SACRAMENTO, Calif. — San Francisco offered $2.5 billion to buy PG&E Corp.’s grid facilities serving the city Friday as the company announced it was postponing a controversial effort to secure up to $20 billion in bonds to pay its wildfire debts.
The company’s announcement came as state lawmakers prepare to end their session Sept. 13 — and as PG&E gets ready to file a reorganization plan by Monday in U.S. Bankruptcy Court in San Francisco.
San Francisco Offer
The company indicated that the city’s offer — delivered in a letter from Mayor London Breed and City Attorney Dennis Herrera — was not part of its plans for exiting bankruptcy.
“PG&E has been a part of San Francisco since the company’s founding more than a century ago, and while we don’t believe municipalization is in the best interests of our customers and stakeholders, we are committed to working with the city and will remain open to communication on this issue,” PG&E spokesman Andy Castagnola said in a statement.
Breed and Herrera said in a statement that the city’s offer was the result of a “detailed financial analysis conducted by industry experts and encompassing an extensive examination into the company’s assets in San Francisco.”
“The offer we are putting forth is competitive, fair and equitable,” they said. “It will offer financial stability for PG&E, while helping the city expand upon our efforts to provide reliable, safe, clean and affordable electricity to the residents and businesses of San Francisco.”
The purchase would create California’s third-largest municipal utility, after the Los Angeles Department of Water and Power and the Sacramento Municipal Utility District. The city is not seeking to purchase any of PG&E’s gas assets.
The deal would have to clear the bankruptcy court and federal and state regulators, where a central issue is likely to be how the loss of San Francisco would impact the rest of PG&E’s system.
“What that will mean is that folks who live in suburban and rural parts of California are left behind in PG&E’s system, and it’s not clear that the system is economically viable,” Michael Wara, the director of Stanford University’s energy policy program, told the San Francisco Chronicle. “What is the impact of this on people who don’t live in San Francisco?”
IBEW Local 1245 — PG&E’s largest union with 12,000 PG&E employees — has opposed talk of municipalization, creating a website to make its case against a purchase it says would cost closer to $6 billion. “Should city government focus on fighting homelessness, reducing traffic gridlock and building more affordable housing — or should politicians spend $6 billion buying PG&E and running our local utility?” it asks.
Tom Dalzell, business manager for the local, toldThe Wall Street Journal the city’s offer “is off by a factor of four. They don’t have the workforce either — the underground workers, the engineers to run the system.”
The unions also may have an ally in Gov. Gavin Newsom, the former San Francisco mayor and supervisor, who helped defeat two initiatives to create a city-owned utility.
PG&E: Will Revisit Bond Plan
Steven Maviglio, a spokesman for major PG&E shareholders that backed the plan, said they would revisit it next year.
“The timing was simply not right to pass this legislation with just days left in the session,” Maviglio said in an emailed statement. “During the interim, we will continue to work to resolve the bankruptcy case and help PG&E fulfill its commitments. We will return in January with a renewed effort to getting this beneficial legislation the full and fair consideration it deserves.”
PG&E issued a statement Friday saying, “We firmly believe that Wildfire Victim Recovery Bonds are a critical element to the state’s path forward when it comes to addressing wildfire risk.”
California State Capitol
The company filed for bankruptcy in January after two years of devastating wildfires that are likely to cost the utility billions of dollars in damages. The fires included the November 2018 Camp Fire, the deadliest and most destructive in state history.
In recent weeks, PG&E and the hedge funds that control much of its stock have been lobbying lawmakers to draft and pass a measure that would have established a wildfire recovery bond program for the state’s investor-owned utilities. The proposal would have let the state borrow money, tax-free and at low interest rates, on behalf of the IOUs. (See PG&E Seeks $20B Wildfire Bonds Issuance.)
The vehicle for the bond measure was Assembly Bill 235, a wildfire-related measure that stalled in committee earlier this year. It was heavily amended Friday to include the bond provisions, just as PG&E said it would no longer pursue the effort.
The measure was meant to bolster PG&E’s position in bankruptcy and to head off an effort by its unsecured bondholders to take greater control of the company at a substantial discount. Those bondholders had put forward their own reorganization plan that included a $30 billion investment in the company in exchange for guaranteed payment of their notes, which could otherwise be dismissed in bankruptcy, and a big stake in PG&E. (See PG&E’s Bondholders Push $30 Billion Investment Plan.) They waged a lobbying and advertising battle against the PG&E bond proposal in recent weeks, launching a website titled “Stop the PG&E Bailout.”
In August, Judge Dennis Montali, who is overseeing PG&E’s Chapter 11 case, gave PG&E time to file its own reorganization plan without competing proposals, including the bondholders’ plan, but he could still consider alternatives going forward. (See Only PG&E Can File Bankruptcy Plan, Judge Says.)
PG&E has promised to file its own Chapter 11 reorganization plan by Monday, though the court had given it until later this month to do so. An outline of the plan released by PG&E earlier this summer said the utility will pay its debts and compensate fire victims by raising money through stock offerings.
In documents filed with the U.S. Securities and Exchange Commission, two major shareholders, Abrams Capital Management and Knighthead Capital Management, pledged to backstop PG&E’s plan with $15 billion in equity financing. Those firms also backed the legislative bond proposal.
FERC failed to adequately explain how it relied on natural gas exports in approving the Nexus Gas Transmission pipeline in Ohio and Michigan, the D.C. Circuit Court of Appeals ruled Friday (18-1248).
The court said it agreed with the city of Oberlin, Ohio, and the Coalition to Reroute Nexus, a landowners’ organization, that the “commission failed to adequately justify its determination that it is lawful to credit Nexus’ contracts with foreign shippers serving foreign customers as evidence of market demand for the interstate pipeline.”
The court, however, declined to vacate FERC’s approval of the 256-mile pipeline, saying, “We find it plausible that the commission will be able to supply the explanations required, and vacatur of the commission’s orders would be quite disruptive, as the Nexus pipeline is currently operational.”
At issue is the commission’s August 2017 order granting Nexus a certificate of public convenience and necessity under Section 7 of the Natural Gas Act and its July 2018 order rejecting rehearing (CP16-102, et. al.).
| Nexus Gas Transmission
The 36-inch pipeline runs from receipt points in eastern Ohio to pipeline connections in southeastern Michigan, allowing delivery to customers in northern Ohio, southeastern Michigan and the Dawn Hub in Ontario. Nexus Gas Transmission is a 50/50 partnership between DTE Energy and Enbridge.
FERC found that Nexus’ precedent agreements were “the best evidence” that the pipeline would serve unmet market demand. Although the precedent agreements represented only 59% of Nexus’ capacity, the commission concluded that existing pipelines could not absorb that amount of gas.
The petitioners claimed Nexus’ precedent agreements should be ignored because half of them are with affiliates. The court backed the commission’s explanation that it fully credited Nexus’ agreements with affiliates because it found no evidence of self-dealing.
But the court agreed with the petitioners’ claim that the precedent agreements are not strong evidence of market demand because two of the agreements, totaling of 260,000 dth/day, are intended for export to Canada. If the commission excluded the exports, Nexus would have precedent agreements for only 625,000 dth/day, about 42% of its 1.5 million dth/day capacity.
“The commission never explained why it is lawful to credit demand for export capacity in issuing a Section 7 certificate to an interstate pipeline,” the court said.
“Section 7 states that the commission may issue a certificate of public convenience and necessity for ‘the transportation in interstate commerce,’ and we have explicitly refused to interpret ‘interstate commerce’ within the context of the act so as to include foreign commerce.
“Accordingly, we remand to the commission for further explanation of why — under the act, the Takings Clause [of the Fifth Amendment], and the precedent of this court and the Supreme Court — it is lawful to credit precedent agreements with foreign shippers serving foreign customers toward a finding that an interstate pipeline is required by the public convenience and necessity under Section 7 of the act.”
The court rejected challenges to FERC’s approval of Nexus’ proposed 14% return on equity and its finding that the pipeline does not “represent a significant safety risk to the public.”
The case was decided by Judges Judith W. Rogers, Sri Srinivasan and Robert L. Wilkins, and the opinion filed by Wilkins.
One of the biggest blank spots on CAISO’s Western Energy Imbalance Market map could be partly filled if four Colorado utilities join the West’s expanding real-time trading market.
Xcel Energy, the state’s largest load-serving entity, and three partners — Black Hills Energy, Colorado Springs Utilities and Platte River Power Authority — announced Friday they were evaluating joining one of the markets with the help of a consulting firm. If that eventually happens, they’d be the first entities in Colorado to join an energy imbalance market.
“Working together, we have the potential to drive down fuel costs and provide customers with more energy from wind and solar resources,” Alice Jackson, president of Xcel Energy – Colorado, said in a news release. “We’re pleased to continue this regional collaboration and urge other power providers to consider joining us.”
The four utilities already share resources and balance peak demand through a joint agreement, but they see “value in joining a larger market to expand opportunities to exchange energy with neighboring utilities and be able to reliably integrate more clean energy into their systems,” Xcel said.
Motivating Factors
Political and financial factors likely influenced the decision.
Colorado Gov. Jared Polis signed a bill in May that reauthorized the Public Utilities Commission and implemented a host of new environmental requirements for it and utilities. SB19-236 requires utilities to submit greenhouse gas-reduction plans and instructs the PUC to investigate the potential benefits of joining a regional energy market.
“This exploration is in keeping with the passage of [the bill],” Xcel said.
A prior effort by Colorado utilities to join an RTO went south in April 2018, when Xcel upended a plan for the Mountain West Transmission Group to join SPP. Xcel, the group’s largest member, pulled out, saying it wasn’t in its best interests. (See Xcel Leaving Mountain West; SPP Integration at Risk.)
Xcel has also been engaged in a long-running turf battle with the city of Boulder over the city’s efforts to acquire the utility’s local assets and form a municipal utility intended to supply carbon-free energy by 2030. The city filed condemnation proceedings in June while simultaneously engaging in a separation proceeding with Xcel before the PUC, with both proceedings still playing out.
Boulder’s efforts were seen by some as spurring Xcel’s pledge in December to become the first major investor-owned utility to supply its customers with 100% carbon-free energy. The company said it would cut carbon emissions by 80% in 2030 and go all-green by 2050.
Polis, in his policy “roadmap” to achieving 100% renewable energy by 2040, has set similar goals for the state.
Reaction and Predictions
Xcel’s announcement was met with general praise from supporters of regional markets, including CAISO.
“The Western EIM has proven it can deliver as we enter a new era in the energy industry,” the ISO said in a statement sent to RTO Insider. “We support the efforts of these four Colorado utilities to join the Western EIM, which includes some of the largest electric utilities in the West. The current Western EIM participants have realized nearly three-quarters of a billion dollars in total benefits while reducing more than 400,000 metric tons of carbon emissions.”
CAISO’s latest figures show its continually expanding EIM saved its participants more than $736 million since it started in November 2014. Its current nine members include Arizona Public Service, PacifiCorp and NV Energy. Nine other entities scheduled to join include Arizona’s Salt River Project, in 2020, and the Los Angeles Department of Water and Power, in 2021.
The Bonneville Power Administration is well along the path to joining the EIM, filling in the second big gap in CAISO’s EIM map in the Pacific Northwest. (See Customers Probe BPA on EIM Impact.)
SPP said it, too, welcomed the interest.
“SPP has been working with several Colorado and regional utilities interested in participating in a wholesale electricity market,” a spokesman said in an email. “Having studied and observed the value of our energy imbalance and day-ahead markets over the last several years, we’re confident we can enhance the affordability and reliability of electricity in Colorado and across the west today and in the future. We stand ready to serve potential customers in the west if and when they determine the value of SPP’s services is right for them.”
Jennifer Gardner, senior attorney with Western Resource Advocates and chair of the committee that nominates leaders for the Western EIM, said Xcel and other Colorado utilities joining a regional market makes sense, especially to facilitate trade of Rocky Mountain wind energy with solar power from California and the Desert Southwest.
“We’ve seen a lot of market activity taking place in the last two to four years,” Gardner said. “These utilities realize there are more benefits to be gained with renewable energy integration … if they expand their footprint.”
Transmission connections to SPP or CAISO could be difficult with limited pathways, but a western connection may be more practical, she said.
Leaning Toward CAISO or SPP?
To perform the EIM study, Xcel and its partners selected the Brattle Group, a firm not usually associated with those intending to join that market. That led to some speculation that the Colorado utilities were leaning toward SPP.
An Xcel spokeswoman said in an email that wasn’t the case.
“At this time, we are waiting for the results of the study and are not leaning in any particular direction,” Michelle Aguayo said.
Gardner said it’s true that EIM entities have generally used another firm, E3, but she doubts the choice of Brattle signals a preference for SPP.
“The choice of who’s doing a study isn’t so important. This is just a personal preference” on the part of utilities, some of whom have used Brattle before, she said.
In energy conferences across the West in recent years, representatives of the intermountain states have expressed concern that California would dominate a regional market controlled by CAISO. They’ve been hesitant to go along with the ISO’s desire to form a Western RTO but have joined the EIM because its board is made up of members from other states and because participation is wholly voluntary.
Moreover, California’s huge population and demand for electricity is enticing.
Will financial calculations win out, or is a loathing of California and greater affinity for SPP more likely to control?
Carl Zichella, Western transmission director for the Natural Resources Defense Council and a strong supporter of regional markets, suggested that it could go either way but that CAISO might be the better choice because of its established track record and better connections.
“The power and efficiencies of wholesale energy markets are becoming increasingly clear to all load-serving entities in the West,” Zichella said in an email. “The CAISO’s Western EIM has surpassed $720 million in benefits for market participants and is continuing to grow. SPP’s Energy Imbalance Service has worked well for its members in the Eastern Interconnect.
“Colorado utilities must now decide whether their best deal is obtained by looking east — across the Eastern Interconnect’s limited DC ties — or West, toward the Western EIM.”
External Market Monitor David Patton and Internal Market Monitor David Naughton both endorsed major portions of ISO-NE’s Energy Security Improvements (ESI) plan before the New England Power Pool Markets Committee on Tuesday, with Naughton also spelling out his concerns for policing market power.
ISO-NE’s proposal includes day-ahead generation contingency reserve (GCR) and replacement energy reserve (RER) ancillary services.
“We’ve been recommending the ISO implement day-ahead reserve products for a number of years,” said Patton, president of Potomac Economics. “We’ve seen that they have significant value in other RTOs.”
[Editor’s Note: In compliance with NEPOOL rules, all quotes in this article were taken from speakers’ written materials or approved by them after the meeting.]
This graph illustrates ISO-NE’s basis for the proposed day-ahead generation contingency reserve (GCR) and replacement energy reserve (RER) ancillary services. The RTO says it will take into account the unloaded supply capability available to recover from a large supply contingency (GCR) in addition to what additional unloaded supply capability is available to fill the energy gap created when the reserve requirement is restored (RER). | ISO-NE
Potomac Economics’ “2018 Assessment of the ISO New England Electricity Markets” report found about 4,000 hours of commitments made through the day-ahead market to meet spinning reserve requirements last year. But those commitments are essentially out-of-market commitments, Patton said, “because while the physical constraints are embedded in the day-ahead market, there’s no market product associated with them, so they are not priced.”
The result: “understated” day-ahead prices relative to the system’s needs and increased net commitment-period compensation (NCPC) uplift payments.
“These [new] products will allow those requirements to be recognized and priced through the market,” he said.
Patton said the proposed day-ahead energy option component, while not essential, will provide additional incentive for scheduled resources to be available when called upon.
“It’s critical that [the day-ahead products] have a physical obligation to be available and have the ability to supply the product that the ISO is procuring — that they not be purely financial.”
Energy Imbalance Reserves
Patton said the proposed energy imbalance reserves are “probably the most innovative component” of the RTO’s plan, allowing the day-ahead market to “fully reflect” the system’s physical needs. He said it could allow ISO-NE to procure the resources through the market and “allow the day-ahead prices to fully reflect the system’s requirement.”
Allocating the cost of the forward energy procurement to negative deviations will create an incentive for load to be “more fully scheduled day-ahead” and should reduce the reliance on the reliability unit commitment (RUC) process, he said.
Patton said the current allocation of NCPC to deviations should be eliminated or changed to be based on cost causation. “It is very important in this design to stop [allocating] inefficient costs to virtual load so it will efficiently arbitrage differences between the day-ahead and real-time LMPs,” Patton said in his presentation.
Day-ahead Replacement Reserves
Patton also endorsed procurement of day-ahead replacement reserves, saying it should help ensure reliability in the operating day by incentivizing resources to be physically prepared to operate if needed in real time while reducing the need for out-of-market actions.
He said the requirement should be dynamic to reflect operators’ determination of the system’s needs. During cold spells, the replacement reserve quantity could be high, while on most days the need would likely be zero. “The Tariff should describe the process for determining the quantity,” he said.
Because uncertainties and risks change as operators move from the day-ahead market into the operating day, Patton said, “we do not believe it is desirable to require procurement of the same product in real time.” Instead, the RTO should procure in real time the operating reserves that are actually needed during the operating day, he said.
Multiday Market
Patton was more skeptical of the value of a multiday-ahead market, saying most of its benefits would likely be limited to cold weather events when firm fuel constraints are binding.
Patton said he had concerns about “unintended consequences” and the need for liquidity in such a market to ensure prices reflect the expected real-time prices for each day. Liquidity in the day-ahead market is driven by virtual trading, and ISO-NE has “probably … the least liquid set of virtuals” of any market, partly because of “the mindless allocation of real-time NCPC,” he said. Moreover, he said, it would entail running a market 52 weeks a year to realize a week or two of significant benefits.
Patton said the proposed day-ahead product, while extremely helpful, will not address the entire fuel security issue because it will not coordinate limited fuel inventories when the demand for secure fuel spikes.
He said a “more targeted” solution would be to procure a firm energy product that is coordinated over a five- to seven-day time frame only when needed — a few weeks each winter when a cold spell occurs. It would be optimized with commitments and schedules in the day-ahead market.
Seasonal Procurement
Patton reiterated his call for eliminating the forward reserve market, saying it should not be modified to address fuel security.
He said “an efficient forward market” that procured products that settle against the same product in the operating time frame — while not essential — could help facilitate seasonal fuel procurement decisions.
“We do not support proposals to procure products forward (three years ahead or seasonally) that do not exist in the operating time frame,” he said.
IMM Memo
Later in the meeting, IMM David Naughton expanded on a memo outlining his review of the ESI. Naughton said the ESI proposal correctly seeks to value the “missing product” of energy security and said it could obviate the need for out-of-market interventions such as capacity market retentions and having oil-fired generators on standby during the operating day.
He said it seeks to provide a means for physical supply to recover the fixed costs of a call option for LNG or the delivery of fuel oil. But he said the RTO should spell out clearly in the rules the types of costs intended to be included in the “unrecovered fixed cost” component of the option offer.
He also said the rules should explicitly require resources to physically provide energy to cover their ancillary service obligations.
“We understand the potential efficiency benefits over time of allowing speculative participation. However, we believe that the design is more likely to provide the secure energy when needed if participation is predicated on physical capability to provide secure energy, a clear expectation of meeting dispatch instructions in real time and a financial consequence for non-delivery that will deter speculative participation,” Naughton said.
The IMM stressed the importance of the seasonal forward component, saying it may become the primary market for clearing ancillary service obligations. “In practice, many of the actions to secure fuel are taken — and costs incurred — well in advance of the operating day. Relying on spot market revenue from the ESI products alone may entail significant cost-recovery uncertainty for participants who incur costs well in advance of the operating day.”
He warned that “any differences between the fixed costs included in the forward market and in the day-ahead ESI market” would undermine price convergence and incentives.
Market Power
Naughton said ESI must be carefully evaluated for market power issues in an analysis that considers “a broad range of future scenarios.”
He noted that the proposal is intended to address supply shortages that imply “potentially some degree of market power in the periods when secure energy is most needed. This can be compounded by the significant increase in (explicit) capacity reservation in the [day-ahead market] clearing, as a result of the new ancillary service requirements, and the level of ownership concentration of physical assets available to meet the reservation requirements.”
The increase in capacity reservations from the day-ahead market will reduce residual supply and “increase the likelihood that one or more participants will have market power, especially in the ancillary service products with a vertical demand curve,” he said.
He said the impact of market power could be magnified if it is exercised with respect to the new ancillary services products or the existing energy product. “To the extent market power can be exercised in one of these products to increase the price, it is likely that the price of the other products (including energy) being co-optimized will also increase.”
The IMM said it should address market power vulnerabilities through ex ante reviews to mitigate uncompetitive offers as part of the market clearing. “The ex ante approach protects price formation from the exercise of market power and does not introduce uncertainty about final prices via ex post correction, redistribution of rents through resettlement and/or lengthy regulatory enforcement activities,” he said. “The ESI market design should not rely on ex post measures, such as claw-back, enforcement action and/or [Federal Power Act Section] 206 filing for unjust and unreasonable rates.”
Andrew Gillespie, ISO-NE | ISO-NE
He opposed the proposal that participation in the day-ahead market for ESI products be voluntary, saying it would open the market to physical withholding.
He also called for consideration of a must-offer requirement for capacity resources with the physical ability to provide the ancillary services products. Capacity resources have such a requirement for energy in the day-ahead market and for both energy and reserves in the real-time energy market.
Naughton’s memo included concerns that key portions of the ISO-NE proposal would not be completed until after the RTO made its first planned FERC filing to meet an October deadline. Those concerns became moot when the commission last week extended the deadline by six months. (See FERC Extends ISO-NE Fuel Security Filing Deadline.)
ISO-NE Principal Analyst Andrew Gillespie delivered a presentation and answered questions on the proposal during most of the rest of the daylong meeting, the first of two scheduled this week.
ERCOT on Wednesday asked Texans to reduce their electricity usage Thursday and Friday, when the state is expected to see some of the highest temperatures of the year amid tight reserve margins.
The National Weather Service expects temperatures to reach triple digits in all the state’s major metropolitan areas through Sept. 7. The grid operator issued an extreme hot weather alert on Tuesday for Friday and Saturday.
ERCOT is projecting peak demand of 72.7 GW on Thursday and 73.3 GW on Friday. That would smash the two new September demand records of more than 68.4 GW set earlier this week, which themselves were more than 1.5 GW above the previous mark set in 2016.
“ERCOT’s job is to ensure power is available all over Texas,” CEO Bill Magness said in a statement. “When electricity demand and heat reach levels like we expect on Thursday and Friday, we ask Texans to consider taking a few steps to help keep power flowing for all of us.”
Public Utility Commission Chair DeAnn Walker echoed Magness’ comments and noted the stress placed on generators by the sustained high temperatures.
“Operating at high efficiency like this can be a bit of a balancing act, so the PUC and ERCOT are working together to encourage Texans to conserve on Thursday and Friday afternoon,” she said in a statement.
The markets are expecting real-time prices to spike along with the temperatures. Thursday prices in the day-ahead market were settling on Wednesday afternoon at just over $5,000/MWh for the 5 p.m. hour.
Heat will be a major factor during Saturday’s Texas-LSU game. | Texas Sports
ERCOT expects to see the same trough of early afternoon wind generation that, combined with nearly 5 GW of generation outages, replicates the situations that led to the grid operator calling two energy emergency alerts (EEAs) in August. Prices hit the $9,000/MWh limit during both EEAs. (See “ERCOT CEO Briefs Commission on Summer Performance,” Texas PUC Briefs: Aug. 29, 2019.)
However, the grid operator expects demand to be higher this week than it was during the EEAs.
ERCOT began the summer with an 8.6% reserve margin. It set a new all-time peak of 74.7 GW on Aug. 12, and it has recorded 11 other demand marks above the record set a year ago. Last year, ERCOT broke its previous record 14 times.
Austin, home to ERCOT, exceeded 100 degrees Fahrenheit during 27 of August’s 31 days.
FirstEnergy Solutions asked the Ohio Supreme Court on Wednesday to block a vote to repeal $150 million in subsidies for its two nuclear plants.
The company argued the new ratepayer fees — ranging from 80 cents up to $2,400/month — are equal to a tax, making the underlying legislation, House Bill 6, ineligible for the petition that Ohioans Against Corporate Bailouts is currently circulating for a ballot referendum. (See Ohio Nuke Ballot Petition Approved.) The lawsuit names both the group and Secretary of State Frank LaRose, the state’s chief election official, as defendants.
“The charges levied by House Bill 6 are a tax and laws providing for the levy of a tax are exempt from a referendum under the Ohio Constitution,” said Tom Becker, an FES spokesperson. “The referendum is inherently misleading and confusing to Ohio voters. Ohioans and the state of Ohio should be spared the costs associated with this futile attempt to place this unconstitutional referendum on the ballot.”
Perry Nuclear Power Plant, located about 40 miles northwest of Cleveland
FES requested a truncated timeline giving the anti-subsidy group (referred to in the lawsuit as the respondents committee) just five calendar days for a response. Briefs on the merits would be due from FES in another 15 days and from the committee 15 days after that before potential oral arguments.
Meanwhile, Ohioans Against Corporate Bailouts has until Oct. 21 to gather almost 266,000 signatures for the referendum to appear on the November 2020 ballot.
“Time is of the essence in this case because the respondent committee, within the last few days, has started undertaking a misleading and ultimately futile solicitation of voter support and signatures for the committee’s illegal referendum effort,” FES wrote. “It is inherently misleading and confusing to Ohio voters for the respondent committee and its circulators and other agents to circulate and file a referendum petition that states, implies or otherwise suggests that H.B. 6 is subject to a referendum when that is not true.”
Gov. Mike DeWine signed the Ohio Clean Air Act into law on July 23 after months of debate over whether the Davis-Besse and Perry nuclear plants were worth saving. (See Ohio Approves Nuke Subsidy.) FES, currently negotiating a Chapter 11 bankruptcy settlement plan, said both facilities would close without the subsidies — taking 4,300 jobs and most of Ohio’s carbon-free emissions with them. The act replaces the state’s renewable energy mandates with ratepayer surcharges to support the reactors and two Ohio Valley Electric Corp. (OVEC) coal plants.
Gene Pierce, spokesperson for Ohioans Against Corporate Bailouts, blasted the lawsuit in an emailed statement that called into question FES’ legal standing and state lawmakers’ own attempts to frame the bill as anything but a tax.
“This frivolous lawsuit is another desperate attempt by FirstEnergy Solutions to protect their ill-gotten billion-dollar bailout,” he said. “In addition to having no legal basis, their own proponents in the legislature repeatedly stated that H.B. 6 was not a tax increase in their efforts to secure enough votes for passage of the bill.”
The Western Energy Imbalance Market is poised to expand across Northern California after three municipal utilities and the Western Area Power Administration’s Sierra Nevada (WAPA SN) division jointly announced they intend to join the growing real-time market.
The Balancing Area of Northern California (BANC) and WAPA said Wednesday they will sign an implementation agreement with CAISO that would allow WAPA SN and BANC members Modesto Irrigation District (MID), Redding Electric Utility and Roseville Electric Utility to begin trading in the EIM in April 2021. The decision does not affect any other WAPA regions.
The agreement represents the second phase of BANC’s approach to incorporating its members into the EIM. Sacramento Municipal Utility District (SMUD) entered the market in April. (See SMUD Goes Live in Western EIM.)
“BANC is excited to expand its participation in Phase 2 after becoming the first publicly owned agency to become an EIM entity,” BANC General Manager Jim Shetler said in a statement. “The success of Phase 1 … and the benefits we’ve realized encouraged more of our public power members to participate. We expect the transition will be as smooth for Phase 2 as it was for Phase 1.”
BANC members Modesto Irrigation District, Redding Electric and Roseville Electric will join the Western EIM in spring 2021, along with WAPA-SN. | BANC
While SMUD represented the first publicly owned utility to join the EIM, WAPA SN would be the first federal power marketing agency to participate. The Bonneville Power Administration, which operates about 15,000 miles of transmission in the Pacific Northwest, has begun a multiyear effort to examine EIM membership. (See Customers Probe BPA on EIM Impact.)
WAPA SN primarily markets wholesale power generated by the U.S. Bureau of Reclamation’s Central Valley Project, which includes the Shasta, Folsom, Trinity and New Melones dams. Its customers include towns, rural electric cooperatives, public utility districts, federal and military agencies, and Native American tribes in Northern and Central California and parts of Nevada.
Together with BANC, the agency is part owner of the California-Oregon Transmission Project, a 340-mile, 500-kV line that links BANC’s balancing authority area to BPA’s territory. The two connect via the Captain Jack substation in Southern Oregon, one of two major transfer points for energy flowing between the Northwest and California.
“Joining the Western EIM will help SN ensure the reliable delivery of our hydropower while adjusting to a changing energy mix. Given our footprint within the BANC balancing authority area, the Western EIM is the best fit for SN,” WAPA SN Regional Manager Sonja Anderson said.
MID provides electricity to more than 122,000 customers and irrigation water to 2,300 agricultural accounts in California’s Central Valley. The utility’s portfolio consists of about 66 MW of hydroelectric resources and 389 MW of gas-fired generation, including three peaking units.
“Joining the EIM will provide MID continued access to the market’s diverse, readily-available power resource mix,” MID General Manager Scott Furgerson said. “Access to this low-cost, growing pool of resources will also further ensure and enhance service reliability to our customers.”
MID estimates it will incur $3.3 million in start-up costs and about $1 million in annual expenses to participate in the EIM, with recovery anticipated within three years.
Redding Electric serves more than 42,000 residential and commercial customers within the city of Redding and owns 83 MW of gas-fired generation. With about 53,000 customers, Roseville Electric obtains most of its power from its own gas-fired generation and WAPA.
BANC members Shasta Lake and Trinity Public Utilities District have not committed to the EIM.
The task team examining changes to how MISO selects its Board of Directors is closing in on a set of recommendations that could alter eligibility requirements for future members.
Among the possible suggestions? Reserving a board seat for candidates who have experience representing the interests of utility customers.
The Board Qualification Task Team (BQTT) could offer up that and more later this month at MISO Board Week in St. Paul, Minn.
Jennifer Easler, an attorney with the Iowa Office of Consumer Advocate, said the move would ensure customer views are better represented on the board.
“I believe the current structure is more heavily dominated by industry perspectives,” Easler said during a Sept. 3 BQTT conference call. “I believe the price of particular initiatives is something good to keep in the forefront.”
Easler said she envisioned the position being filled by anyone with experience advocating for consumer interests, whether at a public or non-governmental organization. She said it would be helpful for RTOs to be more cost-conscious.
But some members of the task team cautioned a consumer expertise requirement might be too broad and is probably already represented among current board members. Others said they worried further earmarking of board seats for specific backgrounds could lead to a shallower pool of candidates.
MISO’s Transmission Owners’ Agreement dictates that the nine-member board contain six members with experience in corporate leadership at the senior management or board level or in the areas of finance, accounting, engineering or utility laws and regulation. The three remaining director seats are divided among those with transmission system operations, transmission planning and commercial markets and trading experience.
When she served on the Nominating Committee last year, Madison Gas and Electric’s Megan Wisersky said she was explicitly told to look for candidates with a regulatory background, even though regulatory experience was not a prerequisite. The committee eventually recommended then-sitting Minnesota Public Utilities Commission Chair Nancy Lange. (See MISO Elects Lange to Board; Keeps 2 Incumbents.)
“Where does this come from?” she asked, calling for MISO and its Advisory Committee to be more transparent about which skills and background they’re seeking each year in new directors. She asked MISO to share how it decides what qualifications will help better position the RTO to navigate grid change.
MISO earlier this year tasked the BQTT with examining possible Nominating Committee changes, either expanding or eliminating the RTO’s yearlong “cooling-off” period imposed on board candidates, and potentially detailing more director qualifications.
Exelon’s David Bloom said the team will likely provide a draft of its recommendations at the Sept. 18 Advisory Committee meeting during MISO Board Week. The AC is expected to vote in December on whether to put the recommendations before the board’s Corporate Governance and Strategic Planning Committee.
MISO sectors have generally agreed to recommend increasing the number of stakeholder representatives on the Nominating Committee that selects board candidates. (See MISO Sectors OK Expanding Nominating Committee.) The BQTT appears ready to suggest boosting the number of stakeholder seats from the current two to three or four and rotating the sectors from which participants are drawn. Three committee seats are reserved for sitting board members.
The BQTT also looks set to recommend applying MISO’s current yearlong cooling-off period before board eligibility to state and federal regulators as well as those coming out of the industry.
“State commissioners and staff are market participants in every sense of the word but the legal definition. Their decisions affect what happens in MISO,” Wisersky said.
Three MISO directors’ terms will conclude at the end of this year. Additionally, the board is involved in a special process to decide on a candidate to replace former board member Thomas Rainwater. (See “Board Moving on Rainwater Replacement,” MISO Board of Director Briefs: June 20, 2019.)
BQTT leaders will likely ask MISO to extend the life of the group by at least a month in order to consider feedback from AC members through October. Bloom said while he hoped the team could wrap up next month, he wouldn’t rule out an extension through the end of the year.
A group of grassroots organizations opposed to high-voltage transmission projects summed up the initial comments in FERC’s inquiry into its transmission incentive policies quite nicely (PL19-3).
“Those who profit from transmission incentives believe incentives should remain the same or be increased. Those who pay transmission incentives believe incentives should be reduced or phased out entirely. And those who believe transmission incentives are key to saving the planet champion new incentives at any cost,” said the group, which included organizations such as the Coalition for Rural Property Rights, the Eastern Missouri Landowners Alliance, Say NO to NECEC and STOP Transource Power Lines MD. “It is the unenviable position of this commission to referee these disparate interests to set policy that best serves its mission to ensure economically efficient, safe, reliable and secure energy services for consumers.”
Under an inquiry it opened in March, FERC is examining whether it should continue to grant transmission developers certain incentives, whether to increase or decrease them, and whether they should be based on projects’ risks and challenges or on the benefits they provide. Initial comments were submitted in late June. (See Tx Incentives NOI Brings Calls for Broader Reforms.)
Stakeholders largely reiterated their positions as they rebutted each other in their reply comments in the docket, submitted last week. Below, based on a review of more than two dozen filings, is a sample of what FERC heard.
“Not surprisingly, the initial comments contain conflicting recommendations for how the commission should proceed at this crossroads,” the California Public Utilities Commission said. “There is, however, general consensus that the historical decline in transmission investment that motivated Congress to enact Section 219 [of the Federal Power Act] in 2005 has been conclusively reversed.”
Defense of the Adders
The Edison Electric Institute said it “does not agree with commenters arguing that because Section 219 of the FPA and Order No. 679 have helped to promote increased transmission investment, the job is done and changes to the commission’s incentives policy to continue to encourage transmission development are not needed. Nor does EEI agree with those commenters who go even further and advocate that the commission rollback its incentives policy, because this would be counterproductive to meeting Congress’ objectives in implementing Section 219.”
The New Jersey Board of Public Utilities and the state’s Division of Rate Counsel filed joint comments saying transmission owners should not receive an incentive for RTO membership because “the benefits of RTO membership are a sufficient incentive,” citing economies of scale and efficiencies in the transmission planning process. “If the commission continues the RTO incentive adder, it should not be generically applied ‘regardless’ of why transmission owners participate in RTOs,” they wrote.
But others argued that FERC is required to provide an RTO/ISO participation adder under FPA Section 219. The commission approved the adder in Order 679 in 2006.
U.S. annual transmission investments for FERC-jurisdictional and ERCOT transmission owners up to 2017, with EEI projections beyond | The Brattle Group
“Some commenters that argue for elimination of the current RTO participation incentive do not even acknowledge that the commission is statutorily obligated under FPA Section 219 to provide an RTO incentive,” a group of MISO transmission owners said. “Those that do acknowledge the obligation fail to provide a compelling reason to conclude that the current, modest 50-basis-point adder incentive is no longer reasonable, omit any detail regarding what ‘incentive’ the commission should offer instead, and do not provide any evidence to demonstrate the reasonableness of any such alternative incentive.”
“The initial comments opposing retention of the RTO participation adder do not offer compelling arguments,” American Electric Power said. “Some commenters suggest that the RTO participation adder should be eliminated, or should be phased out for current RTO members and available for a fixed period only for new RTO members. Such proposals are in tension with the legislative text and the commission’s interpretation of that text.”
Others defended the participation adder on its own merits.
“The role of RTOs and the need for consistent, stable membership of transmission owners will only be heightened in the next phase of investments into the transmission system,” MISO said. “Incremental changes, even changes that may occur in separate proceedings over the course of several years, have the potential to erode the foundation upon which RTOs were built.”
MISO insisted the participation adder is necessary to expand voluntary RTO membership, saying that membership has “stalled,” far from the “near universal” participation FERC envisioned when it issued Order 2000 in 1999.
Eversource Energy said that the RTO participation subjects TOs to risks, as they turn over their operational control and transmission planning functions, and they also face coordination issues, such as outage scheduling.
“Transmission-owning RTO/ISO members assume the considerable risks associated with RTO/ISO participation for the benefit of their customers, as many of the benefits of RTO/ISO participation accrue to customers and not to the utilities themselves,” agreed Exelon.
In joint comments, Pacific Gas and Electric and San Diego Gas & Electric urged FERC to maintain both the participation adder and the abandonment incentive, which permits recovery of 100% of prudently incurred costs for projects canceled because of factors that are beyond TOs’ control. Any reduction, even in certain circumstances, could act as a disincentive to new investment, the utilities said.
Competition
Eversource also said the commission should dismiss the suggestion to condition the application of the RTO participation incentive on the relevant RTO or ISO having at least 33% of the transmission investment in its region originating from competitive solicitations. “There is nothing in the language of Section 219c to suggest that the incentive for joining a regional transmission organization should be conditioned upon the level or percentage of transmission investments subject to the competitive solicitation process. Indeed, in the [Notice of Inquiry], the commission itself pointed out that Order No. 1000 is not related to ‘the commission’s obligations under Section 219.’”
EEI’s most recent historical and projected transmission investment data | Edison Electric Institute
Both PJM’s Independent Market Monitor and LS Power said the existing structure provides enough incentive to attract infrastructure investment and, if anything, should subject more projects to competitive bidding.
LS Power asked FERC to withhold incentives from upgrades or new builds that aren’t “independently reviewed.”
“FERC does not need to change its current incentives policies in order for ratepayers to obtain the benefits of competition, but FERC can significantly expand these benefits by taking steps to expand the number of projects selected through competitive transmission solicitations,” the company said.
“Rules permitting competition to provide financing for PJM and other RTO transmission expansion projects could reduce the cost of capital for transmission projects and significantly reduce total costs to customers,” the Monitor said. “Rules that allow incumbent owners to exclude, limit or condition the development of new or replacement transmission projects create barriers to competitive investment.”
Advanced Tech
The Grid Advancement Coalition — 18 companies, environmental organizations and trade groups, including ITC Holdings, the American Wind Energy Association and the Natural Resources Defense Council — called for policies to encourage relatively low-cost investments that could make existing transmission more efficient, such as dynamic line rating and power flow controls. “This action is needed to comply with FPA Section 219b(3), adopted in the Energy Policy Act of 2005, because the commission never introduced specific regulations implementing that section in Order 679 or elsewhere,” it said.
It also asked the commission “act separately to promote a more expansive transmission planning regime that fully considers the benefits of grid expansion and integration across seams.”
“There are many benefits of transmission investments that are unrecognized and uncredited in the commission’s current regulatory scheme, making ‘free riders’ of many consumers while others are faced with locally concentrated costs, leading them to oppose transmission development they should favor,” the group wrote. “The commission should reset that scheme by focusing its evaluation of transmission incentives on the consumer benefits that proposed transmission investments supported by incentives will deliver, rather than on how ‘risky’ or ‘challenging’ a transmission project may be to develop.”
Potomac Economics, which provides market monitoring services for MISO, NYISO and ISO-NE, had also proposed an incentive to encourage the use of dynamic line ratings as a way of increasing existing lines’ capacity. The MISO TOs, however, came out against that idea.
“Introducing economics into transmission facility rating decisions could work at cross-purposes with actions of utility operators to objectively perform their reliability functions,” they said. [On Sept. 10-11, FERC will hold a technical conference on transmission line ratings, with a focus on dynamic and ambient-adjusted ratings (AD19-15)].
The Working for Advanced Transmission Technologies (WATT) Coalition proposed a new incentive for small projects using advanced technologies that produce quantified congestion benefits, an idea supported by AEP.
No New Incentives
But other stakeholders were vehemently opposed to new incentives, increases to existing adders or making qualification for them easier.
“The commission’s incentives policies are already quite flexible and allow transmission owners the ability to seek a range of incentives … for various purposes,” the National Rural Electric Cooperative Association said. “It would be inappropriate, however, to enshrine the various perks that transmission owners want into the commission’s incentive regulations.”
NRECA called out WATT’s proposal specifically, saying such projects “may hold promise of such consumer benefits, but the commission should not approve a new incentive rate treatment for them in this proceeding.” It cited FERC’s 2012 incentives policy statement, where it explained that “having distinct standards apply to advanced technologies contributes to confusion.”
“Sticking with this case-by-case process for these kinds of projects is the best way to ensure that regional planning requirements can be established; that the relevant costs and benefits can be identified and defined; and that the appropriate shared-savings rate treatment can be evaluated,” NRECA said.
| R Street Institute
FERC in Order 679 established a requirement that each applicant must demonstrate that there is a “nexus” between the incentive sought and the risks and challenges of the investment being made.
“Industry commenters that propose making the nexus test less rigorous and the commission’s incentives policy more expansive look ahead to justify their recommendations, by speculating on how the commission’s incentive policy must evolve to appropriately incent investment to facilitate the grid of the future,” the California PUC said. That argument is flawed for several reasons, it said, including a lack of evidence that FERC’s incentives have increased transmission reliability, reduced congestion and lowered costs. FERC needs to show proof before it starts adding new incentives for new purposes, such as ensuring resilience in the face of climate change and extreme weather.
The CPUC rejected suggestions that the commission automatically award the abandoned plant and construction work in progress incentives.
“Instead, the CPUC recommends that the commission should now make the nexus test more rigorous, transparent and data-driven by, for example, implementing a cost-benefit analysis, cost caps and other forms of cost containment, and ex post verification of project benefits.”
The New England States Committee on Electricity said it “strongly disagrees” on the need for a new category of FERC transmission rate incentives to help implement state-jurisdictional energy and environmental laws. It pointed to the Massachusetts Department of Public Utilities’ approval of contracts to deliver power over a new 1,200-MW HVDC line, and the 2015 solicitation by Massachusetts, Connecticut and Rhode Island for clean energy projects, none of which ended up needing new transmission, as evidence that “transmission incentive reforms are not needed to advance New England states’ laws.”
The Eastern Massachusetts Consumer-Owned Systems (EMCOS) said the commission “should be wary” of any proposal to grant TOs additional incentives. “The evidence shows that continued transmission investment has produced smaller and smaller benefits to consumers at greater and greater costs,” the group said. “If the commission chooses to revisit Order No. 679, it should examine whether the costs of its current transmission incentives outweigh the benefits produced.”
The grassroots groups were more colorful, urging “the commission to proceed thoughtfully, and with a realization that transmission owners will continue to chase higher returns and profit, no matter the decision reached in this docket.”
“Like any spoiled child whose lollipop is taken away, transmission owners may kick and scream and promise to hold their breath until they die. We all know that’s an impossibility and that highly profitable transmission investment will continue to happen, even without an incentive lollipop.”
Michael Brooks, Amanda Durish Cook, Rich Heidorn Jr., Michael Kuser, Hudson Sangree and Christen Smith contributed to this report.
FERC last week rejected an administrative law judge’s finding that PJM’s transmission study process is unjust and unreasonable for developers seeking to secure incremental auction revenue rights (IARRs) by making upgrades to reduce grid congestion (EL15-79).
The commission reversed ALJ Philip C. Baten’s January 2018 initial decision ordering PJM to reinstate three interconnection queue positions he said were unfairly eliminated when developer TranSource refused to pay for a facility study, the next stage of its interconnection process after the system impact study (SIS). FERC also reversed Baten’s conclusion that PJM should refund TranSource’s SIS application fees. (See FERC Judge Faults PJM, TOs on Transmission Upgrade Process.)
TranSource filed a complaint in June 2015 contending that PJM and transmission owners Public Service Electric and Gas, PPL, Jersey Central Power & Light and Delmarva Power & Light inflated the cost of upgrades necessary to approve three requests for IARRs. (TranSource is not to be confused with Transource Energy, a joint venture of American Electric Power and Great Plains Energy.) (See Transmission Developer: PJM TOs Inflating Upgrade Costs for ARRs.)
The commission affirmed Baten’s decision to reject other remedies TranSource sought, including its claim for $63.6 million in “lost business” opportunities. And it agreed with Baten that it could not determine whether the $1.7 billion in upgrades PJM identified were indeed necessary, noting that the case focused on the impact studies, which are supposed to produce only “good faith” cost estimates.
Readington-Roseland Line
TranSource’s upgrade proposals used facility ratings from FERC Form 715 filings made by PJM on behalf of the TOs. Baten said that was a “reasonable” assumption based on “statutory and regulatory provisions” and language in PJM’s Tariff.
PJM testified its cost estimates were based on the line ratings expected at the time that the project being studied would be in service, including planned upgrades. PJM’s estimates also incorporate the host TO’s review of limiting elements based on the methodologies they file under NERC reliability standard FAC-008-3. The methodologies are not public and not the same as those used for Form 715.
A primary conflict was over estimates for upgrading PSE&G’s Readington-Roseland 230-kV line in New Jersey.
PJM’s analysis of transmission upgrade requests under Tariff Attachment EE is done in two steps. The SIS provides developers with an estimate of what their plan will cost with +/- 40% accuracy.
The first component of the SIS is the simultaneous feasibility test, in which PJM tests whether the developer’s IARR request can be accommodated without diminishing the income of the current ARR holders. After that, PJM identifies the facilities that are impacted by the IARRs, and the relevant TOs conduct “desk-side” studies — so called because they do not involve site visits — using the confidential methodology to identify upgrades needed to accommodate the IARRs and their estimated cost.
If the developer chooses to proceed based on the SIS results, PJM conducts an in-depth facilities study that requires a refundable deposit of at least $100,000 and is supposed to provide a more accurate itemization of required upgrades.
A facilities study done for Exelon in late 2014 pegged the cost to repair the Readington-Roseland line at about $14.2 million. Although the towers had been in service for 80 years, “based on visual observation only, tower replacements are not anticipated,” the study said.
But an SIS done for TranSource six months later increased the estimate more than nine times to nearly $126.5 million. When Richard Crouch, a PSE&G electrical engineer, reviewed the project three months later, he called for a complete wreck and rebuild for more than $142.7 million, a $16 million increase.
Analyses of the condition of the Readington-Roseland line was a source of contention in the TranSource case. | PJM
By 2016, PSE&G engineers had put the line on its list of facilities violating the company’s Form 715 end-of-life criteria.
TranSource contested the SIS for Readington-Roseland and its other requested upgrades, saying it lost financing because of what it called PJM’s “badly inflated” estimates. The RTO eliminated TranSource’s queue positions when it refused to pay for the studies.
Baten ruled that the lack of transparency in PJM’s SIS process made it “unduly discriminatory” to merchant developers by depriving them of business opportunities.
But while the commission directed PJM to add more detail regarding its SIS methodologies and assumptions to its Tariff, it ruled that the RTO’s treatment of TranSource “represent a transparent process that is just and reasonable.” It said the Exelon facilities study cited by TranSource was an interconnection study, not a transmission planning study.
The commission also reversed Baten’s findings that the line rating methodology lacked transparency and that it was reasonable for TranSource to rely on Form 715 ratings in conducting its own evaluation of its upgrade requests.
And it said the judge ignored precedent and the facts in concluding that PJM’s SIS process was unduly discriminatory. Citing Congress’ creation of classes under civil rights statutes, Baten concluded that FERC had “created a class” of merchant developers and established “benefits for the class.” He said that since the IARR program began in 2007, only one project (combining five queue positions) had been awarded IARRs out of 41 Attachment EE queue positions.
FERC said Baten failed to make a finding that PJM treated TranSource differently than other Attachment EE customers or that Attachment EE customers were treated differently than other classes of customers.
“We agree with PJM, the PJM transmission owners and trial staff that the presiding judge’s reliance on the fact that very few Attachment EE requests have resulted in IARRs being awarded is misplaced,” the commission said. It added that he ignored testimony from David Egan, then manager of PJM’s Interconnection Projects Department, that “to make a profit under Attachment EE, a developer must find a ‘sweet spot’ where the transmission upgrades reduce congestion, but enough congestion remains so that the resulting IARRs have value.”
The commission dismissed as moot TranSource’s request to require PJM to add a pre-SIS phase to the Attachment EE process, noting that FERC approved the addition of a feasibility study to the process in April 2018.
