ERCOT Technical Advisory Committee Briefs

ERCOT’s Technical Advisory Committee last week tabled a proposal to pay lost opportunity costs to generators ordered to ramp down for grid reliability, choosing instead to take advantage of extra time on the calendar and schedule a workshop on the issue.

The Board of Directors remanded the proposal (NPRR649) back to the TAC in February. It had received 56% support in a TAC roll call vote in November, short of the two-thirds threshold for approval. (See LOC Rule Sent Back to ERCOT’s Stakeholder Process.)

The TAC set March 7, 9 or 23 as possible dates for the workshop. The committee doesn’t meet again until March 31, giving it a month and a half before it must report back to the board April 12 with either a final version of NPRR649, an alternative version or reasons for rejecting it.

TAC Chair Randa Stephenson said she would prefer an early workshop, but she also wanted to ensure ERCOT staff had enough time to draft language that helps the committee develop alternative recommendations.

Kenan Ögelman, vice president of commercial operations, said the delay would give staff ample time to write a new nodal protocol revision request that would be an “option B.”

“It would be very different from the existing 649,” Ögelman said. “We would like to spend more time on option B and describe it better.”

Staff is working on what Ögelman called “attestation language” that better describes the circumstances of ramping down units in the day-ahead market.

The attestation language “needs to be broad enough to cover the multiple ways people use their units for hedging purposes,” Denton Municipal’s Lance Cunningham said.

DREAM Task Force Submits Final Report

The TAC told its Distributed Resource Energy Ancillaries Market (DREAM) Task Force to develop a matrix of “actionable, clear points” for the committee to consider at its April meeting.

The committee was responding to the final report of the task force, which was chartered to analyze the regulatory and market framework governing distributed generation resources’ participation in ERCOT.

The report sought the TAC’s direction on eight policy questions that might be put to stakeholder votes. Ögelman told the committee ERCOT would like to merge a staff white paper with the DREAM team’s work before going through the stakeholder process.

“We would like to start working on NPRRs and other potential changes,” Ögelman said. “We would like to engage stakeholders further on an individual basis as we work through the issues.”

“I want to be clear on exactly what DREAM and ERCOT are asking TAC to do with this information, the items in the white paper and presentation,” said Diana Coleman, senior market specialist with the Texas Office of Public Utility Counsel.

ERCOT, which has a little more than 550 MW of DG, is projecting those resources will grow by 10% annually.

The task force said ERCOT lacks explicit rules for DG resources 10 MW or greater that are connected at a distribution voltage, and that intend to inject into the distribution system rather than reduce load. It also needs a more precise definition of the term “customer,” the task force said, citing “ambiguous reference[s] to distribution customer, load, etc.”

“These are rapidly growing, very flexible resources,” said Shell Energy’s Greg Thurnher, the task force chair. At 10% growth, he noted, ERCOT would essentially be adding the capacity of a nuclear unit similar to those at the South Texas Project over about seven years.

Thurnher said the wide disparity of business interests and opinions within the DREAM team “make it difficult to make further progress — absent a voting structure.”

ERCOT has DG resources in more than 7,600 locations in competitive areas. Its congestion revenue rights software can only handle about 600 resource nodes at a time.

“There are computing constraints to how large we can make this system,” Thurnher said.

“The key to the nodal market is having as much visibility into the market as possible,” Calpine’s Randy Jones said. “We need to give ERCOT the observability they have to have, and to be able to model” DG resources.

Other stakeholders said the proposed changes are an “unnecessary layer of complexity.” They also discussed optionality between load zone and nodal pricing.

“These types of resources are growing in ERCOT and will have an impact on market solutions,” Ögelman said. “The stakeholders can address the potential growth in distributed resources, and you address those by having market rules.”

Regional Haze Workshop

The committee and its Wholesale Market Subcommittee agreed to hold a workshop devoted to regional haze and reliability-must-run (RMR) services.

ERCOT staff had proposed a fall date for the workshop, after any potential litigation on EPA’s regional haze rules is settled. However, the WMS and other market participants expressed a desire to hold the workshop earlier.

“You’re not getting anything by fall from the courts,” Stephenson said.

“If [market participants] are more focused on the RMR aspects of it, we can have the workshop sooner, rather than later,” Citigroup Energy’s Eric Goff said. “If you’re talking about the regional haze aspect, that’s a lot of moving parts.”

Goff noted that EPA dismissed ERCOT’s concerns about reliability implications, saying, “If ERCOT doesn’t have enough notice on RMR operations, maybe it should change the notice of suspension requirements.

“I don’t know if they considered the kind of Pandora’s box that opens,” he said. “ERCOT could benefit from the market’s input on fleshing out the protocol language.”

Ögelman said ERCOT staff would commit to coming back to the TAC and reviewing the RMR processes, but that its answers might be different.

“ERCOT needs to bring their concerns and ideas,” Stephenson said. “The stakeholders have their concerns. Now, we need ideas and solutions.”

Ancillary Service Redesign Project

ERCOT staff is conducting an additional cost-benefit analysis on the ancillary service redesign project and should be done in time for the Protocol Revisions Subcommittee’s March meeting, ERCOT’s Kenneth Ragsdale told the TAC.

While ERCOT has been successful in complying with NERC reliability standards, its ancillary service framework, which dates back to the late 1990s, “does not adequately address ongoing changes to the ERCOT system,” nor does it anticipate those in the future, such as DG and utility-scale intermittent renewables, according to NPRR667.

“ERCOT still believes 667 has some worthy concepts in it,” Ragsdale said.

He said staff is considering phased transition plans for the NPRR, allowing it to be implemented sooner.

Reserve Discount Factor Proposal

ERCOT staff told the committee it will be recommending changes to the reserve discount factors (RDF) used in its physical response capability calculation as a result of unannounced testing conducted in 2014-15.

When temperatures are below 95 degrees, staff is suggesting a resource’s high sustained limits (HSL) should not be discounted. However, when temperatures exceed 95 degrees, HSLs would be discounted, but only by 1%, instead of the current 2%.

Manager of Operations Planning Sandip Sharma said ERCOT would recommend procuring additional responsive reserves when temperatures are above 95 degrees.

Amanda Frazier, senior director of regulatory policy at Energy Future Holdings, said her company analyzed 12 months of data and found similar results to ERCOT’s. “We did see a difference in the high hours,” she said. “But does it make sense to reduce the RDF to zero in hours not above 95?”

Calpine’s Jones questioned ERCOT’s motivation. “If you’re producing more [responsive reserves] for price formation, just say so,” he said.

Ögelman responded that the idea behind the change was “not necessarily” price formation, but the 1% discount factor.

“There’s evidence we should wait a bit, and there’s evidence we should reduce it all the way to zero,” he said. “In the proposal, it can only come down 1%. I would point to the existence of reserve discount factors as the driver for action.”

ERCOT staff will take the proposal back to the Reliability and Operations Subcommittee. According to the staff timeline, the issue will come back to the TAC in April.

NPRRs, Subcommittee Goals Approved

The TAC approved its goals and strategic objectives for 2016, along with the goals of its Commercial Operations, Reliability and Operations, and Wholesale Market subcommittees.

The committee also easily approved two NPRRs and a system change request, along with a nodal operating guide revision request it had tabled in January.

NPRR749, Option Cost for Outstanding CRRs.
NPRR750, Clarify Resource Status when Providing Fast Responding Regulation Service.
SCR787, Maintain NDCRC Data for Generator Transfer Between Resource Entities.
NOGRR143, Alignment of Nodal Operating Guiders with NERC Reliability Standard, BAL-001-TRE1.

Budget Issues

The Protocol Revisions Committee told the TAC that ERCOT has raised its internal labor rate from $65/hour to $75/hour in calculating impact-analysis cost estimates and project labor costs for staff who work on capital projects. The PRS said the old rate had been in effect for more than 10 years.

ERCOT has allocated a $400,000 contingency fund for 2016-17 market projects to ensure board-approved revision requests are not delayed. The change does not affect the system administration fee.

Leadership Posts Filled

The TAC unanimously approved the re-election of Adrianne Brandt as its vice chair. Brandt left Austin Energy for San Antonio’s CPS Energy shortly after the year began, requiring a second vote from members before she could officially take her position.

The committee also approved the Retail Market Subcommittee’s leadership (Chair Kathy Scott of CenterPoint Energy and Vice Chair Rebecca Reed Zerwas of NRG Energy) and that of its four working groups and task forces.

— Tom Kleckner

March 1, 2016

FERC Denies Rehearing of Winter Reliability Order

By William Opalka

FERC on Wednesday denied rehearing of its September order endorsing the interim Winter Reliability Program for ISO-NE (ER15-2208).

The commission had endorsed a proposal made by the FERC Asked to Determine ISO-NE Winter Reliability Program.)

NEPOOL’s proposal was based on the 2014/15 winter program — which provided compensation for any unused oil or LNG remaining at the end of the winter — and added demand response.

ISO-NE’s proposal provided compensation for unused oil or LNG, but it would have also compensated nuclear, hydro, biomass and coal-fired resources and did not include DR.

Entergy had challenged the order, saying FERC’s stated preference for a market-based solution to mitigate winter natural gas supply constraints should have tipped the balance toward the RTO’s more fuel-neutral program.

“The record reflects that including such resources in the program would not provide any additional winter reliability benefit to the region,” the commission wrote. “While Entergy argues that additional payments to coal, nuclear and hydro resources would likely incentivize these resources to take incremental measures to ensure performance during the winter, this assertion is contradicted by substantial expert testimony supporting the NEPOOL proposal.”

FERC repeated its assertion that it prefers market-based solutions, but it said an out-of-market solution is “appropriate” until ISO-NE’s Pay-for-Performance program begins later in early 2018.

Shortly after the September order, Entergy’s Pilgrim nuclear plant in Massachusetts was removed as a capacity resource for the 2019/20 commitment period. It will be closed no later than 2019. (See Entergy Closing Pilgrim Nuclear Power Station.)

March 1, 2016

MISO Advisory Committee Briefs

The Stakeholder Governance Working Group (SGWG) narrowly avoided retirement in a 10-7 vote at MISO’s Feb. 23 Advisory Committee meeting.

Speaking on behalf of MISO’s Transmission-Dependent Utility sector, Gary Mathis said it was too early to sunset the group because management plan language stipulates it should be retired only “after redesign implementation.”

“I would place an abundance of caution on [retiring] this today,” Mathis said. “We’re going to learn things in the implementation that will need to be discussed further and captured in the governance guide.”

Mathis added it would be impossible for the group to fully implement its redesign by March. Exelon’s Marka Shaw asked why the group could not be absorbed into the Steering Committee as originally planned.

Mathis said he was concerned that new participants might interrupt the continuity of redesign work. “You’ll have the institutional memory running through this,” he said.

Mathis said he expected the SGWG to remain busy until at least after mid-2016, as the group would next focus its attention on setting priorities for 2016.

Ten voting members were in favor of the extension, with seven opposed and three abstentions. Use of the revised governance guide and fillable issues form were also approved by general consent at the meeting. (See MISO Stakeholders Finish Governance Guide Changes.)

While the SGWG was left standing, MISO’s Data Transparency Working Group is expected to retire as planned after a final March 7 meeting. Subsequent data requests will be processed through the Steering Committee. Tom Welch, MISO liaison to the DTWG, said the internal review process will be largely unaffected by the change, with updates still delivered using MISO’s data request tracking spreadsheet.

Additionally, MISO’s Regional Expansion Criteria and Benefits Working Group was transitioned from a task force and will begin to report to the Advisory Committee, which approved the group’s charter and management plan during a Feb. 24 meeting.

AC to Begin Setting Priorities, Conducts Elections for RASC Chairs

Two months into 2016, MISO’s Advisory Committee is still working to set priorities for the year.

“I know it’s late in the year, but as the Advisory Committee, we need to determine what our priorities are,” committee Chair Audrey Penner said Feb. 24.

Penner said the committee should base its choices on MISO’s five identified priorities for 2016: the Clean Power Plan, electric-gas coordination, seams optimization, grid technology advancement and enabling infrastructure development.

The committee also discussed nominations for chair and vice chair of the newly created Resource Adequacy Subcommittee.

Tia Elliott, director of regulatory affairs at NRG Energy, said electronic ballots would be sent to stakeholders following the Advisory Committee’s Feb. 23 approval of the RASC charter and management plan. As in the Advisory Committee, votes conducted in the RASC are not binding.

RASC leaders should be elected in time for the group’s first meeting scheduled for March 2 at MISO’s Little Rock offices.

Nominating Committee Elections to be Held Earlier

Two stakeholder vacancies on the Nominating Committee for the MISO Board of Directors need to be filled more quickly than usual, according to Michelle Bloodworth, MISO executive director of external and stakeholder affairs.

MISO plans to hold elections for the vacant positions during the March 23 Advisory Committee meeting. Bloodworth attributed the need for a quick turnaround to the board’s new, pared-down meeting schedule.

The committee consists of three independent board members and two stakeholders appointed by the Advisory Committee.

Citigroup Energy’s Barry Trayers said he would like to resume efforts to change the Nominating Committee structure, which stalled last year. He noted that other MISO committees have larger numbers of stakeholder representatives, typically one from each sector.

“The stakeholders right now are outnumbered 3-to-2 on the committee, and I don’t think that’s appropriate,” Trayers said.

Bloodworth said that the Corporate Governance and Strategic Planning Committee would need to alter the Nominating Committee’s bylaws before more seats could be added to the panel.

“I think that’s something we’ll take under advisement,” Penner said.

— Amanda Durish Cook

March 1, 2016

Exelon-Pepco Deal in Doubt as Mayor, Consumer Advocate Balk at New Terms

By Suzanne Herel

Exelon’s proposed acquisition of Pepco Holdings Inc. looked in doubt Tuesday as D.C. Mayor Muriel Bowser and the Office of the People’s Counsel announced their opposition to revised terms set out by the Public Service Commission last week.

The two are among nine settling parties that must agree to the new deal in order for it to be approved without further commission action. At issue for both was the reallocation of $25.6 million from a customer investment fund that would have shielded residential customers from rate hikes until 2019. The DC PSC: Will OK Exelon-Pepco Deal for Additional Concessions.)

“The PSC’s counterproposal guts much-needed protections against rate increases for D.C. residents and assistance for low-income D.C. ratepayers. That is not a deal that I can support,” said Bowser, who was instrumental in bringing the parties back to the board to negotiate a new settlement after the commission rejected the merger in August. The PSC agreed to reopen the matter in October. (See DC PSC’s Counteroffer below.)

People’s Counsel Sandra Mattavous-Frye echoed Bowser’s concern. “The commission’s order eviscerates the benefits and protections essential to render the proposed merger in the public interest by making changes to the $25.6 million rate offset provision for residential customers, which was the single most critical provision I supported,” she said.

“I am hopeful all parties and consumer participants to this case will not lose sight of the real issue in this case — the protection of our most vulnerable residents. Going forward, we will need to work cooperatively to ensure that all consumers in all eight wards of our city are guaranteed affordable rates and reliable service, and that once the fanfare dies down, our most vulnerable residents are not forgotten.”

Exelon-Pepco-Stock-Price-Chart-web — Pepco’s stock price dipped on news of Mattavous-Frye’s dissent before nosediving when Bowser’s statement was released. Exelon was down only marginally after news broke but quickly rebounded.

Pepco’s stock price dipped on news of Mattavous-Frye’s dissent before nosediving when Bowser’s statement was released, dropping by more than $3, a decrease of 13% from Monday’s close, to $22.81/share. Exelon was down only marginally after news broke but quickly rebounded to near its opening price of $31.80/share.

Both Bowser and Mattavous-Frye, along with Attorney General Karl Racine, opposed the initial merger offer but signed on to the revised settlement. Racine’s office also expressed his opposition to the revisions. “With the guarantee that residential ratepayers won’t be impacted until April 2019 no longer part of the deal, he determined that the settlement as revised was no longer in the public interest,” Racine spokesman Robert Marus said.

In an earnings call last month, Exelon CEO Christopher Crane said the company would abandon the $6.8 billion deal if it didn’t have PSC approval by March 4.

Asked Tuesday whether Exelon planned to walk away if a deal can’t be struck in the 14 days given the settling parties, spokesman Paul Elsberg said, “We continue to have conversations with the D.C. government and other settling parties about the commission’s order and the new provisions. The discussions are ongoing, and we will provide an update at the appropriate time.”

Meanwhile, opponents planned a press conference for noon Wednesday across from D.C. government headquarters to urge the settling parties to reject the deal. That press conference will still occur as planned.

“D.C. is ready to move on,” said Anya Schoolman, head of D.C. Solar United Neighborhoods. “D.C. residents are ready to work toward an affordable, reliable and sustainable electricity system without Exelon. We hope Mayor Bowser will join us.”

Kellie Armstead Didigu, a spokeswoman for the PSC, confirmed that the order requires all settling parties to agree on the revised terms for the deal to be approved outright, quoting from the order: “All of the settling parties are directed to review the alternative terms in the revised [nonunanimous settlement agreement] and file a notice with the commission secretary no later than 14 days from the date of this order, either accepting the revised NSA, or requesting other relief. … If all the settling parties accept the revised NSA … then the joint application for approval of a change of control of Pepco as amended by the revised nonunanimous settlement agreement … is deemed approved as being in the public interest.

“If the settling parties request other relief … then the nonsettling parties may file comments on the settling parties’ filing or make a filing requesting other relief with the commission secretary, within seven days of the date of the settling parties’ filing of requesting alternative relief.”

Said Didigu, “Because nothing has been filed yet by the settling parties in response to paragraphs 206 or 208 of our order, and the commission does not want to anticipate what will be filed by the settling parties, the commission cannot address what the next steps are at this time.”

If Exelon does decide to sweeten the deal with D.C., it likely will have to return to the other states where the merger had been approved under a “most favored nation” status — Virginia, New Jersey, Maryland and Delaware.

The PSC on Friday took two 2-1 votes on the settlement brokered by Bowser’s office. The first rejected the settlement as filed, with Commissioner Willie Phillips dissenting. The second offered four concessions that, if agreed to by the settling parties, would mark the deal approved. Commission Chairwoman Betty Ann Kane was the dissenting vote.

DC PSC’s Counteroffer

In a 2-1 vote, the D.C. Public Service Commission on Friday rejected the Exelon-Pepco merger as proposed, citing four reasons why Chairwoman Betty Ann Kane and Commissioner Joanne Doddy Fort deemed it not in the public interest.

But Fort then departed from Kane, saying the settlement negotiated by Mayor Muriel Bowser’s administration was “not fatally flawed” and could be fixed with additional concessions.

In a second 2-1 vote, Commissioner Willie Phillips joined Fort in offering a revised settlement including four changes that they said would make the deal acceptable without further commission action.

The order requires all of the settling parties to agree to accept the revised settlement within 14 days. In addition to Exelon and Pepco, that includes the Office of People’s Counsel; the District of Columbia Government; the D.C. Water and Sewer Authority; the Consumer Law Center; the National Housing Trust; the National Housing Trust-Enterprise Preservation Corp. and the Apartment and Office Building Association of Metropolitan Washington.

The proposed changes address the allocation of the $72.8 million customer investment fund (CIF) and Exelon and Pepco’s role in development of a solar generation facility and four microgrids. Below is a summary of the issues and the proposed changes.

ISSUE 1: A $25.6 million allocation from the proposed CIF for base rate credit relief excludes non-residential ratepayers. The commission also worried that the allocation could undermine its ability to address the current negative rate of return for residential ratepayers and the resulting subsidies placed on non-residential consumers.

Proposed Change: Strike “residential” from the name of the credit. Defer a decision on allocating the relief until the next Pepco rate case. At that time, the parties in the base rate case would have a chance to recommend to the PSC how the credit should be distributed and over what period of time.

ISSUE 2: Exelon’s designation as developer of a solar generation facility at the D.C. Water and Sewer Authority’s Blue Plains Advanced Wastewater Treatment Plant and Pepco as developer of four microgrids undermines competition and grid neutrality.

Proposed Changes: Remove provision naming Exelon the developer of a proposed 5-MW facility. Require Pepco to facilitate the project’s interconnection for a vendor to be chosen by D.C. Water. Strike Pepco’s role as developer of public-purpose microgrids; require it to facilitate pilot projects to modernize D.C.’s energy system.

ISSUES 3 and 4: The proposed uses for the CIF for sustainability projects and low-income assistance do not improve Pepco’s distribution system, nor advance the modernization of the district’s energy systems or distribution grid. The proposed allocation method for the CIF deprives the commission of the ability to ensure all money is being used to enhance the distribution system and benefit district ratepayers.

Proposed Change: Create an escrow fund with two subaccounts to hold $32.8 million of the CIF: $21.55 million for pilot projects to modernize the energy system and $11.25 million for energy efficiency and energy conservation programs focusing on housing for low- and limited-income residents. The commission would decide how the funds would be released.

February 26, 2016

Dynegy, Energy Capital to Buy 8.7 GW in $3.3B Deal

By Ted Caddell

Dynegy and private equity firm Energy Capital Partners announced Thursday they are buying the U.S. fossil fuel generation portfolio of French utility ENGIE, a total of 8,731 MW in PJM, ISO-NE and — in a first for Dynegy — ERCOT.

The deal is valued at $3.3 billion. The joint venture, called Atlas Power, is 65% owned by Dynegy and 35% by Energy Capital. Dynegy will operate the fleet, 90% of which is natural gas-fired.

Although it is based in Houston, Dynegy owns no generation in the Lone Star State. Atlas Power will gain 4,564 MW of generation in ERCOT, in addition to 2,775 MW in PJM (Illinois, Ohio, Pennsylvania, Virginia, West Virginia and New Jersey) and 1,392 MW in ISO-NE (Massachusetts).

With the addition of the ENGIE assets, Dynegy will control 35 GW of generation: 43% in PJM, 18% in MISO, 15% in ISO-NE, 13% in ERCOT, 3% in NYISO and 8% in CAISO.

“Today’s acquisition continues Dynegy’s transformation that began in 2011, to build a long-term sustainable portfolio in key competitive markets,” Dynegy CEO Robert C. Flexon said. “This transaction is a compelling value for our shareholders as it is the right assets, in the right markets, at the right price and unlocks considerable synergy value by utilizing our proven integration model and corporate platform.”

Wall Street seemed to like the deal, with shares closing Friday at $9.77, a 17% jump from their open Thursday morning.

Flexon said joining with Energy Capital made sense, and, in fact, was the only way the deal would have come about. “Partnering with Energy Capital … allowed us to bring our strengths together to accomplish this acquisition that otherwise could not have been achieved by either party individually,” he said.

The partnership is a good fit for Energy Capital, too, according to company officials. “We feel this transaction represents an extremely attractive valuation point for Energy Capital to reenter the PJM, New England and ERCOT markets, which we have a long history of successfully investing in,” said Tyler Reeder, a partner at Energy Capital. “The joint venture will benefit tremendously from Dynegy’s strong operating capabilities, commercial risk management and focus on environmental compliance and safety.”

Dynegy said the joint venture borrowed $2.25 billion and put up about $1.185 billion in equity — $770 million by Dynegy and $415 million from Energy Capital — to finance the acquisition. Dynegy said it expects to close the purchase by the end of the year.

Energy Capital is taking a 15% stake in Dynegy. According to the terms of the acquisition, Energy Capital can exit the joint venture four years after closing, either by selling its interest to Dynegy or by engineering the sale of the entire joint venture.

Dynegy said it expects to realize about $90 million in savings per year by combining operations and maintenance functions and cutting corporate overhead.

It is just the latest in large-scale generation acquisitions by Dynegy. Since emerging from bankruptcy in 2011, it has more than tripled its generation portfolio. It doubled from 13 GW to 26 GW in its $6.25 billion purchase of plants from Duke Energy and Energy Capital, a deal approved by FERC last March.

Since 2014, it has boosted its gas generation to 63% of its portfolio, up from 46%, while reducing its coal share from 54% to 37%.

It also has changed its geographic mix, reducing its CAISO and MISO assets to a combined 26% from 65% in 2013.

ENGIE, previously GDF SUEZ, also sold 1.4 GW of pumped storage and conventional hydro assets in Massachusetts and Connecticut to the Public Sector Pension Investment Board, a Canadian pension fund, for $1.2 billion while acquiring OpTerra Energy Services.

ENGIE said the deals will reduce its debt by 5.5 billion euros and help it “reposition” the company in North America.

“With the announcement of this sale, ENGIE is heavily reducing its merchant generation activities and exiting coal-fired generation in the U.S. In North America, ENGIE will retain activities related to power generation (mainly contracted), energy efficiency services (through Cofely, Ecova and now OpTerra), retail electricity, small scale LNG and LNG infrastructures, including participation in the Cameron LNG liquefaction project currently under construction.”

February 26, 2016

DC PSC: Will OK Exelon-Pepco Deal for Additional Concessions

By Suzanne Herel, Michael Brooks and Ted Caddell

WASHINGTON — A split D.C. Public Service Commission said today it would approve Exelon’s $6.8 billion acquisition of Pepco Holdings Inc. in return for additional concessions beyond those negotiated by Mayor Muriel Bowser.

If Exelon and Pepco agree to a revised settlement supported by Commissioners Joanne Doddy Fort and Willie Phillips, the merger will be approved without further commission action, making Exelon the country’s largest utility by customer count.

DC PSC at the bench, ruling on Exelon-Pepco merger — DC PSC Commissioners at the bench (© RTO Insider)

“The commission’s order prescribes new provisions that we and the settling parties must carefully review to determine whether they are acceptable,” Exelon and Pepco said in a statement after the commission’s actions. “Once we have had a chance to study the order and confer with the settling parties, we will have more to say about what it means and our next steps.”

“Obviously we’re hopeful because they didn’t reject it. It appears they want it to happen,” said Pepco spokesman Vincent Morris, who was in the hearing room.

Two 2-1 Votes

In the first of two votes, the commission — which unanimously opposed the merger in August — voted 2-1 to reject a proposal brokered by Bowser’s administration as not in the public interest. Phillips dissented.

But Chairwoman Betty Ann Kane found herself alone in a second 2-1 vote, which said the deal could be salvaged with changes to the settlement.

That motion, offered by Fort, consisted of four concessions regarding the use of the customer investment fund, the development of a 5-MW solar generation facility at the Blue Plains Advanced Wastewater Treatment Plant and the role of Pepco in establishing public-purpose microgrids. (See DC PSC’s Counteroffer below.)

‘Hands Off Ratepayers’ Money’

The Bowser-brokered deal had earmarked money from the CIF for a handful of D.C. groups, including the Sustainable Energy Trust Fund, the District of Columbia Consumer and Regulatory Affairs Green Building Fund and the Low Income Home Energy Assistance Program.

The PSC’s counteroffer takes those funds, totaling $32.8 million, and places them into an escrow account to pay for projects to modernize the district’s energy system and for energy efficiency and energy conservation initiatives focused on housing for low- and limited-income residents. The PSC would have authority over the funds’ disbursement.

“This is a huge slap at the mayor’s office, saying ‘Keep your hands off ratepayers’ money,’” Anya Schoolman, head of D.C. Solar United Neighborhoods, which opposed the merger, told The Washington Post.

The settling parties have 14 days to accept the conditions.

“We will have to carefully review the commission’s order to determine if it meets our goals for ratepayers, especially residents,” Bowser said in a statement.

People’s Counsel Sandra Mattavous-Frye released a statement saying, “At this point, we are carefully reviewing the order to understand the alternative terms PSC put on the table to determine our next steps.”

Exelon Approval Expected

Both supporters and opponents of the deal said they expect Exelon to accept what appear to be modest additional concessions.

Dave Bonar, Delaware’s Public Advocate, said he was surprised at the commission’s initial rejection but was heartened to hear it offer a revised settlement.

“Hopefully the company will accept this, and we can all move on,” he said. “I’m sure [Exelon’s executives] are all in a room someplace, working on a response. Considering as much time and energy and expense that has been put into this, I think [Exelon] will say yes.”

Montgomery County (Md.) Council Vice President Roger Berliner, who has been a steadfast opponent to the merger, said he was “deeply disappointed” and expects the deal will come to pass.

“Oh, [Exelon] may gnash their teeth publicly, but they will take this deal. If I was them, I’d say ‘Oh, this is going to be a bitter pill,’ but nothing proposed is going to be the poison pill,” Berliner said. “There is nothing [in the proposed alternative settlement] that would make them walk away.”

Berliner noted that “questions will be raised” in the other states that approved the merger about some of the deal-sweeteners the district was offered by Exelon. Those agreements were struck under “most-favored nation” status, meaning in the end, all must receive equivalent benefits.

Robert Howatt, executive director of the Delaware Public Service Commission, said he fully expects Exelon and Pepco to accept the D.C. PSC’s proposal.

“This is about what I expected,” he said. He applauded the commission for proposing an alternative. “Assuming the D.C. approval holds, that basically means the merger will go through, and Delaware stands to realize more benefits.”

Fundamental Conflict

The initial vote rejecting the merger prompted cheers in the hearing room — and vertigo for investors.

Pepco shares, which opened the day at $26.50, fell 8.4% at 10:21 a.m. after the first vote was announced. But the stock rebounded just as quickly after the commission offered a way to salvage the deal. Exelon shares fell 1% on the initial news.

Pepco stock closed the day up 0.3%, while Exelon was down 0.78%.

Kane explained her second vote by saying there was no alternative to address the fundamental conflict between Exelon’s commitment to its merchant generation fleet and D.C.’s move toward renewable energy.

She added that there was “no evidence in the record that Pepco could not continue to perform adequately and reliably” without the merger, and that the commission had found PHI to be financially healthy.

“There are additional significant flaws in the [nonunanimous settlement agreement (NSA)] which are not addressed by the proposed alternative terms. In particular, the return of Pepco to an ownership structure that includes energy generation, supply, marketing and sales will result in an entanglement of management, financial health and decision-making. This is a fatal flaw which will adversely affect Pepco and create a diversion of focus that carries it in the opposite direction from D.C. law and policy,” she said.

“I dissent from the conclusion that if they accept these commitments that the acquisition would be in the public interest.”

Phillips voted reluctantly for Ford’s motion, saying he “had no hand in fashioning the conditions.”

“I believe the NSA as presented is in the public interest and should be approved. However, I do not have the majority in my favor,” he added. “I cast my vote today to allow my colleague to circulate proposed terms for the sole purpose of giving the settling parties an avenue to consummate their agreement, instead of resulting in an outright denial.”

GSA Supports Revised Deal

D.C.’s largest consumer of electricity, the federal government, had opposed the merger on grounds that it didn’t provide benefits for non-residential customers. Ford agreed that was a flaw and addressed it in the concessions.

After the votes, the General Services Administration released a statement saying, “We urge the settling parties to accept the new conditions proposed by the commission in response to our stated concerns.”

Opponents Outraged

Paula Carmody, Maryland People’s Counsel, said she was disappointed in the D.C. commission’s offer of a revised settlement. She was heartened, however, by Kane’s dissent.

“The dissent is right on, consistent with our dissent,” she said, noting that her office, along with some environmental and consumer advocacy groups, has an appeal pending with the Maryland Special Court of Appeals after the Maryland Circuit Court upheld the PSC decision last year.

D.C. Councilwoman Mary Cheh said the revisions offered by Fort are “immaterial. They’re a drop in the ocean in terms of what this deal means going forward in the long term in the District of Columbia. We have suffered a terrible loss today, and I’m especially disappointed in Commissioner Fort, who I thought was probably somebody who could look past the big money, the politics and the conflict of interest.”

Schoolman’s group also was disappointed. “Today’s decision is really a Band-Aid on a problem that can’t be fixed,” said D.C. Solar United Neighborhoods spokesman Ben Delman. “Fundamentally, this merger isn’t in the public’s interest and D.C.’s interest.”

Mike Tidwell, director of the Chesapeake Action Climate Network, decried the commission’s actions as a result of “crony politics.”

“While Mayor Bowser and Exelon lobbyists celebrate, D.C. residents will brace for big rate hikes and new roadblocks to clean energy,” he said in a statement. “Exelon wants this deal in order to milk D.C. ratepayers for maximum profits and prop up its own troubled bottom line. After a barrage of lobbying, ads and backroom dealing, Mayor Bowser, and now the PSC, have agreed to turn D.C. ratepayers over to Exelon without securing any substantive public benefit in return.”

Public Citizen called the proposed deal “irredeemable.”

“There are no superficial conditions or short-term fixes that will benefit D.C. consumers,” said spokeswoman Allison Fisher. “It is disappointing that the immense political pressure and the full flex of Exelon’s money and influence trumped district regulators’ mandate to protect D.C. utility customers.”

Two-Year Effort

Friday’s votes capped a two-year effort by the Chicago company to capture PHI’s $7 billion rate base. The addition of Pepco’s 3.3 million customers would boost Exelon to nearly 9.8 million ratepayers. In the process, Exelon spent an estimated $259 million and agreed to $78 million in public benefits.

Exelon offered to pay $27.25/share for Pepco, a 27% premium over the price before word of a possible merger leaked. The deal continues a shift by utilities to increase their regulated assets, with their dependable earnings, and decrease their reliance on volatile merchant generation.

D.C. was the only jurisdiction standing in the way of the merger, which had been approved by FERC and regulators in Delaware, Maryland, New Jersey and Virginia.

Deal Got Second Life

The PSC agreed to reopen the case in October and accepted the companies’ request for an expedited hearing schedule. (See DC PSC Rulings Give Exelon-PHI Merger a Shot in the Arm.)

Exelon CEO Christopher Crane had reiterated during an earnings call with analysts Feb. 3 that Exelon would walk away from the merger after March 4.

Under the deal rejected today, Exelon would have set aside $25 million to offset rate increases through March 2019 and immediately disburse $14 million to customers. (See Details of Exelon-DC Settlement.)

Exelon and PHI would have moved 100 jobs to the district and hired at least 102 union employees, while earmarking $5.2 million for workforce training.

Exelon also would have established the district as its co-headquarters with Chicago, relocating the primary offices of its chief financial officer and chief strategy officer. Also moving to D.C. from Philadelphia would have been the offices of Exelon Utilities.

Tens of thousands of individuals and organizations filed comments on the merger, more than any other issue in the PSC’s history of more than a century.

No Stranger to Mergers

Exelon was formed from the 2000 pairing of Philadelphia’s PECO Energy and Chicago’s Commonwealth Edison. It grew further with the 2012 acquisition of Baltimore’s Constellation Energy. The company has had its share of failed unions, dropping a merger effort with Public Service Enterprise Group in 2006 and having its overtures spurned by PPL in 1995 and NRG Energy in 2009.

As expected, its acquisition of Pepco sailed through reviews by FERC and the Justice Department — the acquisition brought Exelon no additional generation and thus raised no supply-side market power concerns — but had a tougher time in the states and D.C.

New Jersey regulators approved a settlement last February over the opposition of the state consumer advocate. The deal cleared the Maryland Public Service Commission by only a 3-2 vote last May.

DC PSC’s Counteroffer

But Fort then departed from Kane, saying the settlement negotiated by Mayor Muriel Bowser’s administration was “not fatally flawed” and could be fixed with additional concessions.

In a second 2-1 vote, Commissioner Willie Phillips joined Fort in offering a revised settlement including four changes that they said would make the deal acceptable without further commission action.

February 25, 2016

Zibelman: Guaranteed-Savings Rules Meant to Enable Markets

By William Opalka

New York Public Service Commission Chairwoman Audrey Zibelman said that consumer protections approved by regulators Tuesday are meant to combat deceptive practices and boost consumer confidence at a time when more complex energy products are entering the market.

“We found that consumers were paying higher prices by buying from a retailer than they would if they were buying from a utility,” she said in a conference call with media Wednesday.

The PSC held the unusual conference call a day after it approved new rules that drew fire from a national trade group for electric supply retailers. The regulations guarantee savings for retail and small commercial customers who switch to an alternative electric supplier. The rules also provide for tougher enforcement measures against those who prey on vulnerable or uniformed customers (15-M-0127, et al.).

In response, the Retail Energy Supply Association said the rules will only drive energy supply companies out of New York.

Retail Choice ‘Eliminated’?

“The New York State Public Service Commission took the unprecedented action of effectively eliminating retail choice for residential and small commercial customers in New York by substituting the commission’s judgment for that of consumers in determining what energy products offer value,” the group said in a statement.

“Under the commission’s order, retail suppliers would be forced to guarantee savings against a future utility price that, as a monthly variable price, is unknown,” RESA added.

Zibelman said the rules, which are meant to prevent overcharging, are part of the PSC’s plan to provide clear rules for companies and consumers under the Reforming the Energy Vision initiative.

“As we move forward with REV, it’s very important to us that the residential and mass market[s] are able to participate and acquire additional energy services … and in order to do that, we need a great deal of market confidence,” she said.

The commission said “retail energy markets are not providing sufficient competition or innovation to properly serve mass market consumers,” in contrast with markets for large commercial and industrial customers, which it said “are providing substantial benefits … including a wide range of energy-related value-added services that assist customers in managing their energy usage and bills.”

A year-long proceeding under the REV is determining what constitutes a value-added service and how it should be priced, Zibelman said.

The guaranteed-savings rule does not apply to customers opting to buy “green” power. Energy service companies (ESCOs) that offer premium-priced renewable energy will be required to obtain at least 30% from sources eligible under the commission’s Environmental Disclosure Labeling Program, including biomass, biogas, hydropower, solar and wind.

Abuses Cited

The commission is conducting an audit of the 200 ESCOs that operate in New York.

“We have zero tolerance for these unscrupulous companies, whose business model is to prey on ratepayers with promises of lower energy costs only to deliver skyrocketing bills,” Gov. Andrew Cuomo said in a statement. “These actions will root out these bad actors and protect New Yorkers from these unfair and dishonest tactics.”

The commission may impose a “one strike and you’re out” rule for behavior it decides is egregious. It also created a “do not knock” rule for door-to-door solicitations, similar to a “do not call” registry for telemarketers. Violators could be prohibited from operating in the state.

More than 20% of New York’s residential and small commercial customers currently receive energy from ESCOs. There are about 7 million residential electric customers and roughly 4.3 million residential natural gas customers, according to the PSC.

The regulators cited several examples of unacceptable conduct, including four companies in the Hudson Valley that charged more than double Central Hudson Gas & Electric’s price for electricity; a New York City company that charged more than triple Consolidated Edison’s rate for electricity; several ESCOs in upstate New York that charged more than double National Grid’s electric rate; and a company in the Finger Lakes region whose variable rate plan for electricity was eight times what Rochester Gas & Electric charged.

The commission also cited examples of companies falsely representing themselves as local utilities to trick customers into signing inflated contracts. At the Tuesday meeting, commissioners were particularly disturbed by reports of deceptive practices used against customers for whom English is a second language.

February 25, 2016

New Lifeline for FitzPatrick Nuclear Plant

By William Opalka

NEW YORK — In a last-ditch effort the save the James A. FitzPatrick nuclear plant, New York regulators are proposing financial incentives that could be available to the plant’s owners by July.

The New York Public Service Commission on Tuesday proposed to expedite subsidies to keep the plant operating while a more permanent incentive is crafted on the normal regulatory schedule (15-E-0302). A public comment period will last until May 2.

However, Entergy, FitzPatrick’s owner, again said the state’s plans were too uncertain and too late to save the plant on Lake Ontario. Entergy intends to close the plant on Jan. 27, 2017, when its current fueling cycle ends.

New York’s attempts to prop up its nuclear fleet exclude Entergy’s Indian Point nuclear plant, which Gov. Andrew Cuomo wants to close because of its proximity to New York City.

“If the state is focused on reducing CO₂ emissions, the Clean Energy Standard should apply to Indian Point, which is an essential generation resource critical to the state’s goal of reducing CO₂ emissions,” spokeswoman Tammy Holden told Syracuse.com.

Entergy Vice President of External Affairs Mike Twomey said in a statement that no definitive proposal from New York for FitzPatrick has been received since negotiations broke down last year.

“While we share the NYPSC’s concerns about the loss of nuclear generation, the financial implications of its efforts are too uncertain and this proposal comes too late to save FitzPatrick,” he said.

“Entergy met with New York state officials from the governor’s office and with the PSC repeatedly over the last few years to discuss how the current New York market structure disadvantages nuclear generation, how nuclear power’s carbon-free attributes could be recognized in the market and the financial challenges faced by the FitzPatrick plant. Unfortunately, these discussions resulted in no meaningful progress or policy changes by New York state.”

The PSC is already working to create a new tier of zero-emission credits (ZECs) that would be available to upstate nuclear generators next year. The proposed Clean Energy Standard is meant to help put New York on a path to 50% renewable generation by 2030. Nuclear is seen as a zero-carbon bridge to that plan. (See New York Would Require Nuclear Power Mandate, Subsidy.)

The process gained urgency after NYISO released an assessment finding that New York will be short of generation in 2019 with the closing of FitzPatrick and other plants. (See Fitzpatrick Closure Could Leave NY Generation Short.)

The PSC’s move to expedite subsidies to FitzPatrick “gives the commission the opportunity to act very decisively,” Chairwoman Audrey Zibelman said Tuesday. “We do not want to see a plant retire from [the lack] of a short-term solution.”

The expedited subsidy schedule would enable Entergy to refuel FitzPatrick if the company were to change its mind and continue operating the plant.

The PSC plan is modeled after existing renewable energy procurement practices used by the New York State Energy Research and Development Authority. NYSERDA purchases credits using money made available to it by the commission, including system benefits charges. The ZEC funds would also include other money collected from ratepayers.

As in renewable energy production, each ZEC would be paid for 1 MWh of energy produced. ZEC payments would be no more than the amount necessary above existing revenue streams to cover the ongoing costs of the facility for operations and maintenance, capital expenditures, taxes and other expenses. Sunk costs would be excluded.

Raj Addepalli, the PSC’s managing director of utility rates and service, offered a rough estimate of $15/MWh, using as a benchmark the “very complicated” formula just approved by the commission to keep the R.E. Ginna nuclear plant operating. (See NYPSC OKs Ginna Deal.)

That figure was derived from the payments to Ginna under its reliability support services agreement that will fluctuate from $49 to $52/MWh, minus the recent yearly average wholesale energy price of $35/MWh.

Ginna would be eligible to participate in any ZEC program after its RSSA expires on March 31, 2017.

February 25, 2016

Cayuga Coal Plant in Jeopardy

By William Opalka

NEW YORK — The future of one of New York’s last coal-fired generators is in jeopardy following state regulators’ rejection of a plan to repower it to natural gas and their approval of a transmission alternative (12-E-0577), (13-T-0235).

The 312-MW Cayuga generating plant will soon be one of two remaining coal generators in the state, plants that Gov. Andrew Cuomo recently vowed to close or have converted to natural gas by 2020.

But a ratepayer-funded repowering is off the table, the New York Public Service Commission ruled Tuesday. Chairwoman Audrey Zibelman said it would be “unfair” for ratepayers to be saddled with $102 million in additional costs to pay for the repowering. “It would not be in the public interest for New York State Electric and Gas ratepayers to be paying for that,” she said at the meeting. (See Cayuga Power Plant Repowering Opposed.)

She later told RTO Insider that plant owners “are free to repower the plant on their own nickel.”

In a separate order, the PSC signed off on Upstate New York Power Producers’ (UNYPP) sale of Cayuga and the Somerset coal plant outside Buffalo to Riesling Power, a unit of the Blackstone Group (15-E-0580). FERC approved the transaction in January. (See FERC Approves Sale of Doomed New York Coal Plants.)

Over UNYPP’s opposition, the commission also approved a request by distribution utilities NYSEG and Niagara Mohawk to build a two-phase, 14.5-mile project connecting two substations to address reliability concerns in western New York. The $23.3 million Auburn project would use existing rights of ways in Cayuga and Onondaga counties.

Phase 1 was filed as a proposal to build the 115-kV project, with Phase 2 proposed as a supplemental project by the companies to increase its capacity.

A recommended decision in November by an administrative law judge said, “it is uncontroverted that Phase 1 of the project should be constructed as soon as possible to remedy an immediate need to avoid reliability violations and service disruptions, if a major contingent event occurs.”

UNYPP objected to Phase 2, saying that part of the project is not needed if the plant continues to operate. According to the judge’s record decision, both phases are necessary even if the Cayuga units continue to sell into the NYISO market.

The plant is operating under a reliability support services agreement with NYSEG that runs through June 2017 (12-E-0400).

February 24, 2016

Supreme Court Offers Little Support to CPV, Md.

By Rich Heidorn Jr. and Michael Brooks

WASHINGTON — Lawyers for Maryland and Competitive Power Ventures got little support from Supreme Court justices during oral arguments in their federal-state jurisdiction case Wednesday.

The justices also interrogated Paul Clement, attorney for Talen Energy Marketing, which challenged Maryland’s deal for CPV’s combined cycle plant now under construction in Charles County as an improper subsidy.

But none gave any indication that they were inclined to reverse in their entirety lower court rulings voiding the contract. Rather, several justices seemed to be wrestling with whether to reject the contract based on “field preemption” — that it was an intrusion into exclusive federal jurisdiction — or a narrower “conflict” ruling — that it undermined FERC policy because its long-term pricing structure includes incentives different from those provided by PJM’s capacity auction. (Hughes v. Talen Energy Marketing (14-614), CPV Maryland v. Talen Energy Marketing (14-623))

In April 2012, the Maryland Public Service Commission ordered Baltimore Gas and Electric, Potomac Electric Power Co. (PEPCO) and Delmarva Power and Light to enter into a contract that guaranteed CPV — winner of a PSC competitive solicitation — an income stream so that it could finance the facility.

Under the “contract for differences,” CPV St. Charles’ revenues for the sale of 661 MW of energy and capacity would be compared to what the company would have received had the contract prices been controlling. If the contract prices were higher than the market prices, the three electric distribution companies would pay the difference to CPV; if market prices were higher than the contract, CPV would make payments to the EDCs.

The contract was challenged by Talen Energy’s predecessor, PPL, and other generators.

The U.S. District Court of Maryland ruled with PPL and other plaintiffs in saying the contract violated FERC jurisdiction over the wholesale electric market, a ruling upheld by the 4th Circuit Court of Appeals. The Supreme Court declined to hear two related cases in New Jersey decided by the 3rd Circuit.

Opponents said Maryland’s action would suppress capacity prices and that allowing the contract to stand would mean that eventually only subsidized units would enter the auction because those without support could not compete.

Chief Justice John Roberts picked up on this argument shortly after Maryland attorney Scott H. Strauss began speaking. “If it doesn’t suppress prices, why did Maryland do it?” he asked bluntly.

Strauss responded that the state saw a need for more generation than the PJM capacity market was providing. He and CPV attorney Clifton S. Elgarten argued that FERC had addressed price-suppression concerns with the minimum offer price rule (MOPR), which sets a floor on bids by new entrants.

Clement said FERC was siding with Talen in the dispute because “MOPR is not some kind of cure-all that is designed to ward off any price-suppressive bid. … It is a coarse screen to deal with the most egregious cost-reducing bids. It also depends on an estimate of cost.

“And here’s why it doesn’t really work for a bid like this,” Clement continued. “One of the most important costs is your cost of capital. Because [CPV is] getting a 20-year guarantee and no one else is … it destroys the ability to do an apples-to-apples comparison. And then the one thing we know for certain here is that this project ended up displacing a project that actually could be built based on the three-year forward price and without a 20-year contract.”

Strauss insisted Maryland ratepayers would not be providing a subsidy. “Maryland concluded that this was going to be a better deal for ratepayers,” he said. At a time when the generation mix is changing, he said, “the last thing the court should do is to limit state options.”

Boston Pacific, a consultant hired by the PSC, estimated the contract would save residential ratepayers $0.32 to $0.49 per month over the life of the 20-year contract. However, PSC General Counsel Robert Erwin told a FERC technical conference later: “No one knows whether at the end of 20 years Maryland ratepayers will pay CPV or if CPV will have paid Maryland ratepayers.”

FERC’s Position

After the 4th Circuit upheld the lower court’s ruling, CPV filed the contract with FERC, asking the commission to find it just and reasonable. The company had hoped this would nullify the courts’ findings, but FERC said it wouldn’t review a contract that had been ruled invalid.

Strauss and Elgarten, however, maintained that the commission would have found it just and reasonable.

“I don’t understand your position,” Justice Samuel Alito told Elgarten sharply. “You’re arguing that FERC does not think this adversely affects the [capacity] auction? Why has FERC filed a brief arguing the opposite? You’re arguing as if they’re not even here.”

Alito was referring to Ann O’Connell, an assistant to the Solicitor General who argued for FERC. O’Connell made clear the commission’s position in her opening argument.

“In the government’s view, the Maryland generator order is preempted because by requiring the state-selected generator to bid into and clear the PJM capacity auction in order to receive the guaranteed payments provided in the contract, the Maryland program directly intrudes on the federal auction, and it also interferes with the free-market mechanism that FERC has approved for setting capacity prices in that auction,” she said.

“I understood why they were making the MOPR argument at the early stages of this litigation before FERC filed the brief,” Clement said. “But I am a little mystified why, at this late stage of the game, after FERC filed three briefs saying that the MOPR is not sufficient to eliminate price-suppressive bids, that they’re still saying ‘We win because FERC’s on our side.’”

Skeptical Justices

The justices questioned whether the contract would have been legal had it not been tied to the auction and simply subsidized by Maryland.

“It does seem to me important what the kind of state action is,” Justice Elena Kagan told Clement. “If the state had just said ‘we need another power plant’ and had delivered a load of money to CPV and said ‘go build a power plant,’ you’re not saying that that would be preempted, are you?”

“It would depend,” Clement responded. “The way you just described it, [it is] not preempted.”

Roberts posed the same question to O’Connell.

“If the state just paid to build a power plant, that’s not directly targeting what’s happening in the PJM auction,” she said. “Sure, it’s adding supply to the market. But as long as the state is staying within its sphere under the Federal Power Act, that’s fine.”

Some of the justices confessed that they were confused by the details of the PJM capacity auction, something that Elgarten pointed out in his arguments.

“All of the conflict preemption issues should be addressed to FERC,” Elgarten said. “They are not really for this court — which is obviously having trouble conceptualizing how this all works — to resolve.”

This remark did not seem to faze the justices, however. “Truer words were never spoken than ‘I am not quite on top of how this thing works,’” Justice Stephen Breyer said later.

“I’m a little bit like Justice Breyer on this,” Justice Sonia Sotomayor said. “I’m not quite sure how everything is working.”