PJM and the Independent Market Monitor warned last week that they will refer traders who improperly arbitrage price differences between PJM and other regions to the Federal Energy Regulatory Commission for enforcement action.
PJM and the IMM said they will target traders who schedule interchange trades for the last 15 minutes of an hour based on price differentials in the first portion of the hour, a scheme known as “slamming the close.”
Although PJM settles trades based on hourly average prices, it posts prices on a five-minute basis. “Historically we have seen traders submit significant megawatt volumes of transactions only for the last 15 minutes of an hour once they have seen the five-minute prices for the first 20 minutes,” PJM spokeswoman Paula DuPont-Kidd explained.
The PJM-IMM notice said that such “transactions provide no value by way of enhanced market efficiencies or operational benefit and could constitute manipulative, harmful or inappropriate market behavior.”
It also said they would refer to FERC interchange transactions between PJM and external balancing authorities that began at 45 minutes past the hour and end at the top of the next hour, as well as transactions “that would result in the same or similar settlement.”
The notice cited the following examples:
Modifying the volume of an existing schedule for the last 15 minutes of the hour.
Scheduling a transaction that begins at 45 minutes past the hour and continues into the next hour but is partially offset by another transaction in the opposite direction that begins at the top of the hour. This would include trades by corporate affiliates.
Transactions that are scheduled to begin at 45 minutes past the hour and stop at 15 minutes past the top of the next hour if officials believe they were submitted to exploit PJM’s hourly integrated settlements.
2008 Rule
PJM and MISO implemented rules in 2008 to prevent such trading, with PJM requiring that that interchange transactions have a minimum duration of 45 minutes.
But FERC ruled in April that PJM’s minimum duration was inconsistent with Order 764, which required 15-minute energy scheduling intervals with 20-minute notifications. (See FERC Rejects PJM Schedule Rules.) Order 764, issued in 2012, is intended to remove barriers to variable generation sources such as wind.
In 2007, MISO and its Independent Market Monitor determined that nearly 60% of intra-hour schedules between MISO and PJM occurred in the final 15 minutes of the hour. PJM said this resulted in interchange spikes of up to 1,000 MW — increasing uplift charges because of the need to call on combustion turbines to balance the generation swings.
Partial Path Scheduling
PJM and the IMM said they also may refer traders that submit external interchange schedules that appear to have been designed to exploit price differentials and do not result in physical energy flow: “For example, multiple interchange schedules, each of which represents a partial schedule that does not reflect the full physical energy path, or schedules that are in the opposite direction of a portion of a larger transaction that involves multiple Balancing Authorities so as to ‘cancel out’ the physical flow that would otherwise be caused by a portion of the larger transaction.”
Traders who believe they have “a bona fide commercial rationale” for any prohibited transactions should discuss the issue with PJM and the IMM beforehand, they said.
The Markets and Reliability Committee last week heard first reading on proposed deadline changes recommended by the Market Settlement Subcommittee. Assuming they clear the Market Implementation Committee Wednesday, the issues will be brought to an MRC vote at its next meeting Aug. 21.
Power Meter and InSchedule Deadlines
More than two-thirds of Market Settlement Subcommittee members polled supported the following changes:
o Extending the deadlines for electric distribution companies (EDCs) to submit Power Meter and InSchedule data to address problems with reporting output for non-utility generators. The delay will allow a higher percentage of actual load data to be reported in InSchedule, particularly for EDCs with smart meters, and reduce the reconciliation adjustments.
Power Meter deadlines would be extended by an hour effective Oct. 1.
o Monday – Thursday Operating Days: Next business day @ 4 p.m. Eastern Prevailing Time (EPT)
o Extending meter correction data deadlines by one month. The change would allow more time for generators and EDCs to gather data, improving accuracy of submitted corrections and reducing or eliminating later bilateral adjustments. PJM also would gain additional time to process and include the meter corrections in the bill.
o Allowing load reconciliation data to be considered in balancing operating reserve (BOR) for deviation calculations, effective Jan. 1, 2015. The change will affect all participants with BOR deviations. Load reconciliation billing would be performed under the current 60-day schedule.
Capacity Charge Reconciliation
About 78% of Market Settlement Subcommittee members polled indicated support for a change to provide relief for Pennsylvania EDCs squeezed by PJM and Pennsylvania Public Utility Commission deadlines.
PJM requires EDCs to upload their Peak Load Contribution (PLC) and Network Service Peak Load (NSPL) data to eRPM 36 hours prior to the operating day. The Pennsylvania PUC issued an order in April requiring that EDCs switch customers to new energy suppliers within three business days of notification of the switch. Under the PUC’s previous rules, it took 11 to 40 days to switch electric suppliers.
The new rule gives EDCs only one day to update their records to recognize the change and correct the PLC and NSPL values, raising the possibility of retail suppliers receiving inaccurate capacity charges.
The subcommittee proposal would retain PJM’s 36-hour advance submission deadline but allow corrections to be made until noon the next business day.
State Creates Green Fund to Spur Solar Installations
The Department of Natural Resources and Environmental Control and the Sustainable Energy Utility are combining efforts in a Joint Green Energy Fund to help residents, businesses and nonprofits install solar and geothermal technology.
The SEU, a non-profit organization created by the state, has committed $1.5 million for each of the next two years to buy solar renewable energy credits at a price of $0.45/watt for the first 20 years of solar production. The program is open to systems of up to 50 kW in size, regardless of the customer’s electric provider. The state’s original Green Energy Fund was open only to those in the Delmarva Power & Light service territory.
SEU also agreed to put up $2 million over two years to commercial and non-profit geothermal and solar water heating systems. SEU funds come in part from the Regional Greenhouse Gas Initiative.
The Public Service Commission has started public hearings on Pepco’s plan to put 21 of its most troubled feeder lines underground. Pepco said the first leg of the project, which could take up to 10 years, would cost about $434 million.
A Pepco official, Caryn Bacon, said placing feeders underground won’t solve all problems. “It is true when you place a feeder underground it is more difficult to locate the fault,” Bacon said, but she added that the plan calls for redundancies to reduce extended outages. The PSC is expected to rule on the Pepco plan in October.
Court: Regulators Can Force Consumers to Buy ‘Clean Coal’
Illinois consumers could be forced to purchase electricity from the troubled FutureGen 2.0 project as a way to guarantee continued financing for it, a state appellate court has ruled. The ruling upheld an Illinois Commerce Commission ruling.
Illinois has a “Clean Coal Portfolio Standard” mandating that a portion of the state’s energy come from clean coal projects. The FutureGen project, which would retrofit a coal-fired plant and then sequester its carbon dioxide underground, has been languishing while waiting for various court rulings.
The plant could be ready to burn Illinois coal and sequester the carbon dioxide by 2017. With the ruling, Illinois customers could be forced to pay an extra $1 to $1.40 a month for power from the project. Some power suppliers have vowed to appeal the ruling to the state Supreme Court.
The Public Service Commission approved a plan to convert Kentucky Power’s Big Sandy plant in Lawrence County from coal to natural gas.
Kentucky Power said the only way the 278-MW unit could meet air quality standards was to switch to natural gas.
The PSC said Friday that the plan to switch to gas “preserves a viable generating plant operating within the commonwealth, thus retaining some of the current employees and supporting the local tax base.” The retrofit is expected to cost $50 million.
A wind farm proposed for Maryland’s Eastern Shore could be held up by U.S. Sen. Barbara Mikulski, who added language to the defense appropriation bill mandating that no agreement between the developers and the U.S. Navy could be signed until a further study is completed. One of the things the study is researching is the effects of wind farm towers on the radar system at the Patuxent Naval Air Station.
The study isn’t due to be completed until next summer and developer Pioneer Green Energy said the delay could kill the project.
State lawmakers have introduced a package of bills tackling energy pricing, energy efficiency and technology and renewables. Called “Energy Freedom” by the bipartisan group that introduced it, the package addresses net metering, microgrids, fair-value pricing and renewable energy.
The bills have been referred to the House Committee on Energy and Technology. “I just want to make sure we do everything we can to promote renewables and clean-energy development in Michigan,” said state Rep. Jeff Irwin, a southeast Democrat and one of the sponsors.
A law passed two years ago to smooth out volatility in the solar market has resulted in a stable market and new growth in the solar industry, according to a Board of Public Utilities report. “New Jersey’s solar market is sound,’’ BPU President Dianne Solomon said.
The 2012 law was passed after an increase in solar capacity caused a drop in the price of solar credits. The report was required as part of the law, which led to a rebound in the price of solar credits and a corresponding increase in solar installation activity.
State legislators went home last week without producing a law addressing the state’s toxic coal ash sites. The issue became a priority after a spill earlier this year of up to 39,000 tons of ash from a Duke Energy site.
Both the House and the Senate traded bills, but a final bill was never acted on. Senate leaders blamed House members for hobbling a compromise bill with late provisions.
Environmentalists were dismayed by the General Assembly’s lack of action. “This is a multilayered failure of leadership. Both chambers failed to offer the comprehensive cleanup plan they promised at the outset of session,” said Donna Lisenby of the Waterkeeper Alliance.
While lawmakers failed to act, Gov. Pat McCrory did, by issuing an executive order directing the Department of Environment and Natural Resources to start groundwater tests at all of Duke’s ash ponds.
Report: State Officials Lax in Gas Industry Oversight
A report from the state Auditor General issued last week said the Department of Environmental Protection is unable to keep up with the demands presented by the shale gas drilling boom in the state.
Auditor General Eugene DePasquale said the department has failed to address many public complaints about air and water contamination. He also found that the department failed to make gas companies provide drinking water in 14 of 15 contamination cases.
DEP Secretary E. Christopher Abruzzo took issue with the report. “DEP has found that working with operators to obtain voluntary compliance with the law is often a more effective and expeditious method of restoring water supplies,” he wrote.
In an initial ruling, the Public Utility Commission has found that Sunoco’s proposed Mariner East pipeline does not qualify as a utility and therefore is not exempt from local zoning laws.
The company asked the commission for the utility status to help it with the permitting and construction of pumping stations it wants to build for the pipeline. The pipeline is planned to run from the shale gas region in the west of the state to a terminal at Marcus Hook on the Delaware River.
Under state law, utilities are exempt from some local zoning laws.
A “Southern accent reduction” class offered at the Oak Ridge National Laboratory has been cancelled after Southern-bred employees complained. The class, at the U.S. Department of Energy’s largest research facility, was to be taught by a Knoxville speech pathologist, Lisa Scott. She said many businesses offer “accent neutralization” services for foreign employees and those with strong regional American accents, especially ones from New York, Boston and Philadelphia. But Scott said the course was described in an email “in such a way that some people interpreted it that their Southern accent was a problem.”
Quarterly earnings calls aren’t only about the numbers. They are often platforms companies use to highlight other news.
Calpine last week announced plans for a new 760-MW plant in PJM, while PPL said it had proposed a 725-mile transmission line through New York, New Jersey, Pennsylvania and Maryland at a cost of $4 billion to $6 billion.
Exelon, which announced its acquisition of Pepco in its first-quarter earnings call in April, used its second-quarter earnings call to continue its push for state support for its Illinois nuclear plants.
EXELON
Exelon reported net income of $522 million, or 60 cents per share, for the second quarter this year, compared to $490 million, or 57 cents a share, for the same period last year. The 6.5% increase was due in large part to increased capacity prices in PJM, the company said.
The company — which has previously said that some of its Illinois nuclear plants are unprofitable and at risk of closing down — hopes to win state incentives for the plants’ contribution to the economy and their role in helping the state comply with the Environmental Protection Agency’s proposed carbon emissions rule.
“State agencies are drafting a number of reports that will look at the economic value of the units to the local communities, jobs, the value of the energy produced, the value of the low carbon resources,” said Joseph Dominguez, Exelon’s senior vice president of government and regulatory affairs. He said he expected to see the reports in November or December.
“It’s pretty clear that if you lose nuclear plants, your ability to comply with any carbon regime going forward is going to be jeopardized,” CEO Chris Crane said.
PPL
PPL reported earnings of $229 million, or 34 cents per share, compared to $405 million, or 63 cents per share, last year. That included a special charge of $128 million, or 19 cents per share, related primarily to the anticipated spinoff of PPL Energy Supply.
“Strong performance at each of our regulated utilities with stronger margins from our competitive Energy Supply business led to very solid results through the first half of the year,” CEO William H. Spence said.
Route of PPL’s proposed transmission line.
Spence announced that PPL has submitted to PJM a proposal to build a 725-mile, 500-kV transmission line that would run from Western Pennsylvania into New York and New Jersey, with another spur running south into Maryland. Spence estimated the cost for the project at between $4 billion and $6 billion. He said if construction begins by 2017, the project would be completed by 2023 to 2025.
PPL said the line would address both reliability and congestion as well as move power expected to be produced by new generators fueled by shale gas in northern Pennsylvania. Spokesman Paul Wirth said it would address reliability problems on three 230-kV lines: Lackawanna-North Meshoppen, Montour-Sunbury and Siegfried-Frackville.
CALPINE
Calpine reported a profit of $139 million, or 33 cents per share. During the same period last year, it showed a loss of $70 million, or 16 cents per share. Operating revenues drove most of the improvement, as they climbed from $1.57 billion to $1.94 billion, an increase of about 23%.
Calpine signaled its confidence in the PJM market by announcing a new 760-MW generator at its York Energy Center near Delta, Pa. It is to be built on the site of its existing 565-MW combined-cycle plant. Using existing infrastructure will result in construction savings, and its location will allow it to take advantage of shale gas from Pennsylvania fields, according to CEO Thad Hill.
PEPCO
Pepco Holdings Inc. reported adjusted net income of $71 million, or 28 cents a share, compared to $53 million, or 21 cents per share, last year. The company credited higher electric distribution and transmission revenue and lower operation and maintenance expense for the uptick.
Pepco reported that applications for approval of its acquisition by Exelon have been filed with the Federal Energy Regulatory Commission, the Virginia State Corporation Commission, the Delaware Public Service Commission, the D.C. Public Service Commission and the New Jersey Board of Public Utilities.
Filings with the Maryland Public Service Commission are expected in the coming quarter.
DOMINION
Dominion Resources reported earnings of $159 million, or 27 cents per share, compared to $202 million, or 35 cents per share, last year, a decline of 21%. The company attributed the dip to milder weather, and a one-time charge resulting from Virginia legislation that permitted the company to recover 70% of the costs previously deferred or capitalized relating to the development of a third nuclear unit at North Anna and offshore wind facilities. Revenue declined to $2.81 billion from $2.98 billion, or 5.6%.
Thomas F. Farrell II, Dominion’s chairman, president and CEO, noted on a conference call that the company recently received an environment assessment approval from FERC for its Cove Point LNG facility in Maryland. Farrell also noted the company’s acquisition of two solar projects in Tennessee and an agreement to acquire its seventh in California, bringing its total solar projects in operation or development to 232 MW.
AEP
American Electric Power reported earnings of $390 million, or 80 cents per share, compared to $338 million, or 69 cents per share, last year, an increase of about 15%.
CEO Nicholas K. Akins said the company’s regulated transmission business brought in 10 cents per share for the quarter, up from 4 cents for the same period last year. It is a part of the business AEP is counting on.
“The additional $300 million that we’ve allocated to our transmission business in 2014 brings our total transmission capital investment to approximately $1.9 billion, which will support future earnings growth,” Akins said.
PSEG
Public Service Electric Enterprise Group reported a profit of $212 million, or 42 cents a share, compared to $333 million, or 66 cents a share, for the second quarter, a drop of 36%.
An extended outage of its Salem nuclear station’s Unit 2 was the cause of some of the decline. PSEG Power, the company’s generation arm, showed a 74% drop in net income, from $210 million in the second quarter of last year to $54 million for the same period this year.
The company’s regulated utility business reported a 25% rise in profit — $151 million on revenue of $1.435 billion this year, from $121 million on $1.423 billion last year.
“The primary driver of growth — increased investment in transmission in our utility PSE&G — remained strong in the second quarter, offsetting the impact from mixed operating conditions,” PSEG Chief Executive Ralph Izzo said.
From left to right: FERC Acting Chair Cheryl LaFleur; Commissioners Philip Moeller, John Norris and Tony Clark; and FERC Office of Enforcement Director Norman Bay.
WASHINGTON — Summoned to Capitol Hill, members of the Federal Energy Regulatory Commission last week revealed differences over the impact of the Environmental Protection Agency’s proposed carbon emission rule but declined to endorse climate change skeptics’ do-nothing strategy.
Speaking before the House Energy and Commerce Committee’s energy and power subcommittee, Commissioner Philip Moeller renewed his call for a reliability analysis on the impact of expected coal-plant shutdowns while Acting Chair Cheryl LaFleur and other members said such a study was premature.
Moeller and fellow Republican Tony Clark expressed more concern over the rule than the commission’s Democrats. But they refused to join subcommittee Chair Ed Whitefield (R-Ky.) and other Republicans in saying the EPA was wrong to act on climate change.
Whitfield dismissed warnings of increasing droughts, saying they were belied by this year’s bumper corn crop. He also rejected claims that the EPA acted because Congress had failed to do so. “Congress did act by deciding not to act” to approve a cap-and-trade bill in 2010, Whitfield said.
No Takers
Cheryl LaFleur
California Democrat Henry Waxman, co-sponsor of the bill, got his chance to respond a few minutes later, asking the commission members to raise their hands if they believed “there is no need to deal with climate change.” None did.
“We can reduce carbon emissions and keep the lights on,” Commissioner John Norris said. “I feel Congress is missing the point. [The EPA’s proposed rule] is a very gradual transition and a very necessary transition.”
LaFleur pushed back when Texas Republican Joe Barton said the EPA rule appears to conflict with FERC’s mandate to ensure power “at reasonable cost.” (LaFleur was named chairman effective July 30. See related story, Bay to Take FERC Gavel April 15.)
“I do not see the rule as inconsistent with FERC’s responsibilities,” she said.
The proposed rule seeks to reduce carbon dioxide emissions from electric generation by 30% from 2005 levels. The EPA set reduction targets for individual states based on four “building blocks”: unit-level efficiency improvements for coal-fired units; fuel switching from coal to natural gas; renewable energy and nuclear power; and demand-side energy efficiency.
In written responses to the subcommittee’s questions, the members revealed that none but LaFleur had any discussions with the EPA prior to the release of the proposed rule June 2. LaFleur said she or FERC staff met with EPA or Office of Management and Budget officials on seven occasions between February and July and that FERC had told officials of the need to respect reliability concerns in drafting the rule.
Norman Bay Speaks
Norman Bay
The session included FERC enforcement Director Norman Bay, who was confirmed as the commission’s fifth member last month and is awaiting his swearing in. Bay demonstrated that his transition from behind-the-scenes prosecutor to a commissioner is a work in progress, forgetting twice to press his microphone before speaking. Bay professed confidence that “the challenges [of implementing the rule] are manageable.”
Bay also was pressed by Texas Democrat Rep. Gene Green on his running of FERC’s Office of Enforcement. Green said FERC should create an office of compliance to provide “more transparency” to energy traders seeking to avoid running afoul of commission rules. Bay said FERC already maintains a help line and issues “no-action” letters in response to questions about market rules.
Call for Reliability Analysis
Philip Moeller
The session provided Moeller an opportunity to renew his call for a FERC-led reliability analysis. Moeller noted that the EPA has identified 180 GW of coal-fired generation that it expects to be shuttered as a result of the carbon rule and the Mercury and Air Toxics (MATS) rule, which takes effect next year.
Moeller acknowledged that disagreements on the reliability implications are likely but said “a reliability study shouldn’t be that difficult.”
“Getting the electricity reliability experts together in a public and transparent forum to address these questions and develop answers is the responsible approach. Engineers can debate and disagree on details, but presently there is no public forum for this discussion to occur,” Moeller said in written testimony. “Although the EPA’s proposal mentions the concept of reliability more than a hundred times, it’s the details of calculating proper reserve margins and specific load pockets that matter from a reliability perspective.”
But others on the commission agreed with LaFleur, who said that a study “could be more speculative than informative” due to uncertainty over the requirements of the final rule and how it will be implemented by the states.
“You’re not going to prove it is or isn’t going to work because it’s still in development,” Norris told the subcommittee.
Questioning EPA Assumptions
Moeller also raised questions about several of EPA’s assumptions, including its expectation that natural gas generators will reach dispatch factors of 70% and that there will be enough pipeline capacity built to support a change from coal to natural gas.
Moeller said 70% gas dispatch “has been very rarely done in this country.”
Moeller said officials haven’t figured out a way to obtain financing for pipeline expansions to serve generators and that the EPA “doesn’t fully understand the challenges.” Generators are reluctant to sign long-term gas supply contracts — which traditionally have enabled financing of pipelines — because of uncertainty over how much they will be dispatched.
Norris said the increase in natural gas-fired generation capacity assumed by the EPA will be “challenging but not impossible.”
Moeller also suggested the rule could inhibit economic growth by “essentially capping” electricity consumption in 2030 and differed from LaFleur on whether the EPA had adequately accounted for interstate power flows.
Clark said he feared a “jurisdictional train wreck” between the EPA and FERC and said states may be forced into a “‘mother-may-I?’ relationship” with the agency, which will pass judgment on individual State Implementation Plans (SIPs). Once approved, SIPs could limit states’ ability to change building codes and renewable portfolio or energy-efficiency standards, Clark said.
Impact on RTOs
Much of the discussion concerned the rule’s likely impact on PJM and other RTO markets. Moeller said the rule would result in a shift from economic dispatch to “environmental dispatch.”
“It’s a fundamental change … with how the system operates. It needs to be examined very carefully,” Moeller said.
LaFleur said it was “too soon to speculate” on the impact on RTOs. She and Norris expressed confidence in RTOs’ ability to respond, noting that PJM and others have incorporated regional cap-and-trade programs and state renewable portfolio standards into their market operations.
“We’ll have a much better idea of the challenges once the SIPs are done,” LaFleur said.
A state appeals court decided that Commonwealth Edison must pay for the spoiled groceries and other costs that 35,000 of its customers suffered from a series of 2011 storms. The decision could set a precedent and force the company to pay in future cases.
The ruling upheld a 2013 decision by the Illinois Commerce Commission resulting from six summer storms and a blizzard in 2011. ComEd has said the decision could cost it up to $35 million in claims.
Exelon signaled that its Ginna Nuclear Power Plant in Ontario, N.Y., will remain a part of its nuclear fleet when it filed a petition for continued operation with the New York Public Service Commission. Earlier in the year, published reports indicated that the company was considering shutting the plant down, arguing that it was uneconomical.
The petition, filed in late July, indicates that the company will keep the 581-MW Ginna plant running if it gets a good enough power-purchase contract from Rochester Gas and Electric. An earlier study conducted by NYISO indicated that the plant was necessary for the continued reliability of the grid. Without that study, Exelon said, it would have considered shutting down the plant.
Entergy’s Indian Point Nuclear Plant may be temporarily shut down by an order from the New York Department of Environmental Conservation in a move designed to protect fish populations.
The outages, which would affect both units, could be for 42, 62 or 92 days a year, the department has proposed. The outages would take place between May and August of each year during the plant’s 20-year license extension period.
Entergy Vice President of License Renewal Fred Dacimo said taking the units offline during peak energy consumption months would result in increased prices and could lead to blackouts. “All of these impacts might be worth considering if outages at Indian Point were actually necessary to protect fish eggs and larvae, but they are not,” he said. He said Entergy has proposed alternate methods to protect aquatic wildlife.
Bolts that caused an extended outage at Unit 2 of Public Service Enterprise Group’s Salem nuclear plant were composed of an alloy that had been ruled unfit for use in nuclear equipment as far back as 1984, according to findings by the Nuclear Regulatory Commission and other sources.
The failure of the bolts, which were inside two reactor coolant pumps, was found during a scheduled offline period in April as the reactor underwent fuel replacement. PSEG announced in mid-May that the shutdown would be extended to fix the problem. The company restarted Unit 2 last month.
The manufacturer of the bolts, Westinghouse Electric, warned that parts loosened by bolt failures could have created a “substantial safety hazard” if they locked up rapidly spinning parts in one or more of the coolant pumps, according to NRC spokesman Neil Sheehan.
PSEG spokesman Joe Delmar said that Westinghouse issued a technical bulletin on the issue in 1996. The bulletin concluded that even if all bolts on a pump failed, “it would not affect the performance of the pump and, therefore, they did not recommend going in and replacing the bolts with others with different material unless you were going into the pump for another purpose,” Delmar said.
The NRC notified officials at Dominion’s Surry Units 1 and 2 reactors near Newport News, Va., of the problem. Surry is the only other plant to use the same “A-286” alloy bolts in coolant pumps. Dominion is reviewing reports from Salem “to evaluate a course of action going forward,” Sheehan said.
DTE Energy will close two units at its Trenton Channel coal plant in Trenton, Mich., in 2016 in part because of new Environmental Protection Agency emissions rules, the company announced last week. The two units generate a total of 210 MW. The closings will leave a single unit in operation at the plant, the 520-MW Unit 9.
“The decision was made because of new federal emissions regulations taking effect in the next few years, and because of DTE’s focus on reducing customers’ rates and maintaining competitive electric rates in the future,” DTE Randi Berris said.
Exelon and Pepco told the Federal Energy Regulatory Commission last week that competitive and environmental concerns raised by the Independent Market Monitor and others over their proposed merger are unfounded, reiterating their request for FERC approval by Aug. 30.
“None of the objections to the transaction has any merit, and the commission should approve it without conducting an evidentiary hearing or imposing additional conditions,” the companies said in a July 30 filing (EC14-96).
Although the transaction will not substantially increase Exelon’s generation portfolio — Pepco owns only 17 MW — commenters have told FERC the pairing threatens to hurt competition, the health of the Chesapeake Bay, prospects for renewable energy and the PJM stakeholder process.
Commenters also asked FERC to ensure that costs of the transaction are not passed on to transmission customers and to strengthen provisions to prevent cross-subsidization among Exelon’s subsidiaries.
Competitive Concerns
The IMM said FERC should require the companies to provide more information and impose behavioral mitigation to address “potential vertical and horizontal market power issues.”
The Monitor said that Exelon’s ownership of the intrastate natural gas distribution systems of PECO Energy and Baltimore Gas and Electric, combined with the gas assets of Pepco’s Delmarva Power & Light unit, raise concern over gas-fired generators’ access to fuel.
Julie Solomon of Navigant Consulting, who evaluated the competitive impact of the merger on behalf of the applicants, said that new gas-fired generators will likely connect directly to interstate pipelines and bypass Exelon’s local distribution companies (LDCs).
But the IMM said the application did not discuss the state rules for such bypass arrangements and whether LDCs can impose charges or other conditions on generators seeking service directly from an interstate pipeline.
The Delaware Public Service Commission said Exelon and Pepco’s LDCs have the potential to favor their generation affiliates “especially during periods when interstate natural gas pipelines in the Mid-Atlantic are severely constrained,” because they hold gas storage entitlements and firm transportation contracts on interstate pipelines.
Exelon and Pepco said their combination will hold 6% of the interstate pipeline capacity in PJM and 7-8% of the capacity in the AP South region and the 5004/5005 submarket in Maryland. Their share of natural gas storage in PJM will be about 2.5%.
The Delaware PSC also said the companies should demonstrate that they cannot use their LDCs’ pipeline capacity entitlements to raise delivered natural gas prices “and, consequently, electricity prices to the advantage of their generation affiliates.”
Exelon said that because it already owns BGE and PECO, “the only potential vertical market power concern” raised by the merger relates to Pepco’s Delmarva affiliate, “which does not serve any natural gas-fired generation from its local distribution facilities.”
“Certainly the Delaware PSC can make no claim that any of the applicants have ever improperly withheld gas transportation capacity or that the transaction in any way would facilitate the improper withholding of such capacity,” the applicants said.
Exelon Transmission Concentration
The IMM said that the increased ownership of transmission is also a concern and that the applicants overstated PJM’s control over their assets. The merger would give Exelon nearly one-quarter of the PJM transmission network, adding Pepco’s transmission, which accounts for 6.6% of PJM transmission service credits, to Exelon’s current 16.8%.
The IMM also said FERC should consider the impact of the merger on competition among transmission developers under FERC Order 1000.
Transmission owners can determine “the timeliness, the technical requirements for and the costs of” interconnections and set the line limits used by the RTO in their network models, the IMM said.
Exelon “will have substantial and increased influence over decisions that directly relate to competition in PJM among developers of transmission projects. Although the RTO has responsibility for the interconnection process, transmission owners perform interconnection studies for generation. Having a transmission owner involved in the study process creates a conflict of interest if they are also the developer or potential developer of a project or own competing generation,” the IMM said.
The IMM said FERC could address its concerns through behavioral mitigation, such as ordering independent interconnection studies and a process for reviewing and updating transmission limits.
Exelon said the IMM’s concern is “purely hypothetical [and] completely unsupported by any data or other evidence.”
It said its market power is mitigated by both its membership in PJM and FERC’s requirement that all transmission providers operate under the competitive protections of an Open Access Transmission Tariff.
Impact on Transmission Rates
The Southern Maryland Electric Cooperative (SMECO) and the Delaware Municipal Electric Corp. said FERC should prohibit Exelon from recovering its “acquisition premium” — the 25% difference between Pepco’s stock market value and Exelon’s purchase price — through wholesale transmission rates.
SMECO, which depends on seven interconnections with Pepco to supply its members, said that while Exelon promised not to seek recovery of the premium through retail rates, it made no such commitment to wholesale transmission customers. SMECO said FERC should insist Exelon’s promise to hold transmission customers harmless for five years applies to both the acquisition premium and transaction costs.
It also called for revisions to Pepco’s existing formula transmission rate to improve transparency and ensure customers have the information needed to review and challenge future rate-increase requests.
Exelon said it should not be prohibited from recovering merger-related costs if they are offset by merger-related savings. The applicants said FERC lacks jurisdiction to require changes to formula-rate protocols in the merger proceeding. “Such changes to an existing rate schedule may be ordered only in connection with a Section 206 complaint,” the company said.
Cross Subsidization
In their May 30 application to FERC, Exelon and Pepco said that “because of the de minimis nature of the competitive overlap,” the commission should be able to approve the transaction within 90 days.
The Delaware Municipal Electric Corp. said FERC should reject the applicants’ request for an expedited ruling, noting that state regulators have not yet examined the adequacy of the “ring-fencing” measures to address cross subsidization.
The D.C. Office of the People’s Counsel said the financial and geographical size of the merged company raises questions of “whether any one state regulatory body will be able to regulate the local utility subject to its jurisdiction.” The post-merger company would have regulated utilities in Illinois, Pennsylvania, Maryland, Delaware, New Jersey and D.C.
Exelon responded that the merger satisfies the commission’s cross-subsidization standards so that “no particular ring-fencing should be required.”
Environmental Concerns
The Clean Chesapeake Coalition, a group of nine northern and eastern Maryland counties, complained that Exelon — whose post-merger service territory would surround the Chesapeake Bay and its tributaries — has displayed a “lack of environmental due diligence.”
The coalition wants Exelon to do more to prevent sediment trapped by the dam at the Conowingo Hydroelectric Project from being released into the Chesapeake during storms.
The counties said they approached Exelon to express their concerns — at FERC’s direction — after attempting to intervene in the relicensing of the dam. They said that the company has not responded after more than three months. “Such disregard of local government concerns [is] an affront to the public interest,” the coalition said.
The Institute for Energy and Environmental Research and the Nuclear Information and Resource Service, two Maryland-based environmental groups, said the merger will increase Exelon’s influence in public policy debates over the merits of nuclear power versus renewables. Exelon would increase its share of residential electric distribution customers from 50% to 80% in Maryland while adding virtually all D.C. residents.
Exelon has been seeking additional compensation for the carbon-free generation of its nuclear fleet. The environmental organizations said this pits Exelon’s interests against those who support more renewables. The groups cited Environmental Protection Agency estimates that reducing carbon emissions through renewable portfolio standards costs $3 per metric ton while subsidizing “at-risk nuclear units” would be $12 to $17 per metric ton.
“If corporate money is free speech, as the Supreme Court has ruled, then FERC is obliged to consider the effect of increasing Exelon’s ability to speak in the political arena that the merger would cause,” the groups said.
Exelon said the environmental claims are “irrelevant to the commission’s review” of the merger.
PJM Influence
The IMM, Delaware PSC and D.C. Office of the People’s Counsel complained that the merger could give Exelon undue influence in the PJM stakeholder process.
Having divested its generation, Pepco has more in common with transmission-only cooperatives than generation owners such as Exelon; Pepco representative Gloria Godson has often sided with load against supply in PJM debates. (See Pepco to Lose its PJM Voice; Consumers Lose Frequent Ally.)
“The potential for the elimination of [Pepco]’s independent voice in the PJM stakeholder process should give this commission serious pause,” the DC Office of the People’s Counsel said.
The Delaware PSC noted that Exelon is a member of the Electric Power Supply Association (EPSA), the plaintiff in the lawsuit that resulted in an appellate court voiding FERC’s authority over compensation for demand response. “Exelon’s support for that outcome is not in line with consumer interests,” the Delaware regulators said.
The IMM said that “transmission owners have significant leverage” over RTOs and noted that Exelon’s participation in PJM is voluntary.
“Like any organization, RTOs are concerned with protecting their size, scope and importance. The exit of a transmission member would be a very significant negative for an RTO,” the IMM said. “The greater the proportion of the RTO’s assets represented by the transmission owner, the greater the threat of exit to the RTO and the greater the potential influence of the transmission owner over the RTO governance and processes.”
Exelon said the claims are irrelevant and incorrect.
Pepco and Exelon each have one vote in PJM’s top two stakeholder bodies, the Members Committee and Markets and Reliability Committee — Pepco in the Electric Distributor sector and Exelon in the Transmission Owner sector. Post-merger, Exelon will have only one vote in the 14-member TO sector.
“Consequently, far from increasing Exelon’s influence in the stakeholder process, the transaction will reduce by one vote the influence the merged company will have,” Exelon said.
PJM’s Board of Managers will ask the Federal Energy Regulatory Commission to approve a proposal opposed by generators to reduce payments to frequently mitigated units (FMUs).
General Counsel Vince Duane told the Markets and Reliability Committee last week the RTO will make the request under Section 206 of the Federal Power Act because the proposal by PJM and the Independent Market Monitor failed to win two-thirds of the Members Committee in June.
The plan garnered a 65.6% sector-weighted vote of the committee, with support from only 23% of Generation Owners and about half of Transmission Owners and Other Suppliers. End Use Customers and Electric Distributors voted unanimously in favor of the proposal, which would limit FMU adder payments to units whose net revenues are not covering their avoidable cost rate (ACR). (See FMU Proposal Falls Short.)
President Obama last week named Cheryl LaFleur as chairwoman of the Federal Energy Regulatory Commission effective July 30 and said new Commissioner Norman Bay will succeed her in the top spot on April 15, 2015.
LaFleur has been serving as acting chair since Nov. 25, when former Chair Jon Wellinghoff resigned.
Bay, who has served as director of FERC’s Office of Enforcement since 2009, won confirmation to the commission under an unusual agreement that Obama wouldn’t promote him to the chairmanship for nine months.
The compromise was crucial to winning the votes of some who criticized Obama’s plan to make Bay — who has never been a regulatory commissioner — chair immediately upon his appointment.
The last five FERC chairmen served a median of 30 months before becoming chair. Only one served less than a year on the panel before his promotion.
The four-unit, 2,422-MW coal-fired Roxboro Steam Plant in in Semora, N.C., is one of the largest power plants in the United States. (Source: Duke)
The North Carolina Eastern Municipal Power Agency is selling its stake in four Duke Energy Progress power plants to Duke in a deal valued at $1.2 billion, the organizations announced last week.
The agreement involves about 700 MW at two coal-fired plants and three nuclear units. When the deal closes, Duke will be the sole owners of the Roxboro Unit 4 and Mayo Unit 1 coal plants, and the Brunswick Units 1 and 2 and Harris Unit 1 nuclear stations. All of the plants are in North Carolina.
Duke also entered into a 30-year power-purchase agreement to supply wholesale power to the 32 municipalities represented by NCEMPA. The terms of that agreement were not released.
The deal will allow the agency to unburden itself of a large chunk of the approximately $1.9 billion in debt under which it has been struggling.
The single-unit, 900-MW Harris Nuclear Plant is located near New Hill, N.C. (Source: Nuclear Regulatory Commission)
“NCEMPA’s decision to sell its power generating assets was driven by a desire to lower its power costs and reduce its risk of generation ownership,” said NCEMPA spokesperson Rebecca Agner on Friday. “This agreement will reduce NCEMPA’s outstanding debt by more than 70% and make our costs more competitive. After the sale, NCEMPA will not own any generation assets.”
The agreement needs approval from the Federal Energy Regulatory Commission and several state agencies.
Duke spokesman Jeff Brooks said the agreement was attractive for the company for a number of reasons. He acknowledged that the $1.2 billion sales price was somewhat higher than “book value” of the plants, but he said having sole ownership “will provide long-term fuel savings,” benefiting both Duke and its customers.
“These units were among the least costly [in the Duke fleet] to operate from a fuel standpoint,” he said. In buying back the 700 MW of capacity, Duke will be able to increase wholesale energy revenue while lowering its average fuel costs.
Municipalities will benefit from lower debt service costs.
Although Duke has retired a number of coal units in the region in recent years, the Roxboro and Mayo plants are among its youngest and have already seen substantial emissions control retrofits.
“We have made substantial investments in emissions control and dry ash” collection, Brooks said. “The coal units are among the cleanest in the nation.”
The two nuclear stations could run for at least two decades. The licenses for Brunswick Units 1 and 2 are good until 2034 and 2036, respectively. The Harris license expires in 2046.
