Talen Energy last week announced plans to sell the Charles P. Crane generating station, a 399-MW coal-fired plant in Baltimore, to an affiliate of Avenue Capital Group, a global alternative investment firm.
Talen did not disclose the terms of the deal, saying only that “proceeds of the sale are not material.” The announcement comes two weeks after Talen announced it was selling three Pennsylvania power plants for $1.5 billion as part of a strategy to satisfy FERC, which ordered it to divest certain assets when the company spun out of PPL and Riverstone Holdings last year.
Announced sales of the assets, located in the PJM region, total 1,395 MW, including the Crane plant, Talen said.
“Talen Energy continues to review and evaluate options for the remaining identified mitigation assets,” the company said.
The Crane sale is expected to close in the first quarter of 2016.
Deals Approved
Also last week, FERC approved Talen’s $1.175 billion acquisition of MACH Gen and its three combined-cycle power plants, significantly boosting Talen’s presence in the New York and New England markets (EC15-187).
Included in the deal are the 1,138-MW New Athens plant in New York and the 335-MW Millennium plant in Massachusetts. As a result, Talen will own or control 3.2% of the available capacity in NYISO and 1.7% in ISO-NE.
Also part of the transaction is the 1,020-MW New Harquahala plant in Arizona. Taking on this plant was most likely a condition for acquiring the others; New Harquahala is losing money, and Talen has said it might move it or sell it for parts. (See Talen Entering NYISO in $1.2B Deal.)
Forbes reported Friday that Talen had cancelled a $400 million loan it was seeking to support the acquisition. The company cited its “strong liquidity position” and high interest rates as why the loan was no longer “an attractive piece of capital.”
FERC also approved the sale of Talen’s renewable energy subsidiary to California-based Energy Power Partners (EC15-182). The sale includes 25 wind, solar and biofuel facilities totaling 65 MW. While most of these are behind-the-meter facilities, EPP will gain 25 MW in PJM and 4 MW in ISO-NE.
In Pennsylvania, Talen is selling the 704-MW combined-cycle Ironwood plant to a subsidiary of Calgary-based TransCanada for $654 million. The Holtwood and Lake Wallenpaupack hydroelectric projects, with a combined generating capacity of 292 MW, are being purchased by a subsidiary of Quebec-based Brookfield Renewable Energy Partners for $860 million. (See Talen Energy to Sell 3 Pa. Generators for $1.5 Billion.)
At the time those deals were announced, Talen spokesman George Lewis said the company was evaluating offers for six former Riverstone generators in New Jersey.
With the D.C. Public Service Commission poised to decide Wednesday on a timeline to consider the revised terms in Exelon’s bid for Pepco Holdings Inc., opponents spoke out Monday about why they still think the merger is a bad deal for the district.
“This new settlement that came out of the mayor’s office offers very little new beyond what was already on the table and ruled by the PSC as not being in the public interest,” said Anya Schoolman, executive director of DC Solar United Neighborhoods, one of more than 20 public interest groups that formed the Power DC coalition.
She called on the PSC to “shed light on the smoke and mirrors that are in this deal and the process in achieving this deal.”
The PSC voted unanimously in August to reject the acquisition after it had been approved by FERC and regulators in Delaware, Maryland, New Jersey and Virginia.
The companies are asking the PSC to reconsider its decision within 150 days; the intervenors who did not sign on to the settlement are asking for a June 30 deadline to give time for review and public hearings.
“This really should be treated as a new application, as it includes entirely new terms,” said Randy Speck, counsel for DC SUN.
Exelon spokesman Paul Elsberg said the companies’ proposed schedule “affords all parties a fair opportunity to present their positions and [ensures] the commission has a complete record to render its decision.”
The schedule proposes testimony be filed in November, hearings be held in early December and the final brief be filed in late December.
Schoolman also criticized the companies’ tactics, including a media blitz featuring full-page ads listing nonprofit groups that she said are being “bullied” into supporting the merger for fear their funding will be cut. Meanwhile, she said, residents are being approached to sign petitions by people being paid by the companies to collect names.
She also questioned the timing of a recently announced sponsorship deal in which, according to the Washington Business Journal, Pepco gave the district $25 million in return for naming rights on one or more landmarks. “It invites the question of quid pro quo,” Chesapeake Climate Action Network Director Mike Tidwell said.
Myra Oppel, PHI’s vice president for regional communications, said negotiations related to the naming rights deal began in 2013.
“Pepco and the District of Columbia executed a sale agreement in July under which the district will buy property in the Buzzard Point area that will be used to build a major league soccer stadium,” she said.
“Because the development will increase the value of property Pepco and its parent company will still own in the area and Pepco’s varied development and community interests across the District, Pepco sought an opportunity to sponsor one or more projects to be developed in district. The sponsorship rights agreement was signed with the district on Sept. 18, before the settlement agreement was signed. It is not conditioned on the merger closing and has value whether or not the merger closes.”
While the companies’ ad campaign touts the settlement as being good for the environment, Tidwell pointed out that no environmental groups signed on to the agreement.
“If it was a good deal for the environment, I think you would see some of the city’s best known groups supporting this,” he said. “They are all still opposed.”
Elsberg said the revised merger proposal will “accelerate the district’s progress toward its sustainability goals” by committing to the development of up to 10 MW of new solar generation and making it “easier and faster for customers to install solar panels.”
Critics say the deal allows Exelon to count 5 MW of solar already being built at a district sewage treatment plant and does not require the utility to charge fair-market rates for its output.
Also to be considered at Wednesday’s meeting is a filing of intent by newly formed advocacy group DC Public Power, which has outlined a plan to purchase Pepco’s D.C. assets post-merger and turn it into a not-for-profit utility. (See Group Proposes to Buy Pepco’s DC Assets.)
The companies filed a motion asking the PSC to reject the group’s request to intervene in the proceeding “to pursue arguments concerning the hypothetical and ill-defined acquisition of Pepco’s district-based assets by a not-for-profit with undisclosed control and capitalization.”
LITTLE ROCK, Ark. — CEO John Bear said MISO has “reached the limits of the space in Carmel” and needs to explore either expanding or moving its headquarters. He said discussions will follow and the topic will remain at the forefront of the next year.
New MISO Members
The board approved two new members: the Municipal Energy Agency of Nebraska, which provides power to 65 communities in Colorado, Iowa, Nebraska and Wyoming, and Tenaska Frontier Partners, an 830-MW dual-fuel combined-cycle generator near Shiro, Texas, which is connected to both the MISO and ERCOT grids. Jo Williams, director of asset management at Tenaska, said MISO membership was motivated by access to studies and information.
New MISO board members Mark S. Johnson and Phyllis Currie (Source: MISO)
Board Recommends Two New Candidates, Curran
The board agreed to recommend two new board candidates for consideration by the MISO membership.
Phyllis Currie, former general manager of Pasadena Water and Power, and Mark S. Johnson, former vice president of transmission operations for Pacific Gas and Electric, were unanimously approved. They would replace Eugene Zeltmann, whose term is expiring, and fill a new ninth seat on the panel.
The board also recommended the re-election of member Michael Curran, former chairman and CEO of the Boston Stock Exchange and past board chairman.
Directors serve three-year terms and, beginning January 2016, will be held to a three-term limit.
The results of MISO member voting on the candidates will be announced at the annual Members Meeting on Dec. 10.
2015 Spending Boosted Due to NERC Rules
The board approved an amendment increasing the 2015 operating budget by $1.8 million and the capital budget by $2 million. The increases are needed to comply with version 5 of the North American Electric Reliability Corp.’s critical infrastructure protection (CIP) standards, which take effect April 1.
MISO said its compliance review resulted in a “significant increase” in the number of systems classified as CIP, defined as those that would have an “adverse” impact on the operation of the Bulk Electric System if they become unavailable, are degraded or misused.
The $3 million in increased capital spending for CIP compliance was partially offset by a $1 million reduction in other technology spending.
Clean Power Plan
Clair Moeller, MISO executive vice president of transmission and technology, gave the board an update on the RTO’s analysis of the Environmental Protection Agency’s final Clean Power Plan.
He said that although mass-based compliance would be “simpler and less expensive,” MISO also is looking at implications of rate-based compliance. A rate-based method would limit a state’s power fleet emissions based on an average of CO2 tons per megawatt-hour, while a mass-based platform puts a ceiling on total emissions.
Thus far, MISO holds that mass-based compliance seems to be “a simpler, more direct way of incorporating the value of CO2 emissions into generator offers.”
“We’re running as quickly as we can to get this analysis done,” Moeller said.
The board decided to add the CPP issue to future agendas. The same day, MISO’s Steering Committee scheduled a Nov. 6 Clean Power Plan workshop in Eagan, Minn., to go over MISO’s interpretation of the final rule and EPA’s proposed federal implementation plan for states that do not offer their own compliance plan.
Duke Energy announced Monday that it will be buying distributor Piedmont Natural Gas, following a trend of energy companies taking advantage of stable, low natural gas prices to invest in infrastructure.
Duke said it offered $60/share, a premium of about 42% compared to Piedmont’s closing price Friday. Piedmont shares had already climbed about 8.5% in premarket trading Monday. Duke said it would assume about $1.8 billion in Piedmont’s net debt.
Piedmont, based in Charlotte, N.C., serves more than 1 million residential and business customers in North Carolina, South Carolina and Tennessee.
Piedmont and Duke are partners in the proposed Atlantic Coast Pipeline, a planned $5 billion, 550-mile pipeline to run from the Marcellus Shale Field through West Virginia, Virginia and into eastern North Carolina. Dominion Resources is also a major partner in that project.
American Electric Power CEO Nick Akins says a counter proposal to his company’s guaranteed profits plan simply won’t do the trick.
AEP Akins Source: AEP
A staff expert with the Public Utilities Commission of Ohio suggested a three-year power purchase agreement as an alternative to AEP’s request for long-term price guarantees to keep its aging generation fleet viable. During a conference call with analysts, Akins made it clear that the state-offered compromise wouldn’t be enough.
“I’ll just say this: The term has to be substantial,” Akins said. “Because we have to have a feeling that we can invest, with the large capital investments we make in generation, we need to make sure that we can do that and be secure from a future perspective,” he said. PUCO is in the middle of hearing requests from AEP and FirstEnergy for long-term power purchase agreements. Akins said he expects a decision by the end of the year.
Duke Settles Ohio Suit Alleging Improper Rebates for $81 Million
Facing a class-action lawsuit that it improperly gave rebates to some large electric customers, Duke Energy has agreed to pay an $81 million settlement to avoid “costs and uncertainties.” The settlement must still be approved by a U.S. district court in Columbus, Ohio, before it is finalized.
An attorney for the plaintiffs said Duke’s payments to 22 large commercial customers should have been extended to smaller customers. The suit alleges Duke paid the rebates to the large customers from 2005 through 2008, and that the payments violated antitrust and other laws.
More than a million residential and commercial customers were represented in the suit and will share the settlement.
Xcel to Install LED Streetlights Throughout Territory
Xcel Energy has begun a massive, five-year, $100 million effort to replace city streetlights with LED lightbulbs in its eight-state service territory. The plan includes about 100,000 streetlights throughout Minnesota and 25,000 in Wisconsin.
The company estimates that modest-sized cities would save $3,000 to $5,000 per month. Xcel said that the cost of LED lamps has decreased sufficiently to justify the installation. LEDs not only produce brighter light than sodium-vapor bulbs, but they also consume 40 to 60% less electricity.
Xcel tested the large-scale roll-out in 2013, when it installed 500 LED streetlights in West St. Paul, Minn. The utility concluded that the LEDs ultimately offered better lighting at less cost.
The Illinois-based generation and transmission cooperative Prairie Power recently dedicated two 500-kW solar farms in the state: the Spoon River Solar Farm between Havana and Astoria and the Shelby Solar Farm, about 1 mile east of the Lake Shelbyville Dam.
Prairie Power supplies power to 10 electric distribution cooperatives. The facilities cost $1.6 million each.
General Motors and DTE Energy plan to erect Michigan’s largest solar installation by the end of the year on 4.25 acres next to GM’s Warren Transmission plant.
The 2,800-panel array is expected to generate about 1 million kWh of energy per year that will be fed into the grid.
Entergy’s Palisades Nuclear Plant Back Online After Refueling
Entergy brought its Palisades nuclear power plant back online last week after investing $63 million in fuel and $58 million in inspections and equipment upgrades. The Michigan plant shut down Sept. 16.
The company spent nearly $50 million on safety enhancements required after the 2011 Fukushima accident in Japan.
Public Service Enterprise Group says it will spend about $3.5 billion over five years to make its generation fleet cleaner and more competitive.
Most of the money will go toward building more natural gas-fired plants in Sewaren, N.J., and Keys, Md. It also plans to add capacity at its existing nuclear units and upgrade its gas-fired fleet, according to Shahid Malik, PSEG president of Energy Resources and Trade.
Malik said access to inexpensive and plentiful shale gas from the Marcellus region in Pennsylvania was a major reason for PSEG’s decreasing reliance on coal, which has dropped from 30% to 10% of its energy supply in recent years. “The markets don’t care if electricity comes from solar, gas or nuclear,” he said. “They buy based on price and since gas is the lowest-cost fuel, it is replacing coal, oil and even some smaller nuclear plants.”
Revel Casino Power Plant Heading for Court-Ordered Sale
The power plant built to provide electricity to the now-closed Revel Casino in Atlantic City is headed for a court-ordered sale.
Revel Casino
Bank of New York Mellon, trustee for holders of $118.6 million in bonds secured by the facility, last month filed suit to take the collateral from ACR Energy Partners, which owns and operates the plant. ACR is a subsidiary of Energenic, a joint venture between DCO Energy and Marina Energy.
Revel’s previous owners agreed to pay costly monthly financing fees to ACR. Glenn Straub’s Polo North County Club, which bought the casino out of foreclosure in April, has refused to honor the agreement.
AES Shutters Beaver Valley Plant Ahead of Schedule
AES, which had been considering converting its Beaver Valley coal-fired plant to burn natural gas, has scrapped those plans after it couldn’t find a buyer for the power. The Pennsylvania plant is now closed.
The Potter County plant was supplying electricity to West Penn Power and steam to two adjacent factories. But it lost its last electric customer two years ago. It bought its way out of the co-gen agreements, and despite a plan to generate cheaper electricity using natural gas, it couldn’t find any takers.
“It really came as a surprise to us when we saw the barriers go across the driveway,” said Rebecca Matsco, chairwoman of the Potter County Board of Supervisors.
A Virginia company that wanted to build more than 170 wind turbines in Corpus Christi, Texas, is once again seeking clearance for a wind farm from the Federal Aviation Administration, though this one would be smaller and located outside the city limits.
Apex Clean Energy has filed “notices for proposed construction” with FAA for 86 wind turbines. Applications for another 58 wind turbines also are being reviewed. Each wind turbine would measure about 500 feet tall, according to the company’s application. Officials for the Corpus Christi International Airport have expressed concern about the potential risks to air traffic.
Earlier plans for a larger wind farm drew criticism from residents who were concerned about diminishing property values, safety and changes to the area’s aesthetics. Apex voluntarily withdrew its applications with the FAA after the city annexed its property last year. The new plan places all wind turbines outside the city boundary.
Low interest rates for large-scale capital investments are making nuclear generation a more attractive option for those looking to fight climate change, according to an analysis conducted by the International Atomic Energy Agency.
The IAEA determined that investors are looking for a return of between 3% and 7% and, considering that fossil generators will be forced to pay about $30/ton for carbon emissions, says that nuclear generation is less expensive than either coal- or natural gas-fired generation.
It’s a message that has apparently already hit home in China. That country recently unveiled plans to build as many as eight new nuclear stations per year through 2020.
The Markets and Reliability Committee last week failed to reach consensus on a way to reduce spending on Tier 1 synchronized reserves, with proposals by PJM and the Market Monitor both falling short.
PJM’s recommendation would have added an obligation for Tier 1 resources to respond in emergencies and make them subject to penalties if they couldn’t. They could opt out of that duty, but by doing so they would forfeit any credit they would have received outside of responding to a spinning event.
PJM estimated it would have reduced the RTO’s 2014 Tier 1 expense of $27 million by as much as $20.2 million if three-quarters of resources opted out (see chart).
The proposal retained a provision in the existing rules entitling Tier 1 to receive compensation outside of an event when the non-synchronous reserve market price is more than $0 — a concession that the Monitor opposed.
Monitoring Analytics’ Tom Blair said that the Monitor “remains opposed to paying for Tier 1 in any circumstance except when it responds to a spinning event, and then at the synch reserve price.” The PJM proposal, he said, “does not remediate or even address that concern.”
Howard Haas, also of Monitoring Analytics, added, “There’s no reason or rationale to compensate Tier 1 outside of a spinning event. There is no Tier 1-related cost that isn’t already included in the energy offer.”
The PJM proposal received only 54.4% support in a sector-weighted vote, with most Generation Owners (85%) and Transmission Owners (91%) in support and other sectors split or opposed.
Monitor’s Proposal
Steve Lieberman of Old Dominion Electric Cooperative introduced an alternate proposal based on a recommendation by the Monitor that would have eliminated compensation for Tier 1 resources except when responding to an event. It imposed no obligation to respond.
That proposal also failed, receiving 57.4% support, with virtually unanimous support from End Use Customers and Electric Distributors but little backing from Generation Owners (17%) or Transmission Owners (20%).
Tier 1 synchronized reserves are partially loaded generators that have room to increase their output in response to a spinning event, explained PJM’s Adam Keech. Tier 2 resources include demand response, synchronous condensers and generators that would otherwise be running at full output, meaning they incur lost opportunity costs.
Currently, Tier 1 carries no obligation to respond to spinning events, unlike Tier 2. Keech said the purpose of the proposal was to “make the resources that opt in identical to Tier 2 resources today.”
The issue of Tier 1 compensation stems from a problem statement introduced last fall by Monitor Joe Bowring, who referred to them as “available ramp room” that was standing by and doing nothing but costing the RTO more than $85 million per year. (See Monitor: Cut Pay for Tier 1 Synchronized Reserves.)
David “Scarp” Scarpignato of Calpine said that both proposals had their positive and negative sides.
“It doesn’t make sense to pay non-synch reserves payments and not Tier 1. [Non-synch reserves are] not anywhere close to being as valuable” as Tier 1 synch reserves, he said. “You might go so far as to say that Tier 1 should be paid all the time — PJM, while not demanding a response, is expecting a response.
“Tier 1 is providing value that PJM counts on,” he added.
‘Late’ Criticism?
Dave Pratzon of GT Power Group, which represents some generators, took issue with critics of the PJM proposal, which had cleared the Market Implementation Committee on Oct. 7. (See PJM Market Implementation Committee Briefs, Oct. 12.)
“None of these issues were voiced previously,” he said. “No one mentioned an alternative [during the first read at the last MRC meeting]. It’s a little disappointing that we have to wait until the 11th hour to hear that a different proposal will be put up.”
He cautioned his colleagues against ODEC’s recommendation, saying, “Accepting this proposal will open up a lot of other market issues that are unintended consequences.”
Carl Johnson of the PJM Public Power Coalition said his opposition to the PJM proposal was not an about-face.
“We opposed it in the subgroup, opposed it in the MIC and opposed the manual language,” he said. The MIC had approved the proposal with 28 opposed and 16 abstentions.
After both proposals failed, Bob O’Connell of Main Line Electricity Market Consultants, made a motion for a second vote on the PJM proposal. But MRC Chairman Mike Kormos said that under PJM rules, only a member who voted against a measure may ask for it to be reconsidered.
O’Connell acknowledged he had not voted against the proposal and no one else came forward to seek a second vote.
TransCanada told regulators last week that it intends to mothball three of its Ravenswood gas peakers in New York City due to the units’ age and condition.
TC-Ravenswood (Source: TransCanada)
In a letter Tuesday to the New York Public Service Commission, the company wrote that gas turbine units 4, 5 and 6, which began operating in 1970 and total 64.2 MW, could be taken out of service on April 30, 2016. “Over the past 24 months, several operational and maintenance issues have occurred, including evaluation and repairs resulting from Hurricane Sandy. These units are reaching end of life unless substantial investment is made to numerous components.”
Unit 7, of similar size and vintage, was taken out of service in March 2014 after “it experienced an over speed condition, high vibrations, a rotor ground and discovery of failed bolts in the turbine rotor first stage section.”
The units are part of a 2,480-MW complex of gas-fired generators, including baseload plants, in Astoria, Queens. At its full capacity, the complex could serve about one-fifth of New York City’s peak demand.
“Over the next six months, they will continue to operate as we have obligations to make the units available to the New York market,” company attorney Jim D’Andrea told RTO Insider.
The company said it has not made a final decision on the plants’ fate. D’Andrea said that the company would make a decision on whether the units should be refurbished “based on the economics.”
According to the latest NYISO Gold Book, the three plants produced a combined 500 MWh of net energy in 2014.
The PSC will request a study by NYISO to determine if the units are needed to maintain reliability.
LITTLE ROCK, Ark. — MISO said last week it is continuing discussions with SPP on one interregional project, despite earlier staff recommendations to not proceed.
In September, MISO staff said it would not recommend for approval any of the three potential joint projects evaluated by it and SPP. SPP staff has recommended one of the projects, the 11-mile South Shreveport-Wallace Lake 138-kV rebuild in northeastern Louisiana.
SPP said the project would have a benefit-cost ratio of 11.86, assuming MISO funded 80% of the cost. MISO said the same assumptions resulted in only a 0.86 B/C ratio, below the minimum threshold.
But Jennifer Curran, MISO’s vice president of system planning and seams coordination, told the System Planning Committee last week that the RTO might yet support the project if SPP picked up a bigger share of the cost. “We’re continuing discussions with SPP to see if there are alternative price allocations,” she said.
MISO’s Board of Directors will take up staff’s interregional recommendations during its December meeting.
Curran also said a second project considered in the interregional analyses, the Alto-Swartz 115-kV series reactor in West Texas, might have a “fair amount of value.” She said it will be taken into MISO’s regional study process.
Meanwhile, MISO Technical Advisor for Economic Studies Arash Ghodsian met with SPP’s Economic Studies Working Group last week to help the group better understand MISO’s interregional review process and this year’s results.
Ghodsian said the initial interregional study ended in June, and that MISO spent the next three months updating its modeling based on SPP and stakeholder feedback. While an interregional review found the three projects had benefit-to-cost (B/C) ratios of 1.22 or more, MISO decided against recommending any of the three when it reviewed its assumptions after a regional review found the B/C ratios for two of the three projects were under 1. (See “No Go for MISO-SPP Interregional Projects,” in MISO Planning Advisory Committee Briefs.)
Ghodsian said MISO and SPP “effectively collaborated” during the study and said the knowledge gained would improve the interregional planning process.
“We look at it as a great working relationship,” he said. “I don’t know the plans for the future, but we look forward to more interregional studies.”
Brett Hooton, SPP’s senior interregional coordinator, said both RTOs will compile stakeholder feedback on the process for discussion during the Dec. 2 Interregional Planning Stakeholder Advisory Committee.
MISO has notified FERC that it intends to terminate its system support resource agreement with Illinois Power Holdings’ Edwards unit 1 generator in Peoria, Ill., effective Jan. 1 (ER16-129).
MISO said an examination of Edwards 1’s retirement found that new transmission infrastructure, including the 345-kV Maple Ridge-Fargo line and Maple Ridge Substation, are on track for completion by mid-2016 and eliminate the need for the generator to continue under SSR status after this year.
“MISO determined that the last of the transmission reliability projects needed to permit the retirement of Edwards 1 remains on schedule for completion by June 1, 2016, to meet the peak conditions for which Edwards 1 was designated a SSR unit,” the RTO told the commission.
MISO notified Illinois Power in late September that the 90-MW coal-fired unit would be released from SSR status at the beginning of the year and that the agreement would not be renewed. The SSR agreement took effect in January 2013.
The termination of the SSR agreement comes two weeks after FERC affirmed that Edwards should be allowed to recover fixed costs through a full cost-of-service rate when operating is mandatory to maintain reliability. (See MISO SSR Unit’s Recovery of Fixed Costs Upheld.)
The developers of the Northern Pass transmission line have filed for siting approval from New Hampshire with a higher price tag, a slightly altered route and another adjustment in the amount of hydropower the project can carry from Canada.
(Click to zoom.)
Eversource Energy now says the high voltage transmission line from Canada will cost $1.6 billion, up from previous estimates of $1.4 billion. The higher cost reflects changes in the route made in recent weeks after a series of public meetings held in five New Hampshire counties.
The line will carry 1,090 MW, up from an estimated 1,000 MW when project revisions were announced in August. Capacity was revised downward two months ago when an additional 52 miles of the route were proposed to be buried in the White Mountains. (See Northern Pass Opponents Want More of Line Buried.)
The New Hampshire Site Evaluation Committee is expected to take 14 months to review the proposal; Eversource hopes to bring the 192-mile project online in 2019.
The increased costs resulted in part from engineering and design changes to more than 60 structures to reduce view impacts along scenic byways and river and highway crossings. The filing also projects a 9% increase in capacity over earlier estimates.
“At the time we announced the new plan, in August, we were analyzing a number of technical issues surrounding the project and firming up costs,” spokesman Martin Murray said. “Now that we’ve locked in our cable and converter supplier, and completed our technical review, we are comfortable that the project will be capable providing up to 1,090 MW.”
The “filing marks another important milestone in our effort to deliver a clean energy solution that our customers desperately need in order to diversify our power supply and stabilize energy prices,” Bill Quinlan, president of Eversource Operations in New Hampshire, said in a statement.
Project developers noted that Entergy’s Oct. 13 announcement that it will retire the Pilgrim nuclear plant in Massachusetts will reduce New England’s carbon-free generation, “challeng[ing] the region’s clean air goals.” (See Entergy Closing Pilgrim Nuclear Power Station.)
The proposed route would cross over land owned by the Society for the Protection of New Hampshire Forests. That won’t happen without a fight, the group says.
“What Eversource has put forward blatantly and knowingly disregards our property rights and the conservation easements we hold in northern New Hampshire, where they do not have an existing [right of way],” group spokesman Jack Savage said in a statement. “It is unclear to us how they hope to acquire a contiguous route without having access to eminent domain.”
WILMINGTON, Del. — The Members Committee overwhelmingly agreed last week to fund a $450,000 budget for the Consumer Advocates of the PJM States (CAPS), in part through an assessment on electric customers.
According to the proposal, the charge to a residential customer using 12,000 kWh annually will be eight-tenths of a cent. The group also would receive a one-time infusion of $350,000 from Exelon if the D.C. Public Service Commission approves its acquisition of Pepco Holdings Inc., under a settlement brokered with D.C.’s mayor.
“The consumer advocates designated by state statute are in a position of having to be in two places at once — the state where there’s always lots to do, and here at PJM, where most of the charges are coming from,” said CAPS Executive Director Dan Griffiths. That, he said, has stretched the advocates’ resources, making it difficult to monitor the “hundreds” of meetings the RTO holds each year.
“This is something we think is a serious problem because the voice of the retail folks who are ultimately paying the bills is absent.”
Griffiths said the group modeled its budget and funding request on that of the Organization of PJM States Inc. (OPSI), which is funded through a charge in Schedule 9 of the RTO’s Tariff.
The proposal passed with slightly more than 81% of a sector-weighted vote, receiving unanimous support from End Use Customers and 89% from Other Suppliers. About 79% of Electric Distributors supported the funding, along with 71% of Generation Owners and two-thirds of Transmission Owners.
At the Members Committee meeting earlier this month where the plan was introduced, it met resistance from some suppliers, most notably Direct Energy, Talen Energy and Dynegy. Last week, Direct Energy abstained from the vote, while Talen and Dynegy opposed it. (See Consumer Advocates’ Funding Request Sparks Sharp Words.)
Jesse Dillon, assistant general counsel for Talen, repeated his argument that the proposal runs afoul of the First Amendment prohibition against “compelled speech.”
“I’ve already made the policy point that no member should have to fund the advocacy voting of another member, period,” he said. “This one group is receiving treatment that others aren’t. Their voices are no more relevant in the marketplace of ideas than other entities.”
In response to the free speech argument, the consumer advocates penned an Oct. 13 memo to the heads of the Members Committee defending the proposal, saying in part that the doctrine doesn’t apply to government entities, “which the members of CAPS clearly are.”
The memo cites FERC’s approval of OPSI funding in 2006 over a similar objection by Public Service Enterprise Group (ER06-78).
In that case, FERC ruled, “PJM is providing funding to make its job of working with the states easier and more efficient. The ability of any participant to express its views will not be constrained by this proposal.”
Dillon disputed the classification of CAPS as a government entity, noting that the group is a 501c tax-exempt nonprofit organization.
CAPS, made up of consumer advocates from PJM states and D.C., was formed in 2012 with start-up funding from a FERC enforcement settlement with Constellation Energy (IN12-7-00).
West Virginia Consumer Advocate Jackie Roberts pointed out that a portion of electric customers’ bills already go toward having the companies — Appalachian Power, in her case — represented at PJM.
“All we’re asking is that the customers we represent have an opportunity to pay less than a cent a year to have us have a seat at the stakeholder table,” she said.
