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.
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.
Zibelman
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
Durant
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.
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.
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.
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.
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.
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.
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.”
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.
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.
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.
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.”
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.
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.”
SARATOGA SPRINGS, N.Y. — Political leaders’ urge to “do something” to combat high winter power prices risks undermining ISO-NE’s power market just as it has begun adding new generation, the head of the New England Power Generators Association said last week.
Dolan
“We’ve seen new investment come into the region for really the first time in a decade,” NEPGA President Dan Dolan said in a luncheon address at the fall conference of the Independent Power Producers of New York.
He said ISO-NE’s forward capacity market had spurred a “dramatic response,” noting that 13,000 MW of generation is now in the RTO’s transmission queue, up from 5,000 MW a year ago. (See Exelon, LS Power Join CPV in Adding New England Capacity.)
“We’re seeing the market do what it is designed to do,” he said. “But the drive to do something is creating an unprecedented march to out-of-market interventions at the very moment that we’re seeing billions of dollars in investment come into the region.”
The polar vortex and massive snowstorms in Boston in recent winters has created the idea that an “energy crisis” exists that demands immediate action across the region, Dolan said.
He said generators are particularly troubled by two state initiatives.
The first is a drive to “subsidize” hydropower from Hydro-Quebec through transmission and long-term power contracts. Massachusetts Gov. Charlie Baker has proposed legislation to allow 2,400 MW annually of imported power, about one-third of the state’s needs. NEPGA commissioned a study that claims such an arrangement would cost ratepayers $775 million annually in above-market prices, or $20 billion over the life of the 25-year contract.
SPP’s Regional State Committee failed to reach agreement last week on a change in its voting procedures.
During a conference call that stretched over two days, the committee considered three voting structures — simple majority, majority plus one and two-thirds — to be followed when the committee wants to intervene in federal regulatory or judicial proceedings. The seven-person committee voted 4-3 on a majority-plus one structure, falling short of the RSC’s current two-thirds threshold.
The RSC will grow to 11 members Oct. 1 when it adds representation from the Iowa, Minnesota, North Dakota and South Dakota regulatory commissions, giving the committee another chance to revisit the issue. The committee is comprised of regulatory commissioners in SPP’s footprint and provides collective agency input on matters of regional importance related to bulk electric transmission.
“My thought is to take no action and let the new states come in,” said RSC President Dana Murphy of the Oklahoma Corporation Commission. “Maybe that will be the time to look at the language with the full group.”
The previously divided RSC agreed with Murphy on that point.
Congestion Rights Tariff Filing Due
The RSC also reviewed SPP’s progress in meeting an Oct. 30 filing deadline for Tariff changes required by FERC.
The commission conditionally approved SPP’s rules on incremental long-term congestion rights (ILTCRs) last October, and then denied a rehearing request by SPP and intervenors in July (ER14-2553).
Staff told the RSC the language now clarifies that a party constructing an improvement has priority for LTCR capacity made available by the improvement. Short-term rights will be made available as soon as the improvement is in service, with long-term rights awarded during the next annual cycle.
The revised language also allocates LTCRs and ILTCRs for network upgrades funded through a combination of rolled-in transmission rates and directly assigns charges based on the ratio of each party’s funding of directly assigned facilities.
As FERC requested, the proposed Tariff language eliminates the minimum $5 million investment requirement to be eligible for ILTCRs.
The changes, which have already cleared SPP working groups, will be considered by the Markets and Operations Policy Committee at its Oct. 13-14 meeting. The RSC will also vote on the final language before it goes to the Board of Directors in late October.
CPP Task Force Fills Out its Roster
The Clean Power Plan Task Force, which will recommend SPP’s role in addressing the Environmental Protection Agency’s carbon emission rule, has announced its representation.
The task force will be chaired by Mike Wise, vice president of transmission and operations for Golden Spread Electric Cooperative.
Other members of the task force include:
Burton Crawford, KCP&L Greater Missouri Operations Co.; Dennis Florom, Lincoln Electric System; Dale Niezwaag, Basin Electric Power Cooperative; Wayne Penrod, Sunflower Electric Power Corp.; Lauren Quillian, Xcel Energy; and Richard Ross, American Electric Power. Michael Desselle, SPP’s chief compliance and chief administrative officer, will serve as the group’s staff secretary.
The task force has been charged by SPP’s Strategic Planning Committee with reviewing the CPP and EPA’s model federal implementation plan. It will recommend what role SPP should play in assisting states’ compliance, and inform staff and member dialogue with environmental regulators.
In one of its first formal actions, the group and SPP staff hosted a webinar last week for members of the RTO’s 14 states’ air-quality regulators, utility commissions and key governmental contacts at its member utilities.
SPP’s presentation noted its three assessments of the CPP indicate a regional approach to compliance is better than state-by-state approaches. State-by-state compliance would require 114% more generation retirements, a 9% increase in “generation at risk for retirement,” 185% more new natural gas generation and about the same percentage of new renewables, SPP said.
States with multiple RTOs should be aware of the potential for “overlapping impacts that could require broader coordination,” it said.
SPP RE Winter Assessment
SPP’s Regional Entity (RE) shared its draft winter reliability assessment during a webinar last week, saying reserve margins are “adequate” for what is expected to be a normal winter.
The RE said SPP has 67,058 MW of capacity available, with another 761 MW to come online during the winter months. That should be more than enough to meet expected winter peak demand of up to 42,000 MW.
The SPP RE also expects about 162 miles of 230-kV transmission to be added during the winter.
SPP engineer Chris Haley said fuel supply and wind integration remain concerns, but it has not identified any unique or unusual operational challenges for the winter.
Haley also noted SPP will assume planning coordinator functions Oct. 1 for the Integrated System (IS) entities registered with the Midwest Reliability Organization (MRO) Regional Entity: Western Area Power Administration-Upper Great Plains, Basin Electric Power Cooperative and Heartland Consumers Power District.
While Nebraska is still registered with the MRO, both Nebraska and the IS are part of the SPP RTO operational and planning area.
The winter assessment is created using data submitted by SPP reporting entities, which is validated by a peer-review process. The draft assessment will undergo additional peer review at the North American Electric Reliability Corp. before it is finalized.
The SPP RE will host its Winter Preparedness Workshop on Dec. 10.
Entergy Gets PSC Approval for 20-Year PPA with NextEra Solar
The Public Service Commission has approved Entergy Arkansas’ request to enter into a 20-year power purchase agreement with NextEra Energy, which is building an 81-MW solar plant near Stuttgart. The facility, which will cover more than 400 acres, will be the largest solar project in the state.
Environmentalists applauded. “The Sierra Club is excited to welcome this large, home-grown, clean energy project to Arkansas,” said Glen Hooks, director of Sierra Club of Arkansas. “As Entergy is moving toward clean energy, they have also proposed shutting down one of its largest dirty coal-fired plants.”
The new solar production will reduce Entergy’s carbon footprint. “Both nuclear and solar provide emissions-free power and a natural hedge for energy price fluctuations due to uncertain environmental regulations and natural gas volatility,” Entergy Arkansas President and CEO Hugh McDonald said at the project’s announcement in the spring. The project is expected to be completed in 2019.
Delmarva Power and Light says its customers are getting a break on natural gas costs for the fifth straight year. Under new rates taking effect Nov. 1, the average residential customer will save nearly $17/month, it said.
According to the Energy Information Administration, the residential cost of natural gas in the state hasn’t been this low since 2004.
Watchdog Group Says Utilities Scaling Back Energy Efficiency Standards
The Citizens Action Coalition says that utilities are scaling back their energy saving and energy efficiency programs in response to the state’s more relaxed conservation standards.
The state’s energy efficiency standard was replaced by Senate Bill 412, which calls for utilities to establish their own energy efficiency and demand-side management programs rather than meet strict state targets. CAC says the plans for Duke Energy Indiana and Northern Indiana Public Service Co. have set substantially lower targets. It says NIPSCO’s target has dropped from 339 GWh of energy savings to 114 GWh.
“Our fears are coming true or being confirmed,” CAC Executive Director Kerwin Olson said. “The legislation allows the utility companies to establish their own goals. It puts the utilities in the driver’s seat in terms of how much energy efficiency they’re going to do.”
The Corporation Commission has approved a 4% rate hike for Westar Energy that will increase a typical monthly residential electrical bill by $5 to $7.
The Topeka utility fashioned an agreement with KCC staff, many of its largest industrial customers and the Citizens’ Utility Ratepayers Board. Last week, the commission voted unanimously to approve it.
The increase will generate an additional $78 million a year for Westar. The consumer board acknowledged that Westar was entitled to make customers pay for power plant upgrades to meet environmental mandates.
Manitoba Hydro has revealed the planned route for a proposed $350 million transmission line that will link it to the Wisconsin Public Service Corp. grid. The line would run from northwest of Winnipeg to the Manitoba-Minnesota border.
Called the Manitoba-Minnesota Transmission Project, it is part of a deal in which Manitoba Hydro is selling 308 MW of hydro power capacity to WPSC.
Baltimore Customers Might Get Hit with Higher Rates
Baltimore’s Board of Estimates has more than tripled the rate for using city-owned underground conduit. The system’s largest user, Baltimore Gas & Electric, says it will try to pass those costs on to customers in higher rates.
Beginning Nov. 1, companies will have to pay an annual usage charge of $3.33/foot, up from 98 cents. BGE has said it will try to raise residential rates by $7 or $8 per month, and from $15 to $3,350 for businesses, depending on how much electricity they use.
The Baltimore Department of Transportation said the rate increase was necessary to repair the crumbling system, which was built in the early 1900s.
A growing number of residents are joining solar cooperatives, which allow them to save money by buying rooftop solar systems in bulk.
Central Maryland is home to at least nine such groups, and 150 homeowners from the Baltimore area joined Retrofit Baltimore’s first co-op, leading it to open a second round of requests from residents in the City of Baltimore and Baltimore, Arundel and Howard counties.
According to the Community Power Network, which builds solar energy projects, a 9-kW system that normally would cost a homeowner about $31,000 can be purchased by a co-op for $13,000.
A suburban resident and a Baltimore Gas & Electric worker responding to a reported gas leak were injured after a house exploded and five other houses burned in Howard County on Wednesday.
The utility worker, who was responding to a suspected gas leak in an unoccupied house in Columbia, ordered the evacuation of surrounding homes moments before the vacant home exploded. The BGE employee was treated for minor burns and released. Fire officials said a resident of one of the damaged homes suffered respiratory problems and was taken to a nearby hospital.
“I’ve never seen anything like it,” said Ira Gershman, who lives in an adjacent house. “It was like a bomb.” The cause of the explosion is under investigation.
Attorney General Blasts DPU for Approving Pipelines too Quickly
Healey
State Attorney General Maura Healey is criticizing the Department of Public Utilities for approving three contracts for the Northeast Energy Direct pipeline “without knowing all the facts.”
In a letter to FERC, Healey complained that the agency approved requests by Boston Gas, Columbia Gas and Berkshire Gas for long-term capacity on the 188-mile pipeline without considering “the interrelationship of gas and electric markets” and conducting a “factual analysis of future demand.”
Meanwhile, advocacy group Northeast Energy Solutions has asked the Supreme Judicial Court to set aside a DPU order denying the organization’s ability to intervene as a full participant in hearings over the project. The group said the state agency failed to conduct a “fair and comprehensive” hearing. It joins the Pipeline Awareness Network of New England and the Conservation Law Foundation in taking legal action against the DPU.
Kinder Morgan subsidiary Tennessee Gas Pipeline wants to build the pipeline, which would run from Wright, N.Y., to Dracut, Mass. It is undergoing FERC review.
A three-year look at fracking in the state shows that the public isn’t wholly convinced the practice is a good one.
Researchers from the University of Michigan say the oil and natural gas industry, and lawmakers and regulators, have a large job on their hands to convince voters to allow the practice to continue. There is a movement to ban fracking because of environmental and health concerns.
Officials from the Department of Environmental Quality said they will review the report and use it to help make decisions going forward.
The state’s U.S. senators, expressing concern about oil pipeline spills, have proposed legislation that would ban all crude oil transport vessels on the Great Lakes and would increase scrutiny of existing underwater pipelines.
Sens. Gary Peters and Debbie Stabenow, both Democrats, introduced the Pipeline Improvement and Preventing Spills Act, citing concern over the operation of the 62-year-old Enbridge pipeline under Lake Michigan, the site of a 2010 oil spill.
“This common-sense legislation will help us prevent an oil spill in the Great Lakes, whether it’s a tanker accident or a pipeline leak in the Straits of Mackinac,” Peters said. In addition to banning tanker transport on the Great Lakes, it would also designate the Great Lakes a “high consequence” area, calling for increased federal review and safety requirements for existing pipelines.
Utilities Try to Keep up with EV Owners’ Charging Needs
The number of electric vehicles in the state has more than doubled to 3,200 in recent years, and local communities are trying to figure out how to serve and capitalize on the growing market.
Governments are following retailers’ lead and locating electric vehicle charging stations at public facilities such as libraries, regional parks and transit stations, triggering a debate about how much to charge car owners to plug in.
“A lot of private agencies and local governments are struggling with that right now,” said Taud Hoopingarner, Dakota County’s operations management director. “The jury’s still out on what the appropriate rate is.”
Regulators Say New Data Gives Ameren Time to Model SO2
State regulators say they can’t tell if Ameren Missouri’s Labadie coal plant is violating air pollution standards and gave the utility more time to measure air quality before deciding whether to take action.
The Department of Natural Resources disclosed new data gathered by Ameren that caused the department to second-guess its models, which had suggested the plant was violating sulfur dioxide limits. Because of the discrepancy between Ameren’s data and state models, the department recommended calling the area “unclassifiable,” meaning that data might need to be collected for years before determining if the area is in violation of federal rules.
The Air Conservation Commission unanimously adopted DNR’s recommendation at its Sept. 24 meeting.
Electric distribution companies have started setting their winter energy service rates, and the first company out of the gate, Liberty Utilities, has proposed a residential rate of 9.2 cents/kWh from Nov. 1 to July 31, a 40% reduction from last winter’s rate of 15.4 cents.
Liberty serves about 6% of the retail customers in the state, mostly in the Salem-Derry area and Upper Valley. The lower rate means a Liberty residential customer using an average of 500 kWh in November will pay $46, compared to $77 in November of last year.
Eversource Energy, which serves 75% of the state’s residential customers, had the lowest rate of the state’s three regulated utilities last winter, at 10.56 cents/kWh.
The staff of the Public Utilities Commission says that the divestiture of Eversource Energy’s power plants would cost ratepayers money and should be put off for at least five years. An agreement earlier this year resolved several issues that have been pending between the PUC’s Electric Division and the state’s largest utility, such as who pays for $425 million worth of upgrades to the Eversource coal-fired plant in Bow. But changing conditions in the electricity market led the technical staff to suggest the projected savings have been overstated.
“We find that the customer savings as anticipated by Eversource and the settling parties are by no means clear and that the sale of Eversource generation assets at this time may actually burden ratepayers to a greater degree than maintaining the status quo,” according to an analysis by the PUC staff.
Regulators Give Energy Industry 10 More Months to Cut Flaring
Recognizing that economic pressures have made it difficult to meet a strict deadline on capturing natural gas that is flaring from wells, regulators and the governor have given the energy industry another 10 months to cut their gas emissions from wellheads and other parts of the drilling and collecting apparatus by 85%.
Industry officials had argued that widespread adoption of the infrastructure needed to capture the escaping gas was almost impossible to complete by the original deadline. The new deadline is Nov. 1, 2016.
AEP Energy is building a 3.6-MW solar plant and has secured a 20-year agreement to sell the output to the municipal power system of Clyde.
The American Electric Power subsidiary said the Clyde Solar Energy Center will generate enough power to supply 550 residences. The plant, which will be built on 20 acres of city-owned land, is scheduled to be completed by the first half of 2016.
“The City of Clyde has been pursuing this zero emission project since 2011,” city officials said. “This is another major step toward that goal.”
State Rep. David Zimmerman has proposed a bill that would prevent the Public Utility Commission from limiting how much power derived from methane systems could be sold to offset the cost of such systems.
The move stemmed from a debate over whether a state net-metering law requiring utilities to purchase excess power generated by small-scale wind and solar units is fair to the agricultural companies and their customers.
Utilities have complained that paying retail price for wholesale power will drive up the price of electricity. Energy companies also say that getting the power distributed onto the grid shifts costs from one consumer class to another. About 97% of the state’s net metering facilities are solar.
Austin City Council in Fight over Purchasing 600 MW of Solar
The Austin City Council is debating how Austin Energy will pay for 600 MW of solar power by 2017, nearly triple the amount of solar energy currently in the utility’s solar portfolio.
Austin Energy recommends that it should buy 200 to 300 MW of solar power this year through a power purchase agreement with a West Texas solar farm developer. That agreement could cost between $22.5 million and $33.2 million per year for a period between 15 to 25 years, and is paid for through a fuel charge on its customer’s bills.
After it adds 600 MW, Austin Energy would generate more of its power from the sun than any other utility in the state. The utility is set to generate 55% of its power from renewable sources by 2025.
MISO told FERC last week that a group of wind generators alleging special treatment for external generators misunderstands the purpose of the M2 milestone payment in the RTO’s interconnection process (EL15-99).
The generators — EDF Renewable Energy, E.ON Climate & Renewables N.A. and Invenergy — complained to FERC earlier this month that revisions to MISO’s rules would exempt generation outside the RTO’s footprint from providing a cash-at-risk deposit in order to enter the definitive planning phase of the study queue. They argued this was unfair to internal generators, which are required to make the deposit, known as the M2 milestone. (See MISO Beats Challenge on Wind Exports.)
MISO said the complainants are asking that existing external generators seeking network resource interconnection service (NRIS) pay the M2 milestone, which is only required for new generation, regardless of its location. The RTO said the milestone isn’t charged to existing internal generation that only seeks NRIS.
The payment, approved by the commission in 2012, is to discourage speculative projects from entering the queue; withdrawals from the queue result in time-consuming and costly restudies.
“The M2 milestone is a ‘readiness’ milestone, designed to demonstrate that projects are ready to proceed to commercial operation,” MISO said. “External NRIS projects need not demonstrate ‘readiness’ because they must be ‘existing’ generators by definition under the MISO Tariff.”
MISO also disputed the complaint’s claim that not having to paying the M2 milestone gave external generators an unfair competitive advantage. Because it treats existing generation the same regardless of location, MISO said, “under complainants’ theory, internal NRIS-only projects within MISO also would have an unfair advantage, and by extension, also should pay the M2 milestone. Such a position is a collateral attack on the commission-approved Tariff that provides for different payments for NRIS-only projects as just and reasonable.”
‘Unripe Complaint’
MISO also criticized the generators’ decision to file an ‘unripe complaint,’ saying that the language of the revisions was not final. The RTO said such filings circumvent the stakeholder process and that FERC should continue to discourage them.
The generators said that their decision to file was based in part on an e-mail from MISO to Wind on the Wires that said the Business Practice Manual revisions concerning M2 milestone payments was final.
The Planning Advisory Committee in August tabled WoW’s proposal that all external generators seeking NRIS pay a portion of the M2 milestone.
The issue was to be taken up again at the PAC’s Sept. 16 meeting but was struck from the agenda at the request of WoW’s Sean Brady.
Brady said he asked to remove the item from the agenda because of MISO’s email. “Making the BPM language effective immediately indicated that this matter was resolved and a vote on the M2 milestone payment was moot,” he said.
Talen Energy asked FERC on Friday to allow it to sell four generators totaling 1,351 MW in eastern PJM to satisfy divesture conditions the commission set in a December order approving the company’s formation (EC14-112).
In their application to spin off their generation into the new company, PPL and Riverstone Holdings proposed two mitigation packages.
One involved divestiture of six Riverstone plants, and one PPL plant, in New Jersey and Pennsylvania totaling 1,315 MW. The second involved the same six Riverstone plants, plus the 399-MW Crane coal-fired plant in Maryland and two PPL hydro plants in Pennsylvania, for a total of 1,346 MW. (See PPL, Riverstone Accept FERC Mitigation Plan on Talen Spinoff.)
Talen now says it wants to replace the two divestiture packages with a third involving the Crane plant and three former PPL generators in Pennsylvania: the 660-MW Ironwood combined-cycle plant, the 248-MW Holtwood hydro plant and the 44-MW Wallenpaupack hydro generator.
Talen said its request was the result of its inability to negotiate a lease extension for its 158-MW combined-cycle plant in Bayonne, N.J., which was part of both previous divestiture options.
The Bayonne plant provides steam to a tank terminal storage facility, which owns the land beneath the generator. The storage facility is owned by a subsidiary of Macquarie Infrastructure Co., the Australian conglomerate.
Macquarie informed Riverstone last October of its intention not to extend the lease on the generator. (In February, Macquarie agreed to purchase the nearby Bayonne Energy Center, a 512-MW gas-fired generator, from ArcLight Capital Partners.)
Talen said efforts to negotiate an extension of the lease beyond its current expiration in October 2018 “proved futile,” forcing it to retire the plant effective Nov. 1, 2018.
“Accordingly, divesting the Bayonne facility could prove challenging,” Talen said. The proposed “Option 3” divestiture package will provide “the market more flexibility to identify the assets more highly valued by potential purchasers,” it said.
Talen said the revised divestiture plan would have essentially the same reduction in the company’s market power.
The company — which is required to complete its divestiture by June 1, 2016 — asked FERC to rule on its request by Nov. 30.
