ST. PAUL, Minn. — MISO staff will seek board approval in December for about 352 transmission projects totaling $2.4 billion in its 2015 Transmission Expansion Plan.
That’s virtually the same dollar amount as MTEP 14, but this year’s plan includes more baseline reliability projects and what could be the first competitively bid market efficiency project.
The largest of the projects in MTEP 15 is Entergy’s controversial $187 million Lake Charles, La., baseline reliability project to accommodate an industrial upswing in the gulf region. (See Entergy Out-of-Cycle Requests Win MISO Board OK.)
The market efficiency project ranks fifth in cost at an estimated $67 million to $72 million. MISO is considering three alternatives to relieve congestion in southern Indiana, with PJM as a potential partner. MISO Vice President for Transmission Jennifer Curran told the Board of Directors’ System Planning Committee last week that a request for proposals could be posted in January, with developer proposals due in July. (See Southern Indiana Transmission Project Keeps Morphing.)
Another significant portion of MTEP 15 is a bundle of 13 transmission upgrades identified in the voltage and local reliability study to reduce costs in MISO South. Estimated at $300 million, the projects should produce $498 million in 20-year net present value benefits by decreasing the need for uneconomic generation in load pockets such as Amite South and WOTAB, MISO executives told the board.
More Baseline Projects
While the total price tag for MTEP 15 is nearly identical to MTEP 14 — a coincidence, RTO officials said — the complexion of projects differs significantly. Proposed in MTEP 15 are 91 baseline reliability projects totaling $1.2 billion, compared to 50 projects totaling $177 million in 2014.
The 10 most expensive projects in MTEP 15 represent 35% of the total cost.
Projects driven by local needs are fewer in MTEP 15: 251 for a total of $1 billion versus 312 projects for $1.6 billion in MTEP 14.
The big difference was the inclusion in MTEP 14 of the $676 million 500-kV Great Northern transmission line, built in response to a long-term transmission service request from the Manitoba border to the Iron Range in Minnesota.
Interregional Planning
Curran also updated the board on the status of interregional planning efforts, which have shown mixed results.
She acknowledged that at least two of three potential MISO-SPP interregional projects earlier touted to offer $235 million in benefits are now “uncertain to unlikely.”
Including the proposed MTEP 15, MISO will have approved $25 billion in transmission investments since 2003. About $11 billion in projects has been completed.
Curran said the two projects now look less attractive in part because of differences in how the two RTOs modeled the impact of the Environmental Protection Agency’s Mercury and Air Toxics Standards. MISO applied MATS retirement assumptions about SPP generation in the MISO model, but SPP did not have the same retirements show up in its model. (See 2 of 3 MISO-SPP Seams Projects Likely Doomed.)
“There are also differences in the amount and type of generation added, leading to a larger net addition of future generation in the interregional models when compared to the MISO regional models,” MISO spokesman Andy Schonert said. “The magnitude, type and location of these future units can lead to increased transfers and resulting differences in congestion levels at seams, which impacts the projected value associated with certain transmission projects.”
Potential interregional projects with PJM also were pared down.
In June, the RTOs narrowed the list of “quick hit” flowgate projects to two, from 39 in March. Among the survivors is the proposed resagging of the Northern Indiana Public Service Co. section of the Michigan City-La Porte 138-kV line.
The nearly $10 million in congestion relief for the finalists is a big reduction from the $408 million in potential congestion relief that the 39 projects initially identified could have brought. However, Curran told the board that MISO officials found that 22 of the flowgates had already been included in other planned or currently in-service projects.
WILMINGTON, Del. — PJM expects to spend $280 million in 2016, a $3 million increase over 2015, including $36 million on capital projects, according to a preliminary budget presented last week.
The spending plan will result in a composite expense charge of 32.9 cents/MWh, a rate that has remained consistent for the past five years.
About $28 million of the capital projects budget is dedicated to upkeep and enhancement of current applications, systems and infrastructure.
Another $5 million will be spent on new products and services, including the technology to support intraday bidding. The remaining $3 million will go toward interregional coordination, such as coordinated transaction scheduling with MISO.
The Finance Committee is set to consider the budget on Oct. 1 before it goes before the Board of Managers on Oct. 15.
Revisions Will Reveal Closed-Loop Interfaces Earlier
The committee endorsed manual revisions requiring PJM to announce the creation of closed-loop pricing interfaces five days before the close of the next financial transmission rights auction. The rules make an exception for outages of less than 10 days and those setting prices for demand response under current manual and Tariff rules.
PJM uses such interfaces to capture operator actions in LMPs rather than in uplift because its modeling software is unable to set prices for voltage problems. (See “Package Calls for Notice on Pricing Interfaces” in PJM MIC Briefs.)
Changes Pave Way for Transition to Markets Gateway
Members endorsed revisions to the Operating Agreement and Tariff reflecting the transition from the eMarket tool to Markets Gateway. Training on the new tool is expected to be held in the second half of this year.
Change to Manual 37 OK’d
The MRC endorsed changes to Manual 37: Reliability Coordination that modify section 2.4.2 (Change management process), replacing references to the Change Control Review Board with the Enterprise Change Management Standard. The standard ensures that changes to PJM business application systems, programs, data, systems software and hardware are authorized and applied so as not to compromise the stability and security of any information technology component.
They also update the definition of system operating limits (SOL) to make clear that PJM controls to the most conservative limits and that interconnection reliability operating limits (IROL) are an elevated level of SOL, not distinct from them. The changes also clarify what SOLs and IROLs are monitored by the RTO, as well as SOL violations reporting.
ST. PAUL, Minn. — MISO, SPP and intervenors in the dispute over MISO’s use of SPP transmission to deliver power between its northern and southern regions have begun circulating drafts of a settlement amid optimism that it will be filed with FERC in October (ER14-1174).
Discussions on how costs paid to SPP will be allocated within MISO will begin in September “on a separate track,” Eric Stephens, deputy general counsel, told members at the MISO Informational Forum last week. Stephens said confidentiality rules on the settlement talks prevented him from discussing specifics of the deal.
But Market Monitor David Patton told the Markets Committee of the Board of Directors later that the settlement will allow MISO to eliminate use of its $9.57/MWh “hurdle rate” in determining whether to allow more than 1,000 MW of power flows between its two regions.
“We need to make sure that’s the case, but I think the team at MISO did a good job of moving the settlement in a direction that allows us to do that,” Patton said.
MidAmerican Energy’s Dehn Stevens told the Board of Directors meeting later that the Transmission Owner sector is “very comfortable with where [the settlement is] at.”
Organization of MISO States President Libby Jacobs told the board that her group is “very optimistic that there’s resolution on the horizon.”
“OMS would encourage that to be rapidly finished so that everyone’s focus can be on other issues,” she said.
In spring 2014, MISO began limiting flows between its northern and southern regions after SPP complained that MISO breached their joint operating agreement by moving power over its transmission footprint in excess of a 1,000-MW contract path.
While seeking to resolve the dispute with SPP, MISO implemented a $9.57/MWh hurdle rate — an adder to the LMPs of the importing sub-region — to establish market signals indicating when the savings from avoided redispatch costs exceed SPP’s additional transmission charges.
Patton: Fear of FTR Gaming over WAPA Integration Hasn’t Materialized
Patton told the Markets Committee that his staff has seen little evidence to confirm fears that SPP’s integration of the Western Area Power Administration (WAPA) could give market participants an opportunity to game the market by buying financial transmission rights from SPP “whose value predictably would change significantly” following the integration.
“We didn’t see a lot of participants engage in strategic FTR purchases the way we had thought they would,” Patton said.
He said his staff is continuing to review how SPP’s dispatch including WAPA affects MISO’s constraints in the FTR market and market-to-market process.
“We don’t have significant concerns, but it is a significant change because WAPA stretches from the Dakotas down to the southern end of SPP. It’s a huge change in their configuration. You can think of it as similar to our integration of MISO South.”
“So, no red flags, just continued vigilance?” asked Director Michael Curran.
The New York Public Service Commission on Friday requested NYISO to perform reliability studies in western New York after NRG Energy announced it was retiring one coal plant and suspending plans to convert another to natural gas.
NRG said Aug. 25 it would retire the 380-MW Huntley Generating Units in Tonawanda, north of Buffalo, and halt plans to convert the 435-MW Dunkirk Station, southwest of Buffalo, to natural gas.
The PSC request capped a week in which NRG’s announcement and protests over ratepayer subsidies to a third plant roiled the upstate New York power market, putting more than 1,100 MW of generating capacity in question.
NRG said it plans to mothball Dunkirk on Dec. 31, when a current reliability support services agreement expires, and retire Huntley on March 1, 2016.
NRG won approval from the PSC more than a year ago to convert the Dunkirk plant to natural gas at above-market rates. Dunkirk would have received out-of-market payments of $20.4 million per year from National Grid and a one-time $15 million subsidy from New York state.
Entergy, owner of the 838-MW James A. FitzPatrick nuclear plant in western New York, sued the PSC in federal court in February, claiming the subsidies interfered with FERC’s jurisdiction over the wholesale power market. (See FERC: Hearing or Settlement on Dunkirk RSSA Charges.)
NRG said the lawsuit made the planned conversion unworkable. “Currently, NRG expects that the Entergy lawsuit will go to trial and litigation on this case could take years to resolve,” spokesman David Gaier said. “Unfortunately, the Entergy lawsuit has created a tremendous amount of uncertainty for NRG in moving forward with the Dunkirk project, and at this point the project remains on hold.”
NRG blamed low natural gas prices, low energy prices and low capacity prices for the Huntley closure. “Thus, because the facility is not currently economic and is not expected to be economic, NRG intends to retire the units. Should circumstances change, NRG will notify all parties to this notice,” it said.
The PSC requested NYISO consider three scenarios: both Huntley and Dunkirk close; Dunkirk closes but Huntley remains open; and Huntley closes but three Dunkirk generators (Units 2, 3 and 4) remain in service after March 1. The ISO was also asked to describe transmission upgrades or alternative resources that could address any reliability problems resulting from the closures, including cost estimates and implementation schedules.
The PSC also requested that distribution company National Grid reassess its transmission needs. The company had assumed Dunkirk would continue operating, so it may need to plan transmission alternatives if the closure is permanent.
NRG’s announcements could force NYISO to reconsider the conclusions of a recent study that said previous concerns about system reliability were mitigated for 2016 by the restoration of plants such as Dunkirk. (See NYISO: Reliability Concerns Raised Last Year Resolved.)
If the PSC determines reliability is again an issue, it could order National Grid to negotiate an RSSA with NRG to keep the plants running.
Capacity Performance resources cleared at $134/MW-day in the transition auction for the 2016/17 delivery year, PJM announced Monday.
PJM held the auction Aug. 26-27 to obtain CP resources for 60% of the updated reliability requirement for 2016/17, procuring its target of 95,097 MW.
The clearing price was well below the price cap of $165.27 — results that Stu Bresler, senior vice president for markets, said “demonstrated the competitiveness of the auction.”
But speaking at a conference in Boston, Jim Wilson, a consultant for consumer advocates, said PJM paid far more than it needed to, asserting it could have procured the CP resources for only an additional $30/MW-day rather than the “windfall” that resulted from the auction.
Market Monitor Joseph Bowring, also appearing at the conference, declined to comment on the results, saying he would be issuing a comprehensive report in a few weeks.
Of the capacity that cleared, 90,851 MW represented resources committed in previous auctions that now will be converted to the new product at a higher price. The remaining 4,246 MW did not have a prior commitment, or surpassed the level of a previous commitment.
Total capacity offered into the auction was 117,753 MW.
“There wasn’t anything that surprised me that much,” Bresler said in a press conference after the results were announced late Monday. “The clearing price was just about at the point where we expected it to be.
“I thought the level of demand response and energy efficiency was not surprising, so really I think in just about every way it was consistent with what we expected.”
The auction, part of a five-year transition period leading up to a single capacity product type for the 2020/21 delivery year, had been delayed in order to allow DR and energy efficiency resources to participate, per a FERC order. A second incremental auction, for the 2017/18 delivery year, is set for Thursday and Friday, with results expected to be posted on Sept. 9.
The Base Residual Auction for the delivery year — held in 2013, before the introduction of the tougher CP requirements — cleared at prices ranging from $59 to $119/MW-day in most of PJM, with the PSEG locational deliverability area at $219. (See Capacity Auction: New Generation, Imports Up, Prices, DR Down.)
Bresler said 619 MW of DR cleared the auction, of which 227 MW represented a new commitment. All 949 MW of energy efficiency offered cleared, including 423 MW of new resources.
Under the rules of the transition auctions, participation is optional, and market participants may offer all or part of resources that were committed under the Base Residual Auctions for those years as Capacity Performance resources.
The parameters of the transition auctions differ in three aspects, Bresler said: There were no locational constraints modeled; the target was 60%, not 100%, of the reliability requirement; and a price cap was implemented that was calculated to be 50% of the net cost of new entry.
The incremental cost of the transition auction was $2.3 billion, slightly below the estimate of $2.5 billion to $3.6 billion PJM and the Market Monitor had predicted, Bresler said.
Bresler sought to counter news reports that the new Capacity Performance auctions would greatly increase consumers’ power bills, noting that CP costs make up about 15% to 20% of energy bills, and that energy payments are expected to be lower because the new construct will result in better resource availability during times of extreme weather and grid stress.
Breaking down cleared megawatts of capacity by generation source, coal cleared 32,622.3; gas 29,629.4; and nuclear 26,099.8.
The RTO’s first Base Residual Auction under its new Capacity Performance rules, the results of which were released Aug. 21, saw prices rise 37% to $164.77/MW-day in most of the RTO, while the ComEd zone broke out at $215 and Eastern MAAC hit $225.42.
The construct allows capacity resources to receive higher prices in exchange for taking on more responsibilities and stiffer penalties for non-performance.
Capacity Performance resources, which represented more than 80% of capacity acquired in the BRA, were priced at a $15/MW-day premium to base capacity in most of the RTO. In the winter-peaking PPL LDA, the premium was $90. (See PJM Capacity Prices Up 37% to $165 /MW-day.)
FERC on Tuesday rejected complaints from NextEra Energy and Direct Energy seeking to change the way PJM conducts its incremental capacity auctions to transition to its new Capacity Performance product (EL15-88).
The commission found that the companies failed to show how PJM’s clearing methodology for the auctions was inconsistent with the RTO’s Tariff and that their proposed alternative plan “relies on a complicated and untested algorithm to clear the capacity markets.”
“Implementing an untested alternative proposal would require other changes to either PJM’s market design or [Tariff] in order to be justly and reasonably implemented, and therefore complainants’ alternative clearing methodology cannot be said to conform to the [Tariff] itself,” FERC said in its order.
The transition auctions are being held to procure Capacity Performance resources for delivery years 2016/17 and 2017/18. PJM ran the first Base Residual Auction, for 2018/19, under the new product earlier this month. (See PJM Capacity Prices Up 37% to $165/MW-day.) It allows capacity resources to receive higher prices in exchange for taking on more responsibilities and stiffer penalties for non-performance.
Under the rules of the transition auctions, participation is optional, and market participants may offer all or part of resources that were committed under the BRAs for those years as Capacity Performance resources. If cleared, the Capacity Performance commitment would replace the old one and participants would receive the new, higher price.
Incremental Costs
NextEra and Direct Energy argued that this methodology would result in increased costs, in violation of both PJM’s Tariff and FERC’s order authorizing Capacity Performance, which the companies said directed the RTO to procure capacity resources using the “least-cost solution.”
The companies said that in order to do this, PJM needs to take into account the results of the BRAs for 2016/17 and 2017/18 when selecting offers. Rather than simply selecting the lowest price, they suggested that the RTO base its selection of resources on the lowest incremental cost — the difference between the new Capacity Performance price and the price under the original BRA. (See table below.)
Direct Energy and NextEra Energy proposed an alternative clearing methodology for the transition auctions in which PJM would select resources based on the lowest incremental cost (the Capacity Performance price minus the original BRA price), and not simply on the lowest new price.
FERC disagreed.
The RTO’s Tariff does not “require PJM to minimize costs by taking into account existing capacity revenues for the delivery year or other savings in determining the lowest price at which to clear an auction for Capacity Performance products,” the commission said.
FERC also insisted that ordering PJM to revise its methodology now would delay the transition auctions and reduce the amount of time that generators have to install upgrades needed to meet Capacity Performance’s more stringent requirements.
The commission issued its order the day before the first transition auction began. Results for this auction were released on Monday. (See related story, PJM 2016/17 Transition Auction Clears at $134/MW-day.) The second auction will be Sept. 3-4, with results posted on Sept. 9.
Bay Dissents — Again
In a dissent, FERC Chairman Norman Bay agreed with the companies. He said that the transition auctions allow the RTO to avoid making payments it would otherwise make and, in turn, save consumers money.
Bay illustrated NextEra and Direct Energy’s argument with an example of two hypothetical companies, A and B, that are entitled to receive $120/MW-day and $60/MW-day respectively as a result of the BRA. They both bid in the transition auction at $140/MW-day and $100/MW-day respectively. As PJM is required to accept the lowest bid, it takes company B’s bid, resulting in a $40 increase in the price, as opposed to a $20 increase had company A’s bid been taken.
Bay argues that because both companies are offering the same Capacity Performance product, “it simply permits consumers to be charged more in exchange for no additional benefit.” He lamented that “PJM’s methodology ignores the value of this opportunity.”
“This auction will impose a considerable cost on consumers for no additional reliability benefit,” the chairman said, warning that those costs could reach more than $1 billion. “Today’s outcome demonstrates the problems inherent in a complex, flawed design.”
Bay also dissented in FERC’s June order approving Capacity Performance. (See FERC OKs PJM Capacity Performance.) He noted that vote in his dissent to Tuesday’s order.
“I would not have agreed to transitional auctions at all, but having created them, it is the commission’s responsibility to ensure that they result in just and reasonable rates,” he said. “Unfortunately, that has not happened here.”
WASHINGTON — The D.C. Public Service Commission last week unanimously denied Exelon’s proposed $6.8 billion acquisition of Pepco Holdings Inc., sparking applause in the hearing room and sending PHI shares tumbling on Wall Street.
“When this proposed merger is considered as a whole … we conclude that the joint applicants have not met their burden of persuading this commission that the proposed merger is in the public interest,” the three-member PSC said.
Upon the news, PHI shares dropped more than 18%, and Exelon stock dipped more than 3%.
In a joint statement, Exelon and PHI said, “We are disappointed with the commission’s decision and believe it fails to recognize the benefits of the merger to the District of Columbia and its residents and businesses. We continue to believe our proposal is in the public interest and provides direct immediate and long-term benefits to customers, enhances reliability and preserves our role as a community partner.
“We will review our options with respect to this decision and will respond once that process is complete.”
Exelon and PHI have 30 days to ask the commission to reconsider its 181-page order. The companies on Monday released a joint statement, saying they would continue working to complete the merger.
“We remain convinced the decision fails to recognize the substantial immediate and long-term benefits of our merger proposal to citizens, businesses and communities in the District of Columbia,” the companies said. “We want to deliver these benefits to customers and will strive to make that happen.”
Some analysts, however, are pessimistic about the deal succeeding. “While none of the negative items cited by the PSC in their order are glaring hurdles that could not be overcome, the magnitude of ‘small cuts’ appears in our view to suggest a deeper mistrust between the commission and Exelon,” UBS Global Research said.
Following their initial fall, the companies’ stock prices remained steady over the week, and Monday’s statement did little amid another bad day on Wall Street: Exelon closed at $30.75/share, down 2% on the day, while Pepco closed at $22.98/share, a less than 1% drop.
7 Factors of Public Interest
The PSC called the rejection “one of the most significant decisions” it would ever make, noting, “This proceeding has generated more interest and more active participation by parties and interested persons than any other proceeding in the commission’s more than a century of operations.”
The commission said it weighed the proposal on seven factors of public interest, among them the effects on ratepayers and shareholders, market competition and preservation of natural resources and the environment.
“The public policy of the district is that the local electric company should focus solely on providing safe, reliable and affordable distribution service to district residences, businesses and institutions,” Chairwoman Betty Ann Kane said. “The evidence in the record is that the sale and change in control proposed in the merger would move us in the opposite direction.”
Commissioner Joanne Doddy Fort concurred, saying, “The proposed merger would diminish Pepco’s ability to directly raise issues that address the needs of district ratepayers.”
Commissioner Willie Phillips voted to reject the merger application, but he dissented in a secondary vote to issue the actual order.
He agreed the proposed merger was a “bad deal” for the district, but said, “I am disappointed in the loss of the many opportunities inherent in the proposed merger that could have achieved benefits — tangible benefits — for our local communities and across the region.”
Surprise: Md. Wasn’t Biggest Obstacle
When Exelon proposed the deal 16 months ago, analysts predicted Maryland would be its biggest stumbling block. But after months of securing strategic alliances, Exelon won that commission’s 3-2 approval — albeit with 46 conditions. (See How Exelon Won Over Maryland.)
Meanwhile, in the district, opposition steadily stiffened. More than half of the Advisory Neighborhood Commissions and nearly half of the 12-member City Council opposed the deal. The Office of People’s Counsel and the attorney general’s office also advised against approval without significant concessions. (See Deadline Looms for Decisions in Exelon-Pepco Deal.)
As Kane read the commission’s summary of the order, there was a murmur in the room, as those attending the meeting realized that the commission was siding against the merger.
Many in attendance said they were surprised by the ruling, as they were prepared for the commission to approve the deal with concessions similar to other jurisdictions, such as Maryland.
“Honestly, I was pleasantly shocked. I commend them for their courageousness,” People’s Counsel Sandra Mattavous-Frye said of the commissioners. “It will have a domino effect on the entire proposal. The joint applicants have said they cannot go forward without D.C.
“The commission listened to the parties and, more importantly, they looked at the record,” she said, noting, “The applicants had the opportunity to supplement the record. They, too, heard the concerns being raised and chose not to address them.”
“I’m stunned,” said Anya Schoolman, executive director of DC Solar United Neighborhoods, a local solar power advocacy group. “I think … the commonly accepted wisdom was that they would approve it with conditions. And we were waiting to see how stringent those conditions would be.”
“I would almost go to say I’m shocked, because I fully expected that … the commission could have possibly come out in favor of the merger,” said D.C. Councilwoman Mary Cheh, who led the opposition in the district’s legislature.
“I’m just happy for the people of the District of Columbia,” she said. “The real beneficiaries of this, had this gone through, would have been the officers and the shareholders of Pepco and Exelon Corp. The people who would have been harmed are the ratepayers.”
“It was somewhat of a shocker that all other jurisdictions did in fact support this merger,” said D.C. Councilman Vincent Orange, who said he has remained neutral throughout the process. “At the end of the day, the Public Service Commission has ruled, and we’ll have to live with it and move on.”
‘David and Goliath’ Win
Power DC, which had organized opposition, said it was glad the PSC had “followed the will of the district’s electric customers.”
“The proposed acquisition would have been a substantial step backwards in the district’s efforts to move toward more sustainable electricity generation and greater reliance on local, renewable energy. It would have exposed D.C. residents and businesses to the risk of steeply rising electricity bills.
“Pepco has always affirmed its capability to provide a high level of service for its customers without this merger, and it has demonstrated a much greater willingness than Exelon to integrate new, customer-centered technologies.”
Mattavous-Frye called the win a “David and Goliath” scenario.
“I want to commend the public participation,” she said. “This was about consumer empowerment. People did not think their participation would be meaningful, and it is.”
Other Jurisdictions Approved Deal
The deal had been more than a year in the making. All of the other affected jurisdictions had approved it: Virginia, Maryland, Delaware, New Jersey and FERC.
Dave Bonar, Delaware’s Public Advocate, said the decision was a disappointment, but that it “doesn’t mean the deal is not salvageable.”
“They could appeal, or they could make more concessions,” he said. “Or they could just fold their tent and go back to Chicago.”
He said those who worked on getting Exelon’s concessions and reaching consensus were “disappointed.”
“We worked very hard to get this done,” Bonar said.
Critics in Md. Pleased
Mike Tidwell, director of the Chesapeake Climate Action Network, a group that intervened before the PSC in Maryland against the proposed merger, called the decision a “major victory” for the growth of clean energy across the region.
“One good idea that emerged from the proposed Exelon-Pepco (merger) was to create a PSC-guided process to explore ‘performance-based ratemaking.’ Utilities should be rewarded based on how well they perform on energy improvements that enhance our economy and reduce carbon emissions and climate change,” he said. “Hopefully, we can now move on to these solutions.”
Paula M. Carmody, People’s Counsel for the State of Maryland, had urged the state commission to reject the deal.
Last week, she said of its D.C. counterpart, “I think they got it right.
“They hit on the very issues identified in the proceeding before the Maryland commission,” she said, noting that the D.C. group had concerns about the “loss of local influence” over a utility with headquarters in Chicago.
Carmody, whose organization has one of three appeals pending before the Maryland commission, said she is not sure if the district’s decision is a death knell for the merger, “but clearly they can’t close” the deal as it stands now.
“It depends on what the companies do now,” she said. “They could appeal, they could file for reconsideration.” But, she said, the rejection makes the acquisition “problematic.”
A Win for Consumers, Environment
Roger Berliner, an attorney and Montgomery County councilman who had led that area’s opposition, applauded the D.C. PSC for standing up for consumers and the environment.
“As the testimony of countless expert witnesses made clear, Exelon has shown time and time again its interest in favoring its own nuclear generation holdings over renewable technologies like solar and wind, and the merger does far too little to provide benefits to ratepayers, while Pepco’s shareholders stand to benefit tremendously.”
The acquisition would have created the Mid-Atlantic’s largest electric and gas utility — and the country’s largest utility by customer count. Exelon has said the deal would boost its customer base to nearly 9.8 million from 7.8 million and increase its rate base to almost $26 billion from $19 billion.
The Environmental Protection Agency has proposed the first-ever federal regulations governing methane emissions by oil and natural gas drillers. Janet McCabe, EPA’s acting assistant administrator for the Office of Air and Radiation, estimated that exploration companies would need to invest up to $420 million to stop leaks and capture methane from working wells. But she said the industry could save as much as $550 million from captured gas.
The new rules are part EPA’s broader efforts to cut planet-warming emissions. Methane can trap 25 times more heat than carbon dioxide, but dissipates more rapidly. McCabe said the target for methane emission reduction is 20% to 30%.
The oil and natural gas industries are expected to challenge the rules.
July Hottest Month on Record, Federal Weather Agencies Say
July’s average global temperature was 61.86 degrees, making it the warmest month on Earth since records have been kept, federal weather officials said. Scientists from the National Oceanic and Atmospheric Administration said the new mark broke previous records set in 1998 and 2010 by a seventh of a degree, the largest margin ever by which an old record was eclipsed.
“It just reaffirms what we already know: that the Earth is warming,” NOAA climate scientist Jake Crouch said. “The warming is accelerating and we’re really seeing it this year.” NOAA records go back to 1880. The findings were confirmed by records kept by NASA and a Japanese weather agency.
Union of Concerned Scientists Cites DOE Study Slamming MOX Facility
The Union of Concerned Scientists said that a Department of Energy study concludes that the federal program to convert surplus plutonium to commercial grade nuclear fuel is an expensive and risky disposal method.
The UCS said it has obtained a study written by experts from the Nuclear Regulatory Commission, the Tennessee Valley Authority and the commercial nuclear industry that concludes the mixed-oxide fuel (MOX) program under construction in Aiken, S.C., is caught in “difficult, downward spiraling circumstances.”
The report said the cost of the MOX facility has ballooned from $1.6 billion to $30 billion. The report said it would be cheaper and less risky to ship the plutonium to the Waste Isolation Pilot Plant in New Mexico for burial.
The U.S. Department of Agriculture has awarded a $46 million federal loan to North Dakota-based Central Power Electric Cooperative to help finance 51 miles of new power lines and several substations. The funds come from USDA’s Rural Utilities Service electric loan program.
“Demand is the main driver of this,” said Dennis Hill, executive vice president and general manager of the North Dakota Association of Rural Electric Cooperatives. “The little single line with a small transformer just doesn’t work anymore.”
The new lines would be spread throughout the cooperative’s existing 1,300-mile network, according to Hill, who added that the project would commence after a four-year work plan is submitted. CPEC serves nearly 56,000 customers in 25 North Dakota counties.
A FERC administrative law judge has found that BP manipulated the natural gas market in Texas in 2008, and now the company faces millions in penalties and disgorged profits.
“This is a classic case of physical for financial benefits,” Judge Carmen Cintron said. “The evidence in this case shows that the Texas team had hundreds of affirmative acts in furtherance of the manipulative scheme during the investigative period.”
Federal regulators in 2013 proposed that BP pay a $28 million penalty and pay back profits of $800,000 plus interest. The ruling will now go before the full five-member commission for a final ruling. BP has vowed to appeal. “The evidence overwhelmingly demonstrated that BP’s natural gas traders did not engage in any market manipulation,” a company spokesman wrote in an e-mail.
Federal Gulf Oil Leases Attract Low Interest, Prices
A federal auction for drilling rights in the Gulf of Mexico is attracting the weakest interest since 1986.
Plummeting oil prices and industrial contraction meant that only five companies bid, for a total of $22.7 million. The auction happened on a day when American oil prices fell to about $40/barrel. Last summer prices were $100/barrel. The integrated oil giants ExxonMobil, Shell and Chevron didn’t even bother to bid.
“Concerns over the pace of economic growth in emerging markets, continuing (albeit slowing) supply growth, increases in global liquids inventories and the possibility of increasing volumes of Iranian crude entering the market contributed to the changed forecast,” the Department of Energy said.
DOE Gives $5.2 Million Grant to Duke Algae Uses Study
The Department of Energy has awarded a $5.2 million grant to Duke University to study possible uses of algae for renewable energy.
Zackary Johnson, an assistant professor of molecular biology at Duke, is heading a three-year study called MAGIC, or Marine Algae Industrialization Consortium. There have been efforts to derive fuel from algae, but so far none have been economically viable.
“To make algae a competitive player in this field you have to consider all the things the algae are producing,” Johnson said. “We’re essentially trying to make oil the waste product, so that it can compete with fossil fuels.”
A power generator fined $5 million for allegedly cheating ISO-NE wants federal regulators to drop two other allegations or combine them with the original complaint (IN15-4).
FERC fined Maxim Power in May for overcharging ISO-NE by offering into the day-ahead market with a price for oil-fired generation when in fact it was burning cheaper natural gas. (See FERC Fines Maxim Power $5M in Switching Scheme.)
FERC filed suit July 1 in U.S. District Court in Massachusetts to enforce its penalty.
FERC’s suit followed a Notice of Alleged Violations in November that included two other alleged schemes: that the company gamed ISO-NE market mitigation rules in 2012 and 2013, and that it boosted its generators’ outputs during testing using “extraordinary measures” in order to collect inflated capacity payments from 2010 to 2013.
Those two allegations were not mentioned by the commission in its filings seeking to collect the fine.
On Wednesday, Maxim attorney William S. Scherman sent a letter asking four FERC commissioners to add the “unpursued claims” to their federal court suit or confirm that they are no longer pursuing them. Commission Chairman Norman Bay, who headed the Office of Enforcement during the cases’ investigations, has recused himself in the matter.
“Maxim Power should not be forced to litigate piecemeal in federal district court,” Scherman wrote. “This would not only be inefficient and burdensome but also significantly add to Maxim Power’s litigation costs. As the commission knows, all companies consider litigation costs as part of their case assessment. But intentionally seeking to drive up a private entity’s litigation costs is not a reasonable litigation strategy.”
Scherman asked the commission to take action by Sept. 3.
PJM generators will earn $10.9 billion from this year’s capacity auction — a 45% jump from last year — in the first test of the RTO’s new Capacity Performance requirements. But some merchant generators smarting from low gas prices and competition from wind say that’s not enough for what ails them.
Securities analysts said the results will boost earnings for Exelon, Dynegy, NRG Energy, Public Service Enterprise Group, Calpine and Talen Energy.
The results have particular implications for Exelon’s Illinois nuclear fleet and American Electric Power’s potential sale of its merchant fleet.
Exelon: Retirements Still on the Table
Exelon announced Monday that three of its nuclear plants in PJM failed to clear the 2018/19 auction, including the 1,819-MW Quad Cities plant in Illinois, the second year in a row that it failed to clear. Company officials say they may retire Quad Cities if the Illinois General Assembly does not pass legislation that would boost revenues for the company’s nuclear fleet.
Exelon must notify PJM by September of any plants it won’t offer into the May 2016 Base Residual Auction for delivery year 2019/20.
Quad Cities, which has lost about $300 million over the last six years, is expected to lose about $50 million annually, according to Joseph Dominguez, executive vice president for government and regulatory affairs at Exelon.
Analysts from UBS Global Securities called Exelon “the clearest ‘winner’” in the auction because of its assets in both the ComEd zone, where prices hit $215/MW-day, and EMAAC, which cleared at $225/MW-day.
But Dominguez said the increase in capacity prices was a “marginal improvement” for Exelon’s generation. “What we got today is important, but it’s one year’s worth of revenue,” he told the Chicago Tribune on Friday. “We have to see a sustainable path forward.”
FirstEnergy spokesman Mark Durbin echoed Exelon Monday, saying PJM’s rule changes “resulted in clearing prices that really come closer to the operating costs of plants. But it’s only representative of one year; we’re not sure how reflective it is of long-term trends. It is a snapshot in a one-year time frame.”
Capacity revenue represented less than one-fifth of energy market revenue in PJM in 2014.
The results also did not help Exelon’s money-losing Clinton, Ill., plant in MISO. Exelon faces a December deadline for informing MISO if the 1,065-MW plant will be shut down before the planning year beginning June 1, 2016.
Seeking Help from the States
Exelon wants Illinois legislators to approve legislation that would require utilities to purchase credits from low-carbon generators including nuclear and wind. Illinois lawmakers did not take action on the Low Carbon Portfolio Standard before the spring legislative session ended, but they may consider it in November.
AEP and FirstEnergy also are seeking aid from state officials. The companies have asked the Public Utilities Commission of Ohio to approve above-market purchase power agreements from their coal generators.
PUCO has scheduled evidentiary hearings beginning Sept. 28 to consider the request from AEP, which is hoping to boost the value of its merchant fleet for a possible sale. (See Cold Weather, Low Gas Prices Drive AEP Earnings.) The commission is expected to consider FirstEnergy’s “Electric Security Plan” proposal as part of a rate case later this month.
In FirstEnergy’s second-quarter earnings call, CEO Chuck Jones cited PJM’s capacity market changes and the Ohio ESP as “key initiatives [that] will drive the near-term financial strategy” of the company.
Meanwhile, Dominion Resources won approval from the Virginia legislature in February for a nine-year rate freeze, meaning it won’t have to share the rise in capital revenues with ratepayers. Dominion said it wanted to suspend its biennial rate reviews to provide it and customers with “rate stability” as it responds to the Environmental Protection Agency’s Clean Power Plan.
While Dominion is assuming the risk of increased compliance and operating costs, analysts said the freeze allows the company to retain an additional 5 to 8 cents per share of earnings from PJM capacity revenues.
Transition Auctions
With the first auction under PJM’s new rules behind them, generators are now turning their attention to this month’s CP transition auctions for the 2015/16 and 2016/17 periods.
PJM will hold a transition auction on Wednesday and Thursday to obtain CP resources for 60% of the updated reliability requirement for delivery year 2016/17. Results are expected Monday, Aug. 31. The transition auction for 2017/18 (70% CP) will be Sept. 3-4, with results posted Sept. 9.
Participation is voluntary and open to any resource able to meet CP requirements, regardless of whether the resource cleared in the BRA for the delivery year.
FirstEnergy’s Jones said the transition auction results will have a big impact on how much the company is willing to spend to boost its plants’ reliability.
“We need to see where both the Base Residual Auction and then where in particular the transition auctions clear, because those are the more imminent,” he said. “For the Base Residual, you got three years to figure how to get your units reliable for that one. The transition auctions are a little more pressing in terms of time.”
UBS is predicting CP resources will clear the two auctions at about $120/MW-day, a “modest risk premium” to the base capacity resources, which cleared at $59/MW-day for 2016/17 and $120/MW-day for 2017/18 RTO-wide.
Other Generators
PSEG announced that its planned Sewaren Unit 7 had cleared the auction — the only new generation in EMAAC. The company said it plans to begin construction on the $600 million combined-cycle plant in early 2016. The company said it will replace the nearly 70-year-old Units 1, 2, 3 and 4.
PSEG said it cleared about as much capacity as in the 2014 auction, with all but one unit clearing as CP.
Talen declined to share the details of its offerings, but spokesman George Lewis said, “In general, we see the CP product as a positive, and the results from Friday are generally good and certainly within what was expected. It met most people’s expectations.
“Our view is it’s a partial picture at this point,” Lewis said. “We’ll find out more next week and the week after what the outcome of the [transition] auctions will be, and whether the results of the [BRA] will change the way generators or capacity resources will view bidding into these capacity auctions.”
Dynegy and Calpine had no comment on the results. AEP, NRG and AES did not respond to requests for comment.
A Calpine spokesman noted, however, that 4,600 of its 5,700 MW of PJM generation is in either ComEd or EMAAC.
Stocks Tumble
PJM generators saw their shares drop slightly on Monday, but it was a day when the market was down across the board on fears of economic weakness in China. The Dow Jones industrial average finished the day down 588 points, or 3.6%.
Exelon closed the day down 1.1% at $32.64 after an intraday high of $33.54. Dynegy was down 2.4% at $24.71, with an intraday high of $26.51. NRG shares dropped 1.8% to close at $19.22 after seeing an intraday high of $20.36. PSEG closed down 3.31% at $40.65, with an intraday high of $41.83. Calpine dropped 3.82% to close at $15.87, with a high of $16.76.
Talen saw the biggest slump, 4.7%, which brought its shares down to $15.17.
