PG&E Corp. on Monday filed a reorganization plan in U.S. Bankruptcy Court that includes $16.9 billion to pay for wildfire claims, the first step in what is expected to be a protracted battle between wildfire victims and other creditors over the utility’s future.
The San Francisco-based company said the Chapter 11 reorganization plan is designed to enable its debtors to “fairly and expeditiously” treat wildfire claims made before the filing “in full compliance” with recently passed legislation (AB 1054). The law creates a $21 billion insurance-like fund to pay for wildfire damages and is bankrolled by California’s three big investor-owned utilities and ratepayers. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)
The plan would create two trust funds, one capped at $8.4 billion to wildfire victims who were unable to cover all their losses and a second capped at $8.5 billion to reimburse insurance companies for their payouts.
The plan also would cover $1 billion previously announced to fully settle the wildfire claims of public entities.
CEO Bill Johnson said in a statement that the plan “will meet our commitment to fairly compensate wildfire victims and we will emerge from Chapter 11 financially sound.”
“I am confident that we can, and will, provide better service to our customers and communities, and our plan of reorganization is another step in this process,” Johnson said. He said the company will remain focused on reducing the risk of wildfires and continue supporting the state’s clean-energy goals.
PG&E said the plan will achieve a rate-neutral solution for customers and meet AB 1054’s June 30, 2020, timeline to become eligible to participate in an insurance fund for future wildfire claims. The company also said it will honor all pensions and collective bargaining agreements.
Under the plan, PG&E would also assume, or remain responsible, for all power purchase agreements and community choice aggregation servicing agreements. Court documents indicate the utility holds almost 400 PPAs with more than 350 companies, worth about $42 billion.
It remains to be seen whether the wildfire victims will accept PG&E’s offer. In addition, a group of hedge funds seeking to recoup billions of dollars from PG&E are attempting a hostile takeover of the company.
Meanwhile the city of San Francisco made an offer Friday to buy the utility’s city electric operations for $2.5 billion. (See related story, PG&E Ends Bond Bid as SF Makes Wires Offer.)
PG&E said it intends to work with financial institutions over the next several weeks to obtain up to $14 billion in equity financing commitments. Those proceeds will be used to pay wildfire victims and help fund PG&E’s contributions to the state wildfire fund.
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.
The U.S. Bankruptcy Court in San Francisco, where PG&E made the filing, canceled a hearing scheduled for Tuesday.
The Western Area Power Administration, Basin Electric Power Cooperative, and Tri-State Generation and Transmission Association announced Monday they will join SPP’s Western Energy Imbalance Service (WEIS) market, giving the new market a foothold in more than a dozen states. SPP plans to launch the WEIS in February 2021.
As the market administrator, SPP will centrally dispatch energy from the participants every five minutes using the most cost-effective generation to reduce wholesale electricity costs for participants. The market will provide price transparency and allow parties to trade bilaterally and hedge against transmission congestion.
SPP is accepting commitments from additional customers to be included in the market’s initial go-live through Oct. 25.
The footprints of the three members include portions of Arizona, Colorado, Iowa, Kansas, Minnesota, Missouri, Montana, Nebraska, New Mexico, North Dakota, South Dakota, Utah and Wyoming. Arizona, Colorado, and Utah are not part of the RTO’s 14-state footprint.
Basin Electric CEO Paul Sukut cited SPP’s “proven track record in operating energy imbalance and full day-two markets,” its “independent board of directors, a proven stakeholder process and a governance structure that specifically includes commissioners from state regulatory commissions.”
Tri-State CEO Duane Highley said the WEIS will provide “a cost-effective solution that quickly increases market efficiencies, reduces expenses for our members and electric consumers, and supports Tri-State’s rapid transition to cleaner energy.”
Joining from WAPA will be the loads and resources of Pick-Sloan Missouri Basin Program – Eastern Division, the Loveland Area Projects and the Salt Lake City Area Integrated Projects, located in the Upper Great Plains Western Area Balancing Authority (WAUW) and Western Area Colorado Missouri Balancing Authority (WACM).
WAPA Administrator and CEO Mark Gabriel said the agency needed to examine markets because of the increasing pace of change in the electric industry, with new generation options “and pressing needs regarding balancing area operations.”
“We are committed to seeking mutually beneficial partnerships consistent with sound business principles,” he said.
The RTO said it plans to operate WEIS under a “Western Joint Dispatch Agreement,” which it said “guarantees participants a say in the market’s ongoing evolution.” Utilities do not have to be a member of the RTO to participate.
“We’re a stakeholder-driven organization that believes in the power of partnership,” SPP CEO Nick Brown said. “We want to do more than just launch a wholesale electricity market in the West. We want to work with utilities to understand the challenges they face and develop smart solutions that benefit the whole region. That’s how we operate as an RTO, and it’s how we plan to administer this and other contract services in the West.”
SPP also is scheduled to begin providing reliability coordination services for more than a dozen utilities in the Western Interconnection in December. It also intends to offer planning coordination to help utilities study and plan transmission upgrades.
Last week, Xcel Energy, Colorado’s largest load-serving entity, and three partners — Black Hills Energy, Colorado Springs Utilities and Platte River Power Authority — announced they were evaluating both the WEIS and CAISO’s Western Energy Imbalance Market. (See related story, Colorado Utilities Examine Market Membership.)
Basin Electric, headquartered in Bismarck, N.D., generates and transmits power to 141 rural electric systems and 3 million customers in nine states: Colorado, Iowa, Minnesota, Montana, Nebraska, New Mexico, North Dakota, South Dakota and Wyoming.
Tri-State is a not-for-profit generation and transmission cooperative with 43 distribution cooperatives and public power districts that serve 1.3 million people in Colorado, Nebraska, New Mexico and Wyoming.
ERCOT said Monday that it has sufficient installed capacity to meet system demand this fall and winter.
The final fall seasonal assessment of resource adequacy (SARA) indicates the Texas grid operator will have nearly 84 GW of capacity to meet a projected peak demand of 61 GW during October and November. The preliminary SARA for the winter season (December-February) anticipates a peak demand of 62.3 GW.
ERCOT’s fall outlook | ERCOT
The fall SARA — based on normal weather conditions during peak demands from 2003 through 2017 — adds almost 2 GW of planned additional capacity: 296 MW of gas-fired generation, 732 MW of wind and 170 MW of solar resources. It also includes 13,833 MW of forecasted unit outages, based on historical averages for the past three years.
“Our studies show we have sufficient generation for the fall season,” Manager of Resource Adequacy Pete Warnken said in a statement.
An additional 1,179 MW of planned winter-rated capacity is expected to be added between now and December. The final winter SARA will be released in early November.
ERCOT began the summer with 78.9 GW of available capacity and an 8.6% reserve margin.
The SARA report assesses generation availability and expected peak demand conditions at the time it is prepared. The assessment takes into account expected generation outages for routine maintenance and a range of outage scenarios and weather conditions that could affect seasonal demand.
AUSTIN, Texas — Infocast’s Texas Renewable Energy Summit last week brought developers, corporate off-takers, cities, municipalities, cooperatives, the financing community and other key stakeholders to sort out where ERCOT’s market is headed, stay abreast of the latest trends shaping the Texas renewables market, and glean the latest insights into the market.
Meeting in the midst of 100-degree-plus heat along the banks of Lady Bird Lake in downtown Austin with ERCOT facing tight grid conditions, much of the conversation centered on the market’s performance this summer.
John Hall, Texas-based director of regulatory and legislative affairs for the Environmental Defense Fund, complimented ERCOT’s staff on meeting record customer demand despite an 8.6% reserve margin. The grid operator has been forced to call two energy emergency alerts, the first in five years, but avoided taking more extreme measures.
Referring to the “ERCOT movie, which I find the most interesting movie this summer,” Hall asked the panel he was moderating for their opinion.
Jacob Steubing, director of origination and structuring for solar developer Recurrent Energy, agreed with Hall but said, “I’m still holding out for ‘Joker’ with Joaquin Phoenix. It’s getting good press.”
Turning serious, Steubing said, “I’m a solar guy, so going by the book, we think the market design as it stands is ideal. Solar has performed at least as well as expected, and I think the data backs that up. We’re continuing to see more sophisticated buyers seeking that solar shape. Your exposure in Texas is when it’s hot and sunny, and solar is a pretty good hedge for that.”
Karl Dahlstrom, senior vice president of commercial execution for renewable developer Seventus, said ERCOT’s market is unique, given its 2% “consistent load growth every year.”
“The impressive number of renewable buildup is placing pressure on fossil plants,” he said. “We do think the market is working. We’re happy to see the $9,000[/MWh scarcity] prices happen. The purpose of the $9,000 price was to encourage new generation. It will be some time over the next two years to see if that’s changed investors’ expectations.”
“This summer’s been really good. It’s helped improve the market confidence in EROCT and [the Public Utility Commission’s] management of the market,” said Resmi Surendran, senior director of regulatory policy for Shell Energy. “ERCOT is only taking market actions at the last moment. It’s a good example to show market impact on prices. That has shown the importance of having the right market design.”
“You will get your returns in the energy-only market, but be careful what you wish for, because here we are,” PowerFin Partners CEO Tuan Pham said. “This market is designed as a trader’s market. Traders love volatility, and they’re killing it right now. Grandma’s not going to be paying the $9,000 prices, so who pays? The retailers are supposed to, and they will, but prices will eventually get socialized to all the ratepayers. It’s going to take some time to work through the system to socialize Grandma’s bills, but it’s going to happen.”
Pham said if ERCOT operated a capacity market or more defined market, no longer would “traders make a whole lot of money and walk off with their bonuses and never invest in the transmission grid.”
A capacity market is anathema to many of ERCOT’s participants. “As a solar developer, we’re against that,” Steubing said, echoing similar comments from others on his panel.
Bob Helton, ENGIE’s senior director of regulatory affairs, recoiled when a fellow panelist mentioned a capacity market.
“There are three words you can’t say in Texas: blackouts, capacity market and the wall,” he said in jest. “It’s involuntary load shed, load obligation and life-form barrier.”
On a more serious note, Helton said transmission is the biggest issue in the market, saying renewable energy’s “basis risk” — the spread between futures and physical prices — is “horrendous across Texas.”
“That will be the main barrier,” he said. “It’s hard to find projects. We’ll have to look at things completely out of the box.”
Panel: Not All Proposed Projects Will be Built
A panel discussing the generation buildout and connecting the resources to the system cast doubt on the more than 100 interconnection requests by renewable developers. ERCOT’s August generator interconnection status report lists 62.4 GW of planned solar projects and nearly 36 GW of wind projects among the nearly 112 GW of study requests.
“We’re just simply not going to build out 40 GW of solar in the state,” Pham said. He said it’s “apparent” ERCOT’s interconnection processes, bogged down with too many specious applications, need to change. “It’s also important to think about distinguishing between solar and wind. You have investors still stuck in this paradigm of imposing wind expectations on solar energy. Wind is off peak; solar is on peak.”
Sunil Nair, managing director for Transmission Analytics Consulting, called the amount of solar projects in the queue “ridiculous” and said the “basis differential risk is real, and it’s growing.”
“The large amount in the queue … is going to cause issues,” he said. “How much is built or where. Unfortunately, I don’t think anyone has a crystal ball.
“There are growing levels of basis differential risk and congestion risk,” Nair said. “We’ve heard a lot of talk about scarcity pricing … but people are building out in areas where they are competing with other wind and solar projects for transmission access. But you may not see that $9,000 pricing. If located behind a constraint with wind or solar on the margin, you may be sitting at zero or negative pricing, while everyone else is getting $9,000.”
Kip Fox, president of Electric Transmission Texas, a joint venture between subsidiaries of American Electric Power and Berkshire Hathaway Energy, said the end result is a system that does not have enough transmission.
“We’ve had half a billion in congestion costs so far this year. Half a billion solves a lot of adequacy problems,” he said. “When I hear an appeal for conservation from ERCOT, I see a transmission system that is going to be in trouble. We’re going into a period where there is more risk due to increased load and congestion.”
While energy storage facilities are increasingly being added to the interconnection queue, ERCOT insiders are also seeing growing interest from server farms and Bitcoin mining operations seeking reliable transmission service.
“We’ve had a lot of requests from Bitcoin server farms,” Fox said. “Bitcoin is tired of being in Mongolia or the Siberian peninsula. These facilities take anywhere from 10 to 20 MW of power and would love to be hooked up to a reliable grid.”
“You won’t see 40 GW of server farms [in West Texas]. You have prairie dogs out there,” Pham said, offering a dissenting viewpoint. “People who operate those things would rather live in Austin or Silicon Valley.”
Wind Industry Expects Continued Growth
The summit’s speakers continue to see strong growth in the Texas wind industry. The rush to begin construction on approved projects before the production tax credit falls off after 2020 is a key driver, but so could be the groundwork laid back in the 1990s by former Texas Gov. George W. Bush, which has led to acceptance of the industry’s facilities.
Texas opened its electricity market to competition in 1999, which led to a wave of wind development and the need for additional transmission infrastructure. The Competitive Renewable Energy Zones (CREZ) project was the answer, resulting in the construction of 2,400 miles of high-voltage lines, capable of carrying 18.5 GW of West Texas wind to ERCOT’s major load centers.
“You could almost say George W. Bush was the godfather of Texas transmission lines,” Pattern Energy Group Vice President George Hardie said. “The CREZ lines enabled an extraordinary amount of new wind to be developed. Because Texas wind has done extraordinary things for Texas communities, there’s been very little blowback of visual aesthetics. You’re seeing wind projects going increasingly closer to load centers.”
“This has all the fundamentals of being a great place for wind development,” said Susan Williams Sloan, vice president of state affairs for the American Wind Energy Association. “There’s high load, so there are a lot of customers. There are ample wind resources and market rules that allow the developers or generation owners to connect to the grid and get their power to the market. With a low-cost, competitive market … there’s a whole lot of political support for building and hosting wind farms. We’re seeing a lot more interest in hosting more [renewable resources] because it’s been so good for rural economic development.”
Vanessa Tutos, EDP Renewables’ director of government affairs, said there’s no political will for a CREZ II, saying “it’s so much more expensive to build large-scale transmission to serve that cheap generation than it is to use distributed generation.”
“Looking at the economic development that is lost to rural America, renewable energy can be there and help some of the economies,” she said. “The only way to do that is enable access to those markets so we can get these projects developed where they’re needed.”
“You can argue wind has been so successful in Texas, it’s creating some adversities that need to be shaken out,” Hardie said. “We need more transmission, but how conducive is ERCOT to building a new transmission line just to accommodate a 100-MW wind farm in West Texas when there’s already so much wind coming out of there? The CREZ lines have become, in an amazingly short time, all full up. Careful siting and location of wind projects, and where the power is needed, will be the key for the ongoing success of wind.”
Sloan said that while the wind industry may soon be the only form of generation not receiving some form of federal tax subsidy, and without a price on carbon, her stakeholders always find a way to beat expectations.
“If there’s only one technology left competing against other technologies with their incentives and subsidies, and despite the cost of wind coming down 69% over the last nine years, being able to compete against others is going to be tough,” she said. “Since I’ve been in this industry, we’ve beat expectations every way. A technology-neutral tax incentive is something you will see us advocating for.”
Permian Basin Drives ERCOT’s Load Growth
Shannon Caraway, vice president of business development for Solar Prime and a 30-year veteran of the ERCOT market, said that while the grid operator’s 2% annual load growth may be setting the standard, it’s nothing compared to the growth in West Texas’ oil-rich Permian Basin.
“The amount of sheer load growth is just staggering. In my entire career, I can’t remember an area that has grown that fast and worn out a forecast,” he said, noting that peak load in ERCOT’s Far West zone has grown 47% since summer 2017 (2,920 MW to 4,280 MW), accounting for about 27% of ERCOT’s peak load growth.
The growth is fueled by oil and gas production. The Permian Basin is currently producing more than 4.2 million barrels per day, though the rate of growth has slowed in recent months. If the trend continues, it would only mean the load growth slows somewhat.
“As long as oil prices stay above $50 a barrel, production could reach up to six million barrels a day,” said Brian Bartholomew, a U.S. power analyst with BloombergNEF.
The petroleum companies are betting on renewables to help manage their price risk. Exxon Mobil recently procured 250 MW of solar energy in the Permian and 250 MW of wind. Shell is also said to seeking renewable generation. ERCOT’s most recent adequacy report indicated nearly 1,9500 MW of solar energy is already operating in its footprint, with 1,500 MW in West Texas.
“A vast majority of all that West Texas solar sits in the Permian Basin,” Caraway said. “When we came out to the Permian area six years ago, most of the solar development was much farther west, west of Fort Stockton. It had great solar irradiance but almost no transmission. Since then, we’ve seen solar in the Fort Stockton area experience severe congestion.”
American Electric Power on Tuesday said it is revising its 2030 targets for reducing carbon dioxide emissions, increasing them to 70% from 60% over 2000 levels.
AEP also said it believes it can cut CO2 emissions by more than 80% by 2050 from its 2000 levels. The company already has cut its emissions by 59% since 2000, a pace it said was faster than expected.
“We’ve made significant progress in reducing carbon dioxide emissions from our power generation fleet and expect our emissions to continue to decline,” AEP CEO Nick Akins said in a press release, adding that the company’s aspirational goal is zero emissions by 2050.
AEP has achieved many of the reductions so far by shutting down inefficient, out-of-market coal plants. Coal-fired generation accounts for 45% of its capacity today, down from 70% in 2005. Natural gas capacity has increased from 19% to 28% and renewable capacity from 4% to 17% during that time.
“Technological advances, including energy storage, will determine how quickly we can achieve zero emissions while continuing to provide reliable, affordable power for customers,” he said.
The Columbus, Ohio-based company, which has operations in 11 states, said it will invest in renewable generation and transmission and distribution technologies that increase efficiency and expand demand-response and energy-efficiency programs to increase CO2 reductions.
AEP’s resource plans include adding more than 8.6 GW of new wind and solar generation to serve the company’s regulated utility customers by 2030. The company is currently seeking regulatory approval to add 1.5 GW of new wind generation to serve customers in Arkansas, Louisiana, Oklahoma and Texas.
AEP Ohio has a case pending before the state’s public utility commission to have customers finance the building of a 400-MW solar farm, the largest in the state, in southeast Ohio.
The company could also benefit from provisions in the state’s House Bill 6, which will raise and distribute $20 million annually from 2021 through 2027 to help finance six utility-scale solar farms previously approved by the Ohio Power Siting Board.
Akins said last October that the company would focus on smaller renewable projects after Texas regulators rejected its proposed $4.5 billion Wind Catcher project. Wind Catcher would have included a 2-GW wind farm in the Oklahoma Panhandle that would have supplied customers in Oklahoma, Louisiana, Arkansas and Texas. (See AEP to Focus on Smaller Renewable Projects.)
AEP intends to shut down its coal-fired Oklaunion plant in Texas by October 2020. | AEP
The company plans to invest another $2.2 billion in contracted renewables and renewables integrated with energy storage in competitive markets between 2019 and 2023. AEP has added 1,302 MW of contracted renewable energy to its portfolio this year.
Over the long term, AEP plans to invest approximately $25 billion over the next five years to improve efficiency and resilience in its transmission and distribution systems.
AEP said it has factored future carbon regulations into the company’s evaluation of generation resource options and will continue to do so.
[UPDATED to clarify that although Foster will be the third senior executive to leave PJM since the GreenHat default, she had no role in it.]
By Rich Heidorn Jr.
Interim PJM CEO Susan J. Riley on Monday announced a shakeup of the RTO’s State and Member Services Division, the latest in a series of management changes in the wake of the GreenHat Energy default and continued friction with state officials.
Susan Riley, a PJM board member since 2005, was named interim CEO during the search for Ott’s replacement. | PJM
Riley announced that Denise Foster, vice president of the division, will resign effective Oct. 31 and that her unit will be reorganized under Associate General Counsel Jen Tribulski. “With Denise’s decision to step down, we have decided to realign the State and Member Services Division to further demonstrate the organization’s willingness to listen to key stakeholders and provide a more direct line of communication between the executive team, the states and members,” Riley said in a letter to members.
Also Monday, Chief Administrative Law Judge Carmen A. Cintron reported that PJM and intervenors have reached a settlement in principle in the dispute over how to liquidate financial transmission rights left over from the GreenHat default. Cintron ordered a 30-day extension in the settlement deadline to “allow additional time to finalize settlement documents for their filing with the commission” (ER18-2068).
PJM declined to provide details, but spokesman Jeff Shields said the RTO is “pleased that the parties have reached a settlement in principle” and will “provide some high-level discussion around it” at the Market Implementation Committee meeting Wednesday.
The GreenHat default in June 2018 came as PJM was already facing strained relations with some members over state nuclear subsidies, the RTO’s push for increased “fuel security” and a FERC order to change its capacity rules. (See PJM Stakeholders Reluctantly OK ‘Fuel Security’ Initiative.)
Foster will be the third senior executive to leave PJM since the GreenHat default although — by all accounts — she had nothing to do with it.
CFO Suzanne Daugherty retired shortly before the board released a highly critical report on the RTO’s failings in the GreenHat matter. CEO Andy Ott resigned effective June 30, announcing his departure two months after the report was released. (See PJM CEO Andy Ott to Retire.) Riley, a board member since 2005, was named interim CEO during the search for Ott’s replacement.
Denise Foster will be the third senior executive to leave PJM since the GreenHat default, joining CFO Suzanne Daugherty and CEO Andy Ott. | PJM, PUCO, RTO Insider
Under the changes announced Monday, Tribulski will become senior director of member services, with oversight of stakeholder affairs, member relations, and state and member training. Tribulski, who graduated from the Quinnipiac University School of Law in 1993, has more than 20 years of experience in energy law. Her direct reports will be Jim Gluck, director of member relations, and Dave Anders, director of stakeholder affairs.
Former Ohio regulator Asim Haque, who joined PJM in February, will continue as executive director of strategic policy and external affairs.
Haque and Tribulski will report to Vince Duane, general counsel and senior vice president of law, compliance and external relations.
Foster will remain as chair of the Markets and Reliability Committee until her departure, Riley said.
PORTLAND, Maine — ISO-NE on Thursday continued its decade-long tradition of taking its show on the road — this time to Maine — to hear from the region’s residents and share with them the latest activities at the RTO.
Last week’s Consumer Liaison Group (CLG) meeting drew about 100 participants and featured state energy officials, environmental advocates and the energy analytics manager for a leading university.
CLG Coordinating Committee Chair Rebecca Tepper, chief of the Energy and Telecommunications Division at the Massachusetts attorney general’s office, said December’s meeting in Boston will mark the 10th anniversary of the group.
Here is some of what we heard.
As Goes Maine
Dan Burgess, director of Maine Gov. Janet Mills’ Energy Office, talked about a number of legislative measures that marked the first half-year of Mills’ first term.
Describing the energy challenges facing the state, Burgess noted that more than 70% of Mainers are dependent on fuel oil to heat their homes and that they drive 1,000 miles more per year than the national average, with transportation accounting for 54% of emissions.
He said a state bill (LD 1679) to establish the Maine Climate Council saw “broad bipartisan support” in the legislature and that an act to reform Maine’s renewable portfolio standard (LD 1494) was a particular success.
“For years, Maine lagged behind the five other [New England] states in RPS targets, flatlining at 10%, but now tops the chart with an RPS goal of 80% by 2035,” Burgess said. The ultimate goal is 100% of electricity to be generated from renewable resources by 2050.
Among the other bills in the state mentioned by Burgess:
LD 1844 directs the Public Utilities Commission to evaluate the ownership of the state’s power delivery systems, with the first report-back due in March 2020.
LD 1231 funds energy-efficiency programs through a fee on the sale of unregulated heating fuels.
LD 1711 promotes solar energy projects and distributed generation resources.
LD 1766 boosts the heat pump market to save residents money and reduce energy consumption.
Michael Stoddard, executive director of Efficiency Maine Trust, presented an overview of his agency’s work on energy efficiency, including how the state will spend $8 million from the Volkswagen settlement for both electric vehicle rebates and charging infrastructure.
Energy Security and More
Anne George, ISO-NE’s vice president for external affairs and corporate communications, spoke on several topics, including work on the RTO’s Energy Security Improvements (ESI) initiative and the RTO’s preparations for Forward Capacity Auction 14, scheduled for February 2020.
FERC last month granted a six-month extension for the RTO to file its long-term energy security plan, giving the grid operator until April 15, 2020, to complete additional scenario analysis and fully develop the conceptual framework for market power mitigation, she said. (See FERC Extends ISO-NE Fuel Security Filing Deadline.)
She listed off replacement energy reserves, generation contingency reserves and energy imbalance reserves as the three new market options, and she said that stakeholders also are considering a multiday-ahead market and a seasonal forward market.
“We have been focused on these energy options, which are really geared towards preparing the ISO and the region to operate the system … and move those ahead into the day-ahead energy market,” George said.
She also mentioned the RTO’s public meeting scheduled for Thursday in Boston to discuss its Regional System Plan (RSP), which focuses on moving forward as the electric grid evolves to adapt to a changing resource mix. (See New England Officials Speak on Grid Transformation.)
Emissions Reporting
ISO-NE will be asking FERC to approve an operating budget for next year of $174.2 million, about 3% higher than this year, or approximately $1.02/month per consumer in the region, she said.
Preparatory work for FCA 14 is on schedule and the RTO anticipates a November filing with FERC of its auction-related determinations and calculations.
Asked about delays in the federal permitting of offshore wind projects, particularly the 1,200-MW Vineyard Wind project off Martha’s Vineyard, George said that “a potential delay in any of these resources could affect the energy security of the region. But that’s something that we see several years out, and hopefully the studies continue to move forward and those resources start to get developed.”
“It’s a matter of making sure that our markets are providing the right incentives, these resources are getting developed, and then we’re into a system where we don’t see this being a reliability risk,” George said.
Michael Macrae, energy analytics manager at Harvard University, joined the event via telephone and spoke on improving the RTO’s emissions reporting, especially marginal emissions rates.
“I work for Harvard University, and many of the various roles that I’ve played there have done a lot of carbon accounting for how Harvard thinks about its operational strategy for our carbon-neutrality goals,” Macrae said. “In doing so, one of the core, fundamental pieces of that is understanding what do the power system emissions look like.”
After “diving way deep down in the weeds” of the RTO’s data, Macrae said he found two problems, the first of which is that energy imports are excluded from its system greenhouse gas emissions accounting.
“Problem No. 2 is more nuanced, in that ISO-NE overestimates the contribution of marginal units in small, local export-constrained areas,” he said.
Macrae said the RTO could manage the first challenge by incorporating emissions associated with energy imported from New York and Canada. And it could address the second by adopting its Internal Market Monitor’s methodology for reporting marginal emissions based on a unit’s contribution to system load.
Carbon Pricing
Jordan Stutt, carbon programs director at the Acadia Center, presented on the environmental advocacy group’s thinking on regional efforts to price carbon, noting that “we are seeing a better effort to not just track, but to account for carbon emissions.”
Through the Regional Greenhouse Gas Initiative, Stutt said, 16.4% of New England CO2 emissions are subject to a carbon price.
“When we consider that the RGGI price is $5.77/metric ton, and the social cost of carbon is $50/metric ton, you can see that we only account for 1.9% of the cost of CO2 emissions in New England,” Stutt said.
He highlighted the Transportation and Climate Initiative (TCI), a regional collaboration of 12 Northeast and Mid-Atlantic states and D.C. that aims to improve transportation, develop clean energy and reduce carbon emissions from the transportation sector.
“We’re hopeful that by the end of the year, there will be a memorandum of understanding, possibly a model rule that tells what that program will look like,” Stutt said.
NYISO and PJM are looking to incorporate the full cost of carbon emissions into their wholesale energy markets, he said, with New York’s plan expected to be presented to FERC later this year, he said.
“In six New England states, at least one carbon pricing bill was filed in 2019 in each of those states, and those bills have a variety of content, coverage and support,” Stutt said.
“Some of those are just study bills at this point, others are full-fledged policies. Some are economy-wide, while others would exempt certain sectors,” he said.
Stutt noted that the Massachusetts bill (H.1726) filed by state Rep. Jen Benson exempts the electric sector, while a Rhode Island bill (S.0417) nets out the cost of RGGI allowances “similar to the NYISO carbon pricing plan.”
HOUSTON — When Russell Gold, a senior energy reporter with The Wall Street Journal, decided to write a book on climate change, he naturally chose to focus on the long-haul transmission system.
Say again?
“When I think about climate change — and this is not specifically about climate change — there’s balance between hope and despair going on throughout our entire culture,” Gold said. “What’s happening in the Amazon needs to be balanced by hope. Everything that’s going wrong, all these animals disappearing … I wanted to do something on the hope side, on the people trying to arrest climate change and slow it down.”
“This is an energy story and an entrepreneurial story,” he said. “I wanted to find someone, a group of people out there, and tell their story, give people some hope that there are options out there. If you don’t have hope, despair wins.”
Gold’s book tells the story of Michael Skelly, the title’s “one man” who built the second-largest wind power company in the U.S. — Horizon Wind Energy — and then founded Clean Line Energy Partners. Skelly’s plan at Clean Line was to build HVDC lines hundreds of miles long to transport wind energy from the Great Plains to Eastern and Western population centers.
Unable to clear endless regulatory hurdles and landowner opposition, he eventually sold off Clean Line’s projects and is now a senior adviser with the Lazard investment management firm. (See Out of the Game, Skelly Still High on Wind Energy.)
Gold, who has covered energy for the Journal since 2002, said he was struck by seeing Skelly’s projects run into the same long environmental reviews and bureaucratic delays as natural gas pipelines.
“It would be helpful to get a yes or no [answer] in five years,” he said, to some snickers in the audience.
“I didn’t think that would be a laugh line,” Gold said, pausing. “You have your investors saying, ‘This is a fun ride, but we’d like to have something happen.’”
First Mouse … or Donkey
While Skelly may not have been ultimately successful, both he and Gold believe his efforts will help those developers who follow. As Gold writes in his book, “The second mouse gets the cheese … what is usually left unsaid is that the first mouse gets the trap.”
“There’s a really important message here,” Gold said. “If we can find a way to build out the grid to where we can move bulk power around to take advantage of this amazing wind and solar resource we have, Americans can have cleaner and affordable energy.
“I wouldn’t have thought that five or 10 years ago. I think that’s a really powerful message,” he said. “We don’t have one energy policy, one energy grid. We have 50 energy policies and 50 energy grids. It’s difficult to negotiate your way through that.”
Skelly, who has apparently never met a person he doesn’t enjoy talking with — he was a relentless door-to-door campaigner during a failed congressional bid in 2008 — easily emerges as the star of “Superpower.”
“I think there’s a different word for it, and it’s called a ‘donkey,’” Skelly said. “When you work in the transmission business, you feel like a donkey.”
“He’s a fun, entertaining storyteller,” Gold said. “When you’re writing about transmission, you need someone who can make the stories interesting.
“Skelly’s career starts when wind power is emerging from the bad California days. By tracing his career, I was able to write about the wind industry,” he said. “It’s gone from a niche market in the last 20 years, from people who wanted to change the world to a fully functioning industry. I wanted to tell the story, one that you can read and follow along with.”
Skelly gave Gold “unfettered access” to the company and its deliberations as it worked to build as many as five long-haul lines. “People in the company thought this was the stupidest idea they had ever heard,” Skelly said.
The Talking Industry
The Plains & Eastern Clean Line was central to Clean Line’s plans. The 700-mile line from the Oklahoma Panhandle’s wind farms to Memphis, Tenn., was to carry 4 GW of renewable energy for purchase by the Tennessee Valley Authority, proving the viability of Clean Line’s other projects.
Gold remembers sitting in meetings in Clean Line’s fishbowl conference rooms and watching the staff walk by.
“You could tell who didn’t like the project by their scowls,” he told Skelly during the Rice event. “Trying to build a big transmission line is incredibly difficult. It takes a lot of focus. One of my concerns was having this writer in and out of the office would distract you.”
“Heisenberg’s Cat came to be shorthand for the fact that mere measurement of an atom changes it,” he said. “Digging too deep into TVA and how TVA was handling the Plains & Eastern proposal would affect the outcome.”
As a result, Gold was allowed to sit in on Clean Line’s side of the discussions, as long as he held off requests for interview and making details public until negotiations ran their course.
Gold layers story upon story in the book, providing side trips into the long effort to develop renewable energy. He writes about the conception of electricity in Thomas Edison’s Pearl Street Station, Samuel Insull and his nephew’s attempts to build electric monopolies, and a group of students who took on Consolidated Edison in 1970s New York by building a wind turbine atop an East Village tenement.
Industry insiders are likely to come across personally familiar names in “Superpower,” a result of the more than 150 interviews Gold conducted during his intensive research.
Skelly helped Gold pitch the book during the Rice event, saying while he had “no economics in this, we need people to buy this book.”
“I started Clean Line because we realized one of the biggest challenges we faced was getting energy from where the resources are really good to where the power is needed,” he said.
Referencing California’s overabundance of afternoon solar energy, Skelly said, “I’m sure [solar] power is free right now in California. We’re using a lot of power in Texas, so we could use some of it.
“Everyone realizes an interconnected system is an optimal way to build a grid,” he said. “It’s not entirely clear which is bigger: The industry of building a national grid, or the industry of talking about building a national grid? We depend more on a state-by-state approach.”
Reflecting on his experience, Gold said that it will take more than an “entrepreneurial outsider” for the nation to realize the impacts of renewable energy. As he said, “It’s always windy or sunny somewhere” in the U.S.
“If there’s a way to get the different RTOs to cooperate with each other, that would be very helpful,” he said. “The history of the United States grid has gotten bigger and bigger, with more and more networking. Think of an integrated, continent-wide network. There’s a lot of benefits to that.”
And a huge bite of cheese, for the mice that come later.
A call for conservation, lower-than-expected temperatures and slightly higher-than-expected wind energy helped ERCOT avoid taking emergency actions during scarce conditions last week.
The National Weather Service had expected temperatures to reach triple digits in the state’s major metropolitan areas into the weekend. Temperatures ended up being 2 to 4 degrees lower in many of the cities, with rain in some parts of the state helping dampen demand.
Demand dropped as Sept. 6 conditions eased. | ERCOT
ERCOT’s system demand peaked at 68 GW and 68.8 GW on those two days. The latter set a new record for September, elbowing aside the 68.5-GW mark established Sept. 3.
“We are thankful to Texans for helping us conserve,” spokesperson Leslie Sopko said.
On Thursday, wind production was expected to be less than 1.5 GW during the early afternoon hours before coastal winds picked up. However, wind energy contributed an extra half-gigawatt when physical responsive capability was at its lowest.
“When the wind doesn’t blow, it gets interesting,” ERCOT COO Cheryl Mele said last week during the Infocast Texas Renewables Summit. “The driver to the day is how much wind do we have. On our peak days, we’ve definitely had a little less than we did on peak days last year. When [wind] gets down to 2 GW or less, it has an effect on price. We’re all sitting around hoping the wind really does show up.
“Anytime we’re seeing a forecast of less than 2 GW in the afternoon or at peak, it means we’re going to have an interesting day.”
Prices briefly hit triple digits on Thursday during the interval ending at 5 p.m., after settling at just over $5,000/MWh in the day-ahead market. On Friday, prices were in quadruple figures, topping out at about $1,778/MWh during the 2:35-4:45 p.m. time period. Day-ahead prices for Friday’s energy and ancillary services were both about $4,500/MWh for the day.
The Texas grid operator this summer has called two energy emergency alerts, its first in five years. (See “ERCOT CEO Briefs Commission on Summer Performance,” Texas PUC Briefs: Aug. 29, 2019.)
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.
The New England Power Pool Markets Committee met last week to discuss ISO-NE’s proposed Energy Security Improvements (ESI), but the sense of urgency to act has lifted after FERC extended an October deadline by six months.
Todd Schatzki of Analysis Group was joined by ISO-NE economist Christopher Geissler to present an analysis of the impacts of ESI. Pressed by stakeholders on how the study would move forward with the deadline now pushed out to April, Schatzki said the effort will benefit from the additional time — but that his firm is not expecting any delay in its work.
Geissler said that although the energy security improvements team would no longer be “going at breakneck speed,” it was committed to getting out the best design as soon as possible.
The New England States Committee on Electricity (NESCOE) filed the motion for the delay, asserting that the complex market design effort in the region was being unduly rushed. (See FERC Extends ISO-NE Fuel Security Filing Deadline.)
Forward Market
Rebecca Hunter, Calpine senior analyst of government and regulatory affairs, presented again on the company’s proposed Forward Enhanced Reserves Market, expanding on its current position and suggesting modifications to ISO-NE’s proposal. She said Calpine will use the extension to spend more time on draft Tariff language.
“In terms of the need to run RAA [resource adequacy analysis], I do see it happening as often as you would award for EIR [energy imbalance reserves],” Hunter said. “If you think about it, with the ISO awarding resources for EIR, the operators are not going to have any information about those resources being awarded, so when they go to decide who they should commit under the RAA process, they’re going to be starting down from the bottom of the stack.
Calpine’s Forward Enhanced Reserves Market (FERM) is a market design intended to pay all fuel-secure resources equally. | Calpine
“There’s a chance that maybe they’re picking up that same EIR resource in the RAA process, and I do identify that as getting paid for the same thing, that has been awarded twice, or there’s also a chance that they’re running a completely separate resource,” she added.
Geissler led a discussion of the framework for developing a forward component to the ESI design.
“I don’t know how we’d get the linkage between the forward sale of fuel and the expected obligation in the [day-ahead] market, or how those settle,” Geissler said. “For example, if there is no linkage, there may be concerns about how resources can be compensated for fuel through a couple different mechanisms, but at the same time, without a spot market that looks a lot like this, it’s not necessarily clear to me how to link the two in a sensible way.”
Stakeholder Amendments
Christina Belew of the Massachusetts attorney general’s office presented three amendments to the ESI proposal, each to be voted on separately by the MC:
Restrict use of generation contingency reserves, replacement energy reserves (RER) and EIR to winter months; and require impact analysis and NEPOOL stakeholder process before implementing ESI year-round.
Limit use of 90-minute and 240-minute RER options year-round.
Add a sunset provision to the proposed energy security improvements to trigger review of program need and efficacy.
Belew said her office was no longer going to proceed with its forward stored energy reserve proposal — a seasonal auction format for stored energy options — because after modifications were made to address stakeholder concerns, it no longer met the attorney general’s original objectives of providing the most efficient solution at least cost to consumers, fairness to all resources and responsiveness to future changes in resource mix.
NESCOE Director of Analysis Jeffrey Bentz also presented four possible amendments, including restricting EIR and RER to the winter months, but said the group is “considering these as one set of potential amendments, not four separate amendments.”
Another amendment would implement a must-offer requirement for resources with capacity supply obligations, while another would increase by 25% the strike price for ISO-NE’s proposed hourly energy call options — and create two options.
“Even with these amendments, analysis suggests that ESI as amended would be unlikely to fully solve the emerging concerns around market power mitigation but would be a step in the right direction,” he said. “We may decide to separate, eliminate or modify these based on today’s discussion and those going forward.”
David Errichetti of Eversource Energy briefly presented an amendment to address the company’s concern that the RTO’s interim Inventoried Energy Program would overlap with energy security improvements for winter 2024/25.
ISO-NE has promised to develop netting rules to address paying for both programs but has presented nothing yet, so NEPOOL is being asked to approve these rule changes without knowing if the netting rules will avoid paying twice for winter 2024/25 operations reliability, Errichetti said.
Robert Laurita, on behalf of the Connecticut Public Utilities Regulatory Authority and the Department of Energy and Environmental Protection, presented their amendment to the Tariff language concerning quarterly certification of the competitiveness of the energy call option offers in the day-ahead market and the related clearing prices.
Pending consideration of an amendment from PSEG Long Island, the RTO on Wednesday postponed a vote on Tariff changes to clarify that a resource retained for fuel security will only be retained until the end of the fuel security need and no longer than the two-year period allowed by FERC. The MC will vote on the matter at its Sept. 18 meeting. (See “Time Limit on Fuel-security Resources,” NEPOOL Markets Committee Briefs: July 30, 2019.)
