LITTLE ROCK, Ark. — The Board of Directors’ System Planning Committee last week reviewed the status of the 2015 MISO Transmission Expansion Plan, dissecting a few large and contentious projects.
MTEP15, which will be finalized by the board in December, is expected to include 357 projects valued at $2.6 billion. The Planning Advisory Committee voted Oct. 14 to recommend the plan for board approval; the Advisory Committee will consider it in November.
“It’s a big footprint and a lot of different jurisdictions,” said MISO board member Michael Evans, remarking on the 70-plus meetings held thus far on the plan.
Duff-Rockport-Coleman Project
The plan will include the Duff-Rockport-Coleman 345-kV project in Southern Indiana, the RTO’s first project to be competitively bid.
MISO is responsible for the Duff–Coleman portion, estimated at $67.4 million, while PJM will cover the cost of the tie-in to the Rockport substation. The go-ahead on MISO’s portion of the project does not hinge on PJM’s approval of its tie-in project. (See MISO Staff Recommends 3 Economic Projects.)
Paul Kelly, director of federal regulatory policy for Northern Indiana Public Service Co., applauded MISO’s suggestion of an interregional committee for handling such projects in the future. NIPSCO had objected that the project wasn’t studied enough under the MISO-PJM Joint Operating Agreement to flesh out cross-border benefits and RTO cost allocations.
“While we think this project is valid and should be built, we think there are additional efficiencies that might have been squeezed out of this if it were looked at as an interregional project,” Kelly said.
Curran
Jennifer Curran, MISO’s vice president of system planning and seams coordination, acknowledged concerns that PJM’s involvement could add complexity to the competitive bidding process. She said that the situation provided an opportunity to refine “hybrid” projects.
“We remain committed to working towards that goal” of interregional transmission project development, she said.
In that vein, MISO is discussing with ERCOT a potential study on ways to increase transfers between the two regions.
Texas Project
MISO said it is considering a minor design modification suggested by Entergy to an economic project in East Texas included in MTEP15.
The $122.5 million project includes a new 230-kV line from Lewis Creek to a new 345/230-kV substation that will cut into the Grimes-Crocket 345-kV line and a rebuild of the Newton Bulk–Leach 138-kV line.
Resource Adequacy Update
Curran gave the committee a long-term resource adequacy update, saying MISO has high certainty of obtaining 2.6 GW of new resources by 2020 (those under construction or subject to interconnection agreements), with 2.3 GW coming from natural gas, 135 MW from wind and 81 MW from hydro.
The RTO also has 5.3 GW of generation in final studies or seeking regulatory approval. The confidence level for those developments being completed is 50%.
Finally, MISO set a 10% confidence for the completion of 20.7 GW of other active queue projects and for 2.1 GW of generation reported in the MISO-Organization of MISO States survey but not in the queue.
The survey predicts a regional surplus of 1.7 to 2.3 GW for 2016, with sufficient zonal surpluses to offset zonal shortfalls until 2020. The 2014 survey had predicted a 2.3-GW regional shortfall in 2015. (See MISO Survey: No Shortfall Until 2020.)
MISO stakeholders are considering several changes in time for the 2017-18 planning year, including seasonal capacity auctions and speeding up the interconnection queue process by reducing restudies and study cycle timelines.
Tariff Change Would Allow PJM to Sell Excess Capacity for 2016/17
WILMINGTON, Del. — Members overwhelmingly endorsed a Tariff change that would allow PJM to release Base Capacity resources to reflect the Capacity Performance resources it acquired in the transition auction for the 2016/17 delivery year.
Results of PJM Reserve Requirement Study (PJM)
While it planned to include the 2017/18 delivery year in the changes, staff decided to hold off pending a Supreme Court ruling on the Electric Power Supply Association’s challenge to FERC’s jurisdiction over demand response. (See FERC Jurisdiction over DR in Peril as Supreme Court Splits.)
PJM plans to craft the request for the Tariff change to FERC in a way that would permit it to pull it back if the Supreme Court rules that DR could not be used in energy markets and FERC applied the ruling to capacity markets as well.
“There’s some argument out there that jurisdiction is jurisdiction. The hesitancy we have is if EPSA is upheld at the Supreme Court, we don’t know what FERC would do, so we want to leave ourselves open with a safety valve,” said Stu Bresler, PJM senior vice president for markets.
In addition, PJM Assistant General Counsel Jen Tribulski noted that FirstEnergy has a case before FERC regarding DR in capacity markets (EL14-55).
“FERC could take both and make a decision regarding both markets,” she said.
The filing is expected to be made in early December. The third incremental auction is set for February.
Committee Endorses Increase in IRM
With five “no” votes and 19 abstentions, the committee approved an increase in PJM’s Installed Reserve Margin.
The Reserve Requirement Study increased the IRM for delivery year 2016/17 to 16.4% from 15.5% in the 2014 study. IRMs also rose for 2017/18 and 2018/19.
Some members expressed misgivings over PJM’s methodology, saying the rise seemed counterintuitive given the new Capacity Performance product and other efforts to ensure generator reliability. (See “IRM, FPR Rising; PJM Methodology Challenged” in PJM Planning Committee Briefs.)
Steve Lieberman of Old Dominion Electric Cooperative opposed the proposal.
“We don’t take resource adequacy lightly,” he said. “We’re not looking to make things less reliable; we’re just not comfortable with the assumptions made this year. We feel that the IRM that was in place last year is a fair and reliable value to use next year.”
Tom Falin, manager of resource planning, said that CP alone does not automatically result in a lower IRM.
“We have already assumed that generators will perform at the CP standard,” he said. “Our planning studies assume that the forced outage rate applies every day of the year, regardless of how hot and cold, that generators will have about a 7% unavailability rate.”
Winter Peak Studies to be Added to Planning Process
The committee unanimously endorsed changes to Manual 14B: PJM Region Transmission Planning Process adding the RTO’s first criteria for reliability studies focused on meeting winter peaks.
The parameters define the winter peak period as 6 to 9 a.m. and 5 to 8 p.m., from Dec. 1 through Feb. 28.
The studies will include thermal and voltage evaluations; solutions to identified problems will be developed through the Transmission Expansion Advisory Committee.
The criteria will be effective for baseline studies on Jan. 1 and for interconnection queue requests received after the effective date of the revised manual language.
Traditionally, the use of energy in PJM has peaked in the summer, but in the past couple of years, it has seen operational issues “during a lot of other times,” said Mark Sims, manager of transmission planning.
He said new transmission planning standards going into effect will require PJM to study more extreme events.
Regulation Market Proposal, Task Force Charter Approved
Members approved an interim solution to the over-procurement of RegD resources that will be reflected in changes to Manual 11: Energy & Ancillary Services Markets Operations.
The solution moves the benefits factor curve to the left so that it is at zero at 40%. A cap of 26.2% also will be implemented during identified excursion hours — hours when dispatch frequently moves the regulation signal manually.
It also features tie-breaker logic to rank RegD self-schedules or zero-cost offers. (See “Solution, Task Force Proposed to Curtail RegD Resources” in PJM Markets and Reliability Committee Briefs.)
The changes, which take effect Dec. 1, will be reviewed quarterly while a senior task force will seek a long-term solution.
“We believe this proposal goes in the right direction,” said Susan Bruce of the Industrial Customer Coalition. “It’s certainly a good placeholder until the next group does some long-term work.”
In a related vote, the charter for the task force also was approved. Some key activities were added after the issue was discussed at the Operating Committee, including evaluating the causes and effects of prolonged control deviations and identifying common causes for operators manually adjusting the regulation signal.
The group also will re-evaluate:
the regulation requirement;
regulation signal formation, including the potential of RegB and RegD neutrality;
self-schedule and zero-offer resources in the commitment process and impacts on energy market;
the scoring method for regulation testing and regulation service; and
the schedule used in the calculation for the regulation lost opportunity cost.
Subcommittee Formed to Review Governing Documents
The former Tariff Harmonization Senior Task Force will become the Governing Document Enhancement and Clarification Subcommittee, members agreed.
The group will review, identify and propose solutions to substantive and non-substantive inconsistencies and confusing language in PJM’s governing documents.
Members Committee
Nominating Committee Members Elected
Members elected the Nominating Committee for 2015-16. The sector representatives are:
Electric Distribution Sector: Lisa McAllister, American Municipal Power
End Use Customer Sector: Ruth Ann Price, Division of the Public Advocate of the State of Delaware
Generation Owner: Joe Kerecman, Calpine
Other Supplier Sector: Marji Philips, Direct Energy
Transmission Owner Sector: John Horstmann, Dayton Power & Light
NextEra Energy last week asked the D.C. Circuit Court of Appeals to overturn two FERC orders in a generator interconnection dispute with Ameren Illinois.
NextEra filed a petition for review of FERC decisions in May 2014 and August 2015 (ER14-1470), saying it was being overcharged by $6 million under a facilities service agreement between Ameren and NextEra subsidiary White Oak Energy for a wind generation project near Carlock, Ill.
In the first order, FERC conditionally accepted an unexecuted facilities service agreement under which White Oak was required to pay Ameren a monthly network upgrade charge retroactive to Aug. 28, 2007, the date of White Oak’s generator interconnection agreement with Ameren.
NextEra requested rehearing, saying it should only pay Ameren $2.4 million, instead of the almost $8.3 million FERC ordered.
White Oak wind project
NextEra says it is being overcharged because Ameren applied MISO’s “Option 1” pricing to White Oak, under which the interconnection customer provides up-front funding for network upgrades and receives a 100% refund from the transmission owner after the upgrades are complete, with the costs then recovered through a monthly network upgrade charge. The network upgrade includes a return on Ameren’s rate base, operations and maintenance expenses, depreciation and taxes.
That is in contrast with Option 2, under which the transmission owner retains the interconnection customer’s initial funding for the upgrades and the interconnection customer is assessed no further charges.
Option 1 Voided
NextEra is relying on a 2011 FERC order in which the commission ordered MISO to remove Option 1 from its Tariff, saying that it increased the costs to interconnection customers without providing any increase in service compared to other funding options (EL11-30).
The removal was ordered effective March 22, 2011, the filing date of the complaint challenging the funding mechanism. The commission said the removal would not apply to agreements effective before that date as “a reasonable remedy that balances the interests of the parties, the need for regulatory certainty and ease of administration.”
NextEra said Ameren cannot elect to apply Option 1 pricing to the facility service agreement because it didn’t select it when the GIA was executed in 2007.
Ameren responded that MISO’s Tariff did not require it to make an Option 1 pricing selection at the time White Oak agreed to take interconnection service, and NextEra never requested that Ameren commit to a compensation option.
In its Aug. 21 rehearing order, FERC told Ameren to change the GIA to avoid “confusion regarding the full extent of White Oak’s Section 206 rights” but denied NextEra’s request to void the Option 1 charges.
FERC also rejected NextEra’s argument that the FSA should be limited to a return of and on amounts Ameren invested to fund the network upgrades, saying the transmission owner also was entitled to recovery of operations and maintenance costs.
Entergy is expected to announce this week whether it will keep operating the James A. FitzPatrick nuclear plant near Syracuse, N.Y.
FitzPatrick nuclear plant (Source: Entergy)
The company said earlier this month that it would announce a decision by the end of October on whether it would continue to run the 838-MW plant in the face of stiff economic pressure. The 40-year-old facility on the shores of Lake Ontario is due to be refueled in late 2016.
“A decision whether to conduct FitzPatrick’s next refueling outage is expected around the end of the month. The company continues to be focused on constructive discussions with the state,” Entergy spokesman Tammy Holden said on Friday.
Another troubled nuclear plant in western New York has just completed negotiations with Rochester Gas & Electric and other stakeholders to keep operating into 2017 to maintain system reliability. An agreement was filed with the New York Public Service Commission and FERC last week to keep Exelon’s R.E. Ginna plant operating with ratepayer subsidies. (See Ginna Lifeline to End in 2017; Profitable Operation Afterwards ‘Unlikely’.)
Entergy, Cuomo Spar over Negotiations
Negotiations between Entergy and the administration of Gov. Andrew Cuomo, which apparently have been ongoing for months, took an ugly and public turn last week. Cuomo chastised the company for threatening the potential loss of 600 jobs to wring concessions from the state.
“This tactic has been attempted by others in the past and has been unsuccessful. In this state, an entity called the Public Service Commission has oversight over services deemed to be in the statewide public’s best interests. Entergy should keep that in mind. Any decisions will be made on the merits,” he said in a statement provided to Capital Tonight, a cable television program that covers state politics.
The company immediately responded by sending an email to employees that was obtained by the Syracuse Post-Standard. “Most recently, we have heard inaccurate claims that we are ‘holding employees hostage’ or ‘only seeking to improve our bottom line.’ That is simply not the truth. We are facing substantial financial challenges at FitzPatrick and have been negotiating in good faith with New York state over the last several months to obtain certainty for this facility,” wrote Bill Mohl, president of Entergy Wholesale Commodities. “We have a very short window of time remaining to come to a successful resolution with New York state and will be doing everything we can to achieve this. Waiting until the last minute does not serve anybody’s interests.”
Retirement Predicted
An Oct. 13 UBS research note on the prospects for Northeastern nuclear facilities predicts the plant will not survive. “We see single-unit nuclear assets are particularly challenged. We see this plant as next to formally retire,” UBS said.
In an 8-K filing with the Securities and Exchange Commission on Oct. 16, Entergy reported a $965 million impairment charge against the plant, referring to an undisclosed “triggering event” in the third quarter. The plant was previously listed as having a book value of $1.14 billion.
On Oct. 13, Entergy announced the closure of the Pilgrim nuclear plant in Massachusetts, which faces economic challenges similar to FitzPatrick, as cheap natural gas has lowered clearing prices in energy markets. (See Entergy Closing Pilgrim Nuclear Power Station.)
Entergy also wrote down the value of Pilgrim by $677 million. Combined, the two writedowns will total $1.6 billion pre-tax basis and about $1.1 billion after-tax (-$5.93/share).
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.
