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.
The bill for cleaning up coal ash from decades of operations in North Carolina could approach $10 billion, a Duke Energy executive told state lawmakers last week. In February, a broken pipe at an impound pond dumped tons of ash into the Dan River.
Coal ash pile at Duke Energy’s retired Dan River Steam Station in Eden, N.C. (Source: Duke)
Duke said two weeks ago that cleaning up that spill could reach $15 million but would not affect earnings.
But in a meeting with lawmakers last week, Duke’s North Carolina President Paul Newton said cleaning up the estimated 100 million tons of ash at 33 coal ash dumps at 14 coal-fired plants in the state could approach $10 billion unless the company is given some flexibility in how it approaches the problem. Newton said a large part of that cost could fall on ratepayers. “We are doing, and will continue to do, what it takes to make this right,” said Newton, who repeated his earlier public apologies for the spill.
Molly Diggins, the director of the N.C. Sierra Club, scoffed at Duke’s presentation. “Despite being a Fortune 500 company, with profits of $2.7 billion last year, Duke Energy has successfully been allowed to manage its wet coal ash waste as if the clock had stopped half a century ago,” Diggins said.
Time is running out for policy makers to recognize the value of nuclear generation as an “always-on source of carbon-free energy,” Exelon Senior Vice President and Chief Strategy Office William Von Hoene Jr. told the United States Energy Association Public Policy Forum last week.
“The loss of 25% of existing nuclear facilities would cut U.S. progress toward achieving its 2020 climate change goals in half. In fact, closing even a few nuclear plants could make achieving state and national carbon reduction goals difficult or impossible,” Von Hoene said, citing government energy policy and market structures. “The unfortunate reality for nuclear right now is that, despite being the largest, most reliable and lowest-emitting power plants — and among the lowest cost — they are not getting recognized or compensated for those attributes.”
Von Hoene said nuclear generation helped prevent a threat to grid reliability during last winter’s brutally cold weather. Nuclear generation came through when other generation sources, such as coal- and natural gas-fired plants, experienced high outage rates.
Exelon’s Handley Generating Station, Fort Worth, Texas (Source: Exelon)
A combination of plant retirements, nuclear plant uprates, energy efficiency and other programs helped Exelon reach its goal of eliminating 17.5 million tons of greenhouse gas emissions seven years before its 2020 target, the company said last week.
Exelon said it reduced its GHG emissions by 9.8 million tons through fossil plant retirements and company energy-efficiency programs. It chalked up another reduction by adding 316 MW of emission-free generation through uprates to its nuclear fleet. Customer energy-efficiency programs through its BGE, ComEd and PECO utilities counted for a 3.3 million ton reduction, it said.
The Federal Energy Regulatory Commission last week approved NRG Energy’s plan to sell stakes in a collection of co-generation plants in California while obtaining full ownership of a 586-MW natural gas-fired plant in the state. It is the latest in a series of reallocations and consolidations by the company.
NRG, which already owned 50% of Sunrise Power Co. LLC, purchased the other 50% of the natural gas plant from affiliates of oil-producer Chevron, which in turn will assume NRG’s 50% ownership in the co-gens. NRG had assumed the ownership of the co-gens as a result of its recent purchase of Edison Mission Energy.
Xcel Energy ranked as the nation’s top utility in wind energy for the 10th straight year, according to a study from the American Wind Energy Association. Xcel produces more than 5,000 MW through its wind facilities, 15% of its total capacity.
“We embraced wind energy early because it’s clean, cost-effective and will protect our customers against rising fuel prices in the future,” said Xcel CEO Ben Fowke in a written statement. The company said it is ahead of its goal of cutting its carbon emissions by 20%, predicting a 31% reduction over 2005 levels by 2020. Last year Xcel announced plans to expand its wind power use by another 40% over the next several years. The company is finalizing approvals and agreements to participate in nine new projects that will add a total of 1,900 MW throughout its service territory, enough to serve about 900,000 homes.
FirstEnergy Waives Polar Vortex Charges for Residential Customers
FirstEnergy Solutions is backing off plans to assess residential customers a surcharge for spiking energy prices during this winter’s polar vortex. The move came after Ohio regulators announced an investigation into the charges, which would have cost customers $5 to $10 each.
FirstEnergy earlier said it would pass through wholesale energy charges originating from PJM after the RTO had to resort to expensive emergency procedures to ensure system reliability.
Although FirstEnergy’s Ohio residential customers are off the hook, aggregation customers are still subject to it. One Ohio aggregator town, Parma, has filed a complaint with the Ohio regulatory agency about the surcharge, which would average about $7 per customer.
ComEd’s Grand Prairie TX Line Plan Greeted with Opposition
About 300 people attended a public meeting last week to discuss ComEd’s plan for a 60-mile transmission line between Exelon’s Byron Nuclear Generating Station and a substation in Wayne. The Grand Prairie project, intended to relieve transmission congestion in the area, would save customers about $500 million over the course of the first 15 years, said Fidel Marquez, ComEd’s senior vice president for governmental and external affairs. “We fully recognize that people have concerns and questions,” he said, adding, “We understand that no route will satisfy all constituents.”
Many residents said they were opposed to the $250 million aerial transmission project and asked if it could be constructed underground. A ComEd representative said it would cost about $50 million to bury power lines on a single 1.8-mile stretch. The Illinois Commerce Commission is expected to make a decision about the project by mid-July.
High Power Prices, High Demand Push Up AEP’s Earnings, Guidance
Higher demand and increased power costs pushed American Electric Power Co.’s first-quarter earnings up 54% over 2013. The company increased its 2014 earnings guidance to $3.35 to $3.55 a share from $3.20 to $3.40 a share. The company posted earnings of $560 million, or $1.15 per share, up from $363 million, or 75 cents a share, a year ago.
“Solid regulated business results and strong performance from our competitive energy businesses, bolstered by favorable weather and high power prices, resulted in a very positive first-quarter 2014 performance,” CEO Nicholas Akins said in a statement. “Our competitive Generation and Marketing business performed incredibly well during the extreme weather and helped meet record demand in the PJM Interconnection.”
Ameren Illinois is seeking a $69 million rate hike it says follows the mandate to set up a “smart grid” program. If approved, it would mean increases of between $6.37 and $9.55 a month for the average residential customer.
Illinois’ smart-grid law calls for the state’s utilities to invest millions in the electric grid in exchange for a formula-based rate process that lets companies recoup costs quickly. “Rates have decreased significantly through the formula rate process,” Craig Nelson, the company’s senior vice president of regulatory affairs and financial services, said in written testimony submitted to the commission. “As a result, even with the full impact of this rate increase, most residential customers will be paying less in 2015 than they did in 2011.”
Utility watchdogs vowed close scrutiny. “We will do our best to eliminate unjustified spending and reduce the proposed increase as much as possible,” said David Kolata, executive director of the Citizens Utility Board, an Illinois consumer group.
INDIANA Indianapolis Electric Car Program Spurs Call for $16 Million Rate Hike
(Source: Wikimedia)
The city of Indianapolis joined Indianapolis Power and Light in a request for a $16 million rate hike to fund the city’s proposed electric car sharing program.
The rate hike, which would cost the typical residential customer about 44 cents monthly, would go into effect January 2018.
IPL said it would cost about $16 million to build and power 1,000 charging stations for the cars, which residents could rent for as little as 15 minutes at a time. Bollore Group, a French concern, would provide 500 plug-in cars and will invest $35 million in the program.
The electric car sharing service would be the largest in the United States and would complement Bollore’s plan to convert the city’s 3,100-vehicle fleet to electric, natural gas or hybrid vehicles by 2025.
Pepco is asking regulators for a $43 million rate hike, its third increase request in three years. The increase, which would go into effect July 4, would raise the average monthly bill for customers in Montgomery and Prince George’s counties by $4.80. This would come atop a 2013 increase of $27 million.
Pepco has been a magnet for criticism for several years, primarily due to its reliability record. “Pepco should not be allowed to request a rate increase from the [Public Service Commission] until it can prove that it can keep power on consistently for one month,” said Abbe Milstein, founder of Powerupmontco, a group that advocates for ratepayers’ rights.
Pepco CEO Joseph Rigby has said the company plans to file a rate increase request every year for the next couple years.
NEW JERSEY Fisherman Wind Project May Not Be Dead Yet
Fishermen’s Energy said it will appeal the Board of Public Utilities rejection of its proposed 25-MW offshore wind farm. “We are disappointed in this decision but not surprised,” said Paul Gallagher, Fishermen’s chief operating officer following a second BPU defeat last week. “We are grateful that New Jersey has an independent judiciary and look forward to having the merits of our application finally heard.”
Fishermen’s wanted the BPU to delay its ruling until the U.S Department of Energy came out with the final round of grants for demonstration offshore wind projects. Fishermen’s has complained that the BPU overestimated the end-price of the energy its project would generate. The board said last month that the $188 million project would be too risky for electric ratepayers.
The project’s five turbines would have generated about 25 MW of electricity, but the project depended on a mixture of subsidies and federal grants to make sure ratepayers didn’t get stuck with sky-high bills.
PENNSYLVANIA Polar Vortex-Related Rate Spikes Spur Retreat to Default Suppliers
Spiking power rates following the polar vortex spurred nearly 50,000 Pennsylvania electricity customers to back away from competitive suppliers, the Public Utilities Commission said last week. The PUC reported that the retreat from competitive suppliers came after wild price swings for variable rate customers. The PUC said that 2,177,499 customers are signed up with competitive suppliers, down 49,368, or 2.2%, from early March.
The Public Utility Commission agreed to consider a PPL Electric Utilities request to increase customer fees to cover storm damage costs.
On April 3, the PUC approved a rider allowing the company to bill customers for any storm-related damage not covered by the $14.7 million already collected in base rates. The order limited the rider to 3% of PPL’s 2012 distribution revenue, or $25.5 million.
The PUC agreed last week to consider PPL’s request to base the cap on all distribution, transmission and generation fees. “We are seeking clarification on how that 3% cap is calculated,” said Bryan Hay, a PPL spokesman. “We don’t oppose the concept of a cap. We believe the cap is set too low.”
Sunoco Pipeline L.P.’s application to become a public utility, which would exempt its planned 299-mile Mariner East pipeline from local zoning codes, has environmental groups up in arms. Four groups — the Delaware Riverkeeper Network, the Clean Air Council, the Pipeline Safety Coalition and the Mountain Watershed Association — filed requests to intervene in the case before the Public Utility Commission. The groups argue that Sunoco doesn’t qualify as a public utility.
Sunoco is converting a refined-oil pipeline to carry natural gas liquids from the state’s Marcellus Shale fields to an energy hub Sunoco is building at its former Marcus Hook Refinery.
Senate Majority Leader Dominic Pileggi supports shale-gas development but says he is against granting Sunoco’s exemptions. “The economic benefits of the Marcellus Shale industry must be carefully balanced with the potential burdens to our communities and the environment,” Pileggi wrote. “Requiring Sunoco to respect local ordinances related to pipeline construction will help to achieve this balance.”
WEST VIRGINIA Marshall County Approves Combined Cycle Plant
The Marshall County Commission gave its go-ahead for the construction of a $615 million natural gas combined cycle generating plant. The 549-MW plant would be built on a 37.5-acre plot currently owned by Honeywell International.
The plant will need state and federal approvals, but developer Moundsville Power LLC says it is confident of a 2015 construction start, with the plant going into operation by 2018.
Adopting the Market Monitor’s proposed changes to capacity market rules could almost triple auction revenues, the Monitor said in a report last week.
The Monitor said the $5.5 billion generated during the 2016/17 Base Residual Auction last year would have been $6.9 billion if the Short-Term Resource Procurement Target had been eliminated. The target cuts the amount of capacity acquired in the base auction by 2.5%, setting it aside for purchase in incremental auctions for the delivery year.
The 2.5% reduction removed 4,153 MW from the RTO demand curve, the Monitor said in an analysis of last year’s BRA. The target, which reduced clearing prices and quantities for all regions in the auction, should be eliminated, the Monitor said.
“The 2.5% demand reduction is a barrier to entry in the capacity market for both new generation capacity and new DR capacity,” the Monitor said. “The logic of reducing demand in a market design that looks three years forward, to permit other resources to clear in incremental auctions, is not supportable and has no basis in economics.”
‘Inferior’ Demand Response
The Monitor said revenues would have been $10.1 billion if only generation and Annual DR were offered, and Limited and Extended DR were eliminated.
The Monitor said Limited and the Extended Summer DR should be eliminated, and the restrictions on the availability of Annual DR ended, so that DR has the same obligation as generation to provide capacity year round.
“The Annual DR product definition is the only one consistent with being a capacity resource,” the Monitor said.
Eliminating both the 2.5% holdback and “inferior” DR would have produced $15.8 billion in revenues, the Monitor said, almost three times what capacity resources actually received.
Import Impact
The report also looked at the impact of generation imports on clearing prices.
It found that excluding external generation without firm transmission would have boosted revenues to $6.8 billion, an increase of almost $1.3 billion.
Reducing external generation offers by 25% would have increased revenues by $637.5 million, the report said.
The Federal Energy Regulatory Commission last week approved a rule change that will reduce capacity imports by as much as 17% from what cleared in the 2013 auction. (See related story, FERC Clears Capacity Import Limits.)
PJM rules are making it difficult for banks to purchase capacity providers’ revenue streams, Citigroup Energy told the Markets and Reliability Committee last week.
Citigroup Energy’s Barry Trayers presented a first read of a proposed problem statement to consider changing the rules, which require PJM to wait until after the third incremental auction (IA) before reassigning revenue streams from one PJM member to another.
Trayers said Citigroup purchases revenue streams at a discount from capacity providers who prefer to receive their proceeds in a lump sum. “I have customers out there who want to do it. It’s just very difficult to do it,” under current rules, he said. “I’m only [seeking to change] when PJM approves the transaction.”
Trayers said the rule will need to be changed because a proposed Tariff change now pending before the Federal Energy Regulatory Commission would eliminate the third IA, potentially putting such deals in limbo. (See Second Time Not the Charm.)
Harry Singh, of Goldman Sachs, also supported consideration of the rule change but asked for further clarity on whether PJM considers these “auction specific capacity” transactions to be “physical transactions” or simply a reassignment of receivables.
Stu Bresler, vice president of market operations, said the RTO supports “opening discussion” on the issue. PJM Chief Financial Officer Suzanne Daugherty said the change proposed by Citigroup should not increase risks to PJM members because the capacity provider will remain liable for capacity deficiency charges. PJM will retain the capacity provider’s posted collateral and could tap into the reassigned cash flow if needed to cover any shortfalls, she said.
Trayers’ request to waive first read and have an immediate vote on the problem statement was rejected by MRC chair Mike Kormos when several members objected. The issue will be brought to a vote at the MRC’s next meeting.
PJM will ask stakeholders to consider changing the historical allocation of Auction Revenue Rights, Executive Vice President for Markets Andy Ott told members last week.
Ott told the Members Committee webinar that the number of facilities resulting in ARR infeasibilities have increased steadily since 2012, largely due to transmission outages (see chart).
(Source: PJM Interconnection, LLC)
“We’ve seen constraints come up that we haven’t seen before,” Ott said. “… PJM can build its way out of it, but it’s going to take years.”
Ott said PJM will begin discussing Stage 1A ARR allocations at the end of May or early June in hopes of making changes before the next allocation in spring 2015.
ARRs are allocated annually to firm transmission service customers, entitling them to receive a share of the revenues from the annual auction of Financial Transmission Rights. The infeasibilities, in turn, contribute to shortfalls in FTR revenues.
Total ARRs are capped based on historical generation capability and zonal base load. For the 2014/15 allocation, the zonal base load was based on the minimum daily peaks for the year beginning Oct. 22, 2012.
Infeasibilities have increased due in part to uncompensated power flow (loop flow) and additional market-to-market flowgates, but increased transmission outages is the primary factor, Ott said.
Generation retirements — which were not anticipated when the Stage 1A process was designed — also have played a role. More than 15% of Stage 1 historical generation (25,544 MW) has retired or submitted deactivation notices.
The retirements require PJM to remap historical resources to an equivalent generator or create a “dummy” generator for ARR and pricing purposes. This can create additional Stage 1A infeasibilities, PJM says.
“The system seems to be able carry less and less of” the historic, “grandfathered” rights, Ott said. “We really need to take a fresh look at this. The solution is a high-level solution: Change the way things are allocated.”
In June, the Federal Energy Regulatory Commission rejected a complaint (EL13-47) by FirstEnergy Solutions Corp. that sought to bill all transmission users to make up FTR shortfalls. Since then, market participants say, the problem has only gotten worse with cumulative shortfalls exceeding $1.1 billion. (See FTR Holders Seek Shortfall Fix.)
Members agreed to consider an easier method for transmission owners to access real-time generator data, an effort to improve situational awareness and emergency response.
The Markets and Reliability Committee last week approved a problem statement by AEP’s Dana Horton to ease TO access to real-time MW output and MVar data. The data would be used as inputs to the TOs’ state estimators.
Horton said TOs are discouraged from obtaining the information under the current process, which he said is “burdensome and time-consuming.”
The information will improve TOs’ ability to “assess the impacts of external conditions and be able to develop effective plans or implement corrective actions to maintain reliability,” the problem statement said.
Under an issue charge approved by the MRC, the Operating Committee will consider developing new access rules and determine “the appropriate uses, storage and protection of the data.”
