WILMINGTON, Del. — A problem statement and issue charge seeking to develop RTO-wide criteria for end-of-life transmission facilities kicked off a long and heated discussion before being approved by an 80% sector-weighted vote of the PJM Markets and Reliability Committee on Thursday.
Just two of 12 Transmission Owners voted in favor of the proposal, which won 90% or more support from each of the other sectors.
Ed Tatum of American Municipal Power presented the proposal, which AMP co-sponsored with Old Dominion Electric Cooperative, the PJM Industrial Customer Coalition, the PJM Public Power Coalition, LS Power and ITC Mid-Atlantic Development.
“Aging infrastructure is a primary driver of investment,” Tatum said, noting that $5.5 billion in replacement projects have been identified and more are expected. That’s because most of the grid was built 30 to 50 years ago, he said. “We’re concerned about the number of dollars being spent.”
Some transmission owners have criteria for end-of-life facilities, but others do not, treating them as supplemental projects, Tatum said. Supplemental projects are improvements not required for compliance with PJM system reliability, operational performance or economic criteria.
Uniform guidelines would improve how the local and regional planning process determines the need for replacement facilities, according to the problem statement.
The newly formed End of Life Task Force will be charged with developing “alternatives for providing more transparency and consistency in the review of end-of-life projects, including the development of PJM end-of-life-criteria.” It will report to the MRC.
The majority of transmission owners opposed the plan, saying the problem statement prescribed a solution, that such guidelines should be voluntary and that it was illegally treading on the rights of transmission owners to maintain their own equipment. They called for an education session before bringing the issue back for a vote and said any such task force should report to the Planning Committee.
Tatum said the sponsors rejected a proposed revision by the TOs to make the guidelines voluntary because “making it voluntary is the status quo.”
And, he said, “Based on the conversations I’ve had with a number of you, I think that the definition you all may be using for maintenance is a bit expansive. My water heater blew last week and I didn’t maintain it, I replaced it.”
Speaking on behalf of the TOs, Chip Richardson of PPL said, “The TOs have expressed some concern that the very nature of this problem statement would violate their rights. … We think that the MRC needs to understand that this is a task to do something. This is not a problem statement or opportunity to do something. We’re implementing a solution that this group has chosen.”
Richardson said the TOs would have supported the issue if the guidelines were voluntary. He called for an education session to address three issues: to whom the task force should report; the rights of the TOs and PJM under the Consolidated Transmission Owners Agreement; and the implications of such criteria on cost allocations for projects in the Regional Transmission Expansion Plan.
“We’re launching a solution but are not well informed of what the implications are,” he said.
Tatum said it was not the intent of the sponsors to infringe upon TOs’ rights and that the task force would not be considering the issue of cost allocation. While the problem statement suggests “criteria and guidelines” would improve transparency, the task force would consider other approaches that accomplish the goal, he said.
PJM Vice President of Planning Steve Herling said transparency was the RTO’s primary concern as well, and to that end it could support the problem statement and issue charge.
“There’s an expectation as we start our planning process … that there is the opportunity for full vetting,” he said. “As long as [the criteria] are out there and people can see them and we have the opportunity to vet the issues and solutions, I think we’re OK with this moving forward. I’m less concerned with who the group reports to. The same people are going to have to be on the task force regardless.”
Jason Barker of Exelon cautioned that the task force’s work could embroil PJM in litigation if it treads on TOs’ rights under the CTOA.
“This is unquestionably a discussion about cost allocation. The overture here is that that’s not an intent … but it naturally follows from the discussion we’re having. Let’s acknowledge the elephant in the room,” he said, adding, “With regard to the committee reporting, it’s interesting that the sponsors want to put this at the MRC. We have a PC that’s described in our Operating Agreement: ‘The [Planning Committee] shall advise the [Markets and Reliability Committee and PJM] on matters pertaining to system reliability … and planning strategies and policies.’ That’s exactly what we’re talking about here. This is exactly in the PC’s wheelhouse, and there’s really no reason to diverge from it aside from politics.”
Gloria Godson of Pepco Holdings Inc. said the initiative “may be a back door way of imposing a risk profile on the TOs.”
A TO’s asset management practices result in a certain life expectancy for each asset and when the asset needs to be replaced, she explained after the meeting. “If the PJM stakeholders become the determinants of when and how transmission assets will be replaced, [they] will effectively be imposing their risk profile on the TOs and usurping this key corporate decision-making of the company owning the asset,” she said. “Who is going to bear the risk for these assets going forward?”
Dan Griffiths, executive director of the Consumer Advocates for the PJM States, said that no one in his group opposed it.
Jim Jablonski, of the Public Power Association of New Jersey, said he would welcome more transparency in the rates that consumers are charged.
One municipality has seen its annual bill rise over four or five years from $300,000 to $1.5 million, he said. “I get questions about why this is happening,” he said. “I need to be able to explain.”
Co-sponsor Susan Bruce, representing industrial customers, said, “Customers have seen their bills increase on the transmission side like never before.”
The task force’s work, she said, “is meant to be done in a way that is respectful of TOs’ rights and those who end up paying” for transmission costs.
WASHINGTON — A parade of witnesses implored the U.S. Commodity Futures Trading Commission Thursday to reverse its position in a case that they say could undermine the broad exemptions the commission granted RTOs and ISOs in 2013.
At issue is the CFTC’s draft order on a request from SPP seeking the same exemptions from the Commodity Exchange Act (CEA) that the commission granted the six other RTOs and ISOs.
CFTC Chairman Timothy G. Massad (seated), Commissioner Sharon Y. Bowen (L), former Commissioner Mark P. Wetjen (center), Commissioner J. Christopher Giancarlo (R). Wetjen resigned last August, leaving the five-member panel two members short. Source: CFTC
The CFTC’s 2013 order exempted electricity transactions subject to FERC-approved tariffs from most provisions of the CEA while retaining its general anti-fraud and anti-manipulation authority.
SPP was the only grid operator not party to the 2013 order because its day-ahead market was not fully implemented until March 2014. Unlike the 2013 order, however, the draft SPP order includes a preamble stating the CFTC’s intent to preserve “private rights of action” under Section 22 of the CEA.
Representatives of the ISO/RTO Council (IRC), the Public Utility Commission of Texas, the Edison Electric Institute and energy management firm ACES made their case against the preamble language in a hearing of the CFTC’s Energy and Environmental Markets Advisory Committee. No witnesses spoke in favor of the added language.
Undoing the Balance
The preamble could undo “the careful balance of public interests that Congress struck when it directed coordination between the CFTC and the FERC to avoid ‘duplicative regulation’” in the 2010 Dodd-Frank Act, the IRC said in a Feb. 23 letter to the commission.
Texas PUC Commissioner Kenneth W. Anderson Jr. told the committee that FERC and the PUCT are more “efficient” than private legal proceedings in resolving disputes. Allowing private actions, he said, would result in “collateral attacks on FERC- and PUCT-authorized valid market rules, undermining the efficient operation and regulation of electricity markets.”
“This provides an end-run around the absence of a private right of action” in the Federal Power Act and Texas Public Utility Regulatory Act, Anderson said.
Uncertainty
Lopa Parikh, EEI
“Even if the commission decides to only apply this to the SPP RTO … that still creates a lot of uncertainty for EEI members, primarily because most EEI members operate in more than one RTO,” said Lopa Parikh, EEI’s senior director of federal regulatory affairs.
She noted that the commission did not address whether products such as financial transmission rights and virtual trades are subject to the CEA. “And so now to have the possibility of a number of district courts and lower-level courts opining on this decision further creates regulatory uncertainty,” Parikh said.
Administration of FTRs “would no longer be clearly linked to the underlying physical attributes of the grid, as it inevitably would be argued that FERC was divested of jurisdiction over these products due to the ‘exclusive jurisdiction’ provisions of the CEA,” the IRC said. “Such an outcome would create, for the first time, a ‘regulatory gap’ between the allocation and trading of the product itself and its use in addressing real-time congestion on the grid, a matter clearly within FERC’s jurisdiction.”
Jeff Walker (ACES)
Jeff Walker, senior vice president and chief risk officer for ACES, said there was no evidence for a “public interest determination” to add the private rights language to the SPP order.
“Nothing indicates the RTO markets … are opaque pools of interconnected financial entity transactions or instruments,” said Walker, whose company has load-serving entities in five of the seven ISOs and RTOs.
Walker described a scenario involving a generation owner that purchases hedges before taking an outage to repair tube leaks in its boiler.
“Coincidentally, local RTO prices spike,” causing losses for another market participant that held a short physical position and wasn’t expecting the spike. “What does it do? It files a Section 22 action against the generation owner for market manipulation in one of the 100 or so federal district courts.
“Section 22 does not require the plaintiff to prove that the generation owner was not acting in a prudent utility practice manner when scheduling the repair outage,” Walker said. “That is legal uncertainty.”
Separate Rulemaking?
Several witnesses said if the CFTC addresses the private rights issue, it should be done in a separate rulemaking.
“Having worked a lot on these issues in the years right after the passage of Dodd-Frank, there were times when the relations between the CFTC and the FERC were rocky. I think we’ve come into a period of relative calm more recently, which I think those in the industry have welcomed,” said Sue Kelly, president of the American Public Power Association.
“There’s no one from FERC here, so let me just say for them, this could really ruffle some feathers,” she continued. “So I think if you are going to tread into this area, you need to do so very carefully and respectfully of the two agencies’ jurisdiction and have a real full airing of this issue.”
Commissioners Appear Split
All three of the current CFTC commissioners began their terms in 2014, after the 2013 RTO exemption order.
The draft SPP order, published last May, said, “It would be highly unusual for the commission to reserve to itself the power to pursue claims for fraud and manipulation … while at the same time denying private rights of action and damages remedies for the same violations.
“Moreover, if the commission intended to take such a differentiated approach … the RTO–ISO order would have included a discussion or analysis of the reasons therefore,” it continued. “Thus, the commission did not intend to create such a limitation, and believes that the RTO–ISO order does not prevent private claims for fraud or manipulation under the act.”
Commissioner J. Christopher Giancarlo expressed concern over the private rights language in his opening statement. “Commenters have warned that permitting private suits will undermine regulatory certainty and could result in collateral attacks on the finely calibrated electricity market structure that state and federal regulators have enacted,” he said, citing a CEA Section 22 suit by Aspire Commodities and Raiden Commodities against GDF-Suez Energy North America for allegedly manipulating electricity prices in ERCOT. A district court judge dismissed the case in February 2015 based on CFTC’s exemption order, a decision upheld by the 5th Circuit of Appeals last week.
CFTC Chairman Timothy Massad
But Chairman Timothy Massad indicated less sympathy for the witnesses’ concerns over litigation to which regulators are not a party and the risk of conflicting district court rulings. “We face that every day … so I don’t think that issue is really unique here,” he said.
“We certainly want to balance the value of regulatory certainty with the need to make sure there is adequate recourse for private actors. The CEA does provide for private rights of action,” he added.
He also indicated no interest in starting a separate rulemaking on the issue, saying, “I think we have taken a lot of public comments on this in the context of the SPP order.”
Commissioner Sharon Y. Bowen was noncommittal, saying only that she wanted to hear market participants’ concerns.
Michigan Attorney General Bill Schuette is asking the U.S. Supreme Court to enforce its ruling last year and order EPA to put its Mercury and Air Toxics Standards on hold.
Schuette asked the court to issue a stay on the four-year-old mercury rule, which he said it invalidated in its Michigan v. EPA decision last year. In the decision, the court supported Michigan’s position that the mercury rule did not sufficiently consider the adverse economic impact the standard would impose. “We are simply asking the court to enforce its ruling and require the EPA to follow the law like everyone else,” Schuette wrote in a statement.
According to Schuette, the D.C. Circuit Court of Appeals “has failed to vacate the unauthorized rule, leaving it in place with the same force of law despite the Supreme Court’s rejection of it.” His office filed the request last week with Chief Justice John Roberts.
FERC Chairman Norman Bay last week said energy storage has the potential to become a “game changer” when it comes to economic benefit and system reliability. Bay said the commission will need to manage ways to bring the new technology into the nation’s grid.
“Developments in storage have the potential to bring economic and reliability benefits to consumers, perhaps even to be game changers,” he told an audience at the IHS CERAWeek conference in Houston. “Everybody recognizes costs will decline, but the question is how much and how soon.”
The federal government is due to release a new rule meant to prevent offshore wellhead blowouts such as the one that caused the 2010 Deepwater Horizon disaster in the Gulf of Mexico.
The Interior Department’s chief of staff, Tommy Beaudreau, told a Columbia University audience that a new rule has been in the works since the disaster. “We’ve been working ever since to try to develop new standards and new rules with respect to well control, both with respect to that critical piece of equipment, the blowout preventer,” he said.
Blowout preventers are designed to pinch shut well piping near the head in the event of a blowout. The Deepwater Horizon blowout preventer did not work.
Presidential contender Donald Trump last week shared a proposal if he gets elected: scrap EPA.
“Environmental protection — we waste all of this money,” he said during Thursday’s Republican debate. “We’re going to bring that back to the states. We are going to cut many of the agencies, we will balance our budget and we will be dynamic again.”
While he was short on details, such as who or what would oversee environmental policy in the absence of the agency, he said eliminating it would save $8 billion, its entire annual budget.
Lamar Alexander Calls for End to Nuclear Waste Stalemate
Alexander
Tennessee Sen. Lamar Alexander, speaking at a Senate Appropriations Subcommittee, said it is critical for the country to finally develop and execute a program to handle nuclear waste and called for the moribund Yucca Mountain project to be restarted.
“At a time when everyone wants to produce more carbon-free electricity, it makes no sense whatsoever to undermine this source of power by continuing this logjam and not opening Yucca Mountain to dispose of used nuclear fuel,” the Republican said during a subcommittee hearing on the Obama administration’s proposed budget for the Nuclear Regulatory Commission.
He said he would call for a pilot program to designate consolidated storage sites for used nuclear fuel until a permanent repository is developed.
Ole Miss Researchers Get $3M to Investigate Spent Fuel Options
The Department of Energy has awarded $3 million to finance the research of two University of Mississippi professors trying to find new ways to monitor spent nuclear fuel that is sealed up in dry-cask storage. Josh Gladden and Joe Mobley, physics professors, are working on ways to use ultrasonic and acoustic methods to monitor spent fuel.
Their methods could make it possible to ensure the fuel is properly stored, without having to open the storage containers. It is necessary to monitor both the fuel inside the casks, and the casks themselves, to make sure they are intact.
“Since quite a few of these casks are nearing the end of their engineered lifetime, the inspection requirement must be fulfilled in the next five years or so,” Gladden said.
Former NRC Commissioner Calls for Change in Reactor Licensing
Former Nuclear Regulatory Commissioner Jeffrey S. Merrifield said it is time to reconsider licensing requirements for advanced nuclear reactors, saying a new model is needed to help drive private sector development.
“Deployment of this new generation of reactors will require a new model, one that is more dynamic and capable of forming private-public partnership in support of private sector innovation,” he told attendees of a technical summit at the Oak Ridge National Laboratory.
“The current framework of U.S. government policy, legislation, regulation and requirements, research and development support, and fee-based licensing is more aligned with past development efforts,” he said. “This is particularly true of the U.S. Nuclear Regulatory Commission licensing process, which presents one of the largest risk factors confronting private developers of advanced reactors.”
The Arkansas chapter of the Sierra Club released the “2016 Arkansas Clean Air Solution,” which calls on Entergy to shut down Arkansas’ two largest power plants, Independence and White Bluff, by 2027.
Sierra Club said the plan would help the state meet federal clean air safeguards under the Regional Haze Rule. EPA is set to finalize a regional haze plan for Arkansas in August. Under the agency’s proposal, the two plants will be required to significantly reduce emissions of sulfur dioxide.
Entergy has said it plans to stop burning coal at White Bluff by 2028.
South Mississippi Electric Cooperative and Delta Electric Power Association say they are ready to begin generating electricity using a 100-kW solar system recently installed on the eastern edge of the Mississippi Delta. Atlanta-based Hannah Solar installed the 360 panels, which are situated behind Delta Electric’s offices in Greenwood, Miss.
David O’Bryan, Delta Electric’s general manager, said an official commissioning ceremony is scheduled in late March. He said customers in surveys called for more solar plants.
South Mississippi Electric is currently constructing four other similar solar plants in Mississippi, with the goal of partnering with Origis Energy USA to build a large-scale solar facility in southern Mississippi, capable of powering 10,000 homes.
PSEG Solar Source, PSEG’s merchant solar generation arm, bought a 36.3-MW solar project in Colorado from juwi Inc. The $54 million acquisition brings the company’s total solar portfolio to 16 utility-scale projects.
The PSEG Larimer Solar Energy Center is about 25 miles north of Fort Collins, Colo., and has a 25-year power purchase agreement with the Platte River Power Authority. The project was originally called the Rawhide Flats Solar facility. It was built on a 290-acre site own by PRPA. Construction is scheduled to be completed by the end of this year.
“We are delighted to be a part of an initiative that contributes to growing Colorado’s clean energy supply,” said Diana Drysdale, president of PSEG Solar Source.
Louisville Gas & Electric and Kentucky Utilities have offered a limited number of free smart meters for residential and small business customers. The new meters are linked to a website that allows customers to monitor their electricity usage in 15-minute increments. The PPL-owned utilities say the meters will allow customers to better understand their electric consumption.
The program is limited to the first 5,000 LG&E and 5,000 KU customers who enroll. The utilities said they will track participation and interest levels this year to determine if the program should be continued.
The smart meter installation program is separate from KU’s demand conservation program, which uses a device attached to central air conditioning and heat pumps to temporarily interrupt service on peak days to reduce system load.
Dairyland, Xcel Announce Plans to Double Wisconsin’s Solar
Dairyland Power Cooperative and Xcel Energy have announced plans that will add almost 22 MW of solar capacity in Wisconsin, doubling the amount of utility-scale solar generation in the state.
Dairyland is buying the output from 12 solar arrays with a combined capacity of almost 19 MW. Xcel has entered into contracts to purchase the output of solar gardens in the western part of the state for about 3 MW.
Xcel is adding solar throughout the Midwest and said it plans to have more than 250 MW of solar in Minnesota by the end of this year.
Once the biggest natural gas driller in Ohio, Chesapeake Energy no longer has any rigs operating in the state. The nation’s second-largest gas producer, which has been shedding assets and cutting costs in the face of low energy prices, announced fourth-quarter losses of $2.2 billion, compared to $639 million in profits the year before.
While many oil and gas drilling companies are scaling back, few have shown such a drastic reduction in Ohio’s Utica shale fields as Chesapeake. Two years ago, the Oklahoma City company had 64 rigs operating across the country. It now plans to operate four to seven nationwide.
Exelon Wind Turbine Collapses During Snowstorm in Michigan
A wind turbine at an Exelon wind farm in Huron County, Mich., collapsed during a snowstorm last week but caused no injuries or damage, county and company officials said.
The turbine toppled about 5 a.m. on Thursday during a period of high winds and heavy snow. The closest residence is about 2,200 feet from the fallen turbine and mast. Company officials said an investigation is underway to determine the cause.
Peter Sena, who has held a number of executive and operational positions at FirstEnergy and NextEra Energy, has been named president of PSEG Nuclear. He will report to PSEG Power President William Levis.
Sena comes to PSEG from NextEra, where he was senior vice president of operations and chief operations officer. Before that, he spent 15 years with FirstEnergy’s nuclear generation organization.
He is a U.S. Navy veteran and holds a degree in fuel science from Pennylvania State University. He has served as a member of Penn State’s Nuclear Engineering Advisory Board and currently serves on Auburn University’s advisory board.
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.
ERCOT has distributed generation resources in more than 7,600 locations but its congestion revenue rights software can only handle about 600 resource nodes at a time. As a result, DG installations receive load zone pricing when injecting, regardless of their location within a load zone.
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.
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.
Pilgrim nuclear plant (Source: Entergy)
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. (SeeEntergy Closing Pilgrim Nuclear Power Station.)
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.
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.”
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.
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.”
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.
“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.
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
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.
Speaking on behalf of the TOs, Chip Richardson of PPL said, “The TOs have expressed some concern that the very nature of this problem statement would violate their rights. … We think that the MRC needs to understand that this is a task to do something. This is not a problem statement or opportunity to do something. We’re implementing a solution that this group has chosen.”
The Department of Energy has awarded $3 million to finance the research of two University of Mississippi professors trying to find new ways to monitor spent nuclear fuel that is sealed up in dry-cask storage. Josh Gladden and Joe Mobley, physics professors, are working on ways to use ultrasonic and acoustic methods to monitor spent fuel.
