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July 30, 2024

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FERC Gives Conditional OK to Talen Energy

By Ted Caddell

talenThe 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.”

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Connecticut Light Power Wins $130 Million Boost

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.

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NYISO Ordered to Refund $700K in Superstorm Sandy Billing Dispute

nyisoNYISO 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.”

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PJM Markets and Reliability Committee Briefs

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.

Compiled by Suzanne Herel

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Natural Gas, Distributed Generation, Environmental Rules Highlight NYISO Strategic Plan

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.
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ROE Talks Between MISO Industrials and TOs Collapse

By Chris O’Malley

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 opponents said that the adder request is an attempt to claw back some of the revenue TOs might lose if unsuccessful in the base ROE challenge. (See Consumers, Regulators Respond as New Front Opens in MISO ROE Battle.)

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FERC OKs 2018 Entergy System Agreement Exit

By Chris O’Malley

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.

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FERC Bundles Entergy ‘Bandwidth’ Disputes for Hearing

By Chris O’Malley

entergySaying 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.

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FERC Orders Proceedings to Decide PJM’s Postage-Stamp Cost Allocation

By Michael Brooks

cost allocation
(click to zoom)

The Federal Energy Regulatory Commission last week ordered settlement judge and hearing procedures to determine how costs should be allocated for PJM transmission projects of 500 kV or more that were approved before February 2013.

PJM’s “postage-stamp” cost allocation for the projects was challenged in court by the RTO’s Midwestern utilities. The method billed all PJM utilities in proportion to their load, regardless of where the projects were located.

The Seventh Circuit Court of Appeals has remanded the case back to FERC twice, most recently in June. The commission had originally approved the postage-stamp method in 2007 and attempted to justify it in its order on remand. The court, however, ruled that FERC had again failed to show how a western utility would benefit as much as an eastern utility from new transmission facilities in the east. (See PJM: Court Ruling Won’t Upset ‘Hybrid’ Cost Allocation.)

In last week’s order, FERC noted the court’s criticism, saying it expects PJM and the western utilities “to support their respective proposals for cost allocations for these projects with quantitative evidence, or at least an estimate of the benefits, adjusted as necessary to reflect any uncertainty in benefit allocation among the PJM utilities.”

The case concerns 15 projects costing $2.7 billion.

FERC urged PJM and the utilities “to make every effort to settle their disputes before hearing procedures are commenced.” A settlement judge will be appointed by Jan. 2 to oversee the discussions (EL05-121-009).

PJM replaced the postage-stamp method last year with a hybrid formula that allocates half the costs using the former method, with the remaining costs allocated by a solution-based distribution factor (DFAX).

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PJM Seeks to Postpone Some Generation Retirements through 2015/16

By Rich Heidorn Jr.

PJM officials are seeking to postpone generation retirements — or accelerate planned new generation — to help the RTO ride through potential shortages next winter.

PJM

 

Officials told the Markets and Reliability Committee Thursday that they will file proposed cost allocation language with the Federal Energy Regulatory Commission before the end of the year to forestall some of the estimated 9,500 MW of retirements expected next year as a result of the Environmental Protection Agency’s mercury and air toxics (MATS) rule and more than 2,000 MW being shut down by New Jersey’s High Energy Demand Day regulations.

In addition to offering reliability-must-run (RMR) compensation to delay retirements, officials said they are considering incentives to encourage some generation slated to come on line in delivery year 2016/17 to accelerate construction and launch earlier.

In total, officials said they will attempt to secure as much as 2,500 MW of generation through April 2016.

PJM Vice President for Operations Mike Kormos said the RTO is acting in light of the 22% forced outage rate from last January and uncertainty over the role of demand response in the wholesale markets.

The final amount procured will be dependent on load estimates and the projected forced outage rate for winter 2015/16 and the volume of capacity procured at the third incremental auction for the year. No demand response will be permitted to clear in that auction, officials said, because of the appellate court ruling threatening DR’s role in the wholesale markets. (See Verrilli to Seek Supreme Court Review of EPSA Ruling.)

Without such actions, Kormos said PJM estimates it would have about 2% less capacity than it had last winter, when it narrowly avoided voltage reductions or other severe actions.

“There is a cost effectiveness [consideration],” he said. “This isn’t 2,500 MW at all cost. This is an insurance policy.”

The FERC filing will seek authority to negotiate contracts with generation owners. Contracts with individual generators would be filed for FERC approval later. “We have no authority to negotiate this” currently, Kormos said.

PJM has negotiated RMR contracts when past retirements have prompted the need for transmission upgrades. The costs of those contracts were allocated over the relatively small areas benefiting from the new infrastructure.

This filing will likely seek RTO-wide cost allocation because of the broader reliability issues involved, Kormos said.

Market Monitor Joe Bowring said the costs should be limited to incremental costs of “speeding up a [new] unit or keeping [an old one] around.”