FERC on Friday rejected Gladstone New Energy’s complaint that Tri-State Generation and Transmission’s generator interconnection procedures caused the renewable developer to lose its queue position and be assigned network upgrade costs by an “inappropriate” restudy (EL19-97).
The proceeding stemmed from Gladstone’s 2017 interconnection request for a 78-MW wind facility in New Mexico. Tri-State’s final system impact study in 2018 pinned the costs for interconnection facilities and network upgrades at $31.7 million, requiring Gladstone to provide a $7.9 million security deposit.
In April 2018, Gladstone asked Tri-State that its interconnection request be placed into deferral over concerns with the study’s report. The project remained in deferral until September 2019, when Tri-State approved Gladstone’s request to proceed out of deferral. In November, under Gladstone’s protest, Tri-State conducted a system impact restudy. Tri-State filed a facilities study agreement in March, and FERC accepted it, with Gladstone again protesting.
Colfax County, N.M., is home to Gladstone New Energy’s proposed wind facility. | Lands of America
FERC rejected Gladstone’s argument that Tri-State “improperly” restudied the project, saying the restudy and the inclusion of a higher-queued project in its allocated costs were just and reasonable.
Gladstone argued that Tri-State’s interconnection procedures were outdated and did not conform with FERC’s large generator interconnection procedures (LGIP). But the commission said events prior to Sept. 3, 2019, were outside of its jurisdiction. Tri-State only became FERC jurisdictional on that date. (See “Ruling Permits Tri-State to Become FERC Jurisdictional,” SPP FERC Briefs: Week of March 16, 2020.)
The commission also noted that it accepted Tri-State’s proposed LGIP in March, finding them consistent with the pre-jurisdictional procedures that provide projects exiting deferral to be subject to restudy, unless Tri-State deems such analysis unnecessary. FERC said that Gladstone was aware that, as it entered deferral, a restudy was possible once it exited.
FERC last week approved a CAISO Tariff change to increase demand response participation by businesses offering on-site electric vehicle charging and a second change to improve accounting for the load-shifting capabilities of behind-the-meter storage resources (ER20-2443).
The ISO pays DR resources when they curtail load during times of high demand for electricity and strained supply. But a growing share of DR resources now include on-site load, generating capacity and batteries. In particular, the ISO said, a growing trend is providing EV charging at large energy customer locations, such as grocery stores, theaters and office buildings.
“According to CAISO, EVSE [electric vehicle supply equipment] frequently operates under the same retail meter and account as their host facility,” FERC said. “Thus, the entire facility must participate as a single metered resource even though the EVSE and on-site host load may have very different load profiles. CAISO asserts that, by failing to capture the unique load profile of the EVSE, it may send the wrong price signals to EVSE owners, thereby failing to provide incentives to curtail load during peak conditions.”
CAISO also said storage and DR resources can play important roles in managing peak demand, especially during the evening ramp. The net peak after solar declines was a major source of problems for the ISO during its August and September energy emergencies. (See CAISO Provides More Details on Blackouts.)
The ISO said its current rules “only capture the value of reducing demand compared to typical use” and do not incentivize storage resources to increase demand during oversupply conditions, which it said would help maintain reliability, avoid curtailments and stabilize prices.
| Volta
To fix those issues, CAISO proposed two Tariff modifications.
One would treat EVSE as a separate load curtailment measure when providing DR at facilities with on-site load.
“CAISO notes that it will not require such resources to separate their EVSE from the rest of their load, but, where demand response resources elect to measure EVSE performance separately, CAISO states that the resource must submeter the EVSE to avoid comingling the EVSE load and the on-site host load’s performance,” FERC said. “However, CAISO explains that the EVSE and on-site host load will still continue to operate under a single resource ID and will bid and meet CAISO schedules together as a single resource, but [they] will be settled separately based on their individual baselines.”
A second Tariff change creates “a demand response participation model to facilitate load-shifting capabilities of behind-the-meter energy storage resources to better account for when such resources charge or discharge at optimal times.” The change will establish two separate resource IDs: a consumption resource ID to track energy storage charging and a curtailment resource ID to account for the energy storage discharging to increase the site’s load curtailment.
Each resource ID will have its own baseline and DR energy measurement to establish typical use, using methodologies nearly identical to CAISO’s existing metering generator output methodology.
In comments, Southern California Edison supported the changes but worried they could lead to market gaming. CAISO said it was unpersuaded by SCE’s argument.
FERC accepted the revisions effective Oct. 1, saying they would improve DR participation.
“As CAISO explains, EVSE and behind-the-meter energy storage resources are increasing throughout the CAISO footprint at a rapid pace, and the goal of the proposed Tariff revisions is for CAISO’s policies to keep pace with these technological advancements.
“Allowing CAISO to implement these provisions will provide EVSE and behind-the-meter energy storage resources with access to CAISO’s wholesale markets under just and reasonable rules that will also capture their unique characteristics and benefits,” FERC said.
Vistra Energy last week said MISO’s “irreparably dysfunctional” capacity auction design deserves blame for its decision to shutter the last of its Midwestern coal plants.
Houston-based Vistra said it will wind down operations at seven coal plants in Illinois and Ohio by 2027, “or sooner should economic or other conditions dictate.” The competitive supplier said the closures of the four Illinois-based plants are partly because of low capacity payments in the MISO market. Vistra said low natural gas prices, EPA requirements, inadequate state subsidies and an influx of new generation also played a role in its decision to idle the units.
The retirements will leave Vistra with a coal generation presence only in its native Texas by 2027. The retirements will take about 7 GW of capacity offline, mostly in the MISO footprint. They include:
585 MW from the Edwards Power Plant in MISO’s Illinois territory by 2022;
1,185 MW from the Baldwin Power Plant in MISO’s Illinois territory by 2025;
about 1 GW and an additional 239 MW in natural gas-fired generation from the Joppa Power Plant in MISO’s Illinois territory by 2025;
1,108 MW from the Kincaid Power Plant in PJM’s Illinois territory by 2027;
1,020 MW from the Miami Fort Power Plant in PJM’s Ohio territory by 2027;
615 MW from the Newton Power Plant in MISO’s Illinois territory by 2027; and
1,300 MW from the Zimmer Power Plant in PJM’s Ohio territory by 2027.
Most of the plants range in age from 50 to 65 years old. The move follows Vistra’s announcement last year to close four other aging coal plants in downstate Illinois.
Vistra Chief Operating Officer Jim Burke said the company has gone “above and beyond” to try to make the coal plants viable.
“The advance notice of these retirements provides us with ample time to work with our impacted employees and communities to ease the impact of the closures,” Burke said in a statement. “We’ve proven ourselves in previous similar situations to live up to our core principles, taking care of our employees and communities. That will not change.”
Edwards Power Plant | Sierra Club
The company’s statement included a plug for the proposed Illinois Coal to Solar and Energy Storage Act, which would bill ratepayers to develop 300 MW of utility-scale solar and 150 MW of energy storage at 10 existing power plant sites in central and southern Illinois.
Vistra also framed the announcement as an opportunity to accelerate carbon-reduction goals. It introduced a plan to achieve net-zero emissions by 2050 — a more aggressive target than its previous 80% reduction goal by midcentury. It also touted what it called the “Vistra Zero” portfolio, which contains six new solar projects and one battery energy storage project all located in the “attractive Texas ERCOT market.”
MISO Mum on Criticism
MISO representatives declined to comment on Vistra’s complaint over its Planning Resource Auction design, which employs a vertical demand curve. In 2018, FERC Vacates, Upholds MISO Resource Adequacy Rules.)
The Brattle Group in August criticized MISO’s PRA clearing prices as “overly volatile,” saying it muddies investment signals. Brattle senior associate Walter Graf said the RTO’s vertical demand curve results in “bipolar” pricing that is “not consistent with true reliability value, thereby lowering efficiency and limiting the usefulness of prices to signal value.”
Graf suggested MISO adopt three objectives for its PRA:
Enforce resource adequacy requirements on LSEs with penalties for being short “while respecting constraints between sub-regions.”
Facilitate transactions of residual capacity at “fair prices that reflect market conditions.”
Inform timely and efficient investment and retirement decisions as LSEs and states plan how they meet resource adequacy objectives.
However, Graf said Brattle’s critique was not to be construed as a recommendation that MISO adopt a sloped demand curve.
Four years ago, MISO attempted to bifurcate its capacity market by holding a forward capacity auction for its competitive retail areas — which account for less than 10% of its total load — three years ahead of the usual PRA. FERC rejected the proposal.
Vistra’s announcement is the latest in a string of coal generation retirement decisions by the company.
Since 2010, Vistra has announced the retirement of more than 19 GW at 23 coal and natural gas plants. Vistra said most of those announcements have occurred in the past four years, representing more than 16 GW at 19 coal plants. The company also cited an “economically challenged” environment in the ERCOT market when it announced two coal plant closures in 2017. Before its acquisition by Vistra, Dynegy also blasted MISO’s market design as a reason its downstate Illinois coal plants couldn’t survive.
The Sierra Club said Vistra’s latest announcement is among the largest coal retirement commitments ever made in the U.S. It used Vistra’s announcement to call on the company to set retirement dates for its three remaining coal plants in Texas.
Its spring conference having been canceled during the early throes of the coronavirus pandemic, the Gulf Coast Power Association virtually gathered 437 participants last week for its 35th annual Fall Conference.
“I really can’t wait to be together to see you all in person,” GCPA Executive Director Kim Casey said, lamenting her “love-hate” relationship with technology.
Decarbonization and the need for a low-carbon future were among the topics, with a pair of industry experts sharing their expertise during one panel discussion.
“We’re living our future right now,” CenterPoint Energy’s Kenny Mercado said in introducing his panelists. “There’s no better place on earth than Texas to further explore what happens next as we drive our way to a low-carbon future.”
Brett Perlman, Center for Houston’s Future | GCPA
Brett Perlman, CEO of the Center for Houston’s Future and a former Texas Public Utility Commissioner, suggested the state follow the decarbonization example set by Germany, which is similar in size to Texas. The European nation’s guiding principles include continued electrification in parallel to accelerating renewable grid penetration; a focus on renewable power’s ability to displace fossil fuels; using blue hydrogen to address hard-to-decarbonize sectors like steel and refining; and finding entry points for green hydrogen and wind power.
“We want to continue to drive the electrification of things like transportation, reprioritize renewable energy and start to develop this hydrogen resource,” Perlman said. “A lot of this is going to be market-driven. We’ve already seen the market drive coal retirements and storage expansion. There will need to be a policy driver, but we’re waiting on that.”
The Lone Star State leads the nation with 700 million metric tons of carbon dioxide emissions a year. The electric, transportation and industrial sectors each account for about a third of 96% of those emissions. It also leads the nation in wind power with more than 30 GW of capacity, trailing only four countries.
“That’s a surprising picture, for a lot of people,” Perlman said. “Texas is one of the world leaders in non-carbon electric generation. If you asked people, they would say California. They would never guess Texas.
“We have really 10 years, according to climate scientists, to make [decarbonization] work. We have 10 years to really invest in the future, and I don’t see a place that that can happen quicker than ERCOT,” he said.
The Electric Power Research Institute’s Neva Espinoza explained the organization’s Project 2X to 2050, one of the “key pathways” to a decarbonized economy. The initiative looks at the electric, transportation and industry/buildings sectors and how energy efficiency, cleaner electricity, efficient electrification and low-carbon resources will enable decarbonization goals set for 2030 and 2050.
EPRI’s Project 2X to 2050 initiative | EPRI
Espinoza said the U.S. generation fleet is 30% less carbon-intensive that it was in 2005. She pointed out that has resulted in average retail prices that are essentially flat.
“We’re seeing a decoupling of economic growth and CO2 emissions,” Espinoza said. “We have to continue to clean our electric fleet so that it is 50% less carbon-intensive than the 2005 electric fleet. We need to add an additional 30 GW of flexible resources to our grid today.”
Developers Eye Energy Storage
Pat Wood III, former FERC and Texas PUC chair, moderated a panel on resource development and power contracting. He closed the discussion by asking each speaker their one wish.
Priestley Consulting’s Vanus Priestley, who was heavily involved in ERCOT’s market design, said he would take the “immense talent” at ERCOT and work on health care. Broad Reach Power CTO Doug Moorehead opted to see an increase in educational awareness around energy storage, from the seventh grade to college, so “education would be faster.”
Caleb Stephenson, co-leader of Calpine’s wholesale commercial operations group, was more realistic.
“I would like to see a national price on carbon. A lot of people are supporting it, and we need to push this through,” he said. “I’m less optimistic about the reality of the politics around it, but we’re going to keep pushing it. The power sector accounts for less than a quarter of greenhouse gases. We’re going to have to lean on the power sector to push others.”
Pat Wood III (lower right) moderates a panel featuring (clockwise from upper left) Caleb Stephenson, Calpine; Doug Moorehead, Broad Reach Power; and Vanus Priestley, Priestley Consulting. | GCPA
Stephenson said “deeper decarbonization” has renewed the focus on reliability planning and alternatives to peaker plants.
“Recent events in California underscore this point. The days of significant new gas plant development is over,” he said. “This elevates the importance of existing plants. As folks involved in the market, batteries are now the marginal source of new capacity in some regions. Most [load-serving entities’] future plans are overwhelmingly focused on storage.”
Moorehead reminded his audience not to forget about storage’s other assets.
“As renewables flood the market here in ERCOT and elsewhere, energy storage is one of the answers to congestion,” he said. “We’re starting to see now the bankability around energy storage. … I consider battery storage a generation device. It’s effective closer to load, especially in large, urban areas.”
Walker: Summer 2020 Went as Planned
PUC Chair DeAnn Walker reviewed the ERCOT market’s 2020 summer, one without energy emergency alerts or skimpy generation supplies. Just as planned, she intimated.
“The reason we didn’t is exactly what I said when we implemented changes to the ORDC [operating reserve demand curve],” Walker said. “People’s behavior changed.”
Walker’s reference was to a pair of 0.25 standard deviation shifts in the loss-of-load probability calculation since 2018 and using a single, blended ORDC. The curve provides a price adder during periods of generation scarcity. (See Texas PUC Responds to Shrinking Reserve Margin.)
“The market performed great. We had a higher reserve margin going into the summer because of more wind and more solar,” she said. “COVID-19 hasn’t really affected usage. It’s been a different summer, and a lot of it is we have more generation online.”
Walker told moderator and former PUC Commissioner Brandy Marty Marquez that even more generation is on the way.
“Distributed generation is just going to continue to grow. We’re going to see things happen with batteries that no one can envision right now,” she said. “I think we will continue — at least that’s what ERCOT tells me with what’s in the [interconnection] queue — to see a lot more solar and more wind. Whoever thought Texas could put more wind in? But we keep finding ways to put more wind in.
“There is no ISO in the United States or in the world better than ERCOT. I know [it] will stay ahead of it. I don’t really have worries about the summer as much as I did when I came in,” Walker said.
The View from Wall Street
A panel of financial analysts shared their thoughts on the electric sector’s performance during the economic downturn. Rebecca Kruger, managing director for Goldman Sachs, noted that utility share prices tend to trade in inverse proportion to the stock market, but that hasn’t been the case this year.
Rebecca Kruger, Goldman Sachs | GCPA
“You would think [utility stocks] would be trading extremely well … but the sector as a whole is trading at a sizeable discount,” she said. “We’ve always been a believer in scale and diversity in this sector. COVID, for us, brought forward how important scale is. We do see a diverging perspective, with the larger caps tending to outperform.”
“Utility stocks are trading at their cheapest level since the height of the dot-com bubble,” said Bank of America’s Julien Dumoulin-Smith, a familiar presence during electric utility earnings calls. “At the end of the day, what we’re seeing transpire right now is going to result in higher valuations.”
Dumoulin-Smith said the lower discount rates will result in further transmission investment. “Having that low-cost capital is going to invite a lot of transactions for developers,” he said.
That bodes well for an industry where wind, solar and now energy storage have all taken advantage of plunging prices.
“It’s not lost on us that the sector appears to be at a crossroads,” Kruger said. “Two things are driving it: technological advancements — we saw that with renewables, and now with battery storage — and the intense focus on climate change.”
“This industry has already been transforming itself,” said Gabe Grosberg, a senior director for S&P Global. Many more coal plants are slated to close, and there’s continued investment in the industry … $150 billion annually, much of it in renewables. We see a continued trend in renewables … that reflects what the consumers want. They want lower carbon intensity; they want electricity they can count on; but they also want to reduce greenhouse gases.”
COVID Still Major Conversation Piece
As is the case at many events during the new normal, the COVID-19 pandemic was the topic of several conversations.
Delivering one of several keynote addresses, CPS Energy CEO Paula Gold-Williams shared her organization’s response as the pandemic took hold in February and March.
“Our organization had no idea how overwhelming this pandemic would be. It was emotionally intense,” she said. “With our organization, we had to restructure everything. We recognized we were an essential service, and we had to declare every position an essential service. There were 3,100 of us, and it took all 3,100 of us to work.”
Joe Tracy, executive vice president and senior adviser to the Federal Reserve Bank of Dallas’ president, said the pandemic forced the Fed to rely on new forms of data because more forecasting methods rely on “backward-looking” government data.
Phil Wilson, Lower Colorado River Authority | GCPA
“We turned to cellphone data to get a measure of people’s mobility,” he said, noting mobility bottomed out in March and April when Americans started sheltering at home. “We saw it … slowly start to recover as many states got a handle on the virus.”
But no one had a more up-close and personal view of the pandemic than Phil Wilson, the Lower Colorado River Authority’s general manager. Having previously served as Texas’ secretary of state and as the Texas Department of Transportation executive director, Wilson was called upon again when the state’s Health and Human Services Commission’s (HHSC) executive commissioner took a position in his native Louisiana. He balanced both of his jobs during a daily routine that left a little time for dinner and a few hours of sleep.
“You’re only as good as the people working with you, and I had a strong team there. I made some lifelong friends because you’re in the trenches trying to solve some very difficult situations,” Wilson said. “The HHSC has a significant portion of its workforce that can’t work remotely. I wanted to make sure those individuals are just as valued as those who work remotely. It really comes down to the fact you’re as good as your people.”
ERCOT’s Maggio Wins Award
Dave Maggio, ERCOT’s director of market design and analysis, was honored with GCPA’s emPOWERing Young Professionals Award, presented to energy professionals under the age of 40.
Maggio joined ERCOT in 2007 as part of a group of engineers hired to bring the nodal market online. He is currently driving the grid operator’s implementation of real-time co-optimization.
As previously announced, 40-year industry veteran Tom Payton was awarded the Pat Wood Power Star Award by its namesake. The award recognizes significant contributions to Texas’ competitive energy markets.
Payton served on the ERCOT Board of Directors from 2002 until 2006. He retired in 2013 after serving as senior vice president of power for Occidental Petroleum.
A seemingly mundane request for a waiver of an SPP Tariff requirement last week prompted a rare philosophical dispute between FERC’s two Republican members (ER20-966).
At issue was a request by Montana-Dakota Utilities for a one-time waiver of a one-year notice requirement for rolling over its network integration transmission service (NITS).
Under SPP’s Tariff, an existing firm transmission customer with a contract of at least five years has the right to continue taking service from a transmission provider when its contract expires, rolls over or is renewed. But the RTO’s rules stipulate that the customer must notify the provider that it is exercising its reservation priority no later than one year before the end of its existing contract.
In May 2016, FERC approved a partial settlement among Montana-Dakota, SPP, the Western Area Power Administration and Basin Electric Power Cooperative that memorialized an agreement among the parties to resolve seams issues related to the integration of WAPA and Basin into the RTO.
One of the issues the partial settlement was intended to resolve was the provision of network customer transmission credits to Montana-Dakota according to section 30.9 of SPP’s Tariff. The settlement also described the terms and conditions of the NITS agreement (NITSA) signed by Montana-Dakota and SPP. The RTO filed the NITSA on July 27, 2016, retroactively effective Oct. 1, 2015, and to expire five years later.
On Oct. 19, 2019, Montana-Dakota submitted revisions to the NITSA to include additional facilities eligible for the section 30.9 credits. While that revised NITSA was still pending before FERC, the utility was notified by SPP on Jan. 28, 2020, that its original NITS was set to expire on Sept. 30. Montana-Dakota said it contacted SPP the next day to express its wish to roll over the NITS. Because the service was set to expire Oct. 1, Montana-Dakota had been required to notify SPP on Oct. 1, 2019, but the utility said SPP had been on notice of the utility’s intent to do so throughout negotiations for the revised NITSA.
Montana-Dakota contended that it met the four criteria laid out by FERC for granting Tariff waivers: that it acted in good faith; that the waiver is limited in scope; that it solves a “concrete problem”; and that it does not harm third parties.
The utility said it incorrectly assumed that the NITSA was effective as long as the partial settlement remained in effect and that it was unaware SPP’s Tariff required it to provide notification of its intent to roll over. It said the waiver would protect it from substantial network upgrade costs that it and its customers would incur in obtaining new NITS.
Both WAPA and Basin said they supported the waiver; SPP said it did not oppose the request.
In a brief finding, Chairman Neil Chatterjee and Democratic Commissioner Richard Glick voted to grant the waiver, agreeing that Montana-Dakota’s request met FERC’s four requirements. “Montana-Dakota’s failure to comply with the current one-year notice requirement appears to have been inadvertent, and Montana-Dakota states that it notified SPP the day after it was informed that it missed the deadline, providing SPP with notice approximately eight months prior to expiration of its NITSA,” they said.
No Authority
More substantial than the order itself was the dissent issued by Commissioner James Danly, along with a concurrence from Chatterjee that firmly faulted Danly’s legal reasoning.
In his dissent, Danly argued that the commission lacks the authority to grant such a request. “Even if we were to put that infirmity aside, Montana-Dakota’s request fails our four-factor test,” he added.
Danly wove a complicated legal argument that left open the question what latitude — if any — that FERC has in approving waiver requests. He argued that the filed rate doctrine and FERC’s rule against retroactive ratemaking restrict the commission’s ability to grant retroactive waivers. He noted that while those doctrines were developed in cases regarding utility rates, the logic of the doctrines “applies equally” to non-rate tariff cases.
“Because a waiver request is in essence a request that the commission permit a one-time change to a tariff provision, the commission is legally barred by the filed rate doctrine and the rule against retroactive ratemaking from granting a retroactive waiver request unless one of two judicially recognized exceptions applies: (1) the parties had notice that the tariff provision could be waived retroactively; or (2) the tariff provision is embodied in a private contract between the parties, who have agreed in that contract to make the agreed-upon rate effective prior to filing that contract with the commission. Neither of these exceptions apply here,” Danly said.
He said that while the commission “may enjoy some latitude to interpret this precedent,” it must “at least acknowledge that its authority to grant such a waiver is at issue and then identify the source of its legal authority to approve the request.” FERC had failed to meet that standard in the Montana-Dakota docket, he argued.
But even if FERC had the authority to grant the waiver, Danly said Montana-Dakota failed the four-factor test because the utility asserted that the waiver would maintain the status quo through its ability to continue to take NITS to serve its load and maintain the long-term benefits of the partial settlement for the utility and SPP members.
“But the fact that granting the waiver preserves the status quo is exactly why the waiver harms third parties,” Danly argued.
“Preserving the status quo for Montana-Dakota when application of SPP’s tariff would cause it to lose its rollover rights will cause entities that have submitted requests for service to incur substantial network upgrade costs to obtain service to which they would otherwise be entitled absent the waiver, or else be denied service,” Danly said. “The record does not inform us as to the number of requests that would be affected by granting this waiver. Nevertheless, even in the absence of that evidence, we know, based on Montana-Dakota’s own submission, that the request must run afoul of the no-harm-to-third-parties factor.”
Danly said he recognized that denying the request could have “serious consequences” for Montana-Dakota in the form of network upgrade costs passed on to its customers, which “would only have been exacerbated” by FERC’s “inexcusable” eight-month delay in acting on the request, preventing the utility from meeting SPP’s May deadline for participating in the transmission open season.
“Though Montana-Dakota and its customers may be due sympathy, to ignore the consequences of the waiver to other utilities is to take a one-sided view of the equities,” Danly said.
‘Regulatory Inflexibility’
“The dissent, at its core, argues for an approach to waiver requests that requires flawless adherence to all administrative tariff deadlines and denies the commission a modicum of regulatory flexibility to address ministerial or inadvertent errors on a case by-case basis,” Chatterjee countered in his concurrence. “Such an approach ignores the business realities facing public utilities. And it harms consumers. Recent challenges posed by the COVID-19 pandemic have underscored the value of regulatory flexibility when circumstances warrant.”
Chatterjee noted that Danly acknowledged the potential harm to Montana-Dakota customers and said that neither the Federal Power Act nor the filed rate doctrine require such an outcome for an “inadvertently” missed administrative deadline where there is no evidence of harm to third parties.
“The dissent does not sufficiently grapple with the record evidence here that granting the instant waiver not only will avoid harm to customers of Montana-Dakota, but also will avoid harm to specific third parties,” Chatterjee wrote.
The chairman cited WAPA’s comments that failure to grant the waiver could jeopardize the partial settlement, which preventing pancaked rates for WAPA’s Upper Great Plains Region, Basin Electric members and other load-serving entities in the Upper Missouri Zone.
Danly shot back regarding Chatterjee’s criticism of the dissent’s “regulatory inflexibility.”
“It is the law that denies us that regulatory flexibility, inadvertency and circumstance-specific challenges notwithstanding,” Danly said. “To deny a waiver under circumstances such as these might appear inflexible. But the doctrines that constrain us make no allowance for such considerations.”
A briefing by MISO staff last week on the record uplift in the RTO’s energy market caused by Hurricane Laura left stakeholders with more questions than answers.
During a joint meeting of the MISO Markets and Reliability subcommittees, staff recounted the events of Aug. 27, when the Category 4 hurricane made landfall in Louisiana, just east of the state’s border with Texas, damaging about 120 transmission lines and leaving about 730,000 customers in the area without power. (See MISO Keeps Advisories in Effect a Week After Laura.)
The storm caused a unique situation that resulted in nearly $90 million in uplift payments, a record high for the RTO. Though Laura itself barely touched MISO’s Texas footprint — with little rain, wind or even cloud cover, according to the RTO — the hurricane sliced across the West of the Atchafalaya Basin (WOTAB) load pocket, which straddles the Louisiana-Texas border. This created a new load pocket in Texas within WOTAB, which staff variously referred to as the “western load pocket” and the “Hurricane Laura load pocket subarea.”
Hurricane Laura damaged scores of transmission lines as it roared through Louisiana just east of the state’s border with Texas, creating a new load pocket in MISO’s Texas footprint. | MISO
Only three high-voltage transmission lines were available to serve load in the new pocket because of the storm, and the largest, rated at 500-kV, eventually tripped. This led MISO to direct Entergy to shed about 573 MW of load in the pocket, centered around The Woodlands, about 30 miles north of Houston.
MISO’s Tariff requires emergency pricing for load-shedding events, with each node in the affected area set at the value of lost load (VoLL), $3,500/MWh. But according to staff, the RTO’s pricing software does not allow for an area as small as the new load pocket to be automatically priced at VoLL, requiring staff to spend more than 1,000 hours over two weeks manually entering the prices after-the-fact.
Staff said they were confident that MISO followed the Tariff appropriately, and stakeholders did not dispute that. They did question, however, the rationale for pricing what were presumably “dead buses” in the load-shed area.
Stakeholders also expressed confusion over the different labels for the load pocket, the timeline of events and the map provided by staff. They asked that MISO provide clarifications and a more detailed map that included the nodes that were affected and the three remaining transmission lines.
MISO said it would provide such clarifications at the subcommittees’ meetings next month, and that staff will be prepared to discuss lessons learned and potential policy changes.
ISO-NE will ask FERC to exempt energy efficiency resources from capacity performance payments, although the proposal failed to win an endorsement from the New England Power Pool Participants Committee on Thursday.
The proposal received a 58% sector-weighted vote of the PC, short of the 60% endorsement threshold, with unanimous dissent from the End User sector and all 49 Publicly Owned Entity members abstaining from the vote. The Generation, Transmission, Supplier and Alternative Resource sectors supported the change. Last month, the NEPOOL Markets Committee also failed to endorse the proposal along similar voting lines. (See NEPOOL Stakeholders Split over PfP for EE.)
However, the Participants Committee did endorse a related measure to revise the Financial Assurance Policy to exclude EE capacity supply obligations from the calculation of capacity financial assurance requirements. The motion passed with a 79% vote in favor.
The RTO says capacity performance bonuses should be limited to those resources whose performance could be at risk during a capacity shortage. The change is a recognition that EE resources permanently reduce energy consumption and have no real-time performance measures, officials said.
Other Actions
In other action, the committee approved:
Revisions to Operating Procedures 17 and 21. The changes to OP-17 spell out in more detail the ranges of acceptable load power factors for sections of the New England Control Area and the responsibilities of ISO-NE, transmission owners and transmission customers. The revisions to OP-21 incorporate the annual generator winter readiness survey process and the yearly natural gas critical infrastructure survey, intended to ensure the interstate natural gas system is not on electrical circuits subject to automatic or manual load-shedding schemes.
Hydro-Québec interconnection capability credits and installed capacity requirement values for Forward Capacity Auction 15. The HQICC is 883 MW for each month of the 2024/25 capacity commitment period (June through May). The ICR is 34,153 MW, with a net ICR of 33,270 MW.
The 2021 operating and capital budgets for ISO-NE and the budget for the New England States Committee on Electricity (NESCOE). The RTO’s proposed operating budget is $178.6 million, a 2.5% increase from 2020, excluding FERC Order 1000 funding and before depreciation. Its full-time headcount remains unchanged at 587. The RTO’s capital budget is unchanged from 2020 at $28 million. NESCOE’s $2.4 million budget for next year is below the $2.5 million projected in its five-year pro forma budget.
In executive session, the committee also:
approved an extension and amendment to the Generation Information System Administration Agreement between NEPOOL and APX; and
approved the hiring of former National Grid executive Peter Flynn as a project administrator for the Future Grid Study and Rutgers University professor Frank Felder as a consultant on the “Transition to the Future Grid.”
Spees said any useful path forward for New England will have to meet both resource adequacy needs and state policies supporting emission-free generation. She said that the Integrated Clean Capacity Market would be a three-year forward market that attracts the optimal resource mix for reliability and state policy goals. By co-optimizing procurement of unbundled capacity and unbundled clean energy attribute credits, it would be a “fit-for-purpose market for achieving the 80 to 100% clean electricity future,” she said.
Felder told the committee that the goal of his project is to achieve “a common understanding” that defines potential future pathways and the variations and tradeoffs among them.
He said while co-optimizing the Forward Clean Energy Market (FCEM) and Forward Capacity Market (FCM) would “in theory … maximize the social surplus of meeting states’ clean energy objectives and regions’ resource adequacy requirements … it is not clear if [it] can be implemented in practice.”
Without co-optimization, resources offering into the FCEM will have to estimate their expected revenues in the FCM, and if those estimates are incorrect, inefficient outcomes may result.
Felder added that to achieve significant carbon reductions, the emission cap for the Regional Greenhouse Gas Initiative must be “substantially reduced so that prices of emission allowances are close to the” social cost of carbon. Low and non-emitting carbon resources offering into the FCM have larger margins and recover more of their fixed costs in the energy market, enabling them to be more competitive.
CEO, COO Reports
ISO-NE CEO Gordon van Welie briefed the PC on the Board of Directors’ direction to management to prioritize the evaluation of “net carbon pricing” and an FCEM, which he discussed at FERC’s Sept. 30 technical conference on carbon pricing. (See related story, FERC Urged to Embrace Carbon Pricing.)
In prepared remarks to the FERC conference, van Welie said the primary tool for New England states “to effect rapid decarbonization has been to sponsor clean energy resources outside of the wholesale markets, which make the owners of these resources largely indifferent to market prices.” He added that the RTO “has long advocated for carbon pricing as a solution that allows markets to efficiently price emissions without harming price formation.”
Van Welie said the RTO recognizes “that any solution requires a coordinated effort with state and federal policymakers and our stakeholders. Many policymakers are concerned that carbon pricing will lead to cost increases in the wholesale markets. We believe that those increases will be significantly offset by reductions in state programs. Furthermore, we can implement a ‘net carbon pricing’ methodology whereby the emissions fees on resources are automatically rebated to wholesale buyers through our wholesale settlements systems, thereby minimizing the cost impact.”
In his committee report, ISO-NE Chief Operating Officer Vamsi Chadalavada said that the energy market value was $158 million in September, a nearly 50% drop from August and down $53 million from September 2019.
Chadalavada added that development of the 2021 Regional System Plan will start in the first quarter. He said improvements to streamline the plan are underway and include a webpage for economic studies and enhanced environmental and emissions information.
According to Chadalavada, FCA 15 values will be filed with FERC no later than Nov. 10, and 2021 annual reconfiguration auction values will be filed by Dec. 1.
Chadalavada also presented a draft of ISO-NE’s 2021 Annual Work Plan for “innovating for the changing grid; adjusting to impacts of recent events; advancing operational improvements; and managing risks.”
In addition to the Future Grid project, the RTO’s major initiatives will include elements of the Energy Security Initiative, transmission planning for an evolving grid and evaluating the impact of shifting net peak loads.
The RTO also will be reviewing lessons learned from its first competitive transmission solicitation; working on improvements to operational and long-term planning forecasts, including the impact of the COVID-19 pandemic; and moving the financial transmission rights market to a clearinghouse.
Chadalavada also cited upcoming upgrades to the nGEM day-ahead market clearing software and capital projects to protect against increased hacking attempts.
FERC last week accepted two previously rejected unexecuted generator interconnection agreements between SPP, Oklahoma Gas & Electric (OG&E) and a pair of wind farms (ER20-2544, ER20–2545).
The two wind facilities, Frontier Windpower II and Chilocco Wind Farm, were part of SPP’s 2016 definitive interconnection system impact study (DISIS). Staff performed five restudies following the initial DISIS as projects dropped out of the GI queue or interconnection points were re-designated.
The fourth restudy identified Wolf Creek-Emporia as a shared network upgrade needed to accommodate the cluster’s interconnection requests. However, the ensuing restudy indicated the upgrade was no longer needed following the Board of Directors’ 2019 approval of the Wolf Creek-Blackberry competitive transmission project.
SPP revised the original GIAs to remove the Emporia upgrade. It said it filed the unexecuted agreements because OG&E disagreed with the proposed cost allocations, which did not allocate any Blackberry project costs to the wind facilities.
FERC rejected the GIA filings in April, saying their cost allocations were unjust and unreasonable because they were based on the Emporia upgrade. In approving the revised GIAs on Sept. 28, it noted they no longer contain the Emporia upgrade and include the Blackberry project as a contingent facility.
The commission reiterated its position that SPP did not violate its Tariff in performing the fifth restudy, pointing out that 13 higher or equal priority queued interconnection customers had dropped out. FERC disagreed with OG&E’s argument that SPP violated the commission’s interconnection-related pricing policy and cost-causation principles by proposing not to assign Blackberry’s costs to the DISIS group.
“SPP’s proposed cost allocation for the Blackberry project is consistent with the [Tariff’s] requirements for cost allocation,” the commission said.
FERC last week also responded to OG&E’s request to rehear the April order on Frontier II, which was automatically rejected when the commission did not respond within 30 days. The commission provided additional discussion but came to the same conclusion (ER19-2747).
OG&E had argued that FERC “failed to support with substantial evidence” its finding that SPP was allowed to undertake the fifth restudy when some of the projects were withdrawn. The commission declined to address the complaints.
The utility also contended that FERC erred by agreeing with an earlier mistaken SPP statement that a planning assessment justified the fifth restudy, arguing that the assessment contained improper assumptions that cause it to ignore the Frontier project’s impact. The commission reminded OG&E that it found the fifth restudy was not flawed, and it said the utility failed to provide evidence supporting its allegations that SPP never provided “specific assumptions” including in the planning assessment.
Frontier II, at 350 MW, is the largest wind project in Duke Energy Renewables’ fleet. It will be paired with the 200-MW Frontier I, which has been operational since 2016.
Three Northwest law firms last week filed a class action suit against PacifiCorp alleging the utility failed to de-energize power lines that contributed to a set of devastating blazes ignited in Oregon during the Labor Day weekend.
The development highlights the pressures Western utilities increasingly confront as wildfire dangers grow in length and scope, impacting areas previously not prone to the kind of fast-moving conflagrations that have plagued California in recent years.
It also illustrates the tightrope utilities must walk when deciding whether to invoke public safety power shutoffs (PSPS), the policy of pre-emptively shutting down lines to prevent sparking fires in high-risk areas.
The lawsuit, filed with the Multnomah County Circuit Court on Thursday, contends that Portland-based Pacific Power and its parent company PacifiCorp ignored warnings of hot, dry winds coupled with “extremely critical fire conditions” on Sept. 7, leaving lines energized in high-risk fire areas even as other Oregon utilities proactively cut power to avoid igniting trees and brush in the state’s extensive and towering forests.
An unusual wind storm with easterly winds swept the state Labor Day evening, toppling a number of those lines, sparking fires that rapidly swept through the Clackamas, Santiam, McKenzie and Umpqua canyons, as well as other parts of Oregon, the complaint contends.
“Defendants’ energized power lines ignited massive, deadly and destructive fires that raced down the canyons, igniting and destroying homes, businesses and schools,” the complaint says. “These fires burned over hundreds of thousands of acres, destroyed thousands of structures, killed people and upended countless lives.”
Ruins of the Lyons, Ore., home of the lead plaintiffs in the class action suit filed against Pacific Power and PacifiCorp | Jeanyne James/Robin Colbert
As evidence of Pacific Power’s culpability, the lawsuit cites a Northwest Incident Management Team (NIMT) report on Sept. 10 stating that downed lines on Sept. 7 sparked at least 13 fires along a nearly 30-mile stretch of the Santiam Canyon from the town of Detroit west to Mehama. The following day, the ferocious, wind-driven Beachie Creek Fire overran Detroit from the east and ultimately grew to more than 190,000 acres after merging with a separate blaze originally dubbed the Santiam Fire.
The lead plaintiffs in the suit, Jeanyne James and Robin Colbert, lived in the Santiam-area town of Lyons. The couple lost their home, four cars, a garage full of collectibles and tools, and nearly all their personal belongings, according to the suit, which seeks to represent other residents who suffered similar losses.
The complaint cites statements from an NIMT commander, who recounted during an early September press conference that a fire team stationed at the Old Gates School in Gates, east of Lyons, witnessed power lines fall near the school around 9:45 p.m. on Labor Day, sparking a fire that burned down the incident command post. Firefighters and other witnesses saw downed lines ignite fires in other parts of Gates, the complaint notes.
Pacific Power “could have de-energized their power lines during the critical and extremely critical fire conditions, at little to no cost to defendants, and thereby fully eliminate the risk of fire caused by power lines,” the complaint says.
Instead, the utility acknowledged that the Santiam area was not in its PSPS area and only de-energized lines at the request of local emergency agencies, the suit said.
PacifiCorp said it does not comment on pending litigation.
‘No Small Matter’
The filing of the class action Thursday coincided with a special meeting of the Oregon Public Utility Commission on utility responses to the Labor Day wind storm and subsequent fires. Testimony illustrated the complications utilities face when deciding whether to call for shutoffs in high-risk areas. It also demonstrated the differences between the responses of the state’s two big investor-owned utilities, Pacific Power and Portland General Electric.
Stefan Bird, Pacific Power | Oregon PUC
Pacific Power CEO Stefan Bird said the utility introduced PSPS in its planning in 2018 “as a last resort in extreme weather conditions in specific high fire-risk areas of our service territory.”
“We understand it’s no small matter to consider turning the power off for an entire community, and that such an action needs to take in consideration the risks that imposes to critical emergency services that rely on power, such as hospitals, 911 communications, water supply and vulnerable customers that rely on power to meet their medical requirements,” Bird told commissioners.
David Lucas, Pacific Power’s vice president of operations, said conditions on the utility’s system “did not meet protocols” for using PSPS in its high fire-risk areas. However, a map on Pacific Power’s website shows the Santiam Canyon is not even located near any of the utility’s PSPS zones.
“Similar to our colleagues at PGE,” Lucas said, “we did de-energize lines at the request of local emergency agencies to allow firefighters to do their job safely and to assist in removing debris to unblock roadways.” He said utility staff took those actions in the Medford area, about 235 miles south of the Santiam Canyon.
“We know public safety power shutoffs are often a focus when the public hears about utility wildfire mitigation; however, this is only one tool in a utility’s toolbox,” Lucas said. “And as we’ve learned through extensive local community engagement, public safety power shutoff events must be properly planned and coordinated so that a loss of power does not have unintended consequences of actually increasing public safety risk.”
Unlike Pacific Power, PGE did pre-emptively de-energize lines on Labor Day in anticipation of the wind storm, shutting power to about 5,000 customers near Mount Hood in what was the first PSPS event to affect Oregon residents. (See High Fire Danger Prompts First Oregon PSPS Event.)
Larry Bekkedahl, Portland General Electric | Oregon PUC
During the PUC call, PGE Vice President Larry Bekkedahl said the utility was under a “heightened level of alert” in the week before the weather event, prompting it to contact customers and community leaders to plan for a potential PSPS, including relocating “medically fragile” residents.
“This was not a decision we took lightly, as we recognized the hardships that the loss of power presents to many customers,” Bekkedahl said. “On [Labor Day] evening, I made the decision to de-energize in the highest-risk section of our service area” near Mount Hood. PGE subsequently de-energized lines in eight other areas, including towns threatened by both the Beachie Creek and Riverside fires, which at one point threatened to merge.
While the lawsuit does not mention PGE’s actions, it does note that the Eugene Water & Electric Board (EWEB), which serves a territory about 70 miles south of the Santiam area, pre-emptively de-energized lines during the storm.
The complaint noted that EWEB spokesman Joe Harwood told The Register–Guard on Sept. 9 that “I know people weren’t happy, but the idea was not to be the cause of a fire.”
The Northeast Energy and Commerce Association’s Fuels Conference on Wednesday tackled the subject of natural gas bans by local governments, questioning whether they are necessary for the “transition to a clean energy future or major government overreach with unintended consequences.”
Judy Chang, undersecretary of energy in the Massachusetts Executive Office of Energy and Environmental Affairs, said that the transition away from natural gas “is not going to be easy,” noting that gas demand has increased amid decarbonization efforts and that it is used for both heat and electricity.
“New England has very cold winters, and approximately 50% of our households heat with natural gas, and that number has been increasing,” Chang said. “In addition, we are at the end of long pipelines.”
Regulatory Assistance Project principal Richard Cowart concurred, saying, “Phasing out natural gas is probably the most challenging climate policy topic” he has encountered in nearly 30 years of working to decarbonize the power sector.
“I just think [natural] gas is going to be harder,” Cowart said. “The automobile fleet is easier than converting buildings away from fossil fuels, but climate science tells us it has to be done.”
Cowart said gas utilities need new business models and a regulatory transformation as well. “I went through electric industry restructuring, and this is starting to feel a lot like that.”
Clockwise from top left: Tamara Small, NAIOP Massachusetts; Paul Hibbard, Analysis Group; Albert Wynn, Greenberg Traurig; Judy Chang, Massachusetts Executive Office of Energy and Environmental Affairs; Richard Cowart, Regulatory Assistance Project | NECA
Cutting away quickly from fossil fuels like natural gas is not possible, according to Cowart. “Cold turkey is not on the menu,” he said. “We can only exit traditional fossil gas and oil as quickly as we can add renewable electricity, perhaps some clean gases, heat pumps and building renovations.”
Tamara Small, CEO of NAIOP Massachusetts, which represents companies involved in commercial real estate, said that her organization recognizes the effects of climate change, and its 1,700 members embrace projects designed to reduce carbon emissions. Small said any transition away from fossil fuel needs to be done in a “phased approach,” especially in new construction.
“Banning the use of natural gas for new construction means that residents will be paying for electric stoves and other electric appliances that drive up individual utility costs and may burden residents who cannot afford large increases,” Small said. “Energy efficiency needs to go hand in hand with electrification, but there is still a cost impact.”
Paul Hibbard, principal at Analysis Group, said he has not seen “careful economic analysis or assessment of what is the pathway” to reaching net-zero carbon emissions by 2050.
“The most difficult part of decarbonization is putting a pin on the board about when we need to be all-electric in buildings. [It] will be important to provide that runway … to get carbon reductions going much sooner,” Hibbard said.
Tepper Talks About Mass. DPU Petition
Nearly two years after a series of explosions and fires in natural gas lines just outside of Boston in September 2018, the Massachusetts Attorney General’s Office filed a petition with the Department of Public Utilities to investigate the future of the industry as the state “transitions away from fossil fuels and toward a clean, renewable energy future by 2050.”
Rebecca Tepper, the chief of the office’s Energy and Telecommunications Division, said during a keynote speech that “numerous audits and reports” showed how vulnerable the “whole state gas system is.”
“If we sit back and do not plan for how to manage this transition, we will repeat the mistakes of the past, and vulnerable communities will be the ones who suffer,” she said.
Shaela Collins of Columbia Gas (left), and Rebecca Tepper, Massachusetts Office of the Attorney General | NECA
The first phase of the investigation, Tepper said, should require gas companies to submit detailed economic analyses and business plans that project the state’s future gas demand, including potential revenues, expenses and investments, and input from stakeholders on necessary regulatory, policy and legislative changes. The second phase should focus on developing and carrying out the changes required in a way that protects the state’s gas consumers.
“It’s critical that we start planning this now, and that we include all stakeholders in our process,” Tepper said. “I feel like we are at a crossroad. It’s not unlike where we were in restructuring, and we need to work together as a stakeholder community to figure this out.
“We’re not alone in Massachusetts thinking about this,” she said. The petition points to similar actions in New York, where an investigation was opened in March to ensure more useful and comprehensive planning for natural gas usage and investments, and California, which started a proceeding this year to examine the safety and reliability of its natural gas infrastructure, while the state focuses on achieving its long-term decarbonization goals.
“This transition is happening; it’s happening faster than even we thought it would, so neither the status quo nor kicking the problem down the road is going to work,” Tepper said. “This is the time. Not five years or 10 years from now.”
Renewable Natural Gas Opportunities
Judith Judson, Ameresco’s vice president of distributed energy systems, said that the Northeast has a chance to be an early leader in renewable natural gas.
Judson said that Ameresco had discussions with utilities in the Northeast on adding RNG from landfills, waste-water treatment plants or large waste-producing farms to their supply portfolios.
Clockwise from top left: Rick Sullivan, Economic Development Council of Western Massachusetts; Judith Judson, Ameresco; Zach Chapin, Dominion Energy; and Edson Ng, G4 Insights | NECA
“In terms of carbon emissions, it’s considered carbon neutral,” Judson said. “There are a growing number of studies that [RNG] is cost-effective relative to other decarbonization options for heating.”
RNG can be delivered through existing infrastructure without any further capital investment, she said, and it is a baseload, dispatchable renewable fuel source to support resilience objectives.
Judson said that an “economy-wide perspective” is needed to meet carbon goals in a “cost-effective way,” and RNG should be a part.
Looming Mystic Closure Reduces Flexibility
Jake Anderson, head of gas and power fundamentals analysis at Macquarie Energy, said during his keynote that the announced retirement of Exelon’s Mystic Units 8 and 9 “reduces flexibility” for New England gas markets.
Jake Anderson of Macquarie Energy (left) and Jonathan Carroll, Énergir | NECA
Asked if there will be renewed interest in gas storage development from independent or pipeline-affiliated companies, given the gap in storage capacity and production volume, Anderson said, “it’s a tough environment for building storage because the costs haven’t necessarily come down all that much.”
Regardless of the economics, Anderson added, if gas demand grows and LNG terminals need storage, “we’re going to see at some point a resurgence of storage building; it’s just a question of when and how quickly.”
