The bankruptcy of Pacific Gas and Electric could reach another milestone this week as the utility tries to explain its Chapter 11 reorganization proposal in plain English to fire victims and other affected parties.
That reorganization plan is now estimated to cost almost $60 billion, according to recent testimony by PG&E executives before the California Public Utilities Commission.
In a hearing that starts Tuesday, lawyers will debate what’s known in bankruptcy court as a disclosure statement. Once finalized, the statement will be sent out to parties to the bankruptcy who will then get to vote on the plan. (See What Spring Could Bring for PG&E.)
Objections to PG&E’s disclosure statement have been filed by government agencies, fire victims, creditors and others who take issue with aspects of its Chapter 11 plan.
Wildfire victims, represented by the official Tort Claimants Committee, say the revised terms of PG&E’s exit financing could leave a proposed $13.5 billion victims’ trust holding company stock with diminished value.
The U.S. Trustee appointed to the case says the disclosure statement lacks supporting financial information necessary for parties to determine the merits of PG&E’s bankruptcy plan.
Both want U.S. Bankruptcy Judge Dennis Montali to help correct the purported problems.
Surprisingly, however, PG&E’s fiercest critic in recent months, Gov. Gavin Newsom, said he doesn’t want to stand in the way of the disclosure statement being mailed out, even though not all his demands for change have been met by the utility.
Newsom has threatened a state takeover of the company if it doesn’t replace its entire board of directors and make other wholesale changes. But the utility is trying to exit bankruptcy by June 30 so it can participate in a $21 billion wildfire insurance fund created by Assembly Bill 1054, passed last July, the governor’s lawyers noted in court papers filed Friday. (See Newsom Budget Reiterates PG&E Takeover Threat.)
The CPUC must rule on whether PG&E has met the terms of AB 1054 — including whether it can provide safe, reliable service going forward and fairly compensate victims of past fires, such the November 2018 Camp Fire that killed 86 people in the town of Paradise.
Newsom’s lawyers acknowledged PG&E’s Chapter 11 plan, as detailed in its draft disclosure statement, doesn’t fulfill the requirements of AB 1054, but they said it should be allowed to move forward toward a vote anyway.
“Under normal circumstances, it may be prudent for the debtors to delay solicitation until the plan can be further refined to meet AB 1054,” the governor’s attorneys said. “The governor’s office, however, is cognizant that the June 30, 2020, deadline codified in AB 1054 creates unusual tension in these Chapter 11 cases [so that delays could endanger] … the debtors’ ability to ultimately obtain the benefit of the provisions of AB 1054.”
Those financial benefits, insuring the state’s investor-owned utilities against future wildfire liabilities, are necessary for PG&E to remain financially stable going forward, the utility and governor agree.
“Modifications to the plan to resolve the concerns of the governor’s office should not jeopardize the confirmation process, as the governor believes those changes would create a stronger and better managed utility and inure to the benefit of all of the debtors’ constituents,” Newsom’s lawyers said.
The governor’s office has been working with PG&E to address Newsom’s concerns. The parties have engaged in court-ordered mediation and met together in the State Capitol.
A mediation session held Monday in San Francisco “to resolve all outstanding issues between the parties” could bring PG&E, fire victims and state officials closer together, shortening Tuesday’s hearing.
The disclosure hearing is scheduled to start at 10 a.m. before Montali in the U.S. Bankruptcy Court in San Francisco. It could continue into Wednesday if necessary, court papers indicate.
Dominion Energy asked FERC on Friday to reconsider its conclusion that self-supply resources suppress PJM capacity prices, contending the commission’s position is inconsistent with an exemption it granted similar resources in NYISO.
Dominion asked to supplement its Jan. 21 request for rehearing of the commission’s December order requiring PJM to apply the minimum offer price rule (MOPR) to all state-subsidized resources (EL16-49, EL18-178). (See PJM MOPR Rehearing Requests Pour into FERC.)
PJM had asked FERC to approve its previous exemption for self-supply resources owned by public power entities (cooperative or municipal utilities), vertically integrated utilities subject to traditional bundled rate regulation and load-serving entities that serve retail customers. In 2013, the commission ruled that “a self-supply LSE that owns or contracts for a large proportion of the capacity needed to meet its load has no reason to finance uneconomic entry given that such a strategy would not be profitable.” (See Is Self-supply Suppressing Prices?)
Dominion’s 1,661-MW Possum Point Power Station in Dumfries, Va., can burn natural gas and oil. | Dominion Energy
But FERC’s Dec. 19 order found that self-supply resources were subsidized because the energy and capacity they produce are purchased through state-directed procurements.
Dominion said in its rehearing request that the commission failed to justify making self-supply capacity subject to MOPR and ignored evidence that self-supply does not suppress prices.
In the Feb. 20 NYISO order, however, the commission accepted a self-supply exemption proposed by NYISO on terms similar to PJM’s proposal, Dominion said (EL16-92, ER17-996). (See FERC Narrows NYISO Mitigation Exemptions.)
“In the 2020 NYISO order, the commission accepted in part, subject to condition, the NYISO’s proposed self-supply exemption, the NYISO’s proposed net short and net long threshold criteria for the self-supply exemption, and generally all other aspects of the NYISO’s proposed self-supply exemption. … Yet, the commission made no effort to distinguish between its findings regarding the NYISO’s proposal and its nearly opposite findings in this proceeding made just two months prior,” Dominion said.
Dominion Energy owns 27,100 MW of generation. | Dominion Energy
“If the NYISO’s proposal is adequate and the commission continues to find that self-supply entities do not possess the incentive to artificially suppress pricing in the NYISO market, the commission should likewise find that, with well defined guardrails, self-supply entities in PJM also continue to lack the incentive to artificially suppress prices in PJM capacity markets. Moreover, the commission should permit the self-supply exemption in substantially the same form originally proposed by PJM in this case,” Dominion said. “The commission is obligated to provide its reasoning when departing from existing policy or precedent.”
A Dominion official told an energy conference last week that growing vertically integrated utilities such as Dominion may need to leave the capacity market if the ruling is not changed. (See related story, “A Maryland Capacity Auction? Dominion Going FRR?” Overheard at ACORE Policy Forum 2020.)
Dominion Energy Virginia, which owns 27,100 MW of generation, is planning to build 2.6 GW of wind generation off the coast of Virginia and is about halfway through a plan to add 3,000 MW of solar generation.
SACRAMENTO, Calif. — Gov. Gavin Newsom on Thursday reappointed Ashutosh Bhagwat and Angelina Galiteva to their fourth three-year terms on the CAISO Board of Governors.
Bhagwat is a law professor at the University of California, Davis, where he holds an endowed chair in freedom and equality. He has written about the California electricity crisis of 2000/2001 and lectures on constitutional law.
Galiteva is president of NEOptions, a renewable energy design and development firm. She was executive director of the Los Angeles Department of Water and Power and head of its green energy initiative from 1997 to 2003. Galiteva is an attorney with an advanced degree in energy law.
Both have served on the ISO’s board since 2011, when then-Gov. Jerry Brown first appointed them.
In the last nine years, CAISO integrated large amounts of renewable resources, established the Western Energy Imbalance Market and, starting last year, became the reliability coordinator for much of the West.
“The executive leadership team is looking forward to working with the newly reappointed board members, and the entire Board of Governors, as we continue to refine and showcase our vision of a clean, low-carbon power grid,” CAISO CEO Steve Berberich said in a statement. “We appreciate Gov. Newsom’s engagement in the board appointment process and his confidence in our team and our mission.”
The State Senate must confirm the appointments, but Bhagwat and Galiteva will continue to serve, effective immediately. Their terms expire Dec. 31, 2022.
The five-member CAISO board also includes Chair David Olsen, who was first appointed in 2012 and reappointed in January 2019. For the decade prior to his appointment, Olsen was managing director of Western Grid Group, an organization of former state energy officials advocating for grid modernization and clean energy. He was CEO of outdoor clothing manufacturer Patagonia in the late 1990s.
Last year, Newsom appointed University of California, Berkeley business professor Severin Borenstein and business promoter Mary Leslie to the board.
Borenstein is faculty director of the Energy Institute at Berkeley’s Haas School of Business. Leslie was president of the Los Angeles Business Council since 2001 and deputy mayor of Los Angeles under Mayor Richard Riordan in the 1990s. (See Newsom Names New CAISO Governors.)
FERC on Friday rejected Tariff revisions filed jointly by ISO-NE and the New England Power Pool to clarify that resources retained for fuel security reasons will not be retained for other reasons once the fuel security retention period ends (ER20-89).
“While we favor limiting the scope and length of out-of-market actions, we seek to balance that objective against the ability to address reliability concerns,” the commission said. “The proposal here would remove ISO-NE’s ability to retain a fuel security resource to address potential future transmission reliability issues that may arise simply because the resource in question had been retained previously for fuel security.”
The proposed Tariff revisions prompted a protest from Exelon, which owns Mystic 8 and 9, the planned retirement of which prompted the RTO and NEPOOL to seek to retain resources for regional fuel security in the first place.
Exelon argued that the proposal “unduly discriminates” against fuel security resources in general and the Mystic units in particular. The company contended that “the proposal results in different treatment for transmission security resources based on whether the resource has previously provided fuel security service, despite the fact that transmission security and fuel security resources are similarly situated for purposes of retirement,” FERC noted.
Mystic Generating Station, on the Mystic River in Everett, Mass.
The company further argued that if ISO-NE had requested to retain the Mystic units for transmission security rather than fuel security, the Tariff would allow for possible cost-of-service compensation until the transmission reliability need was addressed. However, the fuel security agreement restricted Mystic’s options in a way not faced by other resources, effectively penalizing it for entering into an agreement for fuel security instead of transmission security.
Exelon also pointed to delays in the completion of ISO-NE’s Energy Security Improvements (ESI) initiative. FERC last August granted the RTO a second extension to file the plan, until April 15. The NEPOOL Participants Committee expects to vote on the new fuel security market design at its April 2 meeting.
The RTO’s aspirations to develop a long-term market-based fuel security solution and competitively develop transmission solutions for the Boston area do not constitute substantial evidence that it is just and reasonable to eliminate a reliability safeguard, Exelon said.
In rejecting the revisions, the commission found that “instead of retaining such a resource for transmission security (as it would any other resource that was not previously retained for fuel security), ISO-NE would need to address this issue through either real-time operating procedures, such as shedding load, or through the use of a gap [request for proposals] solicitation.”
FERC said it remains open to ISO-NE and NEPOOL “proposing to revise the relevant reliability review timeline to ensure that resources are not unnecessarily retained when transmission solutions will be in place in time to address identified reliability needs.”
However, the commission did not find just and reasonable “the proposal to make a resource retained for fuel security ineligible to be further retained for transmission reliability purposes.”
FERC last month rejected a related request to roll back the sunset date for a Tariff provision that allows the RTO to retain a resource for fuel security reasons (ER20-645). (See FERC Rejects ISO-NE Fuel Security Sunset Rollback.)
CARMEL, Ind. — MISO might revise and refile a failed proposal designed to set penalties for non-capacity resources that exercise market power through physical withholding.
“We’ve reached out to the IMM to get their view of things,” Executive Director of Market Operations Shawn McFarlane said at the Market Subcommittee’s meeting Thursday. “It seemed like FERC was colloquially ‘not on board.’”
McFarlane said the commission thought the proposal placed too much burden on generators to prove when their operations would be uneconomic. “We’d have to address that issue before a refile,” he said.
Dustin Grethen, MISO market design adviser, said the RTO has observed congestion and binding constraints that could be relieved by non-capacity resources.
MISO will continue to monitor those instances over the upcoming months while it considers the possibility of a future proposal, Grethen said.
MISO counsel Daniel Malabonga characterized the filing’s aims as “uphill in the first place.” He said the RTO will have to find new “middle ground” should it choose to refile.
Potential Dollar Limit on Some Resettlements
MISO’s settlements team is considering subjecting the issuance of certain market resettlements to a dollar value minimum.
Director of Settlements Laura Rauch said the costs of accounting for resettlements as a result of a continuing error (defined as a long-running error that’s not easily discovered) can exceed the cost of the resettlements themselves. For instance, she said a $5,000 resettlement can be entirely eaten up by the “accounting costs of tracking the resettlement charges for all other impacted parties.”
After performing corrective resettlements, MISO has redistributed amounts to impacted market participants ranging from $20 to $1 million, with a median of less than $50,000. In some cases, MISO collects the resettlement amounts from redistribution from up to 220 market participants.
Rauch said the dollar minimum would not apply to most of MISO’s settlement adjustments — which are resolved quickly with corrections settlement statements — or to stakeholder disputes over settlements submitted within the 120-day deadline from the trade date. MISO will also continue to pursue FERC-required resettlements, she said.
Rauch asked stakeholders to suggest a reasonable dollar threshold for resettlements resulting from continuing errors. She said she would likely return to the subcommittee for its April meeting with a proposal.
Spinning Reserves May Get Embedded Deployment Cost Recovery
MISO may give its spinning reserves a simpler means of recouping costs for providing energy, stakeholders heard at the meeting.
The current clearing process for selecting spin service resources doesn’t incorporate costs the resources incur when deployed as contingency reserves, including the shutdown costs for demand response participants. Resources cleared and deployed for spin service “may have real deployment costs that are not recovered under MISO’s current Tariff provisions,” the RTO said.
MISO adviser Michael Robinson said the current selection process is “inefficient, creating uplifts and distorting price signals.” The RTO could include expected deployment costs when it selects spinning reserves, he told stakeholders.
Spinning reserves are resources that remain online and synched to the grid, meant to be available within 10 minutes. MISO has not included energy deployment costs for spinning reserves since it began its ancillary services market in 2009. Spinning reserves committed by MISO are guaranteed to be made whole to their production costs; however, assets committed outside of the RTO’s market don’t have the same make-whole guarantee.
“In some cases, we make the units whole through uplift, and that’s not good. In other cases, we don’t make the resources whole, and that’s not good from the owner’s perspective. … We’d like to sort this out and get all that embedded in a market price,” Robinson said.
He said the gap hasn’t been burdensome so far but could become an issue as more varied types resources offer spinning reserves.
Customized Energy Solutions’ Ted Kuhn said MISO may not currently be selecting the best prices in spin service because it cannot see which assets have high deployment costs. Robinson agreed and said higher deployment costs have become more prevalent in recent years.
MISO stakeholders are requested to provide their opinions on the best means of embedding production costs. The topic will be taken up again at next month’s MSC.
TEMPE, Ariz. — Developers of transmission projects that would send wind power from rural Wyoming and New Mexico to cities in California and Arizona made their cases at this year’s Western Planning Regions Annual Interregional Coordination Meeting on Feb. 27.
The venue for this year’s forum was the Salt River Project’s sleek new LEED-certified meeting-and-classroom facility at its PERA Club, an employee recreation area. The building remains under construction, backed by the red rock formations and popular hiking trails of Phoenix’s Papago Park. High-voltage lines cross the area, juxtaposing transmission towers with distinctly Western scenery.
In a similar way, three transmission projects presented at the meeting would string nearly 1,500 miles of transmission lines, total, across the deserts and mountains of Arizona, Nevada, New Mexico and Utah if developers realize their plans.
The proposed projects include the long-sought Sunzia Southwest Transmission Project, which would link Pattern Development’s Corona Wind Projects, potentially one of the largest wind farms in the Western Hemisphere, to load centers in the Desert Southwest and Southern California via the Palo Verde Hub west of Phoenix.
The $2 billion project would consist of two bidirectional 500-kV lines with a total rating of 3,000 MW. A consortium of developers and utilities are behind the project including Southwestern Power Group, Shell WindEnergy and Tucson Electric Power.
Another project talked up at the meeting was TransCanyon’s Cross-Tie Project, which would traverse 213 miles through central Utah and Eastern Nevada at a projected cost of $667 million. TransCanyon is a joint venture between Berkshire Hathaway Energy and Pinnacle West Capital, the parent company of Arizona Public Service.
The third project presented at this year’s planning session was the TransWest Express, a $3 billion effort by The Anschutz Corp. to connect the company’s massive wind farms in eastern and central Wyoming with Southern California’s 24 million residents. It would run 730 miles, crossing Colorado and Utah, to the Marketplace Hub near Las Vegas.
“There’s been very little planning activity on these because of the absence of regional need seen through these projects, but we’re hopeful that’s changing now as folks are seeing more penetration of renewables and the advantages of Wyoming wind,” said Dave Smith, director of engineering and operations with TransWest.
Bob Smith, a transmission planning consultant with TransCanyon, pointed out that load-serving entities in California, including two of the state’s large community choice aggregators, have signed power purchase agreements to buy Corona wind power, even though the SunZia lines to get it to the state don’t exist yet.
Powerful winds in central New Mexico blow before California’s solar arrays ramp up in the morning and after they go offline at night, potentially mitigating California’s reliability concerns going forward, according to a presentation delivered at a recent WestConnect stakeholder meeting, also at the PERA Club. (See CAISO, CPUC Warn of ‘Reliability Emergency’.)
Developers are hoping construction will start in 2021 or 2022 and that the first line will be in operation by 2024 or 2025.
No Interregional Needs
The planning meeting brought together stakeholders and representatives of CAISO, ColumbiaGrid, Northern Tier Transmission Group and WestConnect to discuss interregional coordination under CAISO Seeks More Transfers with Pacific Northwest.)
Each of the West’s four planning regions detailed its own transmission planning process, identifying regional needs based on reliability, economics and public policy per Order 1000’s requirements. But no interregional needs were identified in the current planning cycle that could streamline transmission in the Western Interconnection.
The impending merger of two of the four planning regions, ColumbiaGrid and Northern Tier, could give rise to new needs, planners said. FERC ruled on Dec. 27 that the proposed merger fell short of Order 1000’s goals of promoting competition and cost savings. It gave the filing entities — seven member utilities of ColumbiaGrid and Northern Tier — time to correct their application’s deficiencies. (See FERC: NorthernGrid Merger Needs More Work.)
NorthernGrid’s members would include Bonneville Power Administration, PacifiCorp, and publicly and investor-owned utilities in California, Idaho, Montana, Oregon, Utah, Washington and Wyoming. Dave Angell, vice president of regional transmission for Northwest Power Pool, one would-be member of NorthernGrid, said at the interregional coordination meeting that the utilities are planning to refile their plan with FERC soon.
WASHINGTON — Renewable industry advocates, environmental activists and congressional Democrats said Wednesday that 2021 may provide the best opportunity in a decade for legislative action to address climate change.
But speakers at the American Council on Renewable Energy (ACORE) Policy Forum said their messaging should emphasize the economic benefits of clean energy industries to win support from organized labor, minority communities, farmers and Republican lawmakers.
Sen. Ron Wyden (D-Ore.) led off the forum with a speech — part political science lecture, part pep rally — on the strategy and coalition building he said is needed to reduce greenhouse gas emissions.
Wyden said Republicans can be brought into a climate change coalition because many of them “have skin in the game on renewable technologies.” He named Sens. Jodi Ernst (Iowa), Martha McSally (Ariz.), John Cornyn (Texas), Cory Gardner (Colo.), Thom Tillis (N.C.) and Susan Collins (Maine).
“I can make the list go on and on,” he said. “Why do I single out those folks? Because they come from places where the wind blows, where the sun shines [and] where they make batteries for energy storage.”
Wyden said renewable vendors and investors need to be in regular contact with their members of Congress to make them aware of the clean energy workers in their constituencies.
“They have to hear from you all the time. … Only those kinds of direct contacts [will] really change people’s mind to the point where they’ll show up and vote … for a package rather than give you a speech.”
Senate Majority Leader “Mitch McConnell [R-Ky.] hears a whole lot more from the oil and gas lobby than he’s hearing from our network as it exists today. If senators go home and they are met by a coalition of 50 businesspeople who say, ‘I want these renewable provisions on storage or wind or wave or solar,’ they come back to Washington. And they say to Mitch McConnell: ‘I gotta have this. I was stunned, Mitch, to see all this support at home for it. I have to have it.’ And then Mitch McConnell finds a vehicle for doing it.”
Aruna Kalyanam, staff director of the House Ways and Means Committee’s Subcommittee on Select Revenue Measures, agreed. “The members of the United States Senate are so entirely parochial. They don’t have to give a damn about the overall issue, so long as they care about the people that are employed that work in that issue,” she said. Senators may not want to speak out on climate, she said. “But my God, are they there to defend the linear generator manufacturers in their state.”
Rep. Paul Tonko (D-N.Y.) said prospects for climate legislation have improved in the 10 years since the failure of the Waxman-Markey cap-and-trade bill, because of falling renewable prices, an improved economy and increasing evidence of climate change.
“I think the big factor is the general public. They now see climate change from a different lens. It’s no longer about protecting the polar bears … no longer just about coastal erosion. It’s about backyard situations. Just this week: the tragedy of a tornado in Nashville, Tenn.; the wildfires in the Southwest; the record rising of the Mississippi; the flooding in Nebraska. It is a backyard issue.”
Jobs and Wages
Neera Tanden, CEO of the Center for American Progress (CAP), said, “The issue around climate is much more salient than ever, not just with Democratic voters, but really with independent voters and in important states like Florida.
“All the remaining candidates on the Democratic side have bolder proposals around climate than any previous nominees or candidates on the Democratic side. And I think the really critical issue going forward in the climate space is going to be around how to make climate a win-win on the economy,” she continued. “We see around the world that when climate has become an issue, conservatives have often [described] it as a job-killer idea that will actually hurt economic growth. … And we expect to see that in the general election, no matter who the Democratic nominee is.”
Tanden said the renewable industry should not be so focused on costs that it fails to deliver on promises of “high-wage, high-benefit jobs that are often, or could be, unionized.”
“I appreciate the difficulty because we’re all in a place where we’re trying to make the cost as cheap as possible. But in a political environment, when jobs that are being lost, to have high-benefits jobs [is essential]. These issues are going to get demagogued unless the jobs that replace them are higher-wage jobs. … To get a large-scale investment, or even think of a mandate, the way to do that isn’t through the climate sphere. It’s obviously through the jobs sphere.”
Tom Kiernan, CEO of the American Wind Energy Association (AWEA), concurred.
“I don’t think politically we will move major carbon or climate legislation without the labor community being — not just OK — but enthusiastic and part of the solution,” he said. “Communities of color need to see themselves in this effort. So … don’t think we’re just going up there and let’s get a $40/ton on carbon and we’re done. … We’ve got to come together there — and that may be new for the industry.”
Ken Kimmell, president of the Union of Concerned Scientists, said labor and minority communities are “open minded” but skeptical of climate policy.
“Organized labor is not yet seeing those high-wage jobs coming. They know there’s some anecdotal evidence of it, but they’re not yet seeing it,” Kimmell said. “And the environmental justice community is just starting to see that it’s possible to have climate policy and policies that simultaneously lower local sources of pollution. So, they’re open to it, but they need to be shown that it’s real.”
Abigail Ross Hopper, CEO of the Solar Energy Industries Association (SEIA), said her organization conducted polling about a year ago to find the message that was most likely to increase support for solar power.
“Is it that we’re competing against another country? Is it that we’re innovative? Is it that we’re low price? Is it that it’s [reducing] carbon?” she asked. “The message that had the most resonance amongst voters was the clean air message, which makes sense when I saw [it], but it’s certainly not what we lead with.”
Kiernan said Republican senators have recently become more receptive to discussing climate issues. “One of them brought up the [importance of] getting the [agricultural] community on board and in sync with us. Yes, they’re well aware of the weather extremes. But if a carbon regime — whether it’s a carbon fee or carbon sequestration — [if] farmers could perhaps get credit for their role in carbon sequestration, [it could] make a big difference.
“The wind industry does that often vis-a-vis wind farms and in the land lease payments,” he continued. “But if we can think [of] a broader regime, that may be a significant tipping point for a fair number of Republican senators.”
Kiernan said the renewable industry also must increase its presence in RTO stakeholder processes, noting that AWEA and SEIA agreed about a year ago to join forces on that front. “We need to redesign a market. That is mostly accomplished at RTOs. And the stakeholders there are not appropriately representative of the future of the grid. We’ve got to be there,” he said.
Carbon Fee? Clean Energy Standard? Cap and Trade?
In addition to plotting strategy, speakers at the daylong forum also discussed individual legislative proposals.
Tonko said he is pursuing a “two-track” approach of preparing major climate legislation that could be passed under a Democratic Congress and administration, while supporting more modest bills in the current term. Tonko said he is encouraged by the bipartisan American Energy Innovation Act (S. 2657), which he said includes important measures on research and development, energy efficiency, workforce development and energy storage. (See Murkowski, Manchin Offer Bipartisan Energy Bill.)
In January, Tonko and other Democrats on the Energy and Commerce Committee released the discussion draft of the Clean Future Act, which seeks to get the economy to net-zero greenhouse gas emissions by 2050. Tomko said a “full comprehensive climate bill … needs to be part energy bill, part infrastructure bill, part environmental protection statute and part workforce development program.” (See Draft Climate Bill Would Make RTO Membership Mandatory.)
Sen. Wyden is hoping to see extensions of clean energy tax incentives in the current Congress. If Democrats take the Senate and he is chair of the Finance Committee in 2021, he said, he will seek to eliminate 45 current energy tax breaks and replace them with three: one each for clean energy, clean transportation fuel and energy efficiency.
The pros and cons of a carbon fee were discussed at a conference earlier last week sponsored by the New York University School of Law Institute for Policy Integrity and Duke University’s Nicholas Institute for Environmental Policy Solutions. (See related story, Carbon Pricing Gains Popularity —and Doubts.)
Kiernan said AWEA supports the “broad brushes” of the Climate Leadership Council’s carbon dividends plan, which claims it will cut U.S. CO2 emissions in half by 2035 with a gradually rising carbon fee, and rebates of $2,000 a year for a family of four.
But, he added, AWEA could support several approaches. “We’ve not ruled out cap and trade or a CES [clean energy standard].
“There are a number of Republicans — unfortunately, more behind closed doors — that are talking about the fee-and-dividend approach and are open to it, if not enthusiastic about it,” Kiernan continued. “They’re not public about it. Obviously, the fee or, quote, ‘tax’ is a challenge politically. But I’ve also talked to some leading Republicans in the Senate that are seeing the opening to potentially moving some type of fee and dividend or at least having a serious discussion about it post-election.”
CAP’s Tanden said beginning with a low carbon fee may be the key to winning congressional approval.
“We all acknowledge that the science requires a relatively large and impactful carbon tax. One way to think about the next 30 years is to have a low carbon tax enacted, which … shows it does not have the dire impact [feared], and they can ratchet up based on targets. … If we’re not meeting targets, it will automatically increase over time so that you are automatically having the impact that you need to have. That’s just one thing to think about because the most important thing is to actually get the carbon tax in law at a time where it’s still going to be heavily demagogued as a middle class tax increase no matter how we structure it.”
Pete Wyckoff, energy and environment policy adviser to Sen. Tina Smith (D-Minn.), touted the Clean Energy Standard Act of 2019, introduced by Smith and Rep. Ben Ray Luján (D-N.M.) last May, which would require electric retailers to sell increasing percentages of carbon-free energy (51% of retail sales in 2021, 77% in 2035 and 96% in 2050).
Resources for the Future said its modeling of the bill indicates that by 2035, it would reduce greenhouse gas emissions by 61%, prevent the retirement of 43 GW of nuclear capacity and increase renewable generation from 30% to 56% of total generation.
Wyckoff said Smith and Luján have had “fruitful” talks with Republicans, although they have no GOP cosponsors yet. “But we have built a coalition,” he said, citing endorsements by Utility Workers Union of America, the United Steelworkers, Xcel Energy, Exelon, UCS, the Clean Air Task Force and former Energy Secretary Ernest Moniz.
Wyckoff said Smith is backing the bill in part because similar bills have received Republican backing. “Our bill is also something she’s interested in because it’s what the states are doing. … No one is passing carbon taxes. But a clean energy standard, if well designed, can give you a lot of the same market benefits of a carbon tax and is much more politically palatable.”
NextEra Energy subsidiaries last week appealed a federal court ruling that upheld a Texas law giving incumbent transmission companies the right of first refusal to build new power lines.
The companies asked for expedited treatment to prevent “irreparable harm.”
NextEra Energy Capital Holdings and four other NextEra transmission owner/developer entities took their case to the 5th U.S. Circuit Court of Appeals in New Orleans (20-50160) after the U.S. District Court for the Western District of Texas last month refused to overturn Texas Senate Bill 1938. (See District Court Dismisses Texas ROFR Repeal.)
The law essentially allows only incumbent transmission companies to build new power lines in Texas by granting regulatory certificates of convenience and necessity to the owners of the endpoints of a new transmission line.
The NextEra units said the Feb. 26 ruling means NextEra Energy Transmission (NEET) Midwest could lose its “lawfully won right” to build the $115 million Hartburg-Sabine transmission project in MISO’s East Texas footprint. NEET Midwest won the project’s rights in 2018 through a competitive bidding process. (See NextEra Wins Bid to Build MISO’s 2nd Competitive Project.)
The 5th U.S. Circuit Court of Appeals grounds in New Orleans | 5th U.S. Circuit Court of Appeals
“Accordingly, without expedited decision on the merits from this court, NextEra will be imminently and irreversibly deprived of its lawfully won right to build and operate a major transmission project,” NextEra said in its appeal.
NextEra’s filing on Friday said the company recently learned that MISO is using its established variance analysis process to study the project and developments around it. The RTO uses the analysis to study projects already approved under its Transmission Expansion Plan that are later disrupted by circumstances that affect the project’s cost, schedule or “the ability of selected developers and transmission owners to complete.”
NextEra said MISO indicated it anticipates a decision reassigning or canceling the project by March 31. MISO would then seek FERC approval of the change, with the commission ruling by June, NextEra said.
MISO told RTO Insider that it continues to plan for the project but wouldn’t say under which developer it will proceed. Should the project revert to the incumbent, it would become Entergy’s responsibility.
Spokesperson Allison Bermudez said in an email that MISO is aware of the recent court action, but confidentiality restrictions limit its ability to talk publicly about the project. Bermudez said MISO will make a further statement once the RTO completes the variance analysis.
NextEra did not respond to a request for comment.
The legislation also affects NEET Southwest’s application with the Public Utility Commission of Texas to transfer ownership of 30 miles of 138-kV facilities from Rayburn Country Electric Cooperative in SPP’s region of East Texas.
NextEra said SB 1938 violates the U.S. Constitution’s dormant Commerce Clause because it allows only the incumbent Texas owners of the end points to build, own and operate new lines. Should the incumbent decline to build the line, it can assign the right only to another Texas entity, NextEra said.
“In effect, Texas has closed its borders to new out-of-state companies from doing this type of business in the state,” NextEra said.
The company also asserted that the law violates the Constitution’s Contracts Clause “because it abridges the ‘existing contractual relationship’” for the Hartburg-Sabine project. It cited the Department of Justice’s “statement of interest” filed last year in NextEra’s appeal of SB 1938 that said the law placed Texas’ deregulated retail electric market “at risk.” (See DOJ Weighs in on Texas ROFR Lawsuit.)
The NextEra companies on March 2 also filed an injunction with the district court asking that its proposed transmission projects be shielded from the new law while they appeal to the 5th Circuit.
“In opposing the preliminary injunction, Texas identified only an amorphous threat to its sovereignty that might result from an injunction,” NextEra said. “An injunction pending appeal will temporarily prevent the imminent, irreversible loss of a $100 million-plus project for NextEra while the 5th Circuit considers the substantial constitutional issues presented here.”
ISO-NE and New England Power Pool stakeholders are collaborating to study market and reliability issues the region will face as it seeks to decarbonize power, transportation and heating over the next three decades.
NEPOOL members discussed the outlines of the study — which was prompted by requests last year from the New England States Committee on Electricity (NESCOE), New England Power Generators Association (NEPGA) and other stakeholders — at the Participants Committee meeting Thursday.
“People are generally very supportive of doing a study,” ISO-NE CEO Gordon van Welie said Friday at a news briefing on the RTO’s 2020 Regional Electricity Outlook, which noted states’ “goals to achieve up to 100% renewable resources” and asked “How do we get there from here?”
“I think the general consensus in the room … is it’s a good thing to go off and study the future power system because that’s going to give us a lot of information to then inform the other discussions that people want to have, which is the market design conversation, and ultimately transmission,” added van Welie, who said electrification will transition the region from a summer- to a winter-peaking electric system.
“There was less clarity around what the scope and objective of the study should be. The discussion yesterday was mostly about process and not scope. And that conversation [about scope] will be coming in due course in the next month or two.”
Projected changes in New England power resources and energy efficiency | ISO-NE 2020 Regional Electricity Outlook
The PC meeting materials included a graphic depicting the study as four bubbles: the objective (assessing the power system needed to meet state energy and environmental policies); study process (identify the resource mix and operational and reliability needs); a gap analysis (to determine whether the current markets plus ESI provide resources and ISO-NE what they need to continue reliable operations); and a discussion of potential market approaches to address any gaps.
Van Welie said that the study’s time frame will be the subject of future stakeholder discussions, but that he expects it to be longer than the next 10 years, when he said electric demand from decarbonization of transportation and heating is projected to increase only slightly.
“When I look at that and the long-term decarbonization goals in the region, I think there will be a hockey stick [rise in demand]. We’re going to have to accelerate — dramatically accelerate — decarbonization of the other sectors, so there will be a steep growth in electric demand over that period,” he said. “It’s important, if we’re going to study the future, that we study that hockey stick because there’s nothing really interesting to study in the next 10 years. The demand’s pretty flat.”
A Brattle Group study released in September predicted that meeting the states’ goals for reducing greenhouse gas emissions by 80% by 2050 will result in a doubling of electricity demand, even with substantial energy efficiency gains.
“I don’t know that we should lock onto specific numbers and multiples at this time,” van Welie said. More important, he said, is how the system will add renewable capacity: through the markets that have served the region for the last two decades, or through long-term power purchase agreements, which would put investment risk back on consumers.
ISO-NE sought to develop a market-based path for renewables to supplant carbon-emitting resources through the substitution auction in the Competitive Auctions for Sponsored Policy Resources (CASPR) program, which allows resources nearing retirement to trade their capacity supply obligations with new state-sponsored resources that did not clear in the primary auction.
The RTO has held two auctions under CASPR. Vineyard Wind, a planned 800-MW offshore wind farm, took over a 54-MW obligation from a retiring resource in Forward Capacity Auction 13 last year. There were no trades this year in FCA 14.
“As we said when we filed CASPR, it’s intended to work over time,” said Anne George, the RTO’s vice president of external affairs and corporate communications. “We still feel like with only two auctions of experience, we need a little more time to see how CASPR works.”
“I think it’s going to take time for those economic pressures to build up” to persuade incumbent generators to retire, van Welie added. “So, we have been very clear about this: We think carbon pricing is a much better solution … which is why you hear us advocating for it.” (See ISO-NE: States Must Lead on Carbon Pricing.)
State renewable portfolio standards in New England | ISO-NE 2020 Regional Electricity Outlook
At a conference in D.C. last week, speakers expressed some doubts about carbon pricing, saying it won’t solve the climate crisis by itself or persuade states to abandon their own clean energy policies. (See related story, Carbon Pricing Gains Popularity — and Doubts.)
“I think it’s going to take time for people to get comfortable with [carbon pricing]. It may take a long time for us to get comfortable with it,” van Welie acknowledged. “Developers are going to be very cautious about trusting the regulatory system around carbon pricing until they see that it’s stable and has longevity.”
The Regional Greenhouse Gas Initiative, which includes all six New England states, “never produced a material carbon price in terms of driving the clean energy transition,” van Welie said. RGGI’s most recent auction in December cleared at only $5.61/ton.
Van Welie contrasted RGGI with Europe, where carbon emissions were trading last week at about 25 Euros/ton ($28), high enough that Royal Dutch Shell, BP and others are willing to build offshore wind on their own balance sheets without long-term PPAs, he said.
Transmission RFP
On an unrelated issue, van Welie said the RTO was “very pleased” with the response to its first-ever competitive transmission solicitation, which resulted in 36 project proposals by the March 4 deadline. (See ISO-NE Issues First Competitive Tx RFP.)
ISO-NE issued the solicitation in December to prepare the transmission system in the Boston area for the retirement of the Mystic Generating Station in Everett, Mass. The proposals will seek to address transmission facility overloads under peak load conditions, as well as system restoration concerns with the underground cable system. ISO-NE hopes to select the finalists for the work by the end of the year.
“We’ve got a lot of work ahead of us,” said van Welie, adding that the RTO will be releasing more details on the responses shortly.
New Member
In addition to its discussion on the futures study, the PC voted Thursday to admit trade group Advanced Energy Economy as a NEPOOL member. AEE, whose members provide energy efficiency, demand response, energy storage and natural gas, renewable and nuclear generation, was admitted as a Fuels Industry Participant.
Operating, Planning Procedure Revisions Approved
Members also approved revisions to the following operating and planning procedures:
OP-18 (Metering and Telemetering Criteria): adds a requirement to telemeter station frequency; identifies equipment requirements; specifies which requirements apply to existing and new equipment; and revises Section I (Purpose) to reflect current practice.
OP-23, Appendix I (Resource Auditing): clarifies the asset ID entry for certain reactive resources without an RTO-assigned asset ID.
OP-3 (Transmission Outage Scheduling): extends the maximum duration for an “opportunity outage” from 96 hours to 108 hours. An opportunity outage is one that fails to satisfy the minimum advance notice time required for planned short-term transmission outage processing and is submitted for RTO approval as a result of an unexpected opportunity to accomplish work that would otherwise require another outage at a less opportune time.
PP-3 (Reliability Standards for the New England Area Pool Transmission Facilities): replaces the term “governance participant” with the terms “market participant” and/or “transmission owner.”
The Upper Midwest needs more transmission, more technology and preservation of some dispatchable generation for the sake of reliability, the CapX2050 study concluded last week.
The 10 Minnesota utilities behind the effort drew three major takeaways from the study:
More transmission infrastructure will be necessary in the Upper Midwest to accommodate resource transition.
Non-dispatchable resources alone can’t meet all energy requirements, so some traditional power plants will still be necessary.
Real-time operational demands will become trickier to manage and will require new procedures.
Building on the CapX2020 transmission effort focused on 2020 reliability needs, the CapX2050 study addresses how the grid can handle widescale reductions in carbon emissions by 2050. (See Minnesota Utilities Reunite for CapX2050 Study.) Like the 2020 effort, the 2050 study concentrated on the transmission system that serves Minnesota, eastern South Dakota and North Dakota, western Wisconsin and the surrounding areas.
The study’s report said grid support in the form of ancillary services will be needed in areas where large, dispatchable generation is retired. New transmission technology and storage resources will be required to deliver ancillary services.
The Brookings County-to-Hampton project, part of CapX2020 | CapX2020
“The variability of the output of non-dispatchable resources, even within a single day, could lead to several thousands of [megawatts] being transferred across the transmission system, with reversals in direction of flow occurring in an equal but opposite magnitude during the same day,” the report warned. “Operating techniques, transmission infrastructure and analysis tools will need to become more sophisticated to more accurately identify and adjust in real-time to deal with these changes.”
The utilities said that simply adding more non-dispatchable resources cannot solve the problem of sometimes deficient energy supply.
“Abrupt changes in weather, including prolonged extreme weather conditions, sudden changes in consumer demand, or disturbances on the transmission system (i.e., outages) will increasingly challenge the ability of the electric grid to provide a continuous supply of energy as more non-dispatchable resources are added,” the report said. It added that maintaining some dispatchable resources and adding energy storage can keep the transmission system reliable.
In what should be déjà vu for MISO planners, the CapX2050 report also called for a “long-term comprehensive regional transmission plan.” The Organization of MISO States has been pressing the RTO for two years to develop a long-term transmission package to accommodate growth of policy-driven generation resources. (See MISO Cracks Door on Long-term Tx Planning.) The report reminded MISO that “transmission expansion has been shown to be cost-effective when considered as part of a larger market.”
At this point, the CapX2050 utilities aren’t calling for any specific transmission projects. CapX2020 culminated in an 800-mile, grid expansion in the Upper Midwest, including four 345-kV transmission lines in Minnesota, North Dakota, South Dakota and Wisconsin and a 230-kV line in northern Minnesota.
Great River Energy spokesperson Jenny Mattson said that while future studies under CapX2050 aren’t being ruled out, none are planned so far.
“Though there is no time frame for additional studies, we’ll continue to evaluate the system in partnership with other utilities and stakeholders, including legislators, regulators, communities and MISO,” Mattson said in an email to RTO Insider.
The utilities also said they’re “ready to engage with public and stakeholders” on planning for new transmission.
