The Northeast Energy Direct pipeline project through southern New Hampshire is the best way to lower electricity prices and increase reliability in New England, the staff of the state Public Utilities Commission concluded in a report released Wednesday.
The 48-page report examined three proposed pipeline expansions and an alternative for increased liquefied natural gas deliveries during the winter. The PUC ordered the study in the spring in response to high natural gas prices and concerns about reliability over the past two winters (IR15-124).
Kinder Morgan’s Northeast Energy Direct project would run on mostly new rights of way from Pennsylvania’s Marcellus Shale region through New York, Massachusetts and New Hampshire, terminating in Dracut, Mass. (See Kinder Morgan Trims Northeast Energy Direct.)
The Access Northeast project led by Eversource Energy and the Portland Natural Gas Transmission System, which would mostly expand pipelines on existing routes, provide lesser benefits, according to the report.
“We view Access Northeast and Northeast Energy Direct as two very cost-effective projects that will moderate future winter electricity prices, though the numbers clearly indicate that NED will provide the greatest benefits to regional electricity customers,” the report said.
Portland Natural Gas did not provide enough information for the PUC to conduct a thorough analysis, according to the report. The report added that Access Northeast would enhance reliability but would have less impact on gas prices.
“As a result of the NED project, [Kinder Morgan subsidiary] Tennessee Gas Pipeline will have the ability to physically deliver into every pipeline system serving New England, as well as to incrementally serve markets along its own pipeline system,” the report adds.
The report is less confident in the ability of LNG to fill in gas supply gaps, as it did during last winter.
“There is no guarantee that the market conditions that enticed LNG tankers to New England in winter 2014/15 will recur in future winters. This means the very high prices of 2013/14 could reappear just as quickly as they disappeared in 2014/15, assuming, of course, similar extreme weather conditions. Finally, it is important to note that the increased availability of LNG in winter 2014/15 did not eliminate price spikes or energy cost premiums,” the report said.
Seeking to improve its ability to unravel complicated market manipulation schemes, FERC last week proposed a new way for identifying connections between companies and individuals.
The commission issued a Notice of Proposed Rulemaking requiring RTOs and ISOs to begin registering market participants through common alpha-numeric identifiers, with lists of their “connected entities” and a description of their relationships (RM15-23).
The proposal would use a new system called Legal Entity Identifiers (LEIs), which are already used by the Commodity Futures Trading Commission and Securities and Exchange Commission to track swaps trades. FERC previously dropped use of the Data Universal Numbering System (DUNS), saying it was not effective for its purposes.
FERC said the new requirements will help the Office of Enforcement police market manipulation by providing a “more complete view of the relationships between market participants and the incentives underlying their trading activities.” The initiative would also help RTO market monitors in probes of cross-market manipulation, FERC said.
The office’s Division of Analytics and Surveillance runs automated screens to detect potential market manipulation. The office also has access to e-Tags, RTO trading data and information from the CFTC, including its Large Trader Report.
“Nonetheless, despite increased access to trading data, the commission cannot fully utilize this information in order to detect and deter market manipulation because of uncertainty regarding the identity of a given market participant, which may trade under different identifiers in different markets and venues,” FERC said. “The commission also lacks a clear window into the relationships between market participants and other entities, which can be complex. Without an understanding of which companies share ownership or debt interests, or who may function in key employment or other contractual roles (such as asset management), it can be difficult to ascertain which individuals or companies may benefit from a given transaction or, indeed, who may be jointly participating in a common course of conduct.”
‘Connected Entities’
The rule would require companies to identify all “connected entities,” a new term defined as those that have certain ownership, employment, debt or contractual relationships. It would replace current affiliate disclosure requirements contained in RTO and ISO tariffs unless the markets request their continuation.
FERC said it wanted a new definition “free of any associations that have developed around the term ‘affiliate,’ and one that is uniform across all of the RTOs and ISOs.”
Connected entities would include companies controlling more than 10% of another, as well as top executives and traders. The scope would extend beyond corporate affiliations, including contractual relationships such as tolling and asset management agreements and debt structures that are convertible to ownership interests.
FERC estimated that about 90% of reported wholesale electricity sales under commission jurisdiction are captured in Electric Quarterly Report data and affiliation information obtained from market-based rate filings and other sources. It sought comment on whether non-RTO market participants should also be required to make filings.
Companies would be required to file their connected entity data before being permitted to participate in RTO markets, and to verify their accuracy annually. FERC and the RTOs would be able to audit the filings to ensure compliance.
FERC said the change may ease compliance for market participants in multiple markets.
But in a concurring statement, Commissioner Cheryl LaFleur expressed concern that the rule “would create a significant new reporting regime for all market participants, as well as the RTOs and ISOs.” LaFleur said she might oppose the final rule if she concludes that “the benefits offered by new compliance obligations outweigh the burdens that will be faced by market participants.”
Comments on the rule will be due 60 days following publication in the Federal Register.
SPP is confident of its preparation for winter, although it will be adding the winter-peaking Integrated System to its footprint in October, Bruce Rew, SPP’s vice president of operations, told FERC.
The IS, which covers much of the Dakotas, will increase SPP’s load by about 15% and provide a contrast to the RTO, which is predominantly summer-peaking. “We don’t foresee any major … concerns for the winter,” Rew said, citing a 60% reserve margin.
SPP has included the IS in its annual winter assessment. It will hold a winter-preparedness workshop on Dec. 10 to cover emergency procedures and industry-wide lessons learned. Rew said gas pipeline representatives have been encouraged to attend, as they have in the past.
Rew said SPP has performed an analysis of this winter’s anticipated conditions and has determined additional actions are not needed. However, should extreme weather cause generation outages, the RTO would move to a “conservative operation alert.” These actions are discussed throughout the year in workshops and with stakeholders. Generally, SPP considers early committal of resources and delaying or postponing generation outages to ensure reliability.
The RTO has updated its regional weather-alert procedures, strengthening communication with gas pipelines, based on the footprint’s weather evaluations. An action plan has been developed and distributed to affected parties, Rew said.
SPP’s emergency operating plan includes criteria that require market participants to notify the SPP balancing authority when they anticipate fuel restrictions below certain thresholds. These notifications are intended to help prepare SPP before any larger fuel issues arise.
Rew said that SPP performs fuel-related assessments throughout the winter, depending on forecasted system conditions. Coordinated load-shed testing between SPP and transmission owners will begin this fall, and there will be weekly communication tests between SPP and participants.
The SPP gas-electric coordination task force has submitted a proposal in response to FERC Order 809 to better align the Integrated Marketplace’s timeline with gas nominations. Earlier posting of day-ahead market results leads to earlier posting of day-ahead reliability unit commitment results in time for the evening gas nomination. (See SPP Moving to 9:30 Day-Ahead Close.)
New York has adequate resources and improved operational practices to face the upcoming winter, a NYISO official told FERC on Thursday. But the infrastructure must still perform, Wes Yeomans, vice president for operations, told the commission.
New York still has a wide diversity of resources, with hydro at 11% of generating capacity and six nuclear facilities representing 14% of capacity, Yeomans said. But the overwhelming resource of choice is natural gas — representing 55% of capacity statewide and 95% in New York City.
More than 80% of gas generation can switch to oil when heating homes and businesses takes priority during cold snaps. “That really is the cornerstone of how we maintain reliability,” Yeomans said.
Natural gas prices in New York are generally far below that of diesel (bottom gray line), but price spikes occasionally made oil cheaper during the last two winters. (Top gray line: crude oil $/barrel)
But just because a resource has dual-fuel capability does not mean it would be available to switch to oil.
“A generator may have the capability to be dual-fuel, but they may make the business decision not to update their permits, or their maintenance, or add oil on-site,” he said.
Yeomans added that in New York, it may be financially advantageous for generators to have lower inventory on-site but rather have “fantastic arrangements” with suppliers to have access to inventory when needed. “Our experience has been that this works pretty good,” he said.
NYISO monitors its resource base through the seasonal generation fuel survey that was recently distributed.
One operational change effective Nov. 1 is an increase in the operating reserve requirement from 1,965 MW to 2,620 MW in day-ahead and real time. Reserve shortages would gradually raise prices and incent the market.
Forward reserve contracts will send price signals to generators “to go buy the fuel,” Yeomans said. “Having this reflected in our real-time pricing is a very significant step.”
Capacity margins in New York are about 10,000 MW but drop to a still-adequate 4,700 MW on a peak day during a once-in-10-year cold snap.
Other initiatives include site visits to units with low capacity factors to identify ways to improve performance. NYISO is also introducing a web-based, fuel survey “portal” that will go into production in December. This will provide the opportunity for generators to post fuel conditions to a video board for ISO operators replacing a manual process.
Yeomans said the ISO has become better at managing its morning ramp, which comes at the end of the gas day, resulting in fewer deratings of its gas generators.
After all the changes were described, the room erupted in nervous laughter when FERC Chairman Norman Bay asked Yeomans about his “comfort level” going into the winter.
ISO-NE said Chairman Philip Shapiro and board members Kathleen Abernathy and Roberta Brown have been re-elected, effective Oct. 1.
The RTO elects its board members through a nominating process that involves representatives from the current board, the New England Power Pool and the New England Conference of Public Utilities Commissioners.
Abernathy joined the board in 2012. Brown joined in 2007, while Shapiro joined in 2010 and was elected chairman in 2014.
Plains & Eastern Clean Line Nears Key Project Milestones
Clean Line Energy’s Plains & Eastern Clean Line is nearing a milestone as it awaits a key environmental report and the federal government’s decision whether to participate in the project.
The Energy Department is expected to complete a final environmental impact statement by late October for the 720-mile transmission line, which would deliver electricity generated by planned wind farms in Oklahoma and Texas to utilities in Tennessee and the southeast. The department will then decide whether to participate in the $2 billion HVDC transmission line. Under Section 1222 of the Energy Policy Act of 2005, the federal government can be involved with transmission projects to relieve electrical grid congestion or to increase transmission capacity.
Federal participation could range from operation, construction, development or ownership of some transmission assets. It would be structured through the Southwestern Power Administration, a federal agency that markets and transmits electricity from hydroelectric dams built by the U.S. Army Corps of Engineers to electric cooperatives, municipal electric authorities and other government users.
Invenergy 386-MW Gas Plant now Online in West Texas
Invenergy Clean Power earlier this month announced that its Ector County Energy Center, a 386-MW natural gas plant near Odessa, Texas, has begun operations.
The plant uses two GE 7FA simple-cycle combustion turbines fueled by Permian Basin natural gas. It is designed to provide peaking energy and respond quickly when ERCOT, the state’s grid operator, requests additional power supply.
NextEra Energy to Develop 300-MW Wind Farm in Texas
NextEra Energy has agreed to become the development partner of the Hale Community Wind Energy project in West Texas, according to project developer Tri Global Energy. The $7.3 million project encompasses more than 122,000 acres leased from about 350 landowners north of Lubbock.
Construction should begin in February or March, with the first turbines in operation by next summer. The project’s first phase is expected to be completed by Thanksgiving 2016.
No announcement has been made concerning power purchase agreements for the project’s expected 300 MW of generation. The energy production is expected to be used by municipalities, major corporations and electrical utilities. Hale Community Energy’s location enables it to supply energy to two major national power grids, ERCOT and SPP.
PSO to Add Solar Capacity, Increase Use of Wind Power
Public Service Company of Oklahoma (PSO) expects to add up to 200 MW of solar capacity and to bolster its wind offerings, according to a planning document outlined before regulators. The utility, which has 543,000 electricity customers in eastern and southwestern Oklahoma, presented its draft integrated resource plan at the Oklahoma Corporation Commission.
The plan represents PSO’s “best guess” at what its capacity and generation mix will look like by 2024. The utility expects to boost natural gas generation, continue to add wind capacity and to make a foray into utility-scale solar. Those changes come along with expected reductions in demand from various energy efficiency and conservation programs.
PSO expects to finish installing smart meters throughout its system by the end of 2016. It also has a pending case before state regulators to get reimbursed for $172 million in system investments and environmental compliance projects to meet federal regional haze rules and mercury and air toxics standards. If approved, the plan would increase residential customer bills 15% in the next year.
Minnesota Power will build the Northland’s first community solar garden next year, allowing customers to support solar energy without erecting solar panels on their homes or businesses.
The utility recently announced it will build a 40-kW solar array in Duluth that will be completed in 2016. The Duluth-based utility also plans a large 1-MW community solar array to be built by a contractor. Its energy production would be purchased by Minnesota Power and by customers who buy subscriptions. The two solar gardens — about 100 solar panels at the smaller site and 4,000 panels at the larger site — will generate enough electricity to power nearly 200 homes.
Both projects were submitted Sept. 10 to the Minnesota Public Utilities Commission, with approval expected in early 2016. Minnesota Power is required to comply with a state mandate to procure 1.5% of its retail electricity from solar energy by 2020.
Equipment Problem Forces Entergy’s Palisades Plant to Shut down Early
Entergy’s Palisades Nuclear Power Plant shut down four days earlier than the planned date for a refueling outage because of an equipment problem.
The plant, near South Haven, Mich., automatically shut down Wednesday when instruments detected a problem with the turbine generator system, the company said.
The problem with the system will be fixed during the refueling outage, the company said. During the planned outage, about a third of the reactor’s 204 fuel assemblies will be replaced.
Duke’s Lynn Good Named to Fortune’s Most Powerful Women List
Duke Energy President Lynn Good was ranked No. 13 on Fortune’s Most Powerful Women list this year. The magazine noted that the 56-year-old chief executive has spent a large part of her time dealing with a massive coal ash spill and other environmental issues.
The magazine’s online issue contained a video of a presentation she gave called, “How I dealt with an environmental disaster.”
Dynegy Wins Slot in MISO Zone 4 Procurement, ICC Says
The Illinois Commerce Commission named Dynegy as one of the winning suppliers of the Illinois Power Agency’s MISO Zone 4 Capacity Procurement event. Dynegy’s share of the awarded capacity was not announced, and the clearing prices remain confidential. The auction sets capacity for the planning year 2016/2017.
“The results of this RFP further validates Dynegy’s MISO investment thesis that the value of MISO capacity is rising as reserve margins tighten,” CEO Robert C. Flexon said.
The weighted average price was $138.12/MW-day. Total capacity provided by suppliers was 1,033 MW.
FERC last week upheld its decision requiring Northern States Power to continue purchasing electricity from a small hydroelectric plant, maintaining that the plant does not have access to MISO’s capacity market (QM15-2-001).
In its June request for rehearing, Northern States argued that FERC erred in requiring that the company show that Twin Cities Hydro, an 18-MW qualifying facility on the Mississippi River in Minnesota, had access to MISO’s markets. The Public Utility Regulatory Policies Act allows for the termination of the mandatory purchase of electricity from a QF if the generator has “nondiscriminatory” access to the markets.
FERC presumes that any QF with capacity less than 20 MW does not have access to the markets and requires utilities seeking to eliminate QF obligations to prove otherwise. In its May 14 order, FERC ruled that while Twin Cities had been selling power in MISO’s energy markets, it could not access the RTO’s capacity market. (See Ruling Denies Northern States’ Request to Halt Hydro Purchases.)
In its rehearing request, Northern States said the law “does not require a showing that the QF currently has met the requirements to sell its capacity into a market or a showing that the QF has had a history of sales. It simply requires a showing that the QF is on a level playing field with other facilities to establish nondiscriminatory access.”
It said FERC’s May 14 order allows Twin Cities, which is owned by Brookfield Renewable Power, to “sit on its hands and then be allowed to take advantage of the purchase requirement through its inaction.”
FERC was not persuaded by the arguments.
Northern States “has acknowledged that the Twin Cities QF cannot, at present, access the MISO capacity market,” FERC said. “The evidence presented by [Northern States’] own witness explained that, if Twin Cities were to submit a network resource interconnection service request, MISO would likely grant Twin Cities only conditional service, pending completion of several transmission network upgrades.”
The commission said the law requires that Twin Cities have “access to the specified markets and not merely that the Twin Cities QF is no more disadvantaged than any other sellers seeking to sell in such markets.”
Northern States also argued that FERC erred when it said that the company had to show access to an organized market, rather than merely a wholesale market.
The commission said no such thing, FERC said. Northern States’ “strawman argument that the May 14 order made such a finding — when, in fact, it did not — is thus without merit.”
Portland General Electric said Friday it will explore joining CAISO’s Energy Imbalance Market (EIM).
The EIM currently provides least-cost dispatch in California and parts of Oregon, Washington, Utah, Idaho and Wyoming, with Nevada-based NV Energy scheduled to join Nov. 1. Puget Sound Energy in Washington and Arizona Public Service plan to join in October 2016.
Also last week, the CAISO Board of Governors approved a proposed governance structure for the EIM. The governing body would have five members charged with representing real-time market participants’ interests, regardless of location. Changes in EIM market rules would have to be approved by the governing body and the ISO board before being filed with FERC.
Atlantic Coast Pipeline Files for Construction Permit with FERC
The owners of the Atlantic Coast Pipeline filed a formal request to FERC to construct the $5.1 billion, 564-mile pipeline to transport natural gas from the shale region of West Virginia to the Virginia and North Carolina coasts.
The owners, led by Dominion Resources and including AGL Resources and Piedmont Natural Gas, pre-filed the application about a year ago. Dominion, the operator, said it hopes to begin construction by the second half of 2016 and to complete it by the end of 2018.
The 30,000-page application asks FERC to declare the pipeline as a public benefit and necessity, which would allow the project to use eminent domain to obtain rights of way. Dominion says it has completed about 85% of the surveying for the project.
A look at the 99 operating nuclear generating stations in the U.S. in the first half of 2015 showed that 75 were operating at high levels and within all security and safety parameters, according to the Nuclear Regulatory Commission. A further 21 needed to resolve one or two low-significance safety items and will need an additional inspection, according to the commission.
But Arkansas Nuclear One Units 1 and 2 and Pilgrim nuclear plant were ranked substantially lower, on the commission’s “Multiple/Degraded Cornerstone Column,” or Column IV. Column V is “Unacceptable Performance Column” and calls for a plant to be shut down.
Pilgrim was marked down because of long-standing low-to-moderate safety findings. The plant’s operators are considering whether they can afford the costly upgrades and repairs required. If not, they say, they may shut down the plant.
Entergy, owner of Arkansas One, is set to brief the commission on steps it has taken to prepare for a major inspection of the plant. An NRC spokesman said about two dozen inspectors are expected to work “many weeks” to perform the full inspection.
NRC issued the poor rating for the plant after a fatal accident in March 2013, when a 500-ton generator part fell and crushed a worker and injured others. The incident also resulted in flooding in some parts of the plant.
Obama Administration Pledges $120 Million for Solar, Renewables
The Obama administration has pledged $120 million in funding to advance solar and other renewable energy technologies. The Department of Energy will oversee most of the programs, which are aimed at boosting solar in 24 states.
The White House noted that 734,000 homes now have solar panels, compared to 66,000 when President Obama came into office.
“President Obama and Vice President Biden are committed to promoting smart, simple, low-cost technologies to help America transition to cleaner and more distributed energy sources, help households save on their energy bills and to address climate change,” the White House said in a fact sheet outlining the efforts.
Nevadans Show up to Question NRC Report on Yucca Mountain
Nearly 100 people turned out at a public meeting to dispute a recently released Nuclear Regulatory Commission report that concluded that there would be “a negligible increase” in health risks if the Yucca Mountain underground nuclear waste repository were completed.
Richard Bryan, chairman of the Nevada Commission on Nuclear Projects, said the state was “steamrolled” into accepting the site, and said he’s not ready “to gamble on the health and safety of Nevadans” when it comes to Yucca Mountain.
The project is at a standstill, after the Obama administration cut off its funding in 2010.
FERC and the Nuclear Regulatory Commission are holding a joint meeting Oct. 21 at FERC headquarters in Washington. The two sets of commissioners will hold discussions during the first portion of the meeting, followed by staff presentations.
Representatives of the North American Electric Reliability Corp. are also expected to participate.
The Nuclear Regulatory Commission said that it is satisfied that PSEG Nuclear had addressed the issues that caused a series of unplanned shutdowns at the company’s Salem 1 station in Lower Alloways Creek Township, N.J., which prompted a higher level of attention from the regulatory agency.
NRC regulations call for a full review if a plant has more than three unplanned shutdowns in 7,000 hours of operation. Salem 1 had a fourth shutdown on Oct. 19. NRC said the company added new employee training to address the issues. The level of NRC oversight at the plant has dropped back down to normal levels.
Nation’s Utilities Perform Well After Fed Interest Rate Ruling
The stock prices of the nation’s electric utilities outperformed every other industrial sector following the Federal Reserve’s decision not to raise interest rates on Thursday.
The industry and investors were watching for the decision because utility stocks historically perform poorly when interest rates increase. The industry is capital-intensive, and utilities typically have to wait for rate increases to catch up with any interest rate increases.
“Interest rate increases are historically negative for utility stocks,” said Kit Konolige, a Bloomberg Intelligence senior utility analyst. “They react a lot like the way the bond market does when interest rates rise, which is negative.”
Sunflower Electric Power lost a second time last week in its bid to recover $5 million it claims it is owed for “backstopping” a power-supply arrangement between Kansas Municipal Energy Agency and Garden City, Kan.
FERC denied Sunflower’s request for a rehearing of a July 2014 order that rejected its complaint (EL14-38-001).
The Kansas-based cooperative had charged the arrangement was unfair and violated FERC and SPP rules, and SPP’s Tariff. Sunflower alleged Kansas Municipal’s firm capacity and firm transmission were insufficient to supply Garden City during January and February 2014 and that delivering wind energy to Garden City did not meet SPP’s dynamic scheduling rules governing the transfer of energy from one control area to another.
By failing to comply with dynamic scheduling requirements, Sunflower said, Kansas Municipal violated North American Electric Reliability Corp. standards.
Sunflower said it was entitled to $5.1 million in compensation for backstopping Kansas Municipal with imbalance energy, ancillary services and firm capacity and for Kansas Municipal’s reliance on the energy imbalance services (EIS) market. Sunflower also asked FERC to eliminate Kansas Municipal’s “unfair marketing advantages” and practices it said threatened grid reliability.
Sunflower was the balancing authority for the area before SPP launched its Integrated Marketplace in March 2014. The dispute arose after Garden City dropped its supply contract with Wheatland Electric Cooperative, a Sunflower member, and switched to Kansas Municipal to supply its 71.5-MW load in January 2014.
FERC denied Sunflower’s complaint in July 2014, saying the cooperative failed to meet its burden of proof.
The commission noted there was no network integration transmission service agreement (NITSA) violation because the wind resources were short-term and, therefore, not part of the NITSA. FERC also pointed out SPP’s Market Monitoring Unit found no violation of the Tariff or evidence that Kansas Municipal negatively affected SPP’s EIS market.
The commission held that neither Kansas Municipal nor SPP could violate the NERC standard in question, “because neither entity was registered as a balancing authority with NERC during the relevant time period,” and that neither Kansas Municipal nor SPP “had any obligation with regard to dynamic scheduling.”
In Sunflower’s rehearing request, it charged that FERC erred in finding Sunflower failed to meet its burden of proof and determining that the supply arrangement did not violate the Tariff.
In denying Sunflower’s request for a rehearing and clarification of the July 2014 order, FERC said the cooperative’s request fell outside the order’s holdings.
“The complaint order principally rested on Sunflower failing to meet its burden of proof,” FERC said. “In contrast, Sunflower’s requests for clarification are general questions regarding the operation of the SPP Tariff. The requests are not specific to the instant proceeding and are inappropriate to raise at this late stage of the proceeding.”
WASHINGTON — As the Sept. 28 deadline approaches for Exelon and Pepco Holdings Inc. to appeal D.C. regulators’ rejection of their merger, Mayor Muriel Bowser is saying little to indicate how she feels about a second try by the companies to close the deal.
On Thursday, local officials and advocates rallied in front of the mayor’s office to urge Bowser to “stand firm” against Exelon and Pepco, amid talk that the companies are lobbying her administration with extra concessions designed to secure her support before they request that the D.C. Public Service Commission reconsider the deal.
Councilwoman Mary Cheh said that the companies want to be able to go before the PSC with the mayor and city’s attorney general saying that additional ratepayer credits — “or whatever little kind of trinket they’re going to throw our way” — now make the deal in the public benefit.
“Right now, believe me, sort of slithering around the district building and other parts of our government are Exelon and Pepco representatives trying to work out some deal that will steal from us the victory that we won on the merits before the Public Service Commission,” Cheh said.
Last week, Exelon placed full-page ads in The Washington Post proclaiming that the “merger is too important to fail,” which opponents at the rally held up as evidence that the companies have not given up.
But even as The Post reported Friday that administration officials are internally discussing whether a revamped deal is possible and that Pepco has warned the administration that rates would go up if the deal was not approved, Bowser has remained taciturn. Cheh told RTO Insider that the council has been “left in the dark” by the mayor.
Speaking on the Kojo Nnamdi radio show Friday, Bowser declined to say whether she’s had any discussions with Exelon, only saying that she agreed with the PSC’s decision last month that the deal, as proposed, was not in the public interest. (See DC Halts Exelon’s Acquisition of Pepco Holdings.)
Bowser also declined to say whether she wanted to support the merger. Noting that other states have approved the deal with concessions, she said, “We’re not them. And it’s always been my position that they have to have in front of us something specific to the District of Columbia that addresses my concerns.”
But ultimately, Bowser said, “whether I think they come to terms or not, the Public Service Commission has to approve or disapprove the merger and then it would follow the legal course beyond that.”
The PSC would have 30 days after the companies file an appeal to make a decision. The companies could turn to the courts as a final recourse, Bowser acknowledged.
“We continue to hear from both sides and our position hasn’t changed — any merger has to be in the best interest of district residents and taxpayers,” Bowser spokesman Michael Czin said in a statement.
“Today we just have two words for Mayor Bowser: Madame Mayor, stand firm,” said the Rev. Earl D. Trent, pastor of the Florida Avenue Baptist Church, at Thursday’s rally. “Stand firm; do not settle for the quick fix. Stand firm against the blistering winds of compromise that Exelon is surely offering. … Stand firm and back the PSC’s decision. Your constituents have clearly spoken.”
FERC last week approved MISO’s rate schedules for the system support resource agreements at three aging power plants on Michigan’s Upper Peninsula but directed the RTO to revisit its general cost allocation methodology to address concerns over how it might be applied to future SSR units.
The order conditionally approved the allocation of SSR costs at Presque Isle, Escanaba and White Pines (ER14-2952-003). The commission had rejected a prior cost allocation plan in an order in February.
FERC found that MISO’s proposed cost allocation methodology “generally complies” with the February order “in that it assigns SSR costs directly to load-serving entities (LSEs) serving loads that would contribute to thermal or voltage reliability violations in the absence of the Presque Isle, Escanaba and White Pine SSR units under conditions that are representative of actual manual and/or automatic responses taken during reliability events.”
But it rejected MISO’s filing as a generally applicable rate schedule, instructing the RTO to address the commission’s remaining concerns in a compliance filing.
FERC said the proposed methodology does not explain how MISO will calculate load distribution factors and does not justify how it selects load buses in identifying SSR beneficiaries.
The commission also said MISO did not provide an adequate explanation of the terms “daily load weighting factor” and “aggregate distribution factor” and failed to justify its proposal to allocate SSR costs at commercial pricing nodes based on their non-coincident monthly peak volumes.
“We find that this approach does not represent the actual conditions studied that caused the constraints, because MISO’s Attachment Y study identifies constraints during the coincident system peak volume, as this is when the SSR unit is most likely needed for reliability purposes,” the commission said.
In last week’s order, FERC dismissed the Michigan commission’s “generic criticism” that MISO’s new methodology is based only on how load contributes to thermal constraints and voltage violations in the absence of the SSR unit. The PSC said MISO failed to consider other factors that could be used to identify LSEs that require the SSR units.
“The Michigan commission has not made a showing that these two factors are insufficient to identify LSEs that benefit from the operation of the SSR units, nor has it identified other factors that MISO should have considered,” FERC said.
