With PJM planners nearing a proposed fix for the Artificial Island stability problem, the issue of who will pay for the project took center stage last week. Delaware regulators were not happy with what they heard.
Paul McGlynn, general manager of system planning, presented the Transmission Expansion Advisory Committee with preliminary cost allocation examples on the two least expensive projects among 10 finalists.
The cost of a $240 million proposal by Exelon and Pepco Holdings Inc. to add a 17-mile 500-kV line paralleling an existing 500-kV line from Red Lion to Hope Creek would be spread among two dozen transmission zones and merchants. The Jersey Central Power & Light zone would be responsible for about 27% of the project, with the Atlantic City Electric zone picking up almost 20%. No other zone was as high as 8%.
In contrast, LS Power’s $234 million proposal to run a 230-kV line across the Delaware River to a new or expanded substation on Delmarva Peninsula would be assigned entirely to the Delmarva Power and Light (“Delmarva”) zone, McGlynn said.
John Farber, of the Delaware Public Service Commission, said he couldn’t understand how Delmarva would be wholly responsible for a project meant to address stability problems in New Jersey. He said the assessment would boost total network transmission costs for Delmarva by 20%.
Farber requested that PJM provide cost allocations for all the projects still under consideration so those who would have to pay could use it to “assess PJM’s decision.”
McGlynn defended the allocation. “The flow on that line [would be] from Salem to Silver Run [Delaware] all year long,” he said.
McGlynn said the cost allocation, which will follow methodology approved by the Federal Energy Regulatory Commission, will not be a factor in determining which project is selected.
Just and Reasonable?
Sharon Segner, of LS Power, said PJM should consider Delmarva’s concerns and whether the RTO’s choice produces just and reasonable rates. “There may be some wiggle room in terms of working with Delaware on the cost allocation,” she said. “It would be worthwhile to be creative.”
The LS Power proposal is the lowest cost option, according to an analysis presented to the TEAC in April. The Exelon-PHI proposal was the second cheapest. (See Planners Near Artificial Island Pick.)
McGlynn also presented the TEAC last week with the results of market efficiency studies that showed neither the southern Delaware crossing nor the line to Red Lion would produce sufficient savings to be a consideration in the selection. The two projects showed benefit-to-cost ratios of 0.25 and 0.15, respectively, well below the 1.25 threshold for market efficiency projects.
PJM has scheduled a special TEAC meeting for May 19 to share information on how the 10 finalists fared in several key areas, including cost, project complexity, siting and permitting.
After receiving feedback from stakeholders, another special meeting will be held June 16 during which PJM will discuss its final recommendation. “I wouldn’t expect, necessarily, a recommendation on the 19th,” McGlynn said. “I expect a recommendation on the 16th.”
The PJM Board of Managers is expected to consider the recommendation at its July 22 meeting.
Artificial Island is the home of the Salem and Hope Creek nuclear plants in Hancocks Bridge, N.J. Five utilities and three independent developers made more than two dozen proposals in PJM’s first competitive transmission project under FERC Order 1000.
FERC Rejects Arbitrage Fix; OKs Most of DR Changes
By Rich Heidorn Jr. and Ted Caddell
PJM yesterday opened the 2017/2018 Base Residual Auction amid modest hopes among generators that the RTO’s rule changes will cause a rebound in prices.
Last year’s capacity auction saw big price drops in most of PJM, compounding the woes of generators, whose energy revenues have been suppressed by cheap shale gas.
PJM stakeholders approved several major changes in an attempt to bolster the capacity market, including a cap on imports and limits on demand response. But lackluster load growth and auction parameters that suggest there may be less price separation this year than last have tempered expectations.
Late Friday, the Federal Energy Regulatory Commission approved most of PJM’s proposal for making demand response an “operational resource.” However, the commission rejected a proposal requiring DR providers to respond to sub-zonal dispatch. The commission also rejected PJM’s proposals for eliminating financial speculation in the auction, instead scheduling a technical conference to develop a solution. (See related story, PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)
2013 Results
In last year’s auction, RTO prices dropped 56% to $59.37/MW-day, while prices in ATSI dropped more than two-thirds (to $114/MW-day) and MAAC fell 29% ($119). Prices in the Public Service zone rose 31% to $219.
Over the objections of consumer advocates and others, FERC approved PJM’s plan to create five import zones with a combined limit of 6,499 MW for this year’s base auction (ER14-503). (See FERC Clears Capacity Import Limits.)
The cap represents a 17% reduction from the imports that cleared in 2013. However, external resources can win an exception to the limits if they are pseudo-tied; have confirmed, firm long-term transmission service; and accept the same must-offer requirement as internal resources. PJM’s planning parameters show that only 1,524 MW of the 6,499 MW are available after 4,777 MW in exceptions.
FERC also approved rules requiring DR providers to give more assurances in their offers (ER13-2108), as well as limits on the clearing of limited demand response (ER14-504) that a PJM simulation suggested could increase capacity revenues by $1 billion annually. (See FERC OKs Limits on DR in Capacity Auction.)
Utility Execs Not Excited
In earnings calls over the last two weeks, executives of PJM companies praised the RTO’s rule changes but said they didn’t expect a dramatic rise in prices.
AEP CEO Nick Akins predicted RTO prices of $80 to $100 but added, “But who knows? I mean … the way this capacity construct works … things happen all the time.” Akins’ prediction is in line with that from UBS Securities, which predicted in February that RTO prices will rebound to $80 with MAAC flat at $120.
FirstEnergy CEO Tony Alexander told analysts he was encouraged by these “modest reforms” but more excited that “momentum is growing for changes that can truly help” such as a premium for having fuel on-site, which could boost nuclear and coal plants.
“I don’t think any of the rules currently approved are going to move the auction substantially,” added Leila L. Vespoli, FirstEnergy’s executive vice president of markets.
FirstEnergy President Donald R. Schneider said the “wildcard” will be the volume of offers from new generation in the interconnection queue.
PSEG CEO Ralph Izzo, however, said it is the actions of DR providers that may have more impact. “Really, a large part of the auction turns on what you expect for DR,” he said. The volume of cleared DR dropped 16% last year over 2012.
PPL CEO William Spence said there are too many variables to make a prediction on prices.
“There are a lot of moving parts, a lot of modifications have been made. There is a lot of kind of noise out there around the residual auctions and so forth,” he said. “So I think for this year at least, we are not going to put out an expectation around where we expect RPM prices to settle out, because there is a lot more uncertainty, in our view, coming into this auction than we have seen in past auctions.”
Spence said neither the auction results nor the spike in energy prices over the winter would influence the company’s long-term strategy. The company is reportedly considering selling its generation assets.
“We continue to have, as our No. 1 priority, the aggressive cost control and optimizing the dispatch of our plants,” he said. “At the same time, we do continue to consider other options that could enhance value. There is no particular data point or viewpoint of forward prices that we are waiting for or that would substantially impact our thought process around strategic options for that business.”
IPP Views
Among independent power producers, Calpine was downbeat while NRG was more positive.
Calpine President and Chief Operating Officer John B. Hill said the company has a “flattish to the modestly down view” of this year’s auction prices. “PJM has pushed forward some very strong rules … but we don’t have super high expectations for the auction this year,” he said.
NRG Energy’s Chief Operating Officer Mauricio Gutierrez was a bit more optimistic. “The combined effect of higher requirements and limits on demand response, the limits on capacity imports and the significant levels of un-cleared coal megawatts are positive signs in PJM,” he said.
Load Forecasts
PJM’s load forecast, released in February, predicts the RTO’s summer peak growing almost 7,000 MW to 164,195 in 2017, a 4.4% increase.
PJM predicted growth of 80 to 120 MW in APS from hydraulic fracturing and a 288- to 896-MW boost in the Dominion zone from new data centers. An undisclosed project under construction is forecast to add 50 to 195 MW to BGE’s summer peak beginning in 2017. Peak demand in the AEP zone was reduced by 370 MW, reflecting the loss of an aluminum smelter.
CETO/CETL ratios
PJM’s planning parameters report noted that planners had added three Locational Deliverability Areas (LDAs) — ComEd, BGE and PPL — to the nine modeled in last year’s auction.
Prior to each BRA, the Capacity Emergency Transfer Objective (CETO) and Capacity Emergency Transfer Limit (CETL) are calculated for each of 27 potential LDAs to determine whether separate demand curves should be modeled for them to ensure reliability.
The MAAC, EMAAC and SWMAAC LDAs are always modeled separately.
LDAs are also modeled separately if the CETL is less than 1.15 times its CETO or the LDA had a locational price adder in any of the three prior base auctions.
PJM can also model LDAs separately if it believes it necessary for reliability.
PJM said it would model the ComEd, BGE and PPL LDAs separately for the first time because of concern over generation retirements. The RTO said it wanted to “proactively identify locational supply concerns before they actually occur.”
PJM said most CETL values are about equal to or slightly higher than last year’s auction. The exception is the Pepco LDA which dropped to 5,208 MW, a reduction of 22% from last year, due to generator retirements.
The PS, DPL and SWMAAC zones showed the lowest CETO/CETL ratios, all below 1.4.
Below is a summary of the issues scheduled to be brought to a vote at the Members Committee meeting Thursday. Each item is listed by agenda number, followed by a summary of the issue.
RTO Insider will be in Cambridge, Md., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
5. Consent Agenda
The committee will be asked to approve the following:
B. Revisions to Manual 34: Stakeholder Process
Changes to voting methods at the Standing Committees, and posting and notice requirements.
Section 8.4: Voting Method
The voting procedures would be changed to allow members to indicate their preference for the status quo over proposed rule changes.
As under current rules, each member may vote yes, no or abstain on each proposed alternative. If one or more alternatives receives more than 50% support, a second vote will be taken asking participants to choose between the most popular change and the status quo.
If a simple majority does not prefer the proposed alternative over the status quo, the chair will lead a discussion to determine whether to continue working toward a proposal with wider support or to terminate work on the issue.
If the status quo receives less than a simple majority, the most popular proposal will be the main motion at the Markets and Reliability Committee. Other proposed alternatives that received greater than 50% support may be considered by the MRC as alternative motions.
Section 10.4: Posting Process Timelines
Members would have five business days to comment on proposed revisions to governing documents before votes of the Markets and Reliability or Members committees (down from the current 10-day requirement).
Section 11.13: Consultation with Transmission Owners and Members
Except in emergencies requiring immediate action, PJM would be required to provide Transmission Owners and PJM members 30 days’ notice before making a Section 205 filing to change the creditworthiness provisions of the Tariff. The notice time for making Section 205 filings on other matters would remain at the current seven days.
C. Settlement Formulation Review – Phase II initiative: Clarifications to the Tariff and Operating Agreement (OA) on regulation shoulder hour lost opportunity costs (LOCs). As a result of a review, PJM discovered that the documents didn’t adequately describe the calculation of the deviation between the regulation set point and the expected output of each regulation resource.
D. Credit Available for Virtual Transactions: Revisions to the Tariff to reflect current PJM practices regarding credit available for virtual transactions. PJM instituted the policy as the result of a FERC Order in 2004 but failed to make accompanying changes to the Tariff. These revisions also correct for changes in credit policy since 2004 (e.g., working credit limit discount is now 25%, not 15%).
E. Synchronized Reserve penalty charges for Tier 2 resources: Clarifications to the Tariff and OA giving generators providing Tier 2 synchronized resources the ability to aggregate these resources in order to avoid retroactive penalties for failure to respond appropriately when called. New language will also be added to Manual 11: Energy & Ancillary Services and Manual 28: Operating Agreement Accounting. Aggregation will not be used in calculating Tier 2 Synchronized Reserve credits; each resource will continue to be credited independently.
F. PJM’s change of mailing address: Changes to the Tariff and Operating Agreement to reflect PJM’s new mailing address to: 2750 Monroe Blvd., Audubon, PA 19403.
6. PJM Board of Managers Nominating Committee (NC)
The committee will be asked to re-elect to the Board of Managers Ake Almgren, who joined the board in 2003, Susan Riley (2005) and Charles Robinson (2011).
Gov. Jack Markell is ready to fill a seat on the Public Service Commission that has been empty for two years, according to reports. Chairwoman Arnetta McRae left the commission in 2011 to take another job, leaving the part-time five-member panel one commissioner short. Commissioner J. Dallas Winslow Jr. was named chairman a few months later, but the fifth commission seat has been empty since.
“The governor is in the process of setting up interviews and plans to nominate a replacement for consideration by the Senate in June,” Markell spokeswoman Kelly Bachman told The News Journal. “There were discussions regarding the possibility of shifting the PSC to a full-time commission; however, at this time we are moving forward on filling the vacancy while maintaining the part-time make-up of the PSC.”
Campaign Flyer for Montgomery County Councilman Roger Berliner (D-1)
A Montgomery County councilman introduced a resolution asking state regulators to require Exelon to improve reliability as a requirement for its takeover of Pepco. Councilman Roger Berliner’s resolution urges the state Public Service Commission to require Exelon to make a “firm commitment” to deliver top quartile performance as a part of its approval of the proposed takeover. Pepco has ranked poorly in performance metrics.
Exelon last month offered to purchase Pepco’s parent company, PHI Holdings, for $6.8 billion. Exelon has promised $100 million in rate credits and other assistance to customers as part of the terms of the purchase.
The commission is currently reviewing a Pepco request for a $43 million rate increase, money the utility has said it needs for infrastructure improvements.
PSEG Reaches $1.2 Billion Settlement on Energy Strong
Public Service Electric & Gas and the state Board of Public Utilities reached a settlement last week on the utility company’s plan to harden its infrastructure to better withstand storm damage. The settlement sets the cost for the system-wide project at $1.2 billion over three years, far less than the original price tag of $3.9 billion. The settlement allows PSEG to recover $1 billion of the costs from customers.
The plan, dubbed “Energy Strong,” was proposed in the wake of the damage done by Superstorm Sandy, which left millions of customers without power. The settlement means cutting the amount of improvements. PSEG Chief Executive Officer Ralph Izzo said he was disappointed that the program was scaled back but glad work will commence. “Clearly, we are not able to make every improvement we planned, but this settlement will allow us to begin to make meaningful upgrades, including upgrading substations that were flooded in Superstorm Sandy and Hurricane Irene,” he said.
Consumer advocates were more optimistic about the settlement. “This has gone from a massive, undefined and frankly unfair program in terms of method of cost recovery, to a now well-defined, targeted work that benefits customers,” said Rate Counsel Director Stefanie Brand.
The state Senate last week passed a two-year freeze in the state’s “green” energy standards and called for studies on their effectiveness. The green standards, mandating renewable energy and energy-efficiency programs, will go back into effect in 2017 without further legislative action.
The original version of SB 310 called for a permanent freeze in the standards, but Gov. John Kasich’s office pushed for the two-year “pause” and further study. Environmentalists, consumer advocates and some business groups have criticized the state’s green standards as too pro-utility. Supporters of the standards freeze, including FirstEnergy, argue that mandating further standards would lead to higher energy bills.
A House-sponsored measure that would cap variable electric rate hikes at 30% – introduced in the wake of the skyrocketing rates during this past winter – made it out of committee but didn’t make it to the floor for a vote before the House recessed.
Rep. Bob Godshall (R-Montgomery) introduced HB 2104 and gathered bipartisan support for the bill. But Godshall said a “full-scale attack” on the bill was launched by electricity suppliers. Some consumers who had signed up for variable rate plans saw bills double or triple this winter.
Electricity suppliers oppose the 30% cap. “HB 2104 in its current form would impose rate caps and price controls contrary to the original intent of electricity deregulation,” said Richard Hudson of the Retail Energy Supply Association. The House may reconsider the bill when it reconvenes in June.
Dominion Virginia Power is seeking a 6% rate increase to cover the unexpected spikes in winter fuel costs and to fund transmission line improvements. The request, filed with the State Corporation Commission last week, would raise a typical residential monthly bill from $107.99 to $114.36 if approved. About $4.46 of that is for fuel costs; the rest is for transmission work.
FirstEnergy subsidiaries Mon Power and Potomac Edison filed a joint rate increase request for $96 million with the state Public Service Commission. Mon Power and Potomac Edison serve about 385,000 and 135,000 customers, respectively. If approved, it would mean an increase of about $14 a month to a typical customer’s bill. The last base rate increase approved by the commission was five years ago.
Norman Bay, President Obama’s nominee for chairman of the Federal Energy Regulatory Commission, is about to get his day in the Senate, along with acting FERC Chairwoman Cheryl LaFleur. Obama nominated Bay, the director of FERC’s Office of Enforcement, on Jan. 30. The president nominated LaFleur to a second five-year term May 1.
It is Obama’s second attempt at filling the chairmanship left vacant since former Chairman Jon Wellinghoff’s term expired. Former Colorado regulator Ron Binz withdrew his nomination in October after failing to win enough support from the Senate Energy and Natural Resources Committee, which will conduct the confirmation hearing for Bay and LaFleur May 20.
Wellinghoff, an ally of Senate Majority Leader Harry Reid (D-Nev.), reportedly lobbied for the nomination of Bay, a former U.S. attorney whom Wellinghoff brought to the commission in 2009.
Committee Chair Mary Landrieu (D-La.), said last week she was impressed with Bay, calling him “very, very knowledgeable about energy markets and structure.” Sen. Joe Manchin (D-W.Va.), however, expressed concern about Bay’s energy experience. Unlike most FERC commissioners in the last decade, Bay has never served as a state utility regulator. Bay had no energy experience before joining FERC. (See FERC Pick a Blank Slate.)
Bay also may face tough questioning over the commission’s enforcement policies, which some critics have labeled heavy-handed. (See FERC, CFTC Reject Due Process Complaints.)
The Tennessee Valley Authority is cutting more than 10% of its workforce through early retirements, attrition and layoffs, its largest staff reduction in more than 20 years.
The federal utility, which has accepted 750 early retirements and won’t fill 1,000 vacant positions, said layoffs will be announced later this year. The company will also lay off 390 Bechtel contract workers from the Wyatt Bar Nuclear Plant in Texas. Staffing levels are at 12,612, down from 51,709 in the 1980s.
TVA says the cuts are necessary to bring staffing levels and electric rates in line with other utilities as power consumption in its service territory drops. TVA President Bill Johnson says he wants a $500 million reduction in annual expenses by next year. TVA supplies power to about 9 million people in Tennessee, Alabama, Mississippi, Kentucky, Georgia, North Carolina and Virginia.
The proposed Fishermen’s Energy project off the coast of Atlantic City and Dominion Resources’ project off Virginia Beach each will receive up to $47 million in federal funding, the Department of Energy announced last week.
Fishermen’s Energy won the grant even though the $188 million project was rejected by New Jersey regulators, who said it would cost utility customers too much. The company wants to build five 5-MW turbines as a laboratory for researchers to learn about offshore wind and investigate interactions between turbines.
The company’s chairman Dan Cohen said the grant was a recognition that “No other project in America is more prepared to put steel in the waters.” A spokesman for the Board of Public Utilities said he could not comment on the grant, noting that Fishermen’s Energy is appealing the agency’s rejection in state court.
Dominion’s project is a 12-MW wind farm to be built 26 miles off the coast of Virginia Beach. It will demonstrate installation, operation and maintenance methods for wind turbines located far from shore, and test hurricane-resistant designs.
A third project to be built off the Oregon coast will also get federal money, the Department of Energy said.
The Nuclear Energy Regulatory Commission is backing off allegations that Exelon purposely violated reporting regulations regarding its nuclear decommissioning funds.
The NRC last year charged that Exelon purposely misled regulators about the funds, but in a ruling issued May 1, it said that it found “insufficient evidence to support a conclusion that Exelon officials acted willfully.” The NRC ruling went on to say, however, that the inaccurate reports in 2005, 2006, 2007 and 2009 about the amount of money in the decommissioning funds was “avoidable.”
The solar array project atop the White House, a project started in 2010, went live last week, White House officials said. It is expected that President Obama will use the installation in announcements this week about further government-backed solar projects. A White House spokesperson described the solar array as capable of generating 6.3 kW and is “part of an energy retrofit that will improve the overall energy efficiency of the building.”
Energy Secretary Ernest Moniz called the installation “a really important message that solar is here. We are doing it, we can do a lot more.”
The Intermittent Resources Task Force will consider ways to implement recommendations of the recently completed PJM Renewable Integration Study.
The Market Implementation Committee voted last week to expand the IRTF’s charter, assigning it to deliver a plan for responding to the study by August.
The study by GE Energy Consulting recommended that PJM make changes in how it calculates regulation requirements and renewable power capacity values. It also suggested ways to improve the RTO’s wind and solar forecasts and ramp rate performance. (See RPS Targets’ Cost: $13.7B in Tx Upgrades.)
In Maryland and the District of Columbia, it would be hard to find a company more hated by consumers than Pepco. At PJM, consumers have had few better allies.
State regulators have no vote in the PJM stakeholder process although they frequently take part in debates. Consumer advocates for nine states and the district vote in the End User Customer sector. [Editor’s Note: An earlier version of this story misstated consumer advocates’ voting rights.]
Aside from them, it is up to the likes of a few large electric cooperatives and coalitions of municipal utilities and industrial consumers to speak up for “load.”
Having divested its generation, Pepco has more in common with Old Dominion Electric Cooperative and Lavallette, N.J., than generation owners such as Exelon. As a result, Pepco representatives Gloria Godson and John Brodbeck have often sided with load against supply.
Gloria Godson
“We’re on the side of the angels here,” Godson told state regulators last year at a meeting of the Organization of PJM States Inc. during a discussion on demand response’s role in the capacity markets. “We are working to implement your public policy objectives and change consumer behavior.”
Pepco will lose its independent voice with its acquisition by Exelon. While Pepco representatives may attend stakeholder meetings and vote at the lower committees, the company will lose its voting privileges at the senior Markets and Reliability and Members committees.
One of 46 Electric Distributor sector members, Pepco will be absorbed under Exelon Business Services Co. Although Exelon is a member of the Transmission Owner sector, its voting preferences are often driven by its generation holdings. Its representatives have been among the leaders of those urging limitations on demand response and other changes to increase prices in the energy and capacity markets.
Federal Energy Regulatory Commission rules prohibit utility holding companies such as Exelon from cross-subsidization or collusion among their subsidiaries — for example, barring the sharing of market-sensitive information between transmission and merchant functions.
Dan Griffiths
The Pepco acquisition raises a more subtle risk, said Dan Griffiths, executive director of the Consumer Advocates of PJM States (CAPS).
“It has to do with the diversity of options,” he said, citing ideas on fulfilling state energy efficiency obligations. “You will see things conforming that might not have in the past. When the voices are silenced, they’re silenced forever.”
The impact was illustrated last October, when Walter Hall, of the Maryland Public Service Commission, told stakeholders that Exelon’s Baltimore Gas & Electric shared Pepco’s concerns over the impact of PJM’s revised rules on state demand response programs.
Exelon’s proposed $6.8 billion acquisition of Pepco Holdings Inc. should clear federal regulatory hurdles easily but may face a tougher time winning support from the states.
The Federal Energy Regulatory Commission and the Justice Department should have few concerns because the Pepco acquisition will bring Exelon no additional generation and thus raise no supply-side market power concerns.
“I think [the regulatory risk is] pretty low at FERC and DOJ,” said an attorney who specializes in utility mergers.
“It sounds like it’s going to be a state battleground as opposed to anything at the national level,” agreed a former New Jersey regulator. “Those guys are going to be spending a lot of time in the state capitols to try to gin up support … lobbying the legislature, talking to the governors’ offices, Chambers of Commerce.”
Exelon has had plenty of experience with mergers. The company 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 also had its share of failures, dropping a merger with Public Service Enterprise Group in 2006 and having its overtures spurned by PPL in 1995 and NRG in 2009.
In a call with securities analysts Wednesday, Exelon CEO Christopher Crane said he was confident the deal will be approved. “The regulatory process is not easy in any jurisdiction,” he said. “We learned a lot from things that worked and things that haven’t worked in the past.”
Regulatory Hurdles
Exelon said it expects to make applications for regulatory approvals within 60 days in hopes of closing the deal in the second or third quarter of 2015.
Under the Federal Power Act, FERC must approve mergers that are “consistent with the public interest.” The commission makes that determination based on the effects on competition, rates and regulation (RM11-14).
Approvals will also be required from the District of Columbia and Maryland (served by Potomac Electric Power Co.), Delaware (Delmarva Power & Light), New Jersey (Atlantic City Electric Co.) and Virginia, where PHI owns property.
FERC has 180 days to rule. Maryland is required to rule within 225 days. Decisions in other jurisdictions may take slightly longer, Exelon said.
Positive Benefits Test
The states will insist the deal provide “positive benefits” or at least no harm. In interviews, state consumer advocates said they will be measuring the deal primarily based on its impact on rates and service quality.
Exelon said the Pepco deal would bring $250 million in “synergies” over the first five years. In its opening bid to the states, Exelon Wednesday proposed a split giving ratepayers two-thirds of the savings with shareholders keeping one-third.
Will that be enough? The states involved have reputations as tough negotiators.
David Bonar
Delaware Public Advocate David L. Bonar said he will push for a deal as attractive to his ratepayers as that offered to Baltimore Gas & Electric customers as a condition for Exelon’s takeover of Constellation. “We think in the long run this will be good for consumers,” he said.
New Jersey Division of Rate Counsel Stefanie A. Brand said she wasn’t sure how generous Exelon’s two-thirds offer is. “I’m not sure what’s typical,” she said. “These don’t come around very often.”
Feelings between New Jersey regulators and Exelon are still bruised by their experience in the failed $17 billion Exelon-PSEG merger. With approval from FERC and the Department of Justice in its pocket, Exelon needed only New Jersey’s approval to complete the deal. But it walked away after 19 months of negotiations with regulators, saying the state had demanded too much.
Stephanie Brand
The two companies had offered to give New Jersey ratepayers $600 million in cash and credits against future rate increases for natural gas delivery. But the Board of Public Utilities sought $820 million and the sale of two generators in addition to the four that the Justice Department had required.
Because Atlantic City Electric is the smallest of the three utilities involved in the current deal, the former New Jersey regulator said, the state is unlikely to be central to the success of the deal.
Analysts at UBS Securities predicted the Maryland Public Service Commission will be the “key hurdle.”
“Given Pepco’s historic regulatory challenges, this is not likely to be an easy execution and integration story,” UBS said.
Good Riddance?
Pepco has had a prickly relationship with regulators in Maryland and D.C. because of complaints about frequent outages and long restoration times. Some say that could play in Exelon’s favor.
Paula Carmody
“Since Pepco doesn’t have the greatest reputation for being reliable, it may mean that people will be happy that they’re being taken over,” said the mergers attorney. “I think that will help. I know that Maryland has in the past been very concerned about competition issues and that’s not an issue here.”
Maryland People’s Counsel Paula M. Carmody said Pepco has improved its service since 2010.
“You do not hear, generally speaking, the level of outrage you heard a couple years ago,” she said. “On the other hand we haven’t had big storms since Sandy.”
Exelon said it is committed to continuing the improvements in system reliability, customer service and outage restoration that Pepco has made.
Sandra Mattavous-Frye
Utilities taken over by Exelon have improved customer satisfaction more quickly than similarly sized electric utilities, J.D. Power told The Washington Post. Among 17 large utilities in J.D. Power’s eastern region, BGE ranked 11th in customer satisfaction and Peco was sixth. Pepco was 16th.
In the district, Pepco’s service quality slipped drastically during a rate increase moratorium that was part of a settlement over the company’s sale of its generation, said D.C. People’s Counsel Sandra Mattavous-Frye.
“Pepco has become more sensitive [since]. I would not want to see a diminishment of the responsiveness,” she said. “You are going from a smaller, more localized entity to a really large conglomerate. [The question is] whether or not that new conglomerate will have an affinity with the local community.”
Local Impact
To address local concerns, Exelon said Pepco will continue its current level of charitable contributions for a decade, promising a total of $50 million. It will maintain the utilities’ headquarters in D.C., Newark, Del., and Atlantic City and a “significant employee presence” in the affected states, it said.
It’s also offering a $100 million “Customer Investment Fund” — about $50 per customer — for rate credits, low income assistance and energy-efficiency programs.
Still, the “synergies” Exelon sees from adding Pepco are certain to mean job cuts.
D.C. law also requires regulators and the counsel to take into account the economic impact on the district, and that means considering the plight of Pepco’s 3,200 employees there, Mattavous-Frye said. The impact on jobs versus the impact on rates is “a balancing issue for me,” she said.
Exelon Everywhere
Maryland’s Carmody noted that most of Maryland will be served by Exelon subsidiaries BGE and Pepco if the merger is approved. The only other providers would be Potomac Edison (no relation to Pepco), two cooperatives and a few municipal utilities.
Is that a problem? Carmody isn’t sure. “I don’t know what those implications might be.”
She said she pays little attention to the promises that accompany merger announcements.
“Whatever they say, it doesn’t matter,” she said. “We’ll do our usual discovery, depositions to see what’s there. Until we see the filing and start digging into it I can’t tell you what our issues are going to be.”
Exelon CEO Christopher Crane said Wednesday the company’s $6.8 billion acquisition of Pepco Holdings Inc. is “the right deal [at] the right time” for Exelon shareholders.
But some analysts aren’t convinced, questioning the purchase price and potential regulatory challenges. They said it also raises questions about the strength of the recent rally in the generation sector.
Exelon will pay $27.25 a share for Pepco, a 27% premium over last Friday’s close, before word of a possible deal boosted Pepco shares Monday.
Exelon said the deal will create “the leading Mid-Atlantic electric and gas utility,” boosting its customer count to almost 9.8 million from 7.8 million (+25%) while increasing its rate base to almost $26 billion from $19 billion (+37%).
At a conference call Wednesday, Exelon executives said the deal would increase the company’s reliable regulated utility cash flow and earnings while preserving the upside from a rebound in power prices. Going forward, the company will get 60% to 65% of its earnings from regulated operations, up from the current 55% to 60%.
Half of the deal will be financed through debt, with the remainder a mix of common stock, mandatory convertibles and cash from $1 billion in sales of “non-core” fossil generation.
The purchase will be “highly accretive,” they said, increasing earnings by 15 to 20 cents per share by 2017.
Synergies
Exelon said the merger will generate $250 million in net “synergies” over five years, of which it will retain one-third and return the remainder to ratepayers. Officials said the synergies are a “very small element” of the accretion, higher leverage being a bigger factor.
Debt rating agencies look at Exelon’s regulated and merchant generation operations in total, Exelon Chief Financial Officer Jack Thayer said. Increasing the reliance on regulated earnings will provide “incremental leverage at the holding company that absent this transaction we wouldn’t be able to do.”
Thayer said Exelon’s projections on the deal assume Pepco returns on equity “very much akin” to those Pepco presented to analysts recently. State regulators would have allowed Pepco to earn as much as 9.6% last year but the company’s infrastructure spending limited its earnings to 7%, according to The Wall Street Journal.
Other Options
In response to analysts’ questions, Crane said alternative investments in conventional or renewable generation would have offered comparatively paltry returns. A combustion turbine costing $750 million to $1 billion would have added “a couple pennies at best” in earnings, he said, versus “15 to 20 cents [for Pepco]. It’s powerful.”
Crane said the purchase would not “deter or distract us from any opportunities on the power side.”
The regulated utilities will provide sufficient cash flow to service debt and the company’s dividend, leaving the company flexibility to grow on the generation side, officials said.
Crane said there was no “ideal” mix of regulated and merchant business. “What we learned in the last downturn in the commodity cycle was our commitments need to be sized to be sustainable … so both sides of the business can stand on their own.”
Analysts’ Doubts
Some analysts expressed doubts about the wisdom of the purchase. In the The Journal’’sHeard on the Street, columnist Liam Denning noted that Exelon is paying 22 times Pepco’s estimated 2014 earnings — a higher multiple than Google commands.
“This is despite the risks presented by a long regulatory review process in tough jurisdictions such as Maryland,” Denning wrote. “Exelon choosing to pay anyway reflects, in part, reasonable hopes it can find efficiencies in Pepco’s business. But it likely owes more to that rally in Exelon’s stock price, which will allow it to fund a large part of the deal by issuing new stock.”
First-Quarter Earnings
Exelon stock has risen about 30% since Jan. 1, thanks to a rebound in power and natural gas prices over the winter. The company Wednesday announced first-quarter earnings of $90 million, or 10 cents a share, compared to a loss of $4 million, or 1 cent a share, for the same period last year. Revenue shot up to $7.24 billion from $6.08 billion last year.
Denning said the rally in Exelon shares was based on the idea that the company’s generation fleet would benefit enough from rising electricity prices to overcome trends flattening demand growth. “That the company has taken the opportunity to buy a pricey hedge in the form of more regulated assets suggests it doesn’t wholly share that view,” he said.
UBS analysts also had questions. “While we appreciate the accretive nature of the transaction, the all-cash deal (in lieu of shares) is unusual and potentially emphasizes a lack of confidence on the combined outlook on behalf of PHI,” they wrote.
“We think the deal could take some wind out of the nascent power recovery, seeing management’s willingness to deploy its newfound currency.”
Too Good to Pass Up
But Crane said the low cost of debt and the flexibility the company retains to make future acquisitions made the deal too good to pass up.
“You have to be opportunistic. You have to be able to create value,” he said. “When you can create value with accretion like this, the right time is anytime it becomes available.”
PJM officials said last week that the RTO’s payments to frequently mitigated units (FMUs) jumped significantly over the winter, lending urgency to efforts to reduce the number of such units receiving “adder” payments.
Adder payments “suddenly became a much larger problem than it was before as a result of conditions that occurred in the winter,” PJM’s Tom Zadlo told the Markets and Reliability Committee Thursday. “We have seen a lot more units being frequently mitigated not because of thermal problems but for units running for reactive and automatic load rejection [black start] support.”
As a result, instead of the typical FMU profile — a combustion turbine running 300 hours per year — payments are going increasingly to generators running 1,000 to 3,000 hours yearly, which are operating “more like intermediate units,” Zadlo said.
PJM Executive Vice President for Operations Mike Kormos said the dynamics changed because rising gas prices made coal units more competitive.
The disclosure came on the first read of a proposal by PJM and the Independent Market Monitor that would limit the adders to units whose net revenues are not covering their avoidable cost rate (ACR). Had the proposal been in effect in 2013, it would have reduced the number of units receiving adders from 112 to only 28 — 23 of which are scheduled to retire.
Zadlo said the proposal will be flexible enough to “self-correct” if capacity market revenues increase, reducing the need for adders.
FMUs were allowed adders of $20 to $40/MWh to ensure that they cover their avoidable, or going-forward, costs. Market Monitor Joe Bowring said the adders became unnecessary for most units since the introduction of the capacity market in 2007 and changes to scarcity pricing rules in 2012.
The PJM-IMM proposal will be brought to a vote at the MRC’s next meeting. It appears to face strong opposition from generators, having won only 27% support in a poll of a generation-heavy Market Implementation Committee subgroup that has been considering alternatives. (See PJM-IMM Plan on FMUs Faces Generator Opposition.)
Ed Tatum, of Old Dominion Electric Cooperative, said the change in the FMU profile suggested a need to consider transmission upgrades.
“We are,” responded Kormos. “Unfortunately, transmission is always playing catch up.”
The proposal would eliminate all adders for fixed resource requirement (FRR) units, which prompted a protest from Dana Horton of AEP. “Why are FRRs getting picked on?” he asked.
The fixed revenue requirement allows load-serving entities to meet their capacity obligations by using their own resources rather than participating in the capacity auction. PJM officials said FRRs get going-forward costs from another revenue stream.
The PJM/IMM proposal is one of six packages on which the MIC subgroup — 22 responders representing 138 members — were polled. Two of the proposals (packages D and E) have since been withdrawn, Zadlo said.
The remaining three alternatives to the PJM/IMM plan each received support of at least two-thirds of those polled.
Package F has been “slightly tweaked” since the polling, Zadlo said.
Paul McGlynn, general manager of system planning, presented the Transmission Expansion Advisory Committee with preliminary cost allocation examples on the two least expensive projects among 10 finalists.
