A U.S. senator is urging FERC to support MISO’s proposal to transfer interconnection rights for existing generators that have been retired, demolished or replaced with new generation.
Tina Smith (Facebook)
Sen. Tina Smith (D-MN) filed comments with FERC early this month, urging the commission to consider that MISO’s generator replacement proposal — currently pending before FERC — stands to benefit renewable generation and could nudge owners of high-emitting generators to make cleaner upgrades (ER19-1065).
In her comments to FERC, Smith said the plan could support the goals behind Minnesota’s Next Generation Energy Act of 2007, which requires the state to reduce its 2050 greenhouse gas emissions to 80% below a 2005 baseline.
“For the electric sector, meeting that goal will require the replacement of high-emitting generators and a continued rapid expansion of low- and non-emitting generators,” she said. “MISO’s proposal will remove incentives for the owners of current high-emitting generators to put off upgrading to low- and no-emission generators by enabling replacement of legacy generating equipment in a manner that avoids significant additional costs.”
Under MISO’s proposal, interconnection customers wishing to replace their generation under the same interconnection agreement would send a request and a $60,000 study deposit to MISO. Over the following 180 days, MISO would conduct a generator replacement impact study similar to its existing material modification study, as well as a reliability assessment similar to its current reliability study for generation retirement.
Upon a finding of no adverse impact from the replacement, MISO would give the customer 30 days to decide to proceed with the replacement project. MISO would then have 90 days to conduct an interconnection facility study, if needed. After that, a replacement project proceeds to negotiation of a draft or amended generator interconnection agreement.
If MISO does find adverse impacts from the study, it would require the interconnection customer to “submit all necessary requirements for a new interconnection request” to begin the definitive planning phase anew. Adverse impacts include increases in thermal loading, a degradation in voltage, a degradation in stability performance and increases in short circuit contribution.
Smith said the proposal will benefit existing wind and solar generators, “ensuring they can continue to replace aging generating equipment with more efficient new equipment as technology improves, also without facing such additional upgrade costs.”
The proposal “facilitates reuse of existing infrastructure, supports state environmental initiatives and helps keep customer costs low,” Smith said, also noting the plant has the support of the American Wind Energy Association and the Clean Grid Alliance.
MISO plans to implement the replacement process by the third quarter of this year. The RTO said the proposal has widespread stakeholder support.
Michigan regulators are stepping into a dispute over how to classify a contested interconnection project included in MISO’s 2018 Transmission Expansion Plan (MTEP).
In a FERC complaint filed last month against MISO and Michigan Electric Transmission Co. (METC), Consumers Energy argued METC’s $21-million, 138-kV Morenci line near the Michigan-Ohio border has more in common with a distribution project than a transmission project and should be classified as such (EL19-59).
Consumers says the seven-factor test laid out in FERC Order 888 supports its contention because the line would be radial in nature. The company asked FERC to determine MISO “cannot approve or mandate the construction of a local electric distribution facility as part of its annual transmission planning process.”
Michigan Public Service Commission | Google Maps
MISO included the Morenci project in its 2018 Transmission Expansion plan over Consumers’ objection, saying it had no authority to address the complaint and the matter should be decided between FERC and the transmission owner. (See MISO Board OKs Full MTEP 18over Stakeholder Complaints.)
But Consumers said MISO’s view that “it is irrelevant whether its transmission expansion plans might include local distribution projects … is unacceptable to Consumers Energy, and it should be unacceptable to FERC, because it is a form of agnosticism with very real consequences.” MISO should vet the classification of its transmission projects — especially contested ones, the company said, asking FERC to remind the RTO of its “inherent obligation” to classify transmission projects.
Consumers argued MISO didn’t attempt the seven-factor transmission test when it should have, but MISO countered it followed both its Tariff and Transmission Owners Agreement, which stipulate the seven-factor transmission test be performed by “appropriate regulatory authorities.” The RTO asked FERC to dismiss the complaint in a May 3 response.
Last week, the Michigan Public Service Commission intervened to claim jurisdictional authority, opening its own case to apply the seven-factor test and scheduling a prehearing conference for June 4 (U-20497). METC, along with affected generator Wolverine Power Supply Cooperative and co-op member Midwest Energy and Communications, have requested FERC delay a decision on the complaint until the Michigan PSC rules in the dispute.
The PSC has also suggested FERC order a modification to the MTEP process to allow state entities with jurisdiction to apply the seven-factor test before a project makes it to the MTEP list.
However, Wolverine Power has argued it has a “time-sensitive need” for a transmission upgrade to deliver wholesale power and said the case is not the “appropriate proceeding to revise the MISO Tariff or to expand the scope of MISO authority to include facility classifications.”
Consumers has said it will suffer “concrete harm” if the line is built, saying it will have to pay for the line in METC’s transmission rates and be prevented from constructing an alternative distribution project to serve Midwest Energy’s anticipated load growth.
Consumers also contends a FERC determination that the line is distribution should be “uncontroversial.” “Federal law does not give MISO the power to approve or compel construction of local distribution facilities, or to regulate such facilities directly,” the company said.
ALBANY, N.Y. — Two environmental advocates from the Sierra Club were the only commenters Monday at the first public hearing on New York’s proposed restrictions on NOx emissions from peaking power plants.
Administrative Law Judge Molly T. McBride was accepting comments and statements for the state’s Department of Environmental Conservation (DEC) at the first of three hearings planned this month on proposed revisions to the agency’s Clean Air Act regulations.
Ona Papageorgiou, an engineer with the DEC Division of Air Resources, said the addition of Subpart 227-3 to Title 6 of the official compilation of state codes and regulations is meant to lower allowable NOx emissions from simple cycle and regenerative combustion turbines (SCCTs) during the ozone season.
The new regulations are proposed to go into effect May 1, 2023, with “initial rate limits of 100 parts per million on a dry volume basis, corrected to 15% oxygen,” Papageorgiou said. Generator compliance plans will be due March 2, 2020.
The DEC plans to submit the regulatory text to EPA as a revision to the state’s Clean Air Act implementation plan. It worked with NYISO, the New York State Energy Research and Development Authority and the state’s Department of Public Service on the proposal, which would apply to resources with a nameplate capacity of 15 MW or greater that bid into NYISO’s wholesale energy markets.
EPA designated the New York metropolitan area (NYMA) as a “marginal” nonattainment area for the 2008 eight-hour ozone National Ambient Air Quality Standard but last year proposed to reclassify the area to “serious” nonattainment.
NOx Table: As demonstrated in the table, on high ozone days newer SCCTs produced 64% of the electricity generated from SCCTs while emitting only 4% of NOx emissions from these sources. | NY DEC
An ‘F’ for Air Quality
“We would like to take this opportunity to applaud the effort and hope it will lead to the closure of many of these aging, inefficient and polluting electric energy generating facilities,” Roger Downs, conservation director of Sierra Club Atlantic Chapter, said at the hearing.
Because the units run to meet electrical loads during periods of peak electricity demand, their operations tend to correspond with hot summer days and associated high ozone levels when heavy use of air conditioning strains the capacity of the grid, Downs said.
“The resulting air quality degradation and increased NOx profoundly affects the health of those living near these peaking plants, exacerbating the asthma, heart attacks and other respiratory ailments that contribute to tens of thousands of hospital visits annually and dozens of deaths in New York’s nonattainment regions,” he said.
DEC assessed 99 high ozone days between 2011 and 2017 and said if the older sources were replaced with newer sources, total NOx emissions from those older sources on those days would drop from the reported 1,849 tons to between 40 and 60 tons, depending on efficiency.
The resulting 1,800-ton decline in emissions over those days — an average reduction of 18 tons per ozone season day — would represent a more than 10% reduction in metro area NOx emissions from electricity generators and an overall 3.5% reduction from all sources, the agency said. Analysis showed that, on high ozone days, newer SCCTs produced 64% of the electricity generated from SCCTs while emitting only 4% of NOx emissions from these sources.
Gail Pisha, representing the Sierra Club’s Lower Hudson Group, said EPA designates Rockland and Westchester counties as nonattainment areas for ozone, and the American Lung Association rates Rockland, Westchester and Hudson counties’ air quality with an ‘F’ for ozone pollution.
The Sierra Club also “anticipates that this new regulation will facilitate better water management, as many of the ageing peaking plants also use egregious amounts of water for cooling,” Downs said. “The billions of gallons of water a day required to cool Ravenswood and Astoria Generating and other facilities drawing from New York waters also contain hundreds of millions of larval fish in eggs that are entrained and entrapped in the industrial intake structures.”
Downs said it is also important to ensure the closed plants’ generating capacity be replaced by renewable energy, and to that end the Sierra Club remains uncomfortable with some language in the regulations that could allow for more lenient air quality rules if the peaking facility accommodates onsite energy storage.
“Energy storage serviced by the same dirty fuel sources significantly undermines the overall climate and air quality goals of this regulation,” Downs said.
Alliance Energy Group’s 55-MW Hillburn Power Plant in Hillburn, N.Y., is a two-on-one simple cycle twin pack plant burning kerosene and natural gas, and is in the process of being permitted to burn biodiesel. | Alliance Energy
DEC will hold its second hearing May 13 at 11 a.m. on the SUNY campus in Stony Brook and the third hearing May 14 at 11 a.m. at the state Department of Transportation in Long Island City.
Requests for information and comments related to the SIP revision may be obtained from Robert D. Bielawa, DEC Division of Air Resources, at (518) 402-8396 or air.regs@dec.ny.gov. Written statements may be submitted until May 20.
The Independent Market Monitor last week fired back at PJM’s request that FERC dismiss its complaint about the RTO’s default market seller offer cap (MSOC), saying the grid operator lacks understanding of the core problem.
In an April 30 filing with the commission, the Monitor scoffed at PJM’s defense that its initial complaint, filed in February, didn’t prove that current rules encourage abuse of market power (EL19-47). The RTO had also argued that it is unlikely that previous Base Residual Auctions “suddenly became unjust and unreasonable” after FERC’s approval of its Capacity Performance construct just four years ago. (See PJM: Dismiss Monitor’s Offer Cap Complaint.)
“The assertion that the system conditions have not ‘drastically changed’ since 2015 has no basis in fact and would surprise any objective observer of PJM markets,” the Monitor wrote.
Capacity prices | Monitoring Analytics
In PJM’s capacity auctions, the default MSOC functions as the “mitigated” offer level, with offers coming in above that level automatically prompting a review for market power by the Monitor. The IMM’s longstanding complaint remains that PJM’s default MSOC has been inflated by the “unreasonable and unsupported” expectation of 30 performance assessment hours (PAHs) annually. As a result, the Monitor said, it has been prevented from effective mitigation of market power, able to subject only a small number of very high offers to unit-specific cost reviews.
The timespan for measuring performance was changed from PAHs to five-minute performance assessment intervals (PAIs) in compliance with FERC Order 825 in 2018. PJM triggers a PAI when it determines a supply reliability issue exists, providing credits for generators that overperform their capacity commitments and penalties for those that underperform.
So far, only one load shed event has occurred within PJM since the CP overhaul in 2015. The event spurred stakeholder action to revise the MSOC calculation, with four proposals failing to garner enough support for inclusion in the Tariff. PJM subsequently dropped the issue, insisting no further investigation was required. (See PJM MRC/MC Briefs: Oct. 25, 2018.)
“Stakeholders’ role is not to make evidentiary determinations,” the Monitor wrote. “That a stakeholder body with divergent financial interests could not agree on another number to use for the expected PAI, with its significant implications for the market seller offer cap and/or the penalty rate, is not justification for PJM’s inaction.”
In August, the Monitor concluded that ratepayers were overcharged by $2.7 billion (41.5%) in the 2018 BRA because of economic withholding encouraged by the inflated MSOC.
“That an overstated MSOC interferes with effective and efficient market power mitigation is undisputed,” the Monitor wrote, noting that PJM “knows the exact details” of which companies and units asserted market power in the 2021/22 BRA.
Further, the Monitor referenced commission directives that instruct PJM to submit five-year informational reviews to evaluate existing rules and reassess the PAHs after gaining experience using the new market design. Auctions “repeatedly” clearing “well below” the default MSOC and with installed reserve margins well above target provides sufficient evidence of a problem.
“The 30 PAH was clearly overstated at the time, even based on the polar vortex experience, and the evidence since 2014 shows that the Capacity Performance model and incentives have resulted in a significant reduction in forced outages, an improvement in incentives and performance, an increase in reserves, and that the 30 PAH is even more overstated today,” the Monitor concluded.
The MSOC issue remains just one of seven outstanding PJM-related dockets with FERC. The Monitor reiterated its belief that the RTO should hold off on all future BRAs until the commission rules on the MSOC — despite PJM’s commitment to move forward with the August auction as planned.
If politics makes strange bedfellows, then transmission policy can create equally unlikely adversaries when it cuts across the competing interests of different environmental groups inclined to agree on most issues.
An example is currently playing out in Wisconsin, where environmentalists, preservationists and renewable energy advocates are at odds with each other over the pending approval of a major MISO transmission line designed to carry wind energy to population centers. Some are seeking to advance the project as proposed, while others support substitute plans that include adoption of local renewable resources.
The $500 million, 345-kV Cardinal-Hickory Creek project would span about 120 miles from Dubuque County, Iowa, to Dane County, Wis. Costs for the joint project involving American Transmission Co., ITC Midwest and Dairyland Power Cooperative would be shared on a load-ratio basis across ratepayers in MISO.
The Wisconsin Public Service Commission will hold six public hearings on the project in June. The commission has until Sept. 30 to review the application and decide on the necessity and placement of the line. The project also still faces a regulatory review in Iowa.
The project’s opponents and supporters in Wisconsin have been filing testimony and exhibits daily, and ATC is in the process of deposing witnesses in the case (5-CE-146).
The Cardinal-Hickory Creek line is the last of 17 MISO multi-value projects (MVPs) to enter the state regulatory approval process. MISO originally expected the project — designed to supplant more than a dozen other upgrades to constrained lower-voltage transmission lines — to be operational between 2018 and 2020.
“It’s unfortunate that it’s taken as long as it has to get into the regulatory process. … There are a lot of complicated pieces. But the longer this goes on, the more it’s preventing cost-effective resources from coming online,” Clean Grid Alliance Executive Director Beth Soholt said in an interview with RTO Insider.
The nonprofit is one of a handful of clean energy organizations backing the line’s construction. Its members include energy industry participants such as Avangrid Renewables, Invenergy, NextEra Energy and Vestas, as well as groups such as Union of Concerned Scientists, Iowa Environmental Council and National Farmers Union.
Soholt pointed out that when MISO identified the project as part of the 2011 MVP study process, it concluded the line would provide multiple benefits, including reliability, facilitating an economic market and helping meet public policy goals like state renewable portfolio standards.
“When you really look at ticking off all those pieces, Cardinal-Hickory Creek is the best option. This is the appropriate project,” Soholt said, adding that about 8,000 MW of existing and proposed wind generation needs the line to deliver energy and mitigate curtailments that are occurring today.
Soholt said that even if planners decide to “upset the apple cart” and forgo the project, the area would likely need a substitute that would contain several similarities to the existing proposal.
“For this particular purpose — to move the wind and solar megawatts that are being constructed — there is no other option, particular when you need to move electrons across time and space.”
She pointed out that MISO generator interconnection studies have long assumed Cardinal-Hickory Creek will be built. If the line isn’t built, interconnection customers may have to bear expensive transmission upgrade costs themselves, rendering some generation projects uneconomic and depriving ratepayers of the additional benefits the line will bring, Soholt warned.
“This line has been embedded into the MISO transmission planning and interconnection process for years,” she said. “Not constructing Cardinal-Hickory Creek will have a domino effect and cause restudies. Once you start that domino, it will get internalized into other projects, and some simply wouldn’t go forward,” Soholt said. She pointed to the RTO’s increasingly interconnected grid, shifting resource mix and more frequent emergency conditions as evidence of the need for additional transmission in the footprint.
“I don’t think I can say strongly enough … the need for transmission is only increasing, not decreasing.”
CGA, Fresh Energy and the Minnesota Center for Environmental Advocacy testified that the project will also reduce Wisconsin’s dependence on pivotal suppliers. Grid Strategies Vice President Michael Goggin pointed out that MISO territory in Wisconsin and Michigan’s Upper Peninsula had at least one pivotal supplier about 40% of the time in 2017.
A Distributed Future?
But landowners and residents have said the project is unnecessary and will impose higher taxes and utility rates, harm property values and agriculture, and destroy portions of the Driftless Area.
Opponents include the Driftless Area Land Conservancy and Wisconsin Wildlife Foundation, represented by Howard Learner of the Environmental Law and Policy Center. The two groups say a 627-page draft review of the line by the U.S. Department of Agriculture’s Rural Utilities Service neglected to consider alternatives that combine lower-voltage lines and investments in battery storage, solar generation and energy efficiency. The agency said each of those separate approaches was impractical, though it didn’t consider the alternatives as a package.
“There are out-of-state environmental groups supporting the line, but the in-state environmental and conservation groups in almost all cases are opposing a large transmission line that would cut a wide swath through the scenic Driftless Area,” Learner said in a phone interview with RTO Insider.
In an agricultural impact statement last month, the Wisconsin Department of Agriculture, Trade and Consumer Protection declined to recommend a specific route for the line, saying all proposed routes would “impact significant acres of farmland.”
U.S. Sen. Tammy Baldwin (D-Wis.) recently joined opponents in criticizing the environmental review by the RUS, calling for a “meaningful analysis” of project alternatives and different routes for the line to cross the Mississippi River.
Wisconsin State Sen. Howard Marklein (R) also questioned the need for the project and asked the PSC for a clear and public justification for the project if the commission votes to approve it.
Learner said such a large line is unnecessary and takes issue that the project was never studied in isolation by MISO.
“When the transmission line was included in the MVP package in 2011, it wasn’t studied individually; it was studied as a portfolio with the other MVPs,” Lerner said. “Secondly, the world and electricity sector has obviously changed since 2011.”
In testimony provided by the Wisconsin PSC, electrical engineer Alexander Vedvik said that while the MVP portfolio “as a whole does in fact create benefits greater than the costs of the portfolio, it is entirely possible that one or more projects included in the MVP portfolio have benefits that are lower than the costs.” Using ATC’s models, the PSC found negative economic benefits were possible in several of the hypothetical cases it studied.
Despite changes over intervening years, MISO still expects benefits from the line. According to the RTO’s 2017 triennial review of MVPs, eastern Wisconsin would see a benefit-to-cost ratio of 1.9-2.9:1, while western Wisconsin would achieve a ratio of 3.2-4.8:1.
“Wind deployment in Iowa, Minnesota, North Dakota and South Dakota has greatly exceeded the already high level that the MVP projects were designed to serve. As a result, the benefits of and need for the Cardinal-Hickory Creek project are even greater than when MISO’s MVP planning process determined the project was needed and provided large net benefits,” Goggin said.
But Learner said at the time the MVP portfolio was approved, grid planners were forecasting a 1 to 1.5% annual growth. Since then, electricity sales and demand have flattened.
Learner also said the line was first studied when “solar energy was only a blip.” Last month, the Wisconsin PSC approved about 450 MW worth of solar development. If realized, the projects will lead to an almost five-fold increase in utility-scale solar generation in the state.
“That’s how fast solar is rapidly accelerating in Wisconsin,” Learner said. “To some degree, this case is about the old energy system versus the newer, cleaner distributed grid.”
No Need, Opponents Argue
Learner said the line will cost ratepayers a total $2 billion to $3 billion locked into rates over a 40-year revenue requirement period “at precisely the time” the industry is rapidly shifting. He likened the energy industry to the telecom industry at the point when cell service was rapidly superseding landlines.
“The world is changing. There’s no credible argument that there’s a need for imported power in Wisconsin to keep the lights on. I don’t think anybody is arguing that Wisconsin needs more imports in order to ensure reliability,” Learner said.
Energy companies in Iowa, Minnesota and the Dakotas are building more wind power, Learner argued, but utilities in those states are not shutting down existing fossil fuel plants, leading to excess generation.
Learner also said the line will support an “unspecified mix” of coal, wind, nuclear and gas-fired generation, not just wind.
The smaller line upgrades that Cardinal-Hickory Creek will render unnecessary, Learner argues, should be proposed on their own if they’re needed for local reliability. “If you need to fix local lines, fix local lines. … Don’t force people to pay billions for an entire transmission line,” he said.
But Soholt maintains that even a multifaceted alternative strategy isn’t a proper substitute for the project. While she foresees growth in distributed resources, she said a major transmission line compared to a distributed solution are “apples and oranges.”
“We can’t use energy efficiency, distributed resources or other local alternatives to move megawatts in time and space across the MISO footprint. There is just no cost-effective and timely substitute for the existing and future wind and solar projects relying on this line,” Soholt said.
“Bringing in distributed resources won’t solve the problem. It doesn’t deliver the megawatts that are being bottled up right now. It doesn’t facilitate the renewable megawatts that are in MISO’s interconnection queue right now,” Soholt said. “You need a grid to be able to move those resources to where they can be used. The idea that we can do this is without high-voltage transmission is not realistic. The grid is going to become more important as we get more distributed resources.”
SCOTTSDALE, Ariz. — The challenges facing the national and Western grids sound like the stuff of movie thrillers.
Speakers at this year’s Western Reliability Summit, hosted by the Western Electricity Coordinating Council, said massive storms caused by climate change could cut off power for days or weeks.
“We ain’t seen nothing yet with respect to hurricanes,” David K. Owens, retired executive vice president of the Edison Electric Institute, said in his keynote address. Owens worked to restore power to Puerto Rico after Hurricane Maria in 2017.
The most significant hurricanes in history, in terms of duration of blackouts, have occurred in the last 10 years, Owens said.
“The grid has got to be hardened,” Owens said. “The grid has got to be smarter.”
Others worried about cyberattacks from overseas.
“A guy in Nigeria can potentially take out your network and every one of your systems,” Michael Lettman, a cybersecurity adviser with the U.S. Department of Homeland Security, told the utility executives and regulators in the audience.
And some envisioned a science fiction future when millions of electric vehicles and rooftop solar arrays will help power the West — and potentially contribute to reliability problems.
“We’re going to see a much more dynamic supply and demand profile on our distribution grid” going forward, said Chris Campbell, senior director of grid modernization for Arizona’s Salt River Project.
WECC CEO Melanie Frye said the once staid business of providing electricity is getting more tangled.
“I am in awe of the ever-increasing complexity of the world in which we’re trying to deliver safe, reliable and secure electricity to our customers,” Frye said in her concluding remarks.
WECC, charged by NERC and FERC with ensuring the reliability and security of the Western Interconnection, holds its yearly summit to let industry leaders air their thoughts.
This year’s summit consisted of four panels that focused on cyber threats, transformational technology, the future of utilities, and changing norms and expectations among consumers and providers of electricity.
‘Waiting for the Cyber 9/11’
In the panel on cybersecurity, speakers urged utilities to prepare for computer shutdowns by practicing their skills with pen and paper. “We’ve got to have ways to fall back manually,” Lettman said.
Cybersecurity needs to be as commonplace as physical security for utilities. “Shaking hands with the FBI when you’re under attack is a bad idea,” he said.
Moderator David Godfrey, vice president of reliability and security oversight with WECC, asked panelists what they saw as the biggest cybersecurity concern in the next five years.
Lettman said attackers could hack into a secure network through an online device such as a baby monitor or a driverless car.
“Cyber Armageddon” had already occurred during the attacks on Ukrainian government ministries, banks and electric utilities in June 2017, he said. Lettman also cited the 2014 hack of Sony Pictures that U.S. officials blamed on North Korea.
Utilities should assume they will be the next target, he said. “We are all now security people whether we like it or not.”
Peyton Price, a Navy fellow with the Idaho National Laboratory, said it’s important to understand that numerous smaller cyberattacks could damage the grid as much as one major attack.
“I think we’re all waiting for the cyber 9/11 … [instead of] death by 1,000 cuts,” he said.
Transformational Technology
In a panel titled “What is the Next Transformational Technology?” SRP’s Campbell also recommended keeping up on “manual processes” in case of computer failure.
“As we depend more on technology, we need to be able to fall back when it’s not working properly,” he said.
He said he saw solar power and EVs as the major transformative technologies in Arizona and other parts of the West.
Utility-scale and rooftop solar will grow in importance in states flooded with sunlight, he said. The number of EVs is expected to increase exponentially, he said.
Mahesh Morjaria, vice president of development with First Solar, said he too believed solar would become a major force. It’s mainstream and inexpensive now, 65 years after Bell Labs invented the first solar cell, he said.
Chris Schroeder, with the nonprofit Smart Electric Power Alliance, said he sees the ability to aggregate rooftop solar and home batteries as transformational. Newer subdivisions can be built with both components, and utilities can call on those resources during short periods of under- or oversupply hundreds of times per year, Schroeder said.
Storage will be the biggest driver of change in coming years, said Kiran Kumaraswamy, vice president of market applications at Fluence Energy. It can siphon excess solar energy from the grid in times of surplus and inject it back into the grid at times of peak demand, he said. It can also be a local resource in areas with supply constraints, he said. (See Calif. Needs Far More Storage to Decarbonize, Panelists Say.)
“With all of these things we see an incredible promise,” Kumaraswamy said.
Changing Norms
Three utility regulators from California, Oregon and Washington talked about reliability concerns as renewable energy becomes a bigger part of the supply mix and community choice aggregators multiply.
Ann Rendahl, a commissioner with the Washington Utilities and Transportation Commission, said her state was on the verge of adopting a 100% clean energy mandate, as California, Nevada and other states have already done. (See Washington, Nevada Join 100% Clean Energy Movement.)
Keeping the grid reliable and ensuring resource adequacy at times of high demand in the West could prove problematic under those mandates, she said. “Washington is not an island.”
In California, 19 CCAs now serve load, including the Los Angeles-area Clean Power Alliance with 1 million customers.
In 2016, investor-owned utilities served 90% of peak capacity load in California, state Public Utilities Commissioner Liane Randolph said. In 2019, IOUs will serve 66% of peak capacity load and CCAs will serve 25%, she said.
It remains uncertain if the CCAs, many of which are startups, can procure enough carbon-free energy to meet legal requirements and peak load, she said. (See Calif. Lawmakers Reveal Growing Divisions Over CCAs.)
In a panel moderated by WECC’s Frye, utility executives and an independent consultant were asked, “What does the utility of the future look like?”
Jeff Guldner, president of Arizona Public Service, said customers will expect utilities to provide the clean energy they demand without wanting to understand the complexity of providing it — while keeping the lights on. Gluts of solar energy without sufficient storage will make that difficult, he said.
Utilities will have to become more customer-oriented, “like Amazon,” Guldner said. “Customers think about their utility like almost nothing.”
Independent consultant Gregory Guthridge said the relationship between utilities and their customers is bound to become “increasingly complex.”
Southern California Edison is working to meet California’s aggressive clean energy mandates, but meeting those goals while incorporating millions of EVs and rooftop solar arrays will be challenging, said Colin Cushnie, the utility’s vice president of power supply. (See Calif. Gov. Signs Clean Energy Act Before Climate Summit.)
Cushnie said he worries California will have to deal with future resource deficiencies.
“That would be the thing that would keep me up at night — how to make all this stuff work.”
NRG Energy said last week it expects to return to service an inactive Texas gas plant in time for summer, giving ERCOT additional capacity to play with.
ERCOT enters summer with a historically low reserve margin of 7.4%. The 385-MW Gregory plant will give the grid operator much needed extra capacity.
Gregory, located just outside Corpus Christi, was shut down in late 2016 when its cogeneration partner, Sherwin Alumina, filed for bankruptcy and ceased operations. It is expected to return to service as a combined cycle facility in early June.
In a statement released after NRG’s first-quarter earnings call Thursday, CEO Mauricio Gutierrez said the Texas Public Utility Commission’s recent actions to strengthen the ERCOT market “reinforced our decision to return Gregory to service ahead of summer.” (See related story, NRG Energy Earnings Drop on ERCOT Hedges.)
The PUC in recent months has worked to improve coordination between electric utilities and pipeline companies and ordered tweaks to ERCOT’s operating reserve demand curve price adder.
ERCOT will release its final resource adequacy assessment for the summer on Wednesday.
TULSA, Okla. — SPP’s Holistic Integrated Tariff Team (HITT) last week shared with stakeholders the result of a year’s worth of work: a draft report of high-level recommendations addressing the footprint’s many challenges.
Now comes the hard part: taking action on the recommendations.
“There’s a heck of a lot of work that’s left,” HITT Chair Tom Kent said during SPP’s April 29 joint quarterly stakeholder briefing. “The working groups will have a lot of effort to put these [recommendations] into actual action.”
Kent, COO for Nebraska Public Power District, said the HITT report makes 21 recommendations in four categories: reliability, marketplace, planning and cost allocation, and strategy. Thirteen of the recommendations, some of which are already in progress, are planned for implementation; the other eight require further study.
The big-ticket cost-allocation recommendations include decoupling Schedule 9 and Schedule 11 transmission pricing zones and allowing the creation of larger Schedule 11 pricing zones and/or Schedule 9 sub-zones. The HITT proposes that if the Regional State Committee adopts a policy to reallocate existing costs within the new pricing zones, it should be done over a five- to 10-year transition period to mitigate cost shifts.
The HITT is also recommending SPP determine whether transmission projects below 300 kV can be fully allocated on a regionwide basis; use incremental long-term congestion rights instead of Attachment Z2 credits as compensation for new sponsored upgrade projects; and evaluate whether it can establish cost allocation and rates under the Tariff for energy storage resources.
The team also recommends SPP continue to improve the Integrated Marketplace by including fast-start resource logic, ramping capability and a multiday, longer-term market product, and to continue developing a market mechanism to hedge load against congestion charges.
Kent said the report is a “tribute to the team working hard and working together, and coming to a strong consensus on the recommendations.”
HITT’s recommendations | SPP
A proposed action plan assigns the recommendations to various stakeholder groups. A timeline anticipates the work being completed by mid-2021.
Larry Altenbaumer, chair of SPP’s Board of Directors, called the HITT’s work “an example of the very best of SPP.”
“We fully recognize 85% of the work is in front of us,” he said. “It’s an exciting beginning of a very important next step for us. I think HITT’s going to be a good thing for us.”
“The industry is changing as rapidly as many of us who’ve been around for a long time have seen it change,” said HITT member Dennis Grennan, a commissioner with the Nebraska Power Review Board. “We must prepare for major changes coming in the next five to 10 years. It’s a real challenge, but it needs to be done so that our consumers back home truly benefit from belonging to SPP and all that comes with it.”
Kent promised a final report by the end of June and said that a final product will be brought to the July stakeholder meetings. He said it will be discussed in detail with the Strategic Planning Committee during its May 9 planning retreat.
The RSC has scheduled in-person meetings with the HITT on May 30 and June 24, and Altenbaumer asked for a workshop to be scheduled where stakeholders can participate in a “top-to-bottom” discussion of the report.
The SPP board charged the HITT with developing recommendations for holistic improvements within the system. The team is composed of 15 board members, state regulators and SPP members. (See SPP’s Tariff Team Begins Carving up the Elephant.)
FERC is re-evaluating how its 2018 decision on transmission owners’ return on equity might affect Entergy Arkansas’ unit power sales tariff from 2013.
The commission April 30 said it could determine a new ROE for Entergy Arkansas and issued an order directing submission of briefs and additional written evidence (ER13-1508-001).
| Entergy Arkansas
The issue dates back six years, when Entergy Arkansas decided to leave the Entergy System Agreement and join MISO. As a result, Entergy Arkansas created a unit power sales tariff that passed through MISO’s ancillary and uplift charges and credits, along with the RTO’s 11% ROE for TOs. Both the Louisiana Public Service Commission and the city of New Orleans protested Entergy Arkansas’ use of the rate. Using the 2014 Opinion 531 that set the ROE for transmission owners in New England, an administrative law judge in 2015 found that 9.01% was reasonable in Entergy Arkansas’ case.
But with Opinion 531 vacated in 2017 and no longer serving as precedent, FERC wants a fresh look at Entergy Arkansas’ ROE. As of last year, the commission said it will no longer rely only on the discounted cash flow (DCF) model, instead using a combination of DCF and the capital asset pricing, expected earnings and risk premium models. (See FERC Changing ROE Rules; Higher Rates Likely.)
“Accordingly, we direct the participants to this proceeding to submit briefs regarding the proposed new methodology for determining just and reasonable ROEs … and whether and how to apply it to the unit power sales tariff,” FERC said.
The commission added that participants in the case “are free to present evidence supporting the proposed new methodology or supporting a different or revised new methodology.” Briefs are due in two months.
NYISO’s electricity markets have reached an “inflection point” as new technologies and “ambitious” public policy goals require the ISO to develop measures to manage the grid’s “next evolution,” according to the ISO’s annual Power Trends report released Thursday.
Last year’s report covered the implications of state policies calling for 50% of the electricity consumed by New Yorkers to come from renewable sources by 2030.
“A year later, however, policymakers seek even more aggressive goals of 70% renewable energy by 2030 and 100% clean energy sources by 2040,” NYISO Executive Vice President Rich Dewey said in a press briefing to discuss this year’s report. The report noted that the ISO is working with stakeholders and policymakers to finish a plan to price CO2 into wholesale markets to support the state’s goal of reducing emissions. (See More Details Divulged on New NYISO Carbon Pricing Study.)
Annual electric energy usage trends in New York from 2000 to 2018 | NYISO
Dewey also highlighted a February proposal by the state’s Department of Environmental Conservation to require peaking units to reduce their emissions of smog-forming pollutants.
“The proposed new rule, which calls for phasing in compliance obligations between 2023 and 2025, could impact approximately 3,300 MW of simple cycle turbines in New York City and Long Island,” he said.
The ISO is engaged in the rule development process and will work to inform policymakers, market participants and investors of the rule’s implications for bulk and local system reliability, but it had no plans to testify at a Tuesday DEC hearing on the subject in Albany, Dewey said.
NYISO has initiated the second phase of its 2018/19 Comprehensive Reliability Plan, which includes a study scenario evaluating the reliability impacts of a potential retirement of all 3,300 MW of peaking units impacted by the DEC’s proposal.
Changing Grid and Goals
“Another trend is the recognition of the need to pay attention to the power transmission infrastructure within New York, both from a transmission and from a generation standpoint, which is aging and needs to be reinvested in to ensure we maintain reliable operation of the system,” Dewey said.
He also highlighted the need to maintain a resilient grid “in light of an uptick in severe storms” and other issues related to climate change.
The Power Trends report also points to a 10-year trend of declining electricity demand in New York, partly because of economic changes, but also increased energy efficiency. The ISO sees demand continuing to decline on EE and behind-the-meter resources, predominantly solar, Dewey said.
“When we look at peak demand, the impact of energy efficiency and behind-the-meter solar will continue to flatten and slightly decrease the need for peak as we move forward into the future,” he said.
Dewey also pointed to the opportunity for storage to become a valuable resource for grid management. The Public Service Commission in December doubled New York’s storage goal to 3,000 MW by 2030 and required the state’s utilities to reduce building energy use by an additional 31 TBtu to meet an EE target of 185 TBtu by 2025. (See NYPSC Expands Storage, Energy Efficiency Programs.)
Forcast electric vehicle energy and peak impacts | NYISO
A countertrend to EE is the increasing adoption of electric vehicles, which will put upward pressure on peaks, with a greater impact in winter than in summer because the peak occurs in the evening, which coincides with consumer EV charging habits, Dewey said. The new report takes its load data from the 2019 Gold Book, NYISO’s annual load and capacity forecast, which this year shows EV usage driving a 66% increase in New York’s projected baseline peak demand growth rate over the next two decades. (See NYISO Draft Gold Book Shows EVs Driving Load Growth.)
The report emphasized the ISO’s faith in competitive markets to provide incentives for investment in renewable resources and finance a more robust transmission system to move power to load.
Absent such infrastructure upgrades, investment in upstate New York renewables could yield diminishing returns for the state’s effort to boost renewable energy output and reduce carbon emissions, Dewey said.
“The NYISO believes that competitive wholesale electricity markets remain central to facilitating the accelerated changes policymakers have proposed in a way that will support system reliability and economic efficiency,” the report said.
