Page 1467 – RTO Insider

October 2, 2015

PJM Members OK $2,000/MWh Energy Market Offer Cap

By Suzanne Herel

VALLEY FORGE, Pa. — The Markets and Reliability Committee voted overwhelmingly Thursday to raise the energy market offer cap to $2,000/MWh in a move that outgoing CEO Terry Boston called “the stakeholder process at its best.”

The MRC approved the new cap by an unweighted 84-17 margin, after which the Members Committee gave final approval by voice vote.

Boston said the Board of Managers would approve the new framework and PJM would be filing a Tariff change with FERC within a couple of weeks.

He apologized for not having the Tariff language ready before the vote, saying, “We were not as optimistic as we should have been about this getting approved this morning and afternoon.” He said the language would be made available to members a few days before the FERC filing.

Boston appeared touched by the vote, which comes as his seven-year tenure nears its end. “In the first meeting of the year, after this was voted down last year, I begged for consensus,” he recalled.

There was a smattering of applause when the vote was revealed at the MRC, and many who had sparred this year over the issue offered praise to PJM staff, each other and the four entities who agreed to withdraw their own proposals in favor of the simplified plan: Direct Energy, Old Dominion Electric Cooperative, PJM Power Providers Group (P3) and the Independent Market Monitor.

“It’s really cool that we were able to pull this off given the short time frame,” said Marji Phillips of Direct Energy, which had initiated the first of the four proposals. “I want to compliment everyone who supported this — especially when I was yelling at you at the last meeting.”

Pepco Holdings Inc.’s Gloria Godson called the vote “a beautiful thing to behold.”

The Details

The proposal caps cost-based offers at $2,000/MWh and allows them to set LMPs, with market-based offers allowed to equal cost-based ones. Generators with approved fuel-cost policies claiming costs above $2,000/MWh would be compensated through after-the-fact review and subsequent make-whole payments.

Supporters of an increase in the cap say it is necessary to ensure that gas-fired generators can recover their costs when fuel prices spike during extreme conditions such as the 2014 polar vortex.

Jeff Whitehead of Direct Energy, whose proposal would have raised the cap to $2,700/MWh for cost-based day-ahead offers and price-based real-time offers, said the company was willing to back the compromise because it ensures “that as much generator compensation cost is recovered as possible in energy prices, which are hedgeable, and something load servers can compete on.”

“Uplift is not [hedgeable] and is a cost that gets rolled into risk adders that get passed on to consumers,” he added.

Likewise, David “Scarp” Scarpignato of Calpine said P3 didn’t believe the consensus proposal offered the “proper price formation,” but the group was willing to support it because it does allow generators to recover costs and raises the level that can set LMPs.

Temporary Change; FERC Action Expected

Some of those who opposed raising the cap previously — or thought the compromise was insufficient — were willing to support what is now assumed to be a temporary solution. FERC on Sept. 17 announced its intention to take action on offer caps and other price formation issues. (See NOPR Requires RTOs Switch to 5-Minute Settlements.)

Exelon’s Jason Barker, who at the last meeting on the issue had criticized the framework, supported it Thursday as “an improvement over the status quo” and said he hoped FERC would improve on the filing. “We will look forward to FERC … recognizing flaws inherent in this proposal,” he said. (See Consensus Near on PJM Energy Market Offer Cap?)

Similarly, Dynegy’s Jason Cox said, “Dynegy reluctantly supports this compromise as a way to ensure that our costs are covered until FERC acts. We believe that we should not allow market distortions and continue to support potential massive uplift during critical periods.”

Susan Bruce of the PJM Industrial Customer Coalition said her group continued to have concerns over the proposal but offered support in return for a promise from the Market Monitor and PJM that there would be “robust reporting” on offers between $1,000, the current cap, and $2,000.

Delaware, Maryland Unconvinced

Representatives of state commissions generally opposed the proposal.

John Farber, public utility analyst for the Delaware Public Service Commission, asked that PJM consider releasing information about the heat rates of the generators setting the clearing price.

Walter Hall of the Maryland Public Service Commission said his agency remained unconvinced of a need to raise the cost cap.

Jim Jablonski of the Public Power Association of New Jersey pointed out that PJM fared better this past winter, which saw colder temperatures, than it had during the previous season’s polar vortex.

And, he said, “Capacity Performance is designed to provide a financial incentive to perform whenever needed and designed to eliminate future emergencies. Reliability, therefore, in our view is protected. We do not think a change is warranted. Two thousand dollars is not supportable except as a compromise, has no factual basis and definitely is going to be open to challenge.”

September 29, 2015

MISO Staff Recommends 3 Economic Projects

By Tom Kleckner

MISO staff said Friday they will recommend three economic projects be included in the 2015 MISO Transmission Expansion Plan. The projects in Southern Indiana, East Texas and Central Arkansas have a projected cost of $281 million, including $85 million that PJM will pay for its share of the Indiana project.

Digaunto Chatterjee, MISO’s director of economic studies, told a special meeting of the Planning Advisory Committee that staff selected the Duff-Rockport-Coleman 345-kV project from among three under consideration near the RTO’s eastern seam with PJM in Southern Indiana.

Chatterjee said the MISO portion of the project — the Duff and Coleman substations and a 28.5-mile single circuit between them — has a benefit-cost ratio of 16.1 based on MISO’s estimated cost of $67.2 million.

The project, expected in service in 2021, should eliminate congestion around Newtonville and Coleman and provide slightly higher economic benefits than the Duff-Coleman alternative. MISO’s cost will be the same as the $67.2 million Duff-Coleman because PJM will pay $85.3 million for improvements that will allow it to eliminate the special protection scheme at its Rockport substation.

“It’s no difference to us whether it’s one project or two projects connecting with each other,” Chatterjee said.

The PJM portion of the project includes two 765/345-kV transformers in Rockport and a 14-mile double circuit between the substation and Duff-Coleman.

Reacting to concern that the PJM portion of the project could result in unexpected costs, Chatterjee said staff “will make it clear to the board MISO stakeholders don’t want any issues from the PJM side to keep us from going ahead with the project.”

“We fully expect Duff to Coleman will be connected to Rockport,” he told the PAC, “but we won’t let PJM’s processes interfere with our portion of the project.”

Chatterjee said he had received a commitment from PJM saying that will approve the project and pay the incremental costs. (See “AEP Agrees to Pay Share of Market Efficiency Project” in MISO Planning Advisory Committee Briefs.)

East Texas Project

MISO is also recommending two economic projects in its South region, including a two-part construction/rebuild that would ease congestion around an East Texas load pocket.

MISO recommends constructing a new 230-kV transmission line between the existing Lewis Creek substation and a new 345/230-kV substation that will cut into the Grimes-Crocket 345-kV line. In addition, it will rebuild the Newton Bulk-Leach 138-kV line.

Chatterjee said the project cleared the benefit-cost ratio under two different future generation scenarios, with a B/C of 1.5 assuming future generation inside the load pocket and a 2.88 B/C with generation added outside the pocket.

The project has an estimated cost of $122.5 million and a projected in-service date of 2021. It would ease congestion on three 138-kV lines.

Arkansas Project

The third project, rebuilding the Mabelvale-Bryant South 115-kV line, would reduce congestion in the southwest Little Rock area. It has a projected cost of $6.1 million and a weighted B/C ratio of 5.88, with an estimated 2020 in-service date.

Staff will accept stakeholder input on the three projects through Oct. 2. Previous feedback and MISO’s responses to the South projects have been posted in the Oct. 2 Market Congestion Planning Study meeting materials.

The PAC will consider MTEP 15 during its Oct. 14 meeting, before the plan goes on to the System Planning Committee in October and Board of Directors in December.

September 29, 2015

FERC Orders Hearing on PJM-TransSource Dispute

A FERC administrative law judge will attempt to settle TransSource’s complaint against PJM concerning the costs of three network upgrades that the company says are being inflated by transmission owners (EL15-79).

TransSource alleges that PJM has refused to provide the company with files relevant to the system impact studies showing the underlying costs of the upgrades, which the company says is in violation of the RTO’s Tariff. PJM maintains that it provided TransSource with all the necessary data and that it is under no obligation to provide the specific files the company is requesting.

The Independent Market Monitor last month requested that FERC settle the dispute. (See PJM Monitor Asks FERC to Resolve TransSource Dispute.) PJM responded by saying it was willing to informally meet with the Monitor, TransSource and the relevant transmission owners to discuss the studies. TransSource rejected this, supporting the Monitor and insisting on a formal process.

The commission said Thursday that it could not rule based on the record before it and set the case for hearing and settlement procedures.

— Michael Brooks

September 29, 2015

IPPNY Fall Conference

More than 170 people attended the Independent Power Producers of New York’s 30th annual Fall Conference at the historic Gideon Putnam resort in Saratoga Springs, a two-day affair of golf and industry talk. See RTO Insider’s coverage:

September 29, 2015

MISO Monitor: Extended LMP Changes Minimal Thus Far

By Tom Kleckner

The MISO board’s Markets Committee met at Potomac Economics headquarters in Fairfax, Va., last week to review the Independent Market Monitor’s quarterly metrics report and its monitoring procedures.

Monitor David Patton, president of Potomac Economics, also provided a preliminary evaluation of extended locational marginal pricing (ELMP), which he said had resulted in very small price changes for most locations.

Patton recommended MISO use more online peakers under ELMP, which he said would increase their price impacts. Only about 1% of the resources are eligible to set prices under ELMP. The program, which was implemented in March, is designed to reduce uplift charges by incorporating all offer costs into the market clearing price.

“Real-time prices should fully reflect the cost of dispatchable resources, but ELMP allows offline units to set the price when you have congestion,” Patton said. “This could be resolved by quick-starting offline units.”

Summer Performance Competitive and Reliable

Patton said the MISO market performed “competitively and reliably” during the summer, despite record peak loads in MISO South in July.

Considerably lower gas prices than a year ago drove down MISO’s average system-wide energy prices for the June-August period. Real-time prices fell 17% from last year’s $28.78/MWh, and day-ahead prices fell 19% to 29.26/MWh.

Congestion was typical for the summer, with both day-ahead and real-time congestion similar to last year. Patton said the market’s price convergence was generally good, with the exception of congested areas in Texas and Louisiana.

“We’re seeing people put in virtual load on one side of the constraint,” he said, “and a virtual bid on the other side.”

The market continues to respond slowly to congestion-related price differences in the day-ahead and real-time markets, Patton said.

The Monitor said “growing pains” in market-to-market coordination with SPP have resulted in some inefficiency and settlement disputes. When the non-monitoring RTO dominates the flows, MISO and SPP have seen swings in dispatch flows over M2M constraints.

“The SPP constraints move so fast,” Patton said. “I’d like to see the two RTOs develop protocols to determine who is in charge of the constraint.”

The summer’s above-average temperatures in MISO South resulted in the extensive commitment of peaking units in the day-ahead and real-time markets.

Some day-ahead hourly commitments exceeded 700 MW per hour, three times the typical rates. Additional real-time commitments resulted in more than 1,100 MW of peaking units running each hour during the quarter, double the amount from last summer.

MISO Monitor’s Procedures

Patton also reviewed with the committee Potomac’s scope and processes as MISO’s Monitor.

The Monitor downloads market data every 30 seconds to allow it to observe market participants’ actions in the market, identify flaws in market rules and support the RTO’s market power mitigation. Potomac develops and maintains the production software that does all the work, but that software is owned by MISO.

“You can only do efficient monitoring if you have highly automated systems,” Patton said, noting Potomac’s ability to run tests and screens in the background and to send automatic notifications. He said he partly attributes the costs between different markets to RTOs’ varying reliance on automated systems.

Potomac also performs monitoring duties for ERCOT, ISO-NE, NYISO and the Regional Greenhouse Gas Initiative. Its 24-member staff includes four Ph.D. economists and a half-dozen software engineers.

Operations Report

MISO staff delivered a positive monthly operational report at the meeting, saying the RTO’s reliability, markets and operational functions all performed well in August.

MISO South set a new peak load of 32.7 GW on Aug. 10, surpassing the previous record of 32.6 GW on July 29. However, system-wide average and peak loads declined 3.6% and 4.2%, respectively, compared to July’s numbers.

Energy prices (based on the average of MISO’s active hubs) for the summer months were below $30/MWh and were at the lowest levels in recent summer months.

Wind production — 2,362 GW in August — increased nearly 20% from July and 75% from August 2014 (1,348 GW). Though wind output typically is at its lowest levels in August, it reached its highest level as a percentage of total generation in five years, at 4.3%.

September 29, 2015

Exelon Appeals DC PSC Decision; DC Mayor Confirms Negotiations

By Suzanne Herel

Exelon on Monday asked the D.C. Public Service Commission to reconsider its rejection of the company’s proposed $6.8 billion acquisition of Pepco Holdings Inc.

The filing came as D.C. Mayor Muriel Bowser’s office confirmed that it is seeking to negotiate a settlement with the companies. “We are engaged in substantive discussions with the companies on a settlement agreement that would address, in a new application, the administration’s concerns,” City Administrator Rashad Young, who is leading the negotiations, said in a statement. “Any settlement agreement would be presented to the PSC for review, public comment and final determination.”

In a radio interview Sept. 25, the day after opponents of the deal rallied outside her office, Bowser had declined to confirm whether she was engaged in negotiations. (See DC Mayor Tight-Lipped on Exelon-Pepco Deal.)

Exelon’s appeal, submitted on the last day of the 30-day appeal period, takes issue with two of the PSC’s findings: that the merger was not in the public interest and that it would not be in the public interest for the commission to identify additional conditions that could make it so.

The 43-page filing maintains the commission’s ruling contained “various errors of law” and reiterated the benefits that the company said the district would receive, quoting at length from CEO Christopher Crane’s direct testimony. (See CEO Crane to DC PSC: Exelon Committed to Jobs, Ratepayers.)

Exelon said the merger would “yield tremendous benefits by unlocking millions of dollars of synergy savings; facilitating the sharing of best practices; enhancing the reliability of service; ensuring the continuity of a skilled workforce; creating net positive job growth in the District of Columbia; guaranteeing Pepco’s active participation in and support of the District of Columbia’s many civic and charitable organizations; and providing Pepco and the District of Columbia with a partner uniquely well-suited to help the District of Columbia advance its sustainability goals quickly and effectively.”

Crane referred to the negotiations with Bowser’s office in a press release late Monday. “Since the Public Service Commission explained why it didn’t approve the merger last month, we’ve worked to learn what’s most important to the district – and we are responding,” Crane said.

“Exelon’s attempt to breathe new life into its takeover of Pepco should be rejected by the D.C. Public Service Commission,” the opposition group Power DC responded. “The PSC unanimously rejected Exelon’s attempt to buy Pepco in August for a very simple reason: the merger is not in the public interest. Nothing Exelon said today will change that fact. Exelon’s business model is fundamentally at odds with the district’s ability to control its own power supply.”

In making its decision last month, the PSC 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. (See DC Halts Exelon’s Acquisition of Pepco Holdings; Pepco Stock Tumbles.)

More than half of the Advisory Neighborhood Commissions and nearly half of the 12-member City Council remain opposed to the deal. The Office of People’s Counsel and the attorney general’s office also have advised against approval without significant concessions.

The acquisition was approved by regulators in all remaining jurisdictions: New Jersey, Maryland, Delaware, Virginia and FERC.

September 29, 2015

NYPSC Chair Zibelman Acknowledges Costs Concerns

By William Opalka

SARATOGA SPRINGS, N.Y. — New York Public Service Commission Chairman Audrey Zibelman last week acknowledged legislators’ concerns over the state’s energy costs but gave no indication that the commission would relent on lawmakers’ demands that it release data on generators’ finances.

Forty State Assembly members and nine state senators signed a letter last week asking the commission to release in full the annual reports submitted by the state’s generation owners.

Generators contend that the reports should be treated as trade secrets because they contain data on their revenues, expenses and profits.

“I understand that people are worried about price confidentiality; I can assure you that the commission takes very seriously its role around maintaining confidentiality and of course we’re reviewing the [disclosure request] against the law,” Zibelman told the fall conference of the Independent Power Producers of New York.

“But I think we can’t disabuse ourselves of the fact that one of the things that’s very important in our markets is to have public confidence and when you have 48 [sic] Assembly people saying ‘We have some concerns,’ we need to start talking about how do we allay those concerns and make sure that there is confidence throughout the state.”

Legislators say the information is essential to determining whether electric competition has resulted in “just and reasonable” rates.

“For too long the industry has operated in secrecy, which is damaging to New Yorkers across the state, who are paying the third highest rate for electricity in the entire country,” the legislators wrote. “In a time where the PSC is taking steps to lead New York into the energy future with [Reforming the Energy Vision], and it’s proceeding to evaluate energy affordability for low-income utility customers, we ask that the PSC do everything it can to make sure that the industry is operating responsibly.”

Cost-Benefit Analysis on REV

The REV initiative also came under criticism at the IPPNY conference from Michael Durant, New York state director of the National Federation of Independent Business.

Durant said he feared REV could result in a “bridge to nowhere” and that his organization will support legislation calling for a cost-benefit analysis for the initiative.

“For REV, we don’t know what it’s going to cost, we don’t know how long it’s going to take and nobody can predict what the end result is,” he said, adding that energy costs are a top concern for his small business members.

Second Request for Release of Reports

The release of the generators’ reports was first requested by Assemblyman James Brennan (D-Brooklyn), who says consumers are being overcharged “billions” by power generators in a flawed market that needs to be “re-regulated” (13-01283 and 11-M-0294).

Brennan, chair of the Assembly Committee on Corporations, Authorities and Commissions, said much of the redacted information is available from other public sources.

“The wholesale electric power industry seeks to conceal its profits from the public by claiming that the bidding system would be undermined if rivals knew each other’s costs,” Brennan said in a statement. “But our evidence shows that argument is without merit because the bidder’s identities are easily ascertainable and their costs are easily calculated from regular federal filings made by these companies.”

The lawmaker’s first Freedom of Information Law request in 2014 was rejected by the PSC’s records access officer, who said the information consisted of protected trade secrets, and that disclosure would cause havoc in the operation of the power markets. Kathleen H. Burgess, secretary of the state Department of Public Service, agreed, rejecting Brennan’s appeal.

Brennan filed a second request in May, which was also rejected by the records access officer. On Aug. 27, Brennan again appealed to the secretary.

This time around, Brennan’s request included an affidavit from energy consultant Robert McCullough that said that heat rate information from power plants is publicly available in the Environmental Protection Agency’s national electric energy data system database.

IPPNY responded with an affidavit that said the database contains estimates and not the actual heat rates that the PSC requires. The records officer agreed.

IPPNY and nuclear plant owner Entergy argued that the disclosure issue had already been decided. “No new facts or circumstances have developed over the past year to warrant a different result now,” an attorney for Entergy wrote in response to the appeal.

Brennan had asked for decision by Sept. 11, but the commission will not rule on his demand for disclosure until Oct. 19. “In light, however, of the length of the appeal, and particularly the 190-page McCullough affidavit, and of the issues raised in the oppositions received thus far from IPPNY and Entergy, a decision on the appeal will require some period of time,” Burgess wrote on Sept. 11.

September 29, 2015

NYPSC Staff Recommends $1.2B in Transmission Projects

By William Opalka

New York Public Service Commission staff on Tuesday recommended that three transmission developers move to the next stage in its AC Transmission initiative to eliminate bottlenecks for downstate load centers.

After evaluating 22 transmission proposals and several non-transmission alternatives from four developers, the staff recommended two main projects: the upgrade of the 91-mile, double-circuit 220-kV Edic-New Scotland-Rotterdam line to 345 kV and the upgrade of the 51-mile, double-circuit 115-kV Knickerbocker-Pleasant Valley line to a 115/345-kV double circuit.

The PSC is expected to vote in December on the projects, which have an estimated price of $1.2 billion (12-T-0502, et al).

The proposed routes would satisfy Gov. Andrew Cuomo’s Energy Highway goal to bring 1,000 MW of power generated upstate to areas of high demand in southeastern New York and New York City.

“Many of the proposals and critiques were responsive to the governor’s call for transmission solutions that maximize the re-use of existing rights of way so as to minimize impacts on the sensitive landscapes of New York. … Staff’s recommended portfolio successfully avoids the opening of new transmission rights of way and also avoids a new crossing of the scenic Hudson River,” the report said. (See Tx Plan to Open NY Choke Points Without New ROWs.)

The developers are NextEra Transmission, North American Transmission and a coalition of utilities and the New York Power Authority known as the New York Transmission Owners. Another private developer, Boundless Energy, was disqualified because its projects, while environmentally sound, did not provide a positive cost-benefit ratio, according to the report.

The Edic-New Scotland-Rotterdam line runs through the Mohawk Valley from Oneida County, near Utica, to Albany County. The Knickerbocker-Pleasant Valley line in the Hudson Valley runs from Rensselaer County to Dutchess County.

Following approval by the PSC, NYISO would be directed to issue a request for proposals to build the two segments. PSC staff said the two upgrades would provide more benefits if other developers were given an opportunity to bid on the project rather than solely selecting the NYTOs.

“The NYTOs and NextEra should be invited to apply to build both segments, and NAT should be invited to build the … Knickerbocker to Pleasant Valley segment,” staff wrote.

Staff said that while “other developers will be able to participate in the NYISO process” and potentially win the contracts, only the three companies will be reimbursed for the costs of participating if they are not selected.

To operate at full capacity, the Knickerbocker-Pleasant Valley project also would require upgrades to Orange and Rockland Utilities’ Rock Tavern terminal and increasing the 11-mile 69-kV Chester-Shoemaker-Sugarloaf line in Orange County to 138 kV.

In an interim report filed in July, PSC staff said that a spring announcement that a 720-MW power plant project had secured financing led to additional study of the Hudson Valley alternatives. (See NYPSC Staff Narrows Transmission Alternatives.)

The additional capacity would allow wind power generation, mostly sited in the northwestern part of the state, to more easily gain access to downstate New York markets.

September 29, 2015

Company Briefs

Alliant Energy plans to build a 2-MW solar facility atop a closed 20-acre coal ash landfill in Wisconsin. Alliant said the 7,600-panel complex near the shuttered Beloit coal-fired power plant will be the largest utility-operated solar site in the state.

Using a brownfield site like the coal ash dump makes sense, according to Geoffrey Underwood of South Korea-based Hanwha Corp., which is developing the solar installation for Alliant.

“Solar projects in general are an excellent re-use for landfill Superfund sites, brownfield sites, in that, one, the length of the projects and the long life of these projects in the 20- to 40-year range give the land additional time to settle and cure,” Underwood said.

More: Wisconsin Public Radio

Duke Plans $1.9B Investment to Modernize its Indiana Grid

Duke Energy plans to invest about $1.9 billion over seven years to improve the reliability of its transmission and distribution systems, Duke Indiana President Melody Birmingham-Byrd said.

Birmingham-Byrd, who took over Duke’s Indiana operations in June, said the electric utility plans to file an investment request with the Indiana Utility Regulatory Commission at the end of the year. The upgrades will replace aging equipment and modernize the grid.

“We have very detailed programs and project plans that have been developed so that we can begin those projects almost immediately after being approved,” she said. Duke serves 810,000 customers in 69 of Indiana’s 92 counties.

More: Tribune Star

NextEra Missouri Wind Project Back from the Dead?

NextEra Energy could be reviving its Osborn Wind Energy Center, a 97-turbine 200-MW wind farm in northwest Missouri that was fully permitted in 2010 but went unsold and was put on hold.

NextEra last week received regulatory approval to build two 197-foot meteorological towers. The company says it is re-verifying wind data with the aim of starting construction in summer 2016.

Over the 30-year project life, NextEra said it would invest about $350 million, which should generate $35 million in local property taxes.

More: St. Joseph News-Press

PSE&G Plans Switching Station at Newark Airport

Public Service Electric & Gas’ $1.2 billion plan to improve reliability in northeastern New Jersey includes a new switching station at Newark Liberty International Airport.

The switching station is an integral part of the utility’s Bergen-Linden Corridor transmission line project. The line will more than double the capacity of the existing 138-kV system, replacing it with a double-circuit 345-kV system.

More: NJ.com

Duke Energy Shows off Dan River Coal Ash Project

Duke Energy last week showed off a new rail yard and loading dock it has put into place to remove coal ash from the grounds of the retired generator where 39,000 tons of coal-combustion byproducts fouled the Dan River two years ago.

The utility’s system will excavate a mountain of coal ash stored on the plant grounds and transport the waste by train to a privately owned landfill in Amelia County, Va. The company is removing the waste under a state mandate to safely store coal ash from its power plant sites.

“Our first phase is to get rid of that whole mountain of coal ash,” said Jim Malloy, project manager at the Dan River site. “The stuff will not see the light of day again.”

More: Greensboro News & Record

DTE’s Fermi 2 Staying Shut Down for Refueling

DTE Energy’s Fermi 2 nuclear generating station will remain shut down after an unplanned Sept. 13 outage caused by a problem with an auxiliary cooling system. The company says it now plans to move up a planned refueling outage that was scheduled for later.

Vito Kaminskas, site vice president, said it was decided to accelerate the schedule for the refueling outage to take advantage of the plant being offline already. DTE shuts down the unit about every 18 months for refueling.

More: Monroe News

3 Hurt in Steam Leak at SC Nuclear Fuel Plant

Three workers were injured Friday from a steam leak at Westinghouse Electric’s nuclear fuel production plant near Columbia, S.C., forcing a section of the plant to shut down.

Plant officials said there was never a public or environmental threat during the incident and that there was no leak of radiation. They said a “mechanical issue,” rather than an explosion, caused the steam leak. The three men, who were not identified, were taken to a burn center at an Augusta hospital.

The leak happened in a wash tank in an area where nuclear fuel assemblies are prepared. Fuel assemblies are hollow rods that are filled with radioactive pellets. When completed, the fuel rods are shipped to nuclear generating stations around the country.

More: The State

Crown Hydro Tries Again to Amend License

Crown Hydro is making a third attempt at building a hydroelectric project at St. Anthony Falls in downtown Minneapolis.

The company is seeking to amend the federal hydropower license it was granted in 1999 but never put to use. This time it wants to install its powerhouse at the upper end of a lock complex owned by the U.S. Army Corps of Engineers, then tunnel underground to release water downstream. Two previous proposals fizzled.

Nearly 70 Minneapolis residents told FERC they think the firm should be required to obtain an entirely new license for the 3.4-MW project. City officials agreed. A FERC official also advised Crown Hydro in 2013 to seek a new license, calling the latest proposal “essentially a different project” that needs new engineering and environmental analysis.

More: Minneapolis Star Tribune

Dallas Billionaire Buys Williams Co. for $37.7 Billion

Dallas billionaire Kelcy Warren’s company Energy Transfer Equity is buying pipeline firm Williams Co., adding about 30,000 miles of pipeline to the 70,000 Energy Transfer already controls. Energy Transfer will pay $37.7 billion in a combination of stock and cash, with $43.50 for each share, about $2 more than the stock’s Friday closing price.

Warren and Energy Transfer have been pursuing Williams since the beginning of the year. Energy Transfer offered Williams $53.1 billion in June, but the offer was rejected by Williams. At the time, Williams said the offer “significantly undervalues Williams.” Since then, however, crude oil prices have plummeted, buffeting the industry.

Those conditions made this the right time to move on Williams, Warren said in an interview with The Dallas Morning News last week. “You try to guess the bottom, and you’re always wrong,” he said. “So you buy a little before or a little after. We believe the time is now.”

More: The Dallas Morning News

September 29, 2015

FERC Sides with SPP Monitor on Mitigated Offers

By Tom Kleckner

FERC last week sided with SPP’s Market Monitoring Unit in a long-running dispute with generators over what costs can be included in mitigated offers. The commission rejected SPP’s proposal to change the definition of costs allowed under mitigated energy offer curves, start-up offers and no-load offers (ER15-2268).

The commission said SPP’s proposal to describe mitigated offers in terms of variable cost rather than short-run marginal cost was “inconsistent” with the commission’s directive in its 2012 conditional acceptance of SPP’s Integrated Marketplace.

“We find that SPP’s proposal to base mitigated offers on variable costs may lead both to inefficient dispatch outcomes, characterized by higher production cost, and to distorted locational marginal prices that do not reflect competitive conditions,” the commission said.

Generators’ Complaints

Generators subject to mitigation had complained to SPP that they weren’t being paid enough because the Monitor refused to include certain expenses, such as long-term service agreements, in its definition of allowed costs. Generators subject to mitigation include those with local market power and those manually committed by SPP or a local transmission owner.

Among the complainants was Golden Spread Electric Cooperative, which said it was suffering losses under SPP’s frequent dispatch of their quick-start units. (See SPP Board Rejects Short-Term Study; Impact on Quick-Start Units Debated.)

After more than a year of stakeholder meetings failed to reach consensus on the definition of short-run marginal costs, SPP in July filed proposed Tariff changes that would replace references to the term with the variable cost components of mitigated offers. The proposal would have set default variable operations and maintenance (VOM) costs that generators could include and listed the types of costs eligible under resource-specific offers.

SPP Monitor Protests

SPP’s filing drew protests and interventions from nearly two dozen market participants and the SPP Monitor, which asked FERC to reject the change, saying it could result in VOM costs that exceed short-run marginal costs and lead to economic withholding.

The Monitor said short-run marginal cost is not a “nebulous term,” but rather a common economic phrase describing the incremental cost of production — in this case, those that vary by megawatt-hour output.

It said SPP’s proposal “attempts to fix a problem that may not exist,” noting that mitigation had decreased significantly since the Integrated Marketplace’s launch in 2014.

Independence Concerns

PJM’s Independent Market Monitor filed a protest supporting the MMU, noting that PJM recently eliminated long-term maintenance from mitigated offers.

The IMM said that the proposed changes raised questions about whether SPP was protecting its MMU’s independence. “When the SPP Market Monitor made interpretations with respect to mitigated offers that SPP market participants did not like, the response was that market participants initiated a stakeholder process to apply pressure on the SPP Market Monitor to compromise or change those interpretations,” FERC said, paraphrasing the IMM’s filing.

The New Jersey Board of Public Utilities also backed the monitors’ arguments, saying approval of SPP’s proposed changes would be “a regression from SPP’s current mitigation rules” and could create an “adverse precedent that spills over to other regions.”

Filing not Supported

In rejecting SPP’s proposal, FERC said SPP failed to define the term “variable cost” or to “describe with specificity what costs may be included in mitigated offers as variable costs that were not previously regarded as short-run marginal costs.

“As such,” the commission said, “SPP proposes to replace one phrase that SPP contends is undefined (short-run marginal cost) with another phrase that is not well defined (variable cost).”

The commission also rejected the proposed default VOM costs, saying SPP’s decision to use the 80th percentile value of costs submitted by market participants would result in figures representative of high-cost units.

The commission said the PJM Monitor’s call for an examination of whether SPP was protecting the independence of its Monitor was outside the scope of the docket. “We note, however, that the SPP Market Monitor’s participation in this case demonstrates the importance of having an independent market monitor … to ensure that markets are competitive.”