The Federal Energy Regulatory Commission Friday rejected a challenge by New England states to recalculate the contributions of demand response and distributed resources in advance of February’s Forward Capacity Auction.
FERC accepted the installed capacity requirement (ICR) filed by ISO-NE for the 2018/19 delivery year (ER15-325). However, FERC did order the RTO to conduct a stakeholder process to develop market rules that would consider DR in time for the 2016 FCA.
The New England States Committee on Electricity said ISO-NE has underestimated the impact of distributed generation and its pay-for-performance (PFP) program on the region’s capacity needs. FERC disagreed.
“We agree with ISO-NE that it would have no basis to use forecasted performance data in the absence of actual historical performance under this nascent two-settlement market design. We therefore support ISO-NE’s current methodology, which incorporates actual resource performance data,” FERC said.
FERC also suggested that a request to include distributed generation as part of the calculation was too soon, saying that the RTO first “must examine the market and operational issues.”
ISO-NE’s Nov. 4 filing established its ICR, local sourcing requirements and Hydro-Quebec interconnection capability credits (HQICC) for FCA 9.
The ISO proposed an ICR value of 35,142 MW, which includes 1,970 MW of emergency generation assumed obtainable from New Brunswick, New York and Quebec. The net amount of capacity to be purchased, after deducting the HQICC value of 953 MW per month, is 34,189 MW, the ISO said.
Southwestern Electric Power Co. announced that it is dropping plans to construct a $116 million, 60-mile transmission line after SPP decided it wasn’t needed. SPP told SWEPCO that its latest forecasts show lower load growth than previous ones for the area.
“Based on SPP’s new findings, we are notifying landowners, community leaders and elected officials that we have withdrawn our application to the [Public Service Commission] for authority to construct the Shipe Road to Kings River transmission project,” said Venita McCellon-Allen, SWEPCO’s president.
The 345-kV line would have run between Benton and Carroll counties. It was a source of contention for both property owners and environmentalists. Opponents to the line successfully petitioned the PSC for a rehearing on the line. SPP is in the process of withdrawing its Notification to Construct, the basis for SWEPCO’s construction plans and application.
A developer of a failed attempt to build a $1 billion data center and power plant on the University of Delaware campus is suing his former business partner.
Robert Krizman, who was recruited to work as president of The Data Centers LLC, filed suit in the Court of Chancery against chief executive Earl Kern, alleging that Kern kept him in the dark about business decisions. Krizman, who was also a minority partner in the project, wants to be released from his share of about $1 million in debt the project racked up.
After months of studies and lobbying, the university decided against hosting the project. Much of the community backlash that doomed the project centered on a proposed 279-MW power plant.
Indianapolis Power & Light asked the Utility Regulatory Commission for a rate increase that would boost the average residential customer’s bill by 8%, its first general rate increase request since 1994.
Although it has been more than two decades since IPL asked for a general rate hike, it has received other boosts, including 3% rate increases for system improvements for each year between 2013 and 2019. The company also filed a request in 2014 to add about $1 to each monthly bill to pay for the conversion of its Harding Street coal-fired plant to natural gas.
IPL’s general rate increase would generate $67.8 million a year in revenue and would boost the typical residential monthly bill by $8. If approved, it would take effect at the end of 2015.
Gov. Terry Branstad’s top energy expert was fired without notice last month, leaving a multi-million dollar energy fund without a leader.
Paritosh Kasotia, team leader of the state energy office, was asked to leave Dec. 8, according to an Associated Press report last week. Kasotia had just returned from a national energy conference when she was told she had been ousted, and she stopped working the same day.
Kasotia began overseeing the Office of Energy Independence under Democratic Gov. Chet Culver, administering grants in the $71 million Iowa Power Fund. Branstad, a Republican, began dismantling the fund after taking office in 2011, moving the energy office to the economic development agency.
Opposition is mounting in the state against a plan by Kinder-Morgan Energy to convert its existing Tennessee Gas Pipeline to carry natural gas liquids from Appalachian shale fields to the Gulf Coast.
Marion County joined Boyle County in passing a resolution opposing Kinder-Morgan’s plan to repurpose the 71-year-old pipeline to carry a mixture of natural gas liquids like propane and butane to a Gulf Coast processing plant. The pipeline passes through 18 counties in Kentucky.
Marion County last year opposed construction of the Bluegrass Pipeline, which also would have carried NGLs. That pipeline died after a state judge ruled that its planners didn’t have eminent domain powers.
The Public Service Commission has approved construction of the first utility-scale solar plant in the state. Kentucky Utilities will own 61% of the 10-MW facility and Louisville Gas & Electric will own the remaining 39%.
The plant will be built on the site of KU’s E.W. Brown Generating Station in Mercer County, with its $36 million cost subsidized by ratepayers.
KU and LG&E originally applied to build both the solar plant and a 670-MW combined-cycle plant. Plans for the natural gas-fired plant were canceled after KU lost nine wholesale power contracts from municipal customers.
Industrial Boom Points Toward Need for New Power Plants
Low utility prices and cheap natural gas are fueling a boom in industrial growth in Louisiana, and utilities are struggling to keep up with demand. Entergy just fired up a new combined-cycle plant, but some estimates show that more plants, or more imported electricity, will be needed by the end of 2015, and still more by the end of 2019.
In addition to building new plants in Louisiana and Arkansas to meet demand, Entergy is purchasing even more power from wholesale markets. “All that will help, but ultimately we’re going to need to build new generation,” said Phillip R. May, head of Entergy’s Louisiana operations. “It has to be new steel in the ground to meet all of this new load. … We’re on the front end of a pretty steep curve in growth.”
Entergy has yet to file a multiyear rate increase request to help finance the need for new plants, but consumer advocates are already marshaling forces to block them if they do. “We don’t feel it’s fair that residential and commercial customers should have to foot the bill (for power) that will be needed primarily by the large industrial sector,” said Casey DeMoss Roberts, head of the Alliance for Affordable Energy. “The industrial customers should have a special rider to pay for it.”
Judge Affirms PSC Ruling on Cove Point Power Plant
A Baltimore judge has upheld the Public Service Commission’s approval of Dominion Resources’ plans to build a 130-MW generating station to support its liquefied natural gas export terminal at Cove Point.
Circuit Court Judge Alfred Nance ruled the PSC did not act outside its authority when approving the power plant. The Accokeek, Mattawoman, Piscataway Creeks (AMP) Communities Council had appealed the PSC decision.
The power plant is part of Dominion’s $3.8 billion project to convert the LNG importation terminal into an export terminal.
Cost of Kemper Plant Keeps Growing: Another $25 Million in Overruns Reported
Mississippi Power, the Southern Co. subsidiary building a coal gasification power plant in Kemper County, revealed a further $25 million in cost overruns in a filing with the Securities and Exchange Commission on Friday. The plant’s initial cost was $2.8 billion and it was projected to begin operations in 2013. The latest overruns bring the cost to more than $6.1 billion, and a report due later this month may detail even more overruns.
Southern Co. said the overruns reduced its after-tax profit by $258 million in the third quarter. The Kemper plant is designed to convert soft lignite coal to gas that will fuel its boilers. Carbon dioxide from the combustion process is to be captured for industrial uses or storage underground.
Similar plants are also experiencing trouble. Duke Energy’s Edwardsport, Ind., plant suffered from construction delays and cost overruns. And FutureGen 2.0, a government-backed project in Illinois, was announced in 2003 and still isn’t operational.
Ameren Missouri has filed a three-year, $135 million energy efficiency plan with the Public Service Commission, saying it would provide more than $260 million in benefits to its customers over 20 years. The company’s first energy efficiency plan, mandated by the state with the intention to cut energy use and reduce emissions, covers two years and runs out at the end of this year.
The new plan, which has 10 programs to help residential and business customers cut energy use and costs, provides incentives for energy-efficient heating and air conditioning equipment, appliances and lighting systems.
A company spokesman said the programs, together, could save up to 426,000 MWh. “That’s equivalent annual use of 33,000 average-size homes on our system, so it’s a very significant amount of savings on behalf of our customers,” Dan Laurent said.
Rejecting its staff’s recommendation, the Public Service Commission voted 3-2 against allowing NorthWestern Energy to buy power from a 25-MW wind farm near Fairfield.
Greenfield Wind would have sold power to NorthWestern for $54/MWh under a 25-year contract. That compares to a recent hydro contract that did get PSC approval at $57 to $58 per megawatt hour.
Commission Chairman Bill Gallagher, one of the objecting voters, said tying the utility, and its ratepayers, into the wind power contract would cost it money when the wind power was available but not needed, and would be sold at a loss on the wholesale market. “The difference in that price is going to be left to the consumer,” Gallagher said.
BPU-Set Gas Rate Means Refunds for Some State Gas Customers
Elizabethtown Gas residential customers will get an average refund of $40 after the Board of Public Utilities approved a lower supply charge.
Company officials said the lower cost of gas from Marcellus Shale production will save its customers $10 million. The refund is on top of the lower gas rate approved by the BPU late last year.
“Essentially, there’s an abundant supply of natural gas now that’s serving to lower prices for customers,” said Duane Bourne, a company spokesman.
Environmental Group Still Concerned About Pine Barrens Pipeline Project
A proposed natural gas pipeline through the Pine Barrens that failed to gain approval by the Pinelands Commission last year poses a “real cause of concern,” according to the year-end report of the Pinelands Preservation Alliance.
The environmental group’s “State of the Pinelands Report” said the commission’s deadlocked 7-7 vote on the pipeline shows that pressures still exist on the natural resources in the area. After the vote, Gov. Chris Christie nominated two new members for the commission, but those appointments were put on hold in a contentious legislative hearing that focused mostly on the pipeline proposal. South Jersey Gas wants to build the pipeline to fuel the B.L. England power plant, which is being converted from coal to natural gas.
“The most well-known threat to the integrity of the Pinelands protection rules over the past year is the South Jersey Gas pipeline issue,” the alliance’s report stated.
PSC Approves Another 172 MW of Wind Power at Antelope Hills
A $240 million wind farm on 22,000 acres in western North Dakota received approval from the Public Service Commission. The 86-turbine, 172-MW Antelope Hills Wind Project near Beulah, Mercer County will be in service by the end of this year, according to PSC Chairman Brian Kalk.
Basin Electric Cooperative has signed a 25-year power purchase contract for the full output of the new facility. It will be added to the 1,600 MW of wind power currently operating in the state and 1,200 MW of wind power already approved by the commission.
Antelope Hills has applied for a 9.5-mile, 345-kV transmission line to carry its output to a grid connection at Basin Electric’s Antelope Valley Station coal-fired plant.
FirstEnergy Sweetens the Pot for its Proposed Rate Plan
FirstEnergy, in an attempt to show support for its controversial “Powering Ohio’s Progress” electric security plan, filed a proposed joint settlement agreement with the Public Utilities Commission.
FirstEnergy’s proposal to receive supply guarantees for several power plants has prompted a backlash from opponents, who said the company had already been rewarded for its merchant plants during the state’s transition to market rates.
Now, in exchange for the price supports, FirstEnergy proposes a freeze on distribution rates through 2019, $23 million in economic development funding and up to $7 million in low-income funding. The company said it has the support of 15 parties, including the city of Akron, labor and various user groups. PUCO will schedule hearings on the plan soon. The commission’s staff hasn’t filed its comments yet.
Sustainable Energy Board Meeting to Spotlight Coming Projects
The annual meeting of the Sustainable Energy Board on Jan. 15 will feature an update on projects for the state.
Met-Ed and Penelec will provide an overview and update on their mapping program that shows where sustainable energy grants were apportioned. West Penn Power will provide an overview of projects funded by its program and will talk about a sustainable energy fund bond program it recently launched with the state. PPL will report on an LED lighting project at Harrisburg International Airport. And PECO Energy will detail its new third-party financing project for renewable energy projects.
The meeting is set for 11 a.m. in Hearing Room 1 of the Commonwealth Keystone Building in Harrisburg.
Keystone May Have Votes in Congress, but State Approval Key
Incoming members of Congress may have approval of the Keystone XL Pipeline in their sights, but the Public Service Commission still needs to grant a crucial approval, and that may not be too easy. More than 40 groups have filed to intervene in the commission’s approval process.
The PSC approved the pipeline in 2010, but that construction permit expired last June. TransCanada has filed for a new construction permit, but most of the groups who have filed with the PSC are against the project.
The commission has scheduled hearings in February, March and April to consider what can be heard and filed at the final hearings, which are scheduled for May 5-8.
LNG Terminal Plans on Hold Due to Falling Gas Prices
Excelerate Energy told the Federal Energy Regulatory Commission that it is putting its floating liquefied natural gas terminal project near Port Lavaca on hold, partly because of plunging natural gas prices.
“Due to the recent global economic conditions, the company has determined that, at this time, this project no longer meets the financial criteria necessary in order for us to move forward with the capital investment,” the company announced last week. The company asked FERC to put its project filings on the shelf until April 1.
The export facility was to have been built in Lavanca Bay, about 30 miles southeast of Victoria. The $2.5 billion project would have been the first floating LNG export terminal in the U.S.
Residents Question Need for Line: Dominion Short on Answers
Northern Virginia residents have questioned the need for a transmission line proposed by Dominion Virginia Power to serve an unnamed high-tech client near Haymarket in Prince William County, west of Manassas National Battlefield Park.
Although Dominion won’t identify the customer, rumors abound that a major Amazon data center is planned for the area. Dominion spokeswoman Le-Ha Anderson said the utility’s existing lines aren’t large enough to supply the prospective client’s needs. Dominion estimates the costs of the new line and a substation are about $65 million.
Residents of Haymarket and surrounding areas say the proposed line would be unsightly and impact property prices. A town hall meeting for residents is scheduled for tonight at Battlefield High School.
The Public Service Commission has approved American Electric Power’s $550 million sale of half of its Mitchell Power Plant to one of its subsidiaries, Wheeling Power.
The 1,600-MW coal-fired plant, on the banks of the Ohio River in Moundsville, is 43 years old, but it recently had its emissions-control systems upgraded.
Another AEP subsidiary, Kentucky Power, owns the other half of the plant. The entire plant had been owned previously by AEP’s merchant generation business.
PSC to Let Cheyenne LF&P to Fix $5.1 Million Mistake
Cheyenne Light, Fuel & Power made a mistake when doing the calculations for its most recent rate case – a $5.1 million mistake. Its 2014 rate case left out a monthly collection from its residential customers of about $8.88 a month. This resulted in a collection shortfall for November and December of $985,875, which would grow to $5.1 million over a full year.
The company asked the Public Service Commission for permission to make up the difference on an interim basis, pending approval of a new rate case. The commission ruled in late December it would allow the company to re-file the rate case, but that ruling is on hold pending an appeal by two of Cheyenne’s industrial customers.
The state collected $43.2 million more in sales and use taxes during the first five months of its fiscal year, ending November. That’s good news for state officials, but there’s bad news on the horizon.
State finance officials say the strongest counties – Campbell, Laramie and Converse – collected $26.1 million of that, and much of that was due to energy industry jobs and services.
“From an industry perspective, the mining [including oil and gas], retail trade and construction sectors have captured most of the collection gains to date,” said Jim Robinson, principal economist for the Economic Analysis Division of the state Department of Workforce Services. But the recent plunge in natural gas and oil prices means tax collections in those counties are almost sure to drop as well.
A Québec pension fund has agreed to spend up to $593 million to acquire up to 30% of Indianapolis Power & Light from AES, which is seeking to lighten its share of U.S. utilities as their coal-fired generation in MISO and PJM face increasing environmental pressure.
IPL on Dec. 23 filed for Federal Energy Regulatory Commission approval on the deal (EC15-56), which also needs an OK from the Committee on Foreign Investment in the United States, an interagency groupthat includes the U.S. Treasury, Department of Energy and State Department.
Caisse de dépôt et placement du Québec (CDPQ) will pay $244 million for 15% of AES Investments, an IPL parent company, and contribute up to an additional $349 million for up to 17.65% of IPALCO Enterprises, IPL’s direct parent, based on capital calls.
At the end of the two-step process, CDPQ will have indirect ownership of 15% to 30% of IPL and will be able to nominate two IPALCO directors. AES Investments would nominate nine of the directors.
Environmental Pressures
IPL, which owns about 2,623 MW of coal-fired generation (83% of its total), is scrambling to comply with the Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS), and may face compliance expenses under the EPA’s proposed carbon emissions rule. In its earnings report for the second quarter, AES said it was too soon to determine what impact the carbon rule, and state plans for implementing it, will have on the company.
From 2014 to 2016, IPL plans to spend $326 million on MATS compliance alone.
At least half of IPL’s capital spending plan involves replacement of coal-fired units. The biggest project, at $600 million, is the construction of a 671 MW gas-fired generating station to replace aging coal units at its Eagle Valley plant, 30 miles south of Indianapolis.
AES’ Second Thoughts About U.S.
Although it is based in Arlington, Va., three-quarters of AES’ pre-tax income from continuing operations comes from its international investments.
AES, which bought IPL in 2000 for $2.15 billion, would see its stake in IPALCO fall to 70% under the deal.
Earlier this year AES tried to sell its Dayton Power & Light’s generation fleet rather than spinning it off into an unregulated subsidiary by 2017, as the Public Utility Commission of Ohio had ordered.
AES bought DPL in 2011 for $3.5 billion, about a 9% premium to DPL’s stock price. But AES later expressed regrets about the purchase, saying it hadn’t received the benefits it expected. In its 10-K filed last February, AES cited Ohio’s market-based pricing and low wholesale prices.
In July, however, AES said it had dropped its plan to sell DPL. “In light of the potential recovery of power prices, as well as PJM capacity prices, AES believes that this business has additional value that can be captured by continuing to own and operate these generation assets,” AES said in a statement.
Moody’s Likes Deal
Moody’s Investors Service said in a Dec. 15 report that the sale would help the credit rating of IPALCO, which is in the midst of a $1.4 billion capital spending plan.
“CDPQ’s contractual commitment is credit positive for IPALCO and its wholly owned subsidiary Indianapolis Power & Light … particularly considering CDPQ’s strong credit quality compared to AES,” Moody’s analyst Natividad Martel wrote.
Moody’s did not change its ratings for IPL, IPALCO or AES, however, which are Baa1 stable, Baa3 stable and Ba3 stable, respectively.
IPL has a current capital structure of 45% equity and 55% debt.Virtually all of the utility’s profits are returned to AES as dividends, which has left the utility thinly capitalized. In the first nine months of 2014, IPL paid $78 million in dividends to AES.
Map of AES’ US businesses (Click to zoom)
Over the last two years, AES contributed $156 million in additional equity to IPL, said Moody’s.AES and CDPQ will contribute another $62 million on top of CDPQ’s $349 million.
Although it would ultimately receive less in dividends from IPL, AES would enjoy a reduction in requirements to make equity contributions to IPL. That will “enhance AES’ parent only free cash flow position,” said Moody’s.
That’s notable because AES recently announced it would double dividend distributions starting in the first quarter of 2015.
As of Sept. 30, IPL had an available borrowing capacity of $249.3 million under its $250 million unsecured revolving credit facility after outstanding borrowings and existing letters of credit.
CDPQ
The purchase is being made by CDP Infrastructure Fund GP, a New York-based investment fund and a wholly-owned subsidiary of CDPQ.
CDPQ has a controlling interest in Gaz Metro Limited Partnership, the biggest natural gas distributor in Quebec and the 100% owner of Vermont’s Green Mountain Power.
In MISO, in which IPL operates, CDPQ has a 24.7% interest in Invenergy Wind, whose projects include Bishop Hill Energy III, in Henry County, Ill.
IPL is asking FERC for expedited approval of the CDPQ deal. Even with Invenergy Wind’s current and proposed projects, Invenergy and IPL would own or control on a combined basis 2% of MISO’s installed generation capacity, IPL said in its filing. IPL noted that FERC recently accepted market-based rate filings by affiliates of Invenergy Wind based in part on the passive nature of the CDPQ interests.
New Source Review Liability
IPL, meanwhile, could find itself facing other environmental costs outside of its $1.4 billion capital program.
Although not mentioned in the context of the CDPQ deal, IPL remains haunted by the specter of a 16-page Notice of Violation the EPA handed the utility in 2009.
It alleges IPL updated three generating plants over 23 years without adding the most modern pollution controls. The EPA’s New Source Review (NSR) requires utilities to undergo a pre-construction review for new plants and whenever existing plants are modified in a way that involves “non-routine” physical changes resulting in a significant increase in emissions.
IPL contends that the maintenance projects were routine.
In its third-quarter earnings report, AES said it has met with EPA officials to resolve the NOV and noted that in other NSR cases the EPA has “required companies to pay civil penalties, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects.” Such an outcome could have a “material impact” on IPL and AES, the company said.
One such case involving similar allegations cost American Electric Power $75 million in penalties and environmental projects as part of a 2007 settlement with the EPA. AEP agreed as part of the settlement to make $1.2 billion in additional sulfur- and nitrogen-control upgrades at its Rockport and Clinch River generating plants.
AEP’s settlement came after almost eight years of litigation.
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.
The transmission rate dispute between MISO’s industrial customers and its transmission owners appears headed for a Federal Energy Regulatory Commission hearing after an administrative law judge recommended last week that FERC terminate settlement proceedings.
Settlement Judge Dawn E.B. Scholz said the parties had reached an impasse (EL14-12).
That clears the way for a pre-hearing conference as early as next month, according to the Organization of MISO States, whose executive committee last week discussed the status of the case.
This fall, MISO industrials filed a complaint contending that the TOs’ current base return on equity — 12.38% except for ATC, at 12.2% — is too high.
MISO industrials contend the base ROE for TOs should not exceed 9.15%, citing changes in financial markets and other factors. Industrials say the lower rate would cut transmission rates by $327 million.
Industrial representatives met with TOs several times to attempt a settlement, to no avail.
At last week’s OMS meeting, Executive Director Bill Smith estimated the case could be resolved by fall 2015.
The dispute follows FERC’s June ruling introducing a new two-step method for calculating electric utility ROEs. Ruling in a case involving New England TOs, FERC tentatively set the “zone of reasonableness” at 7.03% to 11.74%.
Plaintiffs in the MISO case include the Illinois Industrial Energy Consumers, Indiana Industrial Energy Consumers, Minnesota Large Industrial Group and Wisconsin Industrial Energy Group.
A second dispute erupted between the groups on Nov. 6. That’s when industrials, along with consumer advocates and state regulators, asked FERC to reject a request by TOs for a 50-basis point adder as an incentive for their participation in the RTO (ER15-358).
The Federal Energy Regulatory Commission last week conditionally accepted Entergy’s request to terminate the system agreement for its Gulf Coast operating companies beginning in 2018, but it ordered a hearing and settlement proceedings to consider the concerns of regulators in Texas and Louisiana (ER14-75 et al).
The system agreement among Entergy and its operating companies has been the basis for planning and operating its generation and transmission facilities as a single system since 1951.
After Entergy’s April 2011 announcement that it would join MISO, the Public Utility Commission of Texas said the benefits of joining the RTO would be diminished by Entergy Texas’ continued participation in the agreement and called for terminating it sooner than the eight-year notice period required by the pact. Texas regulators argued that Entergy would need no more than three years to achieve operational readiness to participate in MISO’s capacity markets.
Entergy responded by asking FERC permission for a five-year exit. For Entergy Texas that would be in October 2018; for Entergy Louisiana and Entergy Gulf States Louisiana, the withdrawal would be effective in February 2019. (Entergy Arkansas withdrew from the system agreement in December 2013; Entergy Mississippi’s withdrawal is effective in November 2015.)
The company said the original eight-year notice requirement was based on the time frame for constructing a new coal-fired generating plant. It said a five-year notice was now sufficient because that is enough time to plan and build a new gas combined-cycle unit and that the MISO capacity market provides a “backstop” for any shortfalls.
The New Orleans City Council balked, saying that it was uncertain whether all of Entergy’s operating companies would join MISO. It also said five years might not be enough to plan new generation, citing delays in the development of Entergy’s Ninemile Point Unit 6.
The Louisiana Public Service Commission, meanwhile, called for a new “modern, comprehensive tariff” addressing planning and operation of the Entergy system in the MISO market, saying it is improper for Entergy to continue operating under an “anachronistic” agreement developed before RTOs existed.
Louisiana asked FERC to consolidate proceedings concerning the notice question with dockets ER13-432 and ER14-73, which involve revisions to the system agreement related to Entergy’s entry into MISO.
The commission rejected the consolidation request, saying the factual and legal issues were too disparate to combine in a single docket.
FERC did agree to combine the six notice dockets, and it ordered appointment of a settlement judge within 15 days. If the parties cannot reach a settlement, FERC said, the case will go to a public hearing to resolve the factual disputes.
Entergy has more than 2.8 million customers in Arkansas, Louisiana, Mississippi and Texas.
Saying the “time is ripe,” the Federal Energy Regulatory Commission has consolidated four years of Entergy Corp.’s disputed annual cost allocation cases for hearing and settlement.
At issue is how Entergy allocates production costs among its half-dozen operating companies under its system agreement. The companies essentially operate as one system, although each have different operating costs.
Each year payments are made by low-cost operating companies to the highest-cost company in the system, using a “bandwidth” remedy that ensures that no operating company has production costs more than 11% above or below the Entergy system average.
Under the 2014 bandwidth implementation — its eighth —Entergy Texas would pay $15.3 million to Entergy New Orleans.
Regulators in each state where Entergy operates have regularly challenged the annual bandwidth filings. FERC agreed Dec. 18 to review not only the 2014 filing but also Entergy’s fifth, sixth and seventh bandwidth formulas (ER14-2085).
The commission said the filings raise factual issues that it could not resolve based on the existing record. It set a refund effective date of June 1, 2014.
In Entergy’s 2014 filing, the New Orleans City Council sought a hearing to determine if Entergy’s rate calculations and accounting practices are in agreement with the bandwidth formula and previous FERC orders.
The council also raised an issue with the 2013 bandwidth filing, noting that it includes the cancellation costs of the Little Gypsy Repowering Project that a FERC judge in an initial decision (ER12-1384) excluded from the bandwidth calculation.
The Louisiana Public Service Commission, meanwhile, said it wanted a hearing to determine whether Entergy’s inputs are unjust and unreasonable due to incorrect calculations, “misapplications of the formula or imprudence.”
The Public Utility Commission of Texas also sought a hearing on the 2014 filing but asked that it be delayed until the accounting for the previous years are resolved.
“Our preliminary analysis indicates that Entergy’s proposed rates have not been shown to be just and reasonable and may be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful,” FERC said.
