New York regulators have doubled the cap on the amount of solar energy the state’s utilities are required to purchase under its net metering program.
The New York Public Service Commission ordered the increase to 6% of utilities’ peak demand from the current 3% (14-E-0151).
The commission acted in response to a request by environmentalists for an increase and a petition by Central Hudson Gas & Electric, which said it expected to reach the 3% cap in mid-2015, mostly through its residential solar programs.
The state’s 2008 Public Service Law set net metering at 1% of a utility’s peak demand, using 2005 as the base year, then gave the PSC discretion to increase the amount “in the public interest.” Central Hudson’s cap was increased to 3% in 2012 and a 2013 order raised the cap for the state’s other utilities.
Central Hudson is currently at about 83% of its 36-MW cap. National Grid is at 102% of its 196-MW cap, including projects proposed but not yet built within its service territory. As of Sept. 30, no other utility is above 63% of its cap.
The Solar Energy Industries Association, the National Resources Defense Council and other environmental groups had asked the commission to clarify the process for increasing the cap while Central Hudson had proposed increasing it to 12%.
The PSC expressed concerns about shifting costs onto ratepayers that decline or are unable to participate in a solar program. The 3% cap increases the average delivery bill of Central Hudson’s customers by about 0.5%. If all of the new net metering capacity is from solar generation, additional cost increases are expected to be from 0.5% to 1%, the PSC said.
In 2012, Gov. Andrew Cuomo announced the NY-Sun Initiative with a goal of installing 3 GW of solar power by 2023. In April 2014, Cuomo promised $1 billion for the program. Current capacity is more than 316 MW.
The new cap is effective Jan. 2. Central Hudson, Consolidated Edison, New York State Electric and Gas, National Grid, Orange & Rockland Utilities and Rochester Gas & Electric are to make compliance filings by Dec. 22.
The revisions were filed with FERC on Dec. 15, PJM Assistant General Counsel Jim Burlew told the Markets and Reliability Committee.
The revisions dictate that at least 90 days before the deactivation or disposing of a generator, the source receiving reactive power payments submit a filing with FERC either revising its rates or explaining why it has decided not to do so.
New York Gov. Andrew Cuomo’s administration last week banned hydraulic fracturing (fracking) in the state, saying there was insufficient data to overcome concerns over the practice’s health risks.
The long-delayed decision came during a year-end cabinet meeting after the state Department of Health completed a two-year review of the controversial technique to extract natural gas from deep shale formations.
“I have considered all of the data and find significant questions and risks to public health, which as of yet are unanswered,” acting DOH Commissioner Dr. Howard Zucker said. “I think it would be reckless to proceed in New York until more authoritative research is done.”
The Marcellus Shale formation extends from West Virginia, through Pennsylvania and Ohio, to western New York.
In 2012, the Department of Environmental Conservation asked the DOH to review its draft Supplemental Generic Environmental Impact Statement for High-Volume Hydraulic Fracturing (SGEIS). Prior to the health study, the DEC had conducted its own studies dating back to 2008.
The Health Department said it found significant “uncertainties about adverse health outcomes” and inadequate mitigation measures to protect public health.
(Click to Zoom)
The department said several years of study are needed to determine how much risk is associated with fracking. “Until the science provides sufficient information to determine the level of risk to public health from [fracking] to all New Yorkers and whether the risks can be adequately managed, DOH recommends that [it] should not proceed,” the department said in the study.
The ban is unlikely to slow the shift to gas-fired generation in the state, however. According to the U.S. Energy Information Administration, the state generated nearly 60,000 GWh from natural gas in 2012, more than double the output in 2004.
The Federal Energy Regulatory Commission granted MISO’s request to suspend action on long-term transmission service requests (TSRs) between its north and south regions through April 1 as it tries to resolve a flow dispute with SPP.
The waiver (ER14-2022) also allows MISO to waive Tariff requirements and North American Energy Standards Board standards involving flows exporting from MISO South to PJM.
MISO requested the waiver through April 1, 2015, to help it address transmission constraints resulting from its dispute with SPP.
SPP alleged its joint operating agreement with MISO was breached after Entergy joined MISO last year and began transferring electricity over SPP’s lines. SPP has billed MISO more than $35 million for flows exceeding the 1,000-MW physical contact path limit between MISO North and MISO South.
MISO told the commission that the waiver request would affect 10 pending long-term firm TSRs from a single customer totaling 2,831 MW.
MISO’s waiver request provided some insight into its thinking in integrating Entergy before the dispute with SPP arose.
Originally, MISO said it anticipated that the primary restrictions on flows between its north and south regions would be set under the Operations Reliability Coordination Agreement (ORCA), a seams agreement with SPP, and that it would have extra time to negotiate seams agreements governing flows between those regions.
MISO told FERC the need for a 1,000-MW limit on flows between the north and south was a “sudden and unexpected development” and that it hopes to have alternative seams agreements in place by April 1 — the end of the operations transition period under the ORCA.
Interveners — including Southern Co., Louisville Gas & Electric and the Tennessee Valley Authority — opposed the waiver, saying it was “premature for MISO to assume that the [transition period] will not be extended” past April 1.
They said a waiver would prevent an extension of the transition period and deny their ability “to obtain much-needed reliability information on MISO’s planned flow activity.”
In approving the waiver, the commissioners said MISO “has acted in good faith with respect to the Tariff provisions for which [the] waiver is sought. The circumstances that effectively placed a 1,000-MW limit on MISO’s ability to grant additional long-term TSRs over the MISO North-MISO South interface arose relatively suddenly.”
The commission noted that transmission customers likely would be unwilling to fund construction of new upgrades to obtain service at the north-south interface given that the capacity limit is potentially a temporary situation.
MISO had argued that entities faced a difficult choice of consenting to build new capacity that later may not be needed — or losing their queue priority if they decline construction of the capacity.
Duke Energy has agreed to excavate all 3.2 million tons of coal ash at its soon-to-be-closed W.S. Lee Steam Station in South Carolina and to bury the material in a lined landfill.
The move came after lengthy discussions with the Southern Environmental Law Center over the proper disposal of coal ash from the plant.
“This is a historic accomplishment for South Carolina’s rivers and clean water,” SELC lawyer Frank Holleman said. It is the first time environmental groups reached an agreement with Duke on coal ash disposal in either North or South Carolina, he said.
FirstEnergy CEO Alexander Stepping Down After 10 Years
Anthony Alexander, 63, FirstEnergy’s CEO since 2004, is stopping down Jan. 1 to be replaced by Charles Jones, 59, who started with the company in 1978 as a substation engineer and has managed FirstEnergy’s regulated companies since 2010.
The transition occurs as FirstEnergy is reducing its focus on competitive power-generating markets and is returning to its roots as an operator of regulated utilities. Jones said he doesn’t expect any dramatic changes under his leadership. “I don’t think that means I am going to operate the company significantly differently than Tony,” he said.
Alexander will assume the title of “executive chairman” and will remain on the company’s board.
Exelon Generation’s Delaware Station May Have Buyer by Jan. 1
Exelon Generation said it expects to name a buyer by Jan. 1 for its retired Delaware Station on the Delaware River waterfront, north of Philadelphia’s Center City district.
More than a dozen prospective buyers have toured the property, according to Exelon spokesman Bob Judge. Delaware Station, built in 1920, was designed by Philadelphia architect John T. Windrim, who also designed the famous Franklin Institute. The 223,000-square-foot building comes with 10 acres of land and another 6 acres underwater.
The site, near the booming Northern Liberties and Fishtown neighborhoods, was the northernmost of three waterfront Philadelphia Electric power stations, each a variation on a classical temple. All three are retired. One has been repurposed as an office.
Exelon Files for License Renewal for LaSalle Nuclear Station
Exelon has filed license renewal applications for both units of its LaSalle Nuclear Generating Station southwest of Chicago, asking to be allowed to operate the plant until the 2040s.
The plant’s reactors went into operation in 1984. Nuclear Regulatory Commission-issued license renewals are good for 20 years. The application is 2,100 pages long.
Dominion to Buy Carolina Gas Transmission for $492.9M
Dominion Resources has signed an agreement to buy SCANA’s Carolina Gas Transmission for $492.9 million.
Carolina Gas is based in Cayce, S.C., and operates nearly 1,500 miles of interstate natural gas pipeline in South Carolina and Georgia. Its customers are wholesale and industrial. When the deal is closed, it will become part of Dominion Midstream Partners, the arm of the business that also includes Dominion Cove Point LNG, a liquefied natural gas terminal on the western shore of the Chesapeake Bay in Maryland.
Thomas F. Farrell II, chairman and chief executive of Dominion Resources, and chairman and CEO of Dominion Midstream, called the acquisition “a compelling strategic opportunity.”
NRG Energy has agreed to sell its Storm Lake 1 wind farm to Minnesota-based ALLETE Clean Energy for $15 million.
The 108-MW facility at Storm Lake, Iowa, went into commercial operation in 1999. The sale comes after ALLETE bought an adjacent 78-MW wind farm from AES in January.
Susquehanna Unit 1, taken off line two weeks ago due to a water leak inside the containment area, returned to service Friday after repairs.
The unit shut down Dec. 13 to allow workers inside the containment area to fix a minor leak. There was no release of radiation during the event, operator PPL said.
Calpine Signs Gas Delivery Deal with Eastern Shore Natural Gas
Calpine Energy Services has signed a deal with Eastern Shore Natural Gas to supply fuel for the company’s new 309-MW Garrison Energy Centre in Dover, Del.
Eastern Shore, a subsidiary of Chesapeake Utilities, will deliver natural gas to the combined-cycle plant for the next 20 years. Eastern Shore will build seven miles of new pipeline and a compressor station at a cost of about $30 million to fulfill the contract.
Duke Energy continued to expand its solar generation fleet with the purchase of a 20-MW turnkey project in Roanoke Rapids, N.C.
The Halifax Solar Power Project, which went into service this month, was built by solar developer Geenex with backing from ET Capital. The plant was built on a decommissioned airport. The output is being sold through a 15-year agreement to Dominion North Carolina Power.
Duke owns 15 wind farms and 22 solar facilities in 12 states, totaling about 1,000 MW.
The Federal Energy Regulatory Commission said PPL’s plan to spin off its generation and energy marketing business and combine it with Riverstone Holdings to form Talen Energy could get its OK — if it beefed up its market mitigation plans.
“We find [the] applicants’ proposed mitigation is insufficient to address the competitiveness concerns,” the commission wrote (EC14-112).
FERC gave the companies 30 days to come back with a new mitigation plan. Among other demands, it wants PPL to sell off 700 more megawatts of generation than originally proposed, for a total of about 2,000 MW.
PPL and Riverstone Holdings announced in June they would join their generation businesses into a publicly traded independent power producer named Talen Energy. The new company would own 15,320 MW of capacity, including 12,000 MW in PJM.
In their application, the companies proposed selling about 1,300 MW of PJM generation to avoid market power complaints. The companies said that no company with more than 10% of PJM’s summer installed capacity would be permitted to bid for the plants. That would leave out Public Service Enterprise Group, Exelon and NRG Energy.
In its proposal to FERC, PPL gave two mitigation packages. One involved six Riverstone plants and one PPL plant in New Jersey and Pennsylvania — all combined-cycle plants — for a total of 1,315 MW. The second involved the same six Riverstone plants, plus a 399-MW coal-fired plant in Maryland and two PPL hydro plants in Pennsylvania for a total of 1,346 MW.
FERC’s mitigation demands closely mirror those suggested by PJM Independent Market Monitor Joe Bowring. The commission said it will:
Require Talen to make cost-based offers in the energy and regulation market; and
Require Talen to offer into PJM markets the same plants and output as PPL did, prohibiting it from holding back generation to drive prices up.
FERC declined to accept Bowring’s recommendation that it add American Electric Power, FirstEnergy, Dominion Resources, Duke Energy and Calpine to the companies barred from purchasing the plants sold in mitigation.
The commission said that it would subject any buyers to a competitive screening process to prevent market power concerns.
“PPL is carefully reviewing the order,” PPL spokesman George Lewis said. “We are assessing the options presented by FERC in detail and will submit a reply within the 30-day response period that addresses the market power mitigation issues FERC has raised.”
Connecticut regulators approved a $130 million rate increase for Connecticut Light & Power, endorsing a staff draft decision to cut the company’s requested hike by 41%.
The Public Utilities Regulatory Authority’s ruling boosts the fixed residential monthly charge by 20% to $19.25. Regulators also OK’d the utility’s plan for transmission upgrades.
The decision reduces CL&P’s requested 10.2% return on equity to 9.17%. It also imposes a 0.15% penalty for one year for the company’s performance in preparing for and restoring service from two storms in 2011. A $257 million capital spending budget was also approved.
An average residential customer using 700 kWh of electricity will see an increase of approximately $7.12 per month.
NYISO must refund more than $700,000, plus interest, to an energy supplier due to overcharges caused by missing meter data in the aftermath of Superstorm Sandy, the Federal Energy Regulatory Commission ruled (EL14-89) Thursday.
GDF Suez Energy Resources filed a complaint in August asking FERC to order NYISO to reopen billings for electricity supplied in November and December 2012 by Consolidated Edison to 55 Water Street, a commercial office building in lower Manhattan.
Estimated bills for the affected period, based on historical data, were off by approximately 9.7 GWh, or by more than 260%. NYISO’s Tariff bars resettlements after a five month “finalization” deadline without an order by FERC or a court.
FERC said GDF Suez should receive the refund because Superstorm Sandy caused the loss of the building’s meter data and Con Ed did not obtain the available corrected meter data until six weeks after Tariff deadlines had passed. The commission wrote that “significant injustice would result absent commission action because Suez had no recourse for the failure of Con Ed to submit corrected meter data needed for NYISO to issue corrected invoices within the required 150-day meter data finalization period.”
The following items were approved unanimously by the Markets and Reliability Committee Thursday with little discussion or debate.
Tariff Revisions to Metered Load Aggregates
The MRC approved an alternate method for establishing bus distribution factors for zonal and residual metered load aggregates used by the day-ahead energy market. If there are technical problems that prevent PJM from obtaining the load distribution factors from the snapshot one week prior to the operating day, it will use the load distribution factors from the most recently available day of the week that the operating day falls on.
Harmonizing PJM’s Governing Documents
The committee approved an issue charge creating the Tariff Harmonization Senior Task Force, which will report to the MRC. It will be tasked with identifying and resolving inconsistencies in definitions, indemnification, limitation of liability and alternative dispute resolution procedures in the current Tariff, Operating Agreement, Reliability Assurance Agreement and Manual 35 provisions. (See Task Force Proposed to Resolve Inconsistencies in PJM Governing Documents.)
The task force is expected to deliver proposed revisions in six to 12 months.
Standards for Enhanced Inverters
The committee approved standards for inverter-based generators defined as asynchronous generation that have an Interconnection Service Agreement or a Wholesale Market Participation Agreement. The standards, which apply to Federal Energy Regulatory Commission jurisdictional inverters, regard the inverters’ provision of voltage support, reactive power, frequency response and ramp-rate control. The changes will not affect merchant transmission facilities, HVDC inverter-converter facilities or existing generation. (See Enhanced Inverters Clear MRC.)
Manual Changes
The MRC approved changes to the following manuals:
Manual 10: Pre-Scheduling Operations was updated as part of an annual review. “Local Control Center” was changed to “Transmission Owner” in the introduction. A section clarifying outage reporting requirements for facilities providing black start service was added.
Manual 14D: Generator Operational Requirements was modified to be consistent with the revised North American Electric Reliability Corp. standard VAR-002-3, which became effective Oct. 1. The revisions address notifications of status changes on automatic voltage regulators, power system stabilizers and reactive capability.
Manual 01: Control Center and Data Exchange Requirements was amended with the addition of a section regarding user agreements related to the purchase of PJMnet connections.
Concern about natural gas infrastructure is a leading theme of the NYISO 2015-2019 Strategic Plan, released Thursday.
“Growing reliance on natural gas to generate electricity, the expanding role of distributed energy resources and the potential effects of rigorous environmental regulation are key factors influencing the future of the electric system and our strategic priorities,” NYISO Board Chair Michael Bemis said in a statement.
The plan says NYISO’s efforts over the next five years will focus on:
Improving coordination between the gas pipeline delivery system and the New York bulk electric system;
Integrating demand response and distributed energy resources in collaboration with the New York State Public Service Commission’s Reforming the Energy Vision proceeding;
Improving capacity and energy price signals to promote greater fuel assurance and improved unit performance from capacity resources;
Taking advantage of interregional connectivity to lower system costs; and
Employing smart grid technology to respond to the variability of renewable resources.
