control submissions (ER21-30).
The Uplands project is part of the 2020 MISO East cycle of project hopefuls working their way through the RTO’s interconnection queue set to begin study on Feb. 24. Pattern submitted the project under two separate interconnection requests in June in order to connect it to both American Transmission Co.’s 345-kV Hill Valley-to-Cardinal line and the 345-kV Hill Valley substation.
Pattern said it experienced “business interruptions and delays in the land acquisition process caused by governmental orders, health and safety concerns and illness of key personnel resulting from COVID-19.”
| Pattern Energy
The company said that even with business restrictions enacted in Wisconsin from March through May, its agents were able to “sign several thousand acres of land, despite not being able to take any in-person meetings.” However, Pattern said its title specialist became “severely ill in late July/early August 2020, and a land agent was hospitalized for an extended period in late August 2020.” The illnesses “made it difficult to maintain the consistent dialogue necessary to negotiate a land easement and then register the easement with the local authority,” Pattern said. The company said despite conducting outdoor meetings with township boards, landowners and nonprofits, it simply lost too much time to “establish site control for 30,000 acres of land by Nov. 27, 2020.”
FERC said Pattern’s existing 15,000 acres of site control showed that the developer has made “reasonable efforts to satisfy MISO’s site control requirements in a timely manner.”
MISO said it also supported Pattern’s request for extension.
NERC’s Standards Committee moved ahead on a number of standards development projects and organizational matters in a brief conference call on Thursday.
SAR Team Members Sail Through
The committee approved adding two members to the standard authorization request (SAR) drafting team for Project 2020-03 (Supply chain low impact revisions), following up on its appointment of the chair, vice chair and team members in July. (See “SDT Candidate Restored After Application Oversight,” NERC Standards Committee Briefs: July 22, 2020.)
Soo Jin Kim, NERC’s manager of standards development, told the committee that the project team had decided to solicit additional participants because none of the initial 10 members represented entities with only low-impact cyber assets with the potential to be affected by the project. Four people were nominated, of whom NERC recommended two based on the fact that their entities owned such assets. According to standard practice, none of the nominees was identified by name or organization in the meeting. The committee approved the two NERC-endorsed candidates unanimously.
Members also agreed to move forward with a proposal under NERC’s ongoing Standards Efficiency Review process (Project 2018-03) to retire Requirement R7 from reliability standard FAC-008-3 (Facility ratings). The team had originally intended to retire R8 as well, but this decision was revisited after FERC Accepts Removal of 18 NERC Requirements.)
The meeting agenda had included a proposal to accept the SAR for Project 2020-01 (Modifications to MOD-032-1) and appoint members of the standard drafting team, but this item was struck after several members said they had not had a chance to read the final version of the SAR or review industry comments.
Organizational Updates Move Forward
Participants also approved several internal updates intended to help the committee manage its business more smoothly and simplify the transition process for new members. The first of these was a set of revisions to the Process Subcommittee’s (SCPS) scope document, along with its Technical Rationale for Reliability Standards, intended to clarify language and provide “better alignment with the … [Standards Committee] Charter.”
In addition, Chair Amy Casuscelli updated members on the drafting of a training packet for incoming members, an initiative passed at the committee’s meeting in June. (See “SOL, Training Proposals Accepted,” NERC Standards Committee Briefs: June 17, 2020.) The draft document, developed by the SCPS, is being circulated to committee members for feedback and will be implemented in January.
Some members asked if the orientation would be limited to new committee members only or if others would be allowed to participate; for instance, registered entity employees who wished to learn about the committee and its operations, or proxies for members. Casuscelli said the material was “meant for members as a whole,” but that others interested in joining the committee might be allowed to participate. In regard to proxies, she said the issue was not specifically addressed in the orientation materials but promised to have it added before they take effect.
Yeung, Brytowski to Continue Leading PMOS
Finally, Casuscelli named SPP’s Charles Yeung and Great River Energy’s Michael Brytowski for another two-year term as chair and vice chair, respectively, of the Project Management and Oversight Subcommittee (PMOS) on the unanimous recommendation of subcommittee members.
“We couldn’t do the work that we do without the PMOS; you guys are the eyes and ears on the standards projects, and … the team’s been doing great under your leadership, so thank you for that,” Casuscelli said.
