Page 1718 – RTO Insider

October 17, 2015

Opposing Parties: Require a New Merger Application

By Suzanne Herel

The D.C. Public Service Commission should not reopen the record to consider a newly reached settlement in Exelon’s proposed $6.8 billion takeover of Pepco Holdings Inc., parties opposed to the deal said in a filing Friday.

PSC rules prohibit settlements to be submitted after a final decision, the group said, referring to the commission’s Aug. 25 rejection of the merger as not in the public interest. The group argued that the commission should require the companies to file a new application.

The group represents DC Solar United Neighborhoods, Grid 2.0 Working Group, Mid-Atlantic Renewable Energy Coalition and Maryland DC Virginia Solar Energy Industries Association.

The settlement, brokered by Mayor Muriel Bowser’s administration, was filed Oct. 6 in an attempt to persuade the commissioners to approve the deal, which has been approved by FERC, Delaware, Maryland, New Jersey and Virginia. (See Mayor’s Settlement Puts DC PSC on the Spot in Exelon-Pepco Deal.)

Regardless of the agreement, the filing said, “the public continues to share the commission’s concern that the ‘potential conflicts of interest inherent in Pepco’s role and its parent company’s policy positions and interests might inhibit our local distribution company from moving forward to embrace a cleaner and greener environment.’”

The prevailing concern involves Exelon’s commitment to its generation assets, in particular to its partly struggling nuclear fleet.

To shore up that point, the filing includes more than 800 emails from district residents opposing the merger, most using a template letter saying in part, “I am dismayed by the D.C. government’s behind-the-scenes Exelon settlement. Their secretive process took place over the objection of the majority of D.C. ratepayers. … Your unanimous ruling against the merger, and the thorough process that preceded it, restored faith in the district’s democratic institutions. Anything less than a full process now would deprive D.C. residents of our due process rights.”

The petitioners acknowledge that the commission has the right to waive its own rules, but they advised it not do so because of the unprecedented interest the case has drawn — more than 3,000 commenters, the most in the agency’s more than century-old existence.

“Many of the interested customers or groups have justifiably relied on the formal parties to present and champion their positions, including particularly the District of Columbia government and the Office of the People’s Counsel,” the filing said. “Now, both the district government and OPC have acceded to the terms that the joint applicants offered, so they no longer reliably represent the views of residential customers or groups that are unwilling to concede to Exelon.

“The realignment of some parties with Exelon and Pepco effectively muffles the public’s voice in any proceeding that merely reopens the existing case and that does not give other interested individuals or organizations a full opportunity to participate as parties.”

They allege that reopening the case would set a dangerous precedent for future applicants seeking to negotiate a settlement only after the commission has highlighted the deficiencies in their filing.

Friday was the deadline to submit comments regarding the joint applicants’ request to reopen the case.

Also filing opposition was D.C. Public Power, which at the same time submitted its intent to buy Pepco’s district assets and requested to become an intervenor. (See Group Proposes to Buy Pepco’s DC Assets, Form Publicly Owned Utility; Exelon Would Keep Md., Del., NJ PHI Units.)

In addition, the Ward 3 Democratic Committee submitted a filing saying that the settlement amounts to a new proposal and should be treated as such under a new application.

October 16, 2015

Group Proposes to Buy Pepco’s DC Assets

By Rich Heidorn Jr. and Suzanne Herel

WASHINGTON — A newly formed advocacy group on Friday filed its intent to acquire the district assets of Pepco Holdings Inc. and transform it into a not-for-profit utility that it said will generate about $1 billion in savings over the next 20 years.

Not having to pay federal taxes or dividends to shareholders would “unlock” $150 million a year in savings — or about $60 million after subtracting debt — that could be spent on reliability, improvements and rate reductions, said Michael Siegel one of D.C. Public Power’s four board members, in announcing the proposal Friday morning at the National Press Club.

“Additional benefits will accrue by maintaining local ownership and presence as well as additional economic activity,” added board member John Chelen.

In its filing, DCPP also objected to the Public Service Commission reopening the record for Exelon’s proposed $6.8 billion acquisition of PHI and requested late intervenor status because the group was formed April 30, after the filing deadline for joining in the case. Other parties also objected to reopening the record. (See Opposing Parties to DC PSC: Require a New Exelon-Pepco Merger Application.)

‘Strong Interest’ from Lenders

Chelen said the group had received “strong interest” from “recognized investment banks” in financing the deal, which would occur after Exelon consummates the purchase.

The group said the utility’s debt would be “an extremely secure and attractive investment” because of the district’s strong economy and low interest rates for alternative investments.

It said PHI D.C.’s book value was $1.4 billion as of March 2013 — though shareholders would certainly seek a higher price in any sale.

Chelen said the group already had approached Exelon with its interest but was turned down.

Exelon, Pepco: No Deal

In a letter included in the filing, Exelon and PHI attorney Mark Director wrote that the concept “raises many complex legal, financial, regulatory, operational and commercial considerations. It would require substantial time to evaluate those complexities, and that would complicate and delay, rather than simplify and streamline, matters to be considered by the D.C. PSC and would require approvals from other regulatory authorities.

“As Exelon and PHI remain committed to completing their merger as promptly as possible, the companies do not believe it would be productive to have further conversations about your proposal.”

Said Chelen, “DCPP had, in fact, structured its proposal to be as uncomplicated as possible with the intent of facilitating Exelon’s and PHI’s ability to complete their merger. Perhaps the real reason is they were able to attract a better deal for them from the mayor and D.C. officials.”

That settlement was presented Oct. 6 to the PSC, which denied the merger as filed on Aug. 25 as not being in the public interest. (See Mayor’s Settlement Puts DC PSC on the Spot in Exelon-Pepco Deal.) The proposal envisions a non-profit board hiring an experienced utility operator to run day-to-day operations, similar to Long Island Power Authority’s contract with Public Service Enterprise Group.

Exelon referred a request for comment to Pepco. A PHI spokeswoman said Thursday that a district-only system would be “expensive and inefficient.”

Myra Oppel, regional communications vice president at PHI, said the group’s proposal “raises many complex legal, financial, regulatory, operational, commercial and customer considerations that the group has not begun to address.”

The group said it had discussed its proposal with numerous city leaders but not directly with Mayor Muriel Bowser. “Some people are wildly enthusiastic,” said Chelen. “Other people are guarded.”

Public Power in Cities

Of the about 2,200 power providers in the U.S., about 2,000 are public power, including Seattle, Los Angeles, Sacramento, Austin, Jacksonville and Cleveland. Only 200 are investor-owned utilities, though they tend to be in bigger cities.

The group said public power agencies similar to that of Chattanooga, Tenn. — a city about 60% the size of the district — have “extremely high capital productivity,” unlike IOUs, whose profits can increase with higher spending.

“From our point of view, the [Exelon-Pepco] deal relies on an extremely complex, vague and opaque non-unanimous settlement agreement [NSA] that will be a nightmare to monitor and enforce,” Chelen said.

“What is most disturbing is it calls upon divestiture that is the severance of Pepco D.C.-based assets as an ultimate means to ensure compliance,” he said. “The inclusion of this provision affirms that divestiture is the best method to secure the public interest. The NSA severance clause amounts to exclusive acknowledgment that the NSA is a risky deal for the district.”

October 15, 2015

DC Public Power to Propose Alternative to Exelon-Pepco Merger

[EDITOR’S NOTE: See updated story on D.C. Public Power’s filing Friday.]

By Suzanne Herel

A D.C. advocacy group on Friday will release details of a proposed alternative to the Exelon-Pepco Holdings Inc. merger that it says would provide up to $1 billion in benefits to the district over the next 20 years.

In a Sept. 28 filing with the D.C. Public Service Commission, D.C. Public Power, which advocates energy independence for district ratepayers, said that it planned to seek “an agreement with Exelon to acquire between 51 to 100% of PHI’s D.C.-based assets at an agreed-upon price and terms.”

The nonprofit group called its plan “workable and feasible” and said it would “meet all of the D.C. PSC’s concerns with the proposed merger.”

DCPP said a transaction would occur as soon as possible and would provide “appropriate assurances sufficient to satisfy the D.C. PSC, intervenors and elected officials that the acquisition is in the public interest.”

The group said it had shared its proposal with Exelon and the D.C. government, but had “not yet engaged the cooperation of the merging parties.”

Exelon referred a request for comment to Pepco. A PHI spokeswoman said Thursday that a District-only system would be “expensive and inefficient.”

“PHI and Exelon, along with the District government, the Office of the People’s Counsel, and other parties have filed a proposal with the Public Service Commission of the District of Columbia that is reasonable and achievable and delivers significant benefits to D.C. residents and the community. We believe that it is in the best interests of our customers.”

DCPP plans to outline the details at 10 a.m. at the National Press Club in D.C. A statement announcing the press conference claimed the plan would produce a net present value of $1 billion in benefits over 20 years.

Friday marks the deadline for public comment to be filed with the PSC in response to a request by Exelon and Mayor Muriel Bowser’s administration to reopen the record for the proposed $6.8 billion acquisition of Pepco. As of Thursday afternoon, no comments had been posted. Anya Schoolman, head of solar advocacy group DC SUN, which did not sign on to a new proposed settlement brokered by Bowser, told The Washington Post that her group would be filing comments in opposition on Friday.

The D.C. PSC rejected the proposed deal Aug. 25, saying it was not in the public interest, including its effects on ratepayers, market competition and preservation of natural resources and the environment. (See DC Halts Exelon’s Acquisition of Pepco Holdings; Pepco Stock Tumbles.)

Bowser, who hailed the rejection, entered into negotiations with the companies and several interveners who also had opposed the merger, most notably Attorney General Karl Racine and People’s Counsel Sandra Mattavous-Frye. They released a settlement Oct. 6 designed to assuage the PSC’s concern and convince it to reconsider. (See Mayor’s Settlement Puts DC PSC on the Spot in Exelon-Pepco Deal.)

Among the concessions, Exelon would provide a Customer Investment Fund worth $72.8 million, including $25.6 million to offset the effect of any rate increases over the next four years; one-time funding of various renewable and sustainable energy efforts; and a commitment to buy 100 MW of wind power within PJM. (See Details of Exelon-DC Settlement.)

Exelon, based in Chicago, also would co-headquarter its offices in the district.

An initially approved D.C. Council plan to study the feasibility of turning Potomac Electric Power Co. into a city-owned utility was killed in June after Pepco lobbyists communicated with seven councilmembers or their aides. That majority amended the agreement to reallocate the $250,000 to study “emerging alternatives” for energy and energy efficiency. (See Pepco’s Influence Runs Deep.)

October 14, 2015

FERC Jurisdiction over DR in Peril as Supreme Court Splits

By Rich Heidorn Jr.

WASHINGTON — The Supreme Court’s liberal wing indicated support Wednesday for FERC’s jurisdiction over demand response, but the commission faced harsh questions from conservatives Antonin Scalia and Chief Justice John Roberts and swing vote Anthony Kennedy.

Kennedy and Scalia challenged Solicitor General Donald Verrilli’s arguments on behalf of FERC, with Kennedy referring to them as “circular” logic and Scalia expressing opposition to the commission’s “fiddling around” with retail rates.

Justices Stephen Breyer, Sonia Sotomayor and Elena Kagan were equally critical of attorney Paul Clement, representing the Electric Power Supply Association. Sotomayor interrupted Clement early in his argument, demanding “where is that written down?” after the attorney categorized FERC’s intent as trying to reduce retail demand.

EPSA filed the lawsuit challenging FERC Order 745, which set rules for compensating DR in RTO energy markets. In May 2014, the D.C. Circuit Court of Appeals vacated the order, saying DR is a retail product and thus subject to state, not federal, jurisdiction.

Conservative Justice Clarence Thomas and liberal Ruth Bader Ginsburg were silent during the one-hour argument, which drew numerous RTO stakeholders as observers.

If the justices side with their normal allies, the court could end up deadlocked 4-4, meaning the D.C. Circuit ruling would stand. Justice Samuel Alito has recused himself in the case.

“If the court does cast a four-to-four vote at its private conference on Friday, and decides that [is] the most that it can do, that result would be announced promptly, perhaps as early as next Monday,” SCOTUS Blog predicted.

Breyer’s Wife Sells Stock

Bloomberg reported that Alito recused himself because he owns stock in Johnson Controls, which owns EnergyConnect, a DR provider that has filed a brief with the court. Bloomberg also reported that Breyer’s wife owned stock in the same company, which it said Breyer was unaware of when he heard the case. She sold her 750 shares for about $33,000 the following day after an inquiry by a Bloomberg reporter.

FERC sought Supreme Court review because of the growing importance of DR. While the D.C. Circuit ruling explicitly addressed only DR participation in wholesale energy markets, FERC said the ruling also threatened its participation in wholesale capacity markets.

That could create upheaval in markets such as PJM, where capacity auctions represent about 95% of total DR revenue. After some uncertainty, PJM decided to include DR in the 2018/19 Base Residual Auction in August.

The Supreme Court agreed in May to reconsider the D.C. Circuit ruling on two questions:

Whether FERC reasonably concluded that it has authority under the Federal Power Act, 16 U. S. C. 791a et seq., to regulate the rules used by operators of wholesale electricity markets to pay for reductions in electricity consumption and to recoup those payments through adjustments to wholesale rates.
Whether the Court of Appeals erred in holding that Order 745 — which required RTOs and ISOs to pay DR the same LMPs as generation in energy markets — is “arbitrary and capricious.”

(See Supreme Court Agrees to Hear Demand Response Appeal.)

Most of the arguments focused on jurisdiction, however.

Direct Effect

Verrilli led off the arguments and was interrupted almost immediately by Kennedy, who — after noting the interplay between retail and wholesale markets — asked what “marks the end of federal power and the beginning of local power?”

Verrilli did not answer directly, but contrasted the current dispute with the Mississippi Power case, in which FERC ruled that the utility could recover at wholesale its investment in a nuclear plant. The commission was overruled, with the court ruling that FERC had infringed on the authority of the state regulator to deny cost recovery in retail rates as imprudent. “That was a very direct effect on the exercise of state regulatory jurisdiction, which you do not have here,” Verrilli said.

“I find that a pretty fuzzy line, ‘very direct effect,'” Scalia jumped in. He continued, “Yes, FERC has the power to regulate wholesale rates. But … the argument is, not through the fiddling around with retail rates, which is what is asserted is happening here.”

$8 Hamburgers

After several exchanges between the two, Roberts took his turn with Verrilli, comparing FERC to someone “standing outside McDonald’s” offering diners $5 not to go in and spend $3 on a hamburger.

Because of FERC’s action, Roberts said, “the price of a hamburger is actually … $8, because if they give up the $5, they’ve still got to pay the $3. And your answer is, there’s no impact on what the states can do, because they can still say, no, the price of the hamburger should be $2, or it should be $4. The point is that … FERC is directly affecting the retail price.”

Kennedy returned with another question: “Is it fair to say that FERC is luring retail customers into the wholesale market? And if that … were true, would that not be a serious problem for the government?”

“It’s wrong as a matter of history. It’s wrong as a matter of law,” Verrilli responded. “Wholesale demand response was not FERC’s idea… This is a practice that grew up organically out of the private actions of market participants once the wholesale markets were deregulated. It’s exactly the kind of innovative private market conduct that you would hope that deregulation would bring about. And the private actors, the wholesale market operators, brought that idea to FERC as early as 1999.”

Verrilli went on, saying that the Federal Power Act gives FERC authority “over practices that affect … wholesale rates. And there’s just no doubt … that all of the practices FERC is regulating occur in the wholesale auction.”

Limiting Principle

Roberts acknowledged that was true, but he pressed Verrilli to identify the “limiting principle” on FERC’s authority, saying that without one, “FERC can do whatever it wants.”

Verrilli responded that “the effects have to be direct.”

Repeating hypothetical examples cited by the D.C. Circuit, he said, “regulating steel, regulating inputs into electric generation — we don’t think FERC’s authority goes anywhere near that far.”

Verrilli concluded by citing the Chevron doctrine, which says FERC is entitled to deference in its interpretation of the Federal Power Act. “There is no statutory text that unambiguously denies FERC this authority that it’s exercising here over this wholesale conduct.”

Reliability Benefit

Representing DR provider EnerNOC, attorney Carter G. Phillips backed Verrilli, saying that FERC did not create DR but rather responded to a market created by his clients and others who were trying to create a demand-side component to the wholesale market and a way to avoid brownouts. “And so tariffs were filed in order to provide a basis for putting in the demand side. And the reason why this is a direct effect on the … wholesale rates is because it’s an absolute one-to-one relationship. If I put in a unit of — or reduce a unit of — demand, I don’t need as much supply, and that affects the price directly. And that’s the direct relationship that derives from the economic principles.”

Phillips also sparred with Kennedy and Scalia. “FERC’s argument is essentially circular,” Kennedy said. “It says, well, the market forces will work this out — but we define the market.”

Scalia asked Phillips why “all the companies” aren’t in agreement with FERC and EnerNOC. DR provider EnergyConnect, the Coalition of MISO Transmission Customers and the PJM Industrial Customer Coalition joined EnerNOC’s brief.

“Most of the private companies on the other side generate electricity” and see DR as competition, Phillips responded.

Clement, the final attorney to speak, made a point to note that he represented not only the generators that make up EPSA but also load-serving entities that could provide DR under state-sanctioned retail programs.

Signing on to EPSA’s brief were the National Rural Electric Cooperative Association, the American Public Power Association, PPL and Old Dominion Electric Cooperative.

FERC Reducing Retail Demand?

“What FERC was trying to do here was to reduce retail demand by providing payments to retail customers on an otherwise wholesale market in an effort to change the effective price for retail sales,” Clement said. “Now, that sure sounds like something that belongs to the states.”

“Where is that … written anywhere that that was their goal?” interrupted Sotomayor. “What I’ve heard them say is, we’re trying to lower the price of wholesale [power] to a more just amount. That’s what’s in anything I’ve seen written. You’ve recharacterized it.”

Clement persisted: “These retail customers don’t belong on the wholesale market. Whether you think they were lured in or you think they walked in the door, it doesn’t matter. They are in a market where they don’t belong.”

“What’s the horror here of concurrent jurisdiction … if, in fact, it’s lowering prices?” Sotomayor asked.

“You actually have the … federal regulators and the state regulators bidding against each other for the same customers to reduce their same retail demand,” Clement responded.

LMP Too High?

That led Clement to move from the jurisdictional dispute to the second question, saying that while no states raised a jurisdictional objection before FERC itself, Ohio, Illinois and all of the MISO states said FERC should not require compensation at LMP “because that’s too high.”

“And by setting it so high, what you are going to do is you’re going to crowd out our own efforts at dealing with demand response,” Clement said for the states. “Because we love demand response. We want demand response. But we don’t want to pay twice as much as the market really should pay for demand response. And if you’re out there offering our same retail customers the ability to get demand response paid at huge LMP levels, then [states are] going to be crowded out.”

Breyer said Clement’s logic would prevent FERC from allowing large consumers to buy electricity at wholesale, “because that would take the retail customers away from the jurisdiction of the state.”

He continued: “I have found no case … that would say that they cannot do this for the reason you suggest.”

Kagan said Clement’s argument seemed to be that FERC “can’t do anything with respect to demand response.”

Clement disagreed, saying FERC was allowed to have a role in “true wholesale demand response,” which he said meant working through load-serving entities.

He said FERC’s premise “that the sky will fall if you don’t have this precise type of retail customer on wholesale market demand response” was belied by the experience of Southern Co., which does not participate in an RTO or an ISO, yet it has “a greater level of demand response than other parts of the country” subject to Order 745.

Congressional Intent

Kagan said Clement’s argument was at odds with the 2005 Energy Policy Act, “which made it so clear that Congress liked demand response — that it wanted FERC to lower barriers to demand response — to then say, well, FERC has no jurisdiction to do exactly what the policy that Congress articulated is.”

Clement cited Commissioner Philip Moeller’s dissent on Order 745 and comments by the Federal Trade Commission, which he said told FERC “you are picking the wrong compensation level.”

Having saved five of his 20 minutes for closing remarks, Verrilli got the last word, saying Clements’ view of “hermetically sealed-off retail and wholesale spheres” was unrealistic.

“In the real world today, large customers can buy directly. They can do it through contract, and they can also go into the wholesale market auctions and buy, if their states permit it… And this is really no different because demand response entities that want to come in and participate can only do so if their state law allows them to do so. So it’s no different than what’s been going on in the real world for quite a long time.”

Verrilli also responded to Clements’ arguments about the role of load-serving entities in providing DR. FERC “found that load-serving entities don’t have sufficient incentives to engage in demand response. And it’s obvious why they don’t, because they cannibalize their own profits. The higher cost they have, the higher their rate-of-return profits are going to be generated. They will do it under commands from state regulatory agencies to do it, but they’ll do it grudgingly. And what FERC said is you want people to come in who have a real profit motive to do it and that’ll incent the LSEs to get in there and try to get a piece of the action rather than letting it go to somebody else.”

Fears Unwarranted

Verrilli said fears that state and federal DR can’t coexist were unwarranted, saying “we have 24 states in which this is going on. And if this were a problem, you’d expect to see in this administrative proceeding some evidence that it was a problem, and there is zero evidence. You look at all these briefs; there isn’t a citation to anything in the administrative record that suggests that the federal and state programs can’t work in harmony.”

“You’ve got a practice … that has saved billions of dollars in wholesale costs and will save billions of dollars, and it’s an effective tool against blackouts and brownouts, and that nobody has shown in the real world does any harm.”

More: Transcript of Argument; Briefs

October 13, 2015January 15, 2025

SPP, MISO Reach Deal to End Transmission Dispute

By Amanda Durish Cook and Tom Kleckner

INDIANAPOLIS — MISO and SPP have filed a settlement agreement with FERC allowing MISO to use the SPP transmission system to transfer power freely between its North and South regions.

The settlement (ER14-1174, et al.) eliminates the $9.57/MWh hurdle rate established in 2014 after SPP complained that MISO’s use of the SPP grid exceeded a 1,000-MW transfer limit in their joint operating agreement.

The agreement also supplants MISO and SPP’s Operations Reliability Coordination Agreement (ORCA), set in place in early 2014 to address capacity sharing across the region.

Six transmission owners outside of MISO and SPP — Southern Co., the Tennessee Valley Authority, Associated Electric Cooperative, Louisville Gas and Electric, Kentucky Utilities and PowerSouth Energy Cooperative — signed off with the two RTOs on the deal.

Moving forward, MISO’s compensation of SPP and the independent transmission owners will be determined through application of a capacity factor for flows exceeding the existing 1,000-MW contract path. New directional transfer limits were included in the deal: Power flowing from north to south is limited to 3,000 MW, while power flowing south to north is capped at 2,500 MW. Otherwise, the capacity usage provision between MISO and SPP under their joint operating agreement stands intact.

Under the settlement, MISO will pay SPP and the independent transmission owners $16 million — $8 million per year — to settle all claims of compensation from Jan. 29, 2014, to Jan. 31, 2016. Sixty percent of the funds will be paid to SPP, while the remaining 40% will be disbursed to the independent transmission owners. SPP said it will distribute the funds it collects to its members. The RTO will have to file the proposed distribution method with FERC because the funds are not being collected under its Tariff.

The settlement creates an operating committee to manage any disputes that may arise. The committee will be composed of two members each from MISO, SPP and the independent TOs.

The agreement will last seven years from the date of the initial complaint in January 2014. In early 2021, the parties will have the opportunity to give notice to terminate or revisit settlement provisions.

Jennifer Curran, MISO’s vice president of system planning and seams coordination, said that the RTO will “continue to evaluate if there are … appropriate alternatives to the agreement,” including expansion of its own grid to reduce the use of its neighbors’ systems.

“That work will be ongoing to see if there could or would be appropriate transmission solutions,” she said during a press conference.

In recognition of the limits of the 1,000-MW contract path, FERC on Thursday granted MISO a year-long extension on a waiver of Tariff provisions and North American Energy Standards Board rules on the processing of long-term firm transmission service requests (TSRs) between MISO South and MISO Midwest or PJM (ER14-2022-001). “A number of long-term TSRs remain in the queue that seek capacity from the MISO South region to non-contiguous geographic regions outside of MISO. MISO expects the number of these already-sold long-term TSRs to exceed the 1,000-MW threshold until 2019. MISO intends to honor fully these transmission commitments, but they make it very difficult for MISO to process adequately any additional long-term TSRs,” MISO wrote in the waiver request.

The waiver relaxes processing, assessment and timing regulations on long-term TSRs. MISO said that without the waiver, it would be forced to deny the requests.

The waiver, which expired April 1, 2015, now lasts until April 1, 2016 or until the resolution of the dispute between MISO and SPP.

Curran said MISO will file with FERC to remove the hurdle rate.

“We’re excited to have made this filing today. We think it’s a good compromise. Most importantly, it provides us clarity,” Curran said. “It took a lot of work across all parties.”

David Kelley, SPP’s director of interregional relations, said SPP’s main objective was to protect the interests of its members. He called the settlement a “mutually beneficial agreement.”

“Both sides weighed the risks of not settling and realized both parties were better off not litigating and reaching consensus instead. We had some uncertainty, too, for our members, with continued litigation,” Kelley said.

FERC set the dispute for hearings and settlement negotiations in March 2014. The parties met for seven settlement conferences at the commission’s offices in Washington.

MISO said the settlement will allow cost-effective energy delivery through continued shared use of the transmission system.

“We are pleased to have reached a resolution that provides electricity savings to consumers across the MISO region and brings clarity to our members and all stakeholders,” MISO CEO John Bear said in a statement. “With the issue of capacity sharing behind us, we can now collectively return our full attention to the significant challenges facing the industry.”

SPP CEO Nick Brown also praised the arrangement.

“As the SPP region grows and we continue to modernize the electric grid, cooperation with our neighboring regions has never been more important,” Brown said in a statement. “I am pleased we were able to reach this agreement with MISO to ensure that our member companies and their customers are compensated for the use of the SPP transmission system.”

October 13, 2015April 8, 2025

Entergy Closing Pilgrim Nuclear Power Station

By William Opalka

Entergy announced Tuesday it will close its Pilgrim Nuclear Power Station in Plymouth, Mass., no later than June 1, 2019, marking the company’s exit from the New England market.

The company blamed “poor market conditions, reduced revenues and increased operational costs” for the planned closure. The plant has come under increased scrutiny from the Nuclear Regulatory Commission, having earned the second-worst ranking for operational performance. (See Federal Briefs.)

The company said it would cost $45 million to $60 million in direct costs, plus any additional capital expenses, to comply with NRC requirements.

(Source: Entergy)

“The decision to close Pilgrim was incredibly difficult because of the effect on our employees and the communities in which they work and live,” Entergy CEO Leo Denault said in a statement. “But market conditions and increased costs led us to reluctantly conclude that we had no option other than to shut down the plant.”

The 680-MW plant began operations in 1972.

The company blamed low current and forecast energy prices caused by shale gas. The Energy Information Administration reported last week that January 2016 forward contracts for on-peak power in New England are trading at about $90/MWh, versus $190/MWh a year ago.

Entergy says the falling prices would lower annual revenue from Pilgrim by more than $40 million.

It also blamed what it called “wholesale energy market design flaws” that suppress energy and capacity prices, state subsidies for renewable energy and a recent proposal to import Canadian hydropower. (See Baker: Hydropower Contracts Best Way to Lower Costs.)

The merchant plant was relicensed three years ago by NRC and can operate through 2032. But the commission’s decision to place Pilgrim in column 4 of the reactor oversight process action matrix put it in the unwelcome position of being one of three of the country’s 99 nuclear plants so designated.

“We have invested hundreds of millions of dollars to improve — first and foremost — Pilgrim’s safety, as well as its reliability and security, but face increased operational costs and enhanced Nuclear Regulatory Commission oversight,” the company said. “We also take into account the effect on our stakeholders of operating over the long-term if it is not economically viable to do so.” Entergy said the exact date for closing the plant would be decided in the first half of 2016. It already notified ISO-NE that the plant will not be available as a capacity resource starting in mid-2019.

ISO-NE’s 10th capacity commitment period begins in June 2019, with its Forward Capacity Auction slated for February 2016.

Generators are required to notify the RTO by Monday if they will participate in the 2016 auction.

Nuclear power generated 34% of New England’s power in 2014. Pilgrim represents almost 17% of the region’s nuclear capacity.

ISO-NE could ask Entergy to keep the plant online if a study indicates it is needed for grid reliability. If Entergy agrees, it would receive out-of-market payments. But the RTO does not have the authority to prevent a resource from retiring.

The closure of Pilgrim will mark Entergy’s exit from New England. The company closed the 615-MW Vermont Yankee nuclear power plant at the end of 2014 and last week announced the sale of a 583-MW natural gas plant in Rhode Island. (See Entergy Sees Big Gain on Sale of RI Gas Plant to Carlyle.)

The Pilgrim nuclear decommissioning trust had a balance of approximately $870 million as of Sept. 30, which is approximately $240 million above what NRC requires for license termination activities, Entergy said.

Entergy bought the plant in 1998 for $80 million from Boston Edison. Entergy Nuclear was the first company in the nation to purchase a nuclear plant through the competitive bid process, it said.

October 13, 2015

Moeller Leaving FERC Oct. 30; No Replacement in Sight

By Rich Heidorn Jr.

WASHINGTON — FERC Commissioner Philip Moeller announced last week he will leave the commission at the end of the month although President Obama has yet to appoint his successor.

Moeller, one of two Republicans on the five-member panel, announced in May that he would not be returning when his term expired June 30. He said that he expected to serve until his replacement was confirmed.

Nearly five months later, however, Obama has yet to name a replacement. Moeller’s extended term would end when the current session of Congress adjourns this fall.

Even if Obama were to nominate a replacement immediately, it could be months before the commission returns to full strength. Even non-controversial FERC appointees can get enmeshed in Congressional horse trading. For controversial appointees, the process can be even more tortuous.

The seat of former Chairman Jon Wellinghoff went unfilled for almost eight months after his resignation in November 2013. After Obama’s first nominee, Ron Binz, withdrew under fire from the coal industry, it was another five months before Obama named former FERC enforcement chief Norman Bay in February 2014. It took Bay five months to win confirmation on a party-line vote in July 2014.

FERC’s newest member, former Arkansas regulator Colette Honorable, was confirmed unanimously to replace Democrat John Norris after a four-month gap last year.

When Moeller announced his departure in May, speculation on his successor centered on Patrick McCormick III, chief counsel for Senate Energy and Natural Resources Committee Chairman Lisa Murkowski (R-Alaska). (See Moeller Leaving FERC.)

McCormick’s appointment could have challenged the traditional comity at FERC, given Murkowski’s opposition to Bay’s nomination.

But in light of the lengthy delay since his name was circulated, McCormick may no longer be in contention. Asked by Politico whether McCormick was under consideration, Murkowski said, “He’s a very happy man at the Senate Energy Committee. I’m sure happy having him there.”

Moeller, who was appointed by President George W. Bush in 2006, said he plans to seek employment in the energy industry.

Before joining the commission, he worked from 1997 through 2000 as an energy policy adviser to U.S. Sen. Slade Gorton (R-Wash.). Before joining Gorton’s staff, he was the staff coordinator for the Washington State Senate Committee on Energy, Utilities and Telecommunications. He also headed the D.C. office of Alliant Energy and worked in the D.C. office of Calpine.

October 13, 2015

PJM Transmission Expansion Advisory Committee Briefs

PJM and MISO will make a joint filing with FERC later this year to eliminate the $20 million minimum for interregional market efficiency projects, PJM officials told the Transmission Expansion Advisory Committee last week.

The two RTOs indicated their willingness to do so in response to a complaint by Northern Indiana Public Service Co. (EL13-88). NIPSCO, which filed the complaint in 2013 over its frustrations with MISO and PJM’s interregional planning process, says nothing much has changed since then. (See MISO-PJM Cross-Border Projects Still Languishing, NIPSCO Says.)

In an Aug. 14 filing, PJM and MISO said they would lower or eliminate the $20 million threshold. MISO also said it would inform FERC by the second quarter of 2016 on whether it will eliminate its 345-kV minimum on such projects.

PJM and MISO embarked this year on a search for “quick hit” transmission projects on which they might collaborate to relieve congestion.

In a Sept. 3 filing, PJM said the studies found that about three-quarters of the $400 million in cross-border congestion identified was expected to be relieved by regional transmission projects under the MISO and PJM tariffs and that congestion on lower voltage facilities could be eliminated by upgrades costing less than $5 million.

“Reduction or elimination of the $20 million threshold in the [joint operating agreement] and the [345-kV] voltage threshold in MISO’s regional process would enable quick-hit projects to qualify as an interregional project,” PJM said.

PJM officials said they and MISO officials will make a joint filing to remove the $20 million threshold from their Joint Operating Agreement. MISO would file alone if it decides to eliminate the 345-kV threshold from its Tariff.

AEP to Build Rockport Line as Supplemental Project

American Electric Power will build a 14-mile double-circuit line between its Rockport substation and MISO’s Duff-Coleman 345-kV line as a supplemental project in the PJM Regional Transmission Expansion Plan. The project, which is intended to solve stability problems at the substation, will piggyback on MISO’s planned Duff-Rockport-Coleman project. (See MISO Staff Recommends 3 Economic Projects.)

“We clearly should have gotten involved [in the project planning] much earlier,” said Steve Herling, vice president of planning. “MISO was great,” he added, noting that MISO delayed its process to allow PJM to conduct its own analyses.

“We’ve already had a number of conversations with MISO as to how we can be better synched up in the future,” Herling said. “We’re pretty happy it didn’t fall through the cracks. Next time we want to do it in a more formalized way.” (See related story, FERC Sets Nov. 12 Tech Conference on PJM Tx Planning Rules.)

Most AP South/AEP-DOM Proposals Clear Sensitivity Tests

All but one of 11 proposals that passed the initial benefit-cost ratio to address congestion in the AP South/AEP-DOM area also show positive benefits under 10 different sensitivity analyses, PJM planners told the TEAC.

The sensitivities included fuel prices (+/- $1/MMBtu), load forecasts (+/- 2%), interface ratings (changes in anticipated project impacts by 20%) and combinations of fuel price and load forecast sensitivities.

All but two of the projects cleared the 1.25 B-C ratio under all sensitivities and all but one showed congestion savings for the entire RTO. However, nine of the 11 worsened congestion on AEP-DOM alone (see chart).

Planners will continue their analysis by combining components of multiple projects as well as considering projects involving capacitors and reactive devices.

At September’s TEAC, planners focused on only six of the projects, which they labeled “finalists.” (See Transmission Expansion Advisory Committee Briefs.)

No Market Efficiency Projects to be Accelerated

Planners evaluated six planned market efficiency projects but determined that none of them should be accelerated because the projects are either too large to reschedule or their in-service dates are in the near future. An additional six projects expected to reduce congestion also were ineligible because they are being developed by MISO.

SVCs Recommended to Fix High Voltage in AEP, PSEG

Planners will recommend more than $51 million in upgrades to address high voltages in the AEP and PSEG transmission zones.

The AEP project would involve installation of a 450-MVAR static VAR compensator (SVC) at the Jacksons Ferry 765-kV substation and a 300-MVAR shunt line reactor on the Broadford end of the Broadford-Jacksons Ferry 765-kV line. It is expected to be in service in June 2018 at a cost of $51 million.

Planners also will recommend six shunt reactors on the PSEG system in addition to about 1,500 MVARs of approved reactors and SVCs planned to go in service by 2016. Three devices are required as soon as possible; the other three will be installed in coordination with the Bergen-Linden Corridor 345-kV project. No cost estimate was listed for these projects.

Planners Choose $25.8M AEP Proposal over Cheaper LS Power Option

PJM will recommend AEP’s proposed $25.8 million upgrade rather than a $7.4 million proposal by LS Power to address low voltage and overload problems in the AEP zone.

Paul McGlynn, general manager of system planning, said PJM determined that LS Power’s proposal to build a new Grassy Creek switching station would be insufficient to address expected load growth driven by shale gas production in the area. The AEP project, due in service by June 2020, is expected to prevent violations for at least 15 years, PJM said.

“We believe [the AEP project] is the better, more robust solution,” he said.

LS Power’s Sharon Segner questioned why AEP’s more expensive project was selected, saying PJM’s load growth assumptions are too high. “We want to make sure the right solution is picked, even if at the end of it, AEP takes the idea that we proposed,” she said.

Dominion to Spend $273M+ on End-of-Life Projects

Dominion Virginia Power will spend more than $273 million on nine projects to replace aging transmission lines in accordance with its “end of life” criteria, which sets the lifespans for wooden structures, conductors, connectors and porcelain insulators.

The rebuild of the Cunningham-Dooms 500-kV line is expected to cost more than $100 million, with an in-service date of June 2020. Eight other projects, expected to be completed between 2016 and 2019, will total about $173 million.

Exelon Retiring Perryman Unit in BGE

Exelon has decided to retire, rather than repair, its damaged 51-MW Perryman 2 generator in the BGE zone.

Exelon told FERC in April that the 43-year-old oil-fired unit experienced a “severe mechanical failure” in February that would take nine months to repair (ER15-1611).

Exelon said that a portion of a compressor shroud detached, damaging a number of the compressor’s components. “In addition to the compressor issue, electrical testing revealed that the unit’s generator field and stator windings are in a degraded condition,” Exelon said.

PJM planners are conducting a reliability analysis on the retirement request, which was filed Oct. 2. Exelon requested the retirement be effective Jan. 1.

— Rich Heidorn Jr.

October 13, 2015

Pepco’s Influence in District Runs Deep

By Suzanne Herel and Rich Heidorn Jr.

In May, the D.C. Council unanimously approved $250,000 for the Office of the People’s Counsel to conduct a study on the feasibility of the district replacing Potomac Electric Power Co. with a city-owned utility.

The vote set lobbyists for Pepco — no strangers to the Wilson Building, D.C.’s city hall — into high alert.

Public records show that in June alone, Pepco and Exelon lobbyists Tina Ang and John Ray, of law firm Manatt, Phelps & Phillips, communicated more than 60 times with seven D.C. councilmembers or their aides, including in-person meetings, phone calls and electronic messages.

By the end of the month, the study — included in the city’s fiscal year 2016 budget — was dead, with the council voting 7-6 to reallocate the funds for a study on “emerging alternatives” for energy and energy efficiency.

“Presumably, they didn’t even want a study,” said Councilwoman Mary Cheh, an opponent of Exelon’s bid to acquire Pepco who had pushed for the original study.

The amendment to reallocate the funds was sponsored by Councilmember Anita Bonds. Bonds or her staff communicated on 19 occasions with the utility lobbyists in June. Councilmembers Jack Evans, Brandon Todd, LaRuby May and Vincent Orange — all of whom met personally with the lobbyists — and Yvette Alexander, who sent a staff member to the meetings, also voted for the change.

The vote was but one signal of Pepco’s clout in the district.

Orange, a former regional vice president for PHI, chairs the Council’s Committee Business, Consumer and Regulatory Affairs.

Council Chairman Phil Mendelson has been criticized for voting on Pepco matters because he holds enough stock to be required to financially disclose it.

Attorney General Karl Racine, who helped negotiate the Oct. 6 settlement between Exelon and Mayor Muriel Bowser, and Racine deputy Natalie Ludaway conducted work on Pepco’s behalf while at their former law firms. Beverly Perry, senior adviser to Bowser, retired in 2013 as senior vice president and special adviser to the chairman of PHI.

Charity Returned?

In their bid to win approval of the merger, Pepco officials also have looked to cash in chits with the dozens of community organizations the company supports with charitable contributions. In the district alone, Pepco spends about $1.6 million annually on charitable contributions.

Exelon and Pepco claim that more than 80 D.C.-area organizations support the merger, including 30 businesses and associations and nearly four dozen non-profit organizations. At least half of the non-profit groups listed in support were recipients of contributions from Pepco in 2014 or receive funding from the United Way of the National Capital Area, where Pepco CEO Joseph Rigby is the immediate past chairman. John Huffman, CEO of Pepco Energy Services, serves on the board of the Capital Area Food Bank, one of the charitable groups backing the deal.

Business Community Lines up in Support

Rigby also serves on the senior council of the Greater Washington Board of Trade, as well as the boards of the Federal City Council and the Economic Club of Washington — all of which have endorsed the merger.

James C. Dinegar, president of the Board of Trade, told The Washington Post that rejection of the deal would hurt the region’s economy. “There’s a big concern that we’re hanging out the ‘Closed for Business’ sign in the District of Columbia,” he said.

October 13, 2015

Company Briefs

The powerhouse at Duke Energy’s retired Cliffside Steam Station in Mooresboro, N.C., came down in a cloud of dust last week, the latest demolition Duke has conducted to modernize its generation fleet.

The coal-fired station went into service in 1940, and units 1 through 4 were retired in 2011. Units 5 and 6 are coal-fired units equipped with modern scrubber technology and still operate as part of the James E. Rogers Energy Complex.

See a video of the powerhouse implosion here.

More: Duke Energy

Entergy Execs Announce 2016 Exits

Entergy Executive Vice President and Chief Operating Officer Mark Savoff and Executive Vice President and Chief Nuclear Officer Jeff Forbes announced coordinated retirement dates last week.

Both executives plan to shift to advisory roles on Nov. 1 before retiring in 2016’s first quarter. At that time, Tim Mitchell, Entergy’s senior vice president of nuclear operations, will be named acting chief nuclear officer. In an executive restructure, the chief nuclear officer will directly report to Entergy Chairman and CEO Leo Denault. Mitchell will also be a candidate in Entergy’s search for a permanent chief nuclear officer.

Savoff and Forbes joined Entergy in 2003 and oversaw the transition of Entergy’s transmission system to MISO in 2013.

More: Entergy

DTE, GE Working on New Economic BWR Design

DTE Energy is teaming up with GE Hitachi to design a new type of boiling water reactor. While others are working on smaller, modular designs, the two companies are working on advancing the first-ever Economic Simplified Boiling Water Reactor (ESBWR).

The ESBWR incorporates passive safety systems, including a reactor that can cool itself for more than seven days without backup power or any human input. DTE has already received licensing from the Nuclear Regulatory Commission for the ESBWR.

The company said it has no current plans to start construction but said it is “keeping the option open, given the long-term environmental and economic advantages of nuclear power.” Dominion Virginia Power has selected the new design for a possible third reactor at its North Anna site in Virginia.

More: Nuclear Street

Alliant Eyes Boosting Solar Capacity by 50%

Alliant Energy subsidiary Interstate Power & Light in Iowa is planning to increase its total solar energy capacity by 50%, according to a recent request for proposals.

The company said it is looking to develop solar projects of between 1 and 10 MW. It currently purchases about 22 MW of solar capacity from about 1,650 customers in its service territory.

Alliant said the plan is unrelated to an Environmental Protection Agency air emissions settlement that calls for it to spend $6 million on environmental mitigation projects, which could include solar generation.

More: DesMoines Register

Xcel Energy to Accelerate Minnesota Wind, Solar Investments

Xcel Energy says it will reduce its greenhouse gas emissions in Minnesota by increasing wind and solar power investment and replacing two coal-burning generators with a natural gas-fired unit in the mid-2020s.

The plan, submitted to state regulators, would reduce carbon dioxide emissions in the Upper Midwest 60% by 2030 compared with 2005 levels. Until now, Xcel had aimed for a 40% reduction over that period.

Two of the three coal-fired units at Xcel’s Sherco power plant — Xcel’s largest in the region — would be retired in 2023 and 2026 under the plan. The two units, built in the 1970s, would be replaced by a new power plant fueled by natural gas.

More: Minneapolis Star Tribune

PSEG Combined-Cycle Project to Deliver Power by Summer 2018

Construction on PSEG Power’s 540-MW Sewaren 7 combined-cycle project is expected to begin next year at an existing power station site in Woodbridge, N.J.

The $600 million dual-fuel gas-turbine facility is set to deliver power to the PJM market for the summer of 2018.

The project was finalized after clearing the Base Residual Auction in August.

More: Black & Veatch

Line Replacement has Wisconsin Residents Worried

Residents in Onalaska, Wis., are concerned over Dairyland Power Cooperative’s planned replacement of a 65-year-old 161-kV line.

Dairyland, which is based in La Crosse, has been working nearly a decade to replace the 9-mile stretch of line connecting power plants in Alma and Genoa to the grid, and designs are not yet ready, in spite of a late 2016 start date. The cost of the project is calculated between $7 million and $8 million. Other transmission lines in the area have been rebuilt recently or are in the process of replacement.

Residents are worried that the new line, which will carry twice the electricity at the same voltage, will increase exposure to electromagnetic radiation. Dairyland says raising the wires will mitigate exposure.

More: LaCrosse Tribune

NuScale Seeking British Partners for Modular Reactor Design

NuScale Power, a U.S. company developing a small modular reactor with the help of a $217 million Department of Energy grant, is looking for a partner to help make the design a reality in the United Kingdom.

The company, mostly owned by Fluor Corp., is distributing a prospectus in the U.K. seeking a partner in what it says is a chance to get a piece of the $612 billion nuclear market by 2035.

NuScale’s design is on track to come up for U.S. certification next year, and the company says it expects to receive U.S. regulatory approval in the early 2020s. It is currently developing a test model in Idaho, using technology that can be customized for scale, allowing deployment in series, with up to 12 small reactors totaling about 600 MW.

More: Nuclear Street

Indiana’s Rising Power Prices Drive Pushback

Northern Indiana natural gas and electric provider NIPSCO has asked state regulators for an 11.5% hike in residential electric rates. Indiana’s industrial utility customers are protesting the request.

Joseph Hamrock, CEO of NiSource, parent company for NIPSCO and utilities in six other states, said the increases are needed to fund plants, poles and wires that serve as fail-safes even in light of new generating technologies.

More: NWI Times

South Field Energy to Build 1,100-MW Nat Gas Plant in Ohio

South Field Energy announced plans to build a $1.1 billion, 1,100-MW natural gas-fired power plant in Columbiana County, Ohio.

South Field and other companies are taking advantage of the cheap gas being produced at Utica Shale fields in the state. It is the sixth natural gas plant under construction in Ohio, according to the Akron Beacon Journal.

Construction would start in 2017, and the plant should be operational by 2019. South Field is also building an $899 million gas-fired plant in Carroll County.

More: Akron Beacon Journal

Ameren Increases Quarterly Dividend by 3.7%

Ameren increased its quarterly dividend on common stock, from 41 cents/share of common stock to 42.5 cents, an increase of 3.7%. The common share dividend is payable Dec. 31 to shareholders of record at the close of business on Dec. 9. The company’s board of directors also declared quarterly cash dividends to all classes of Ameren Missouri stock and all classes of Ameren Illinois preferred stock.

More: Ameren