FERC to Revamp MBR Rules

Power sellers in PJM and other RTOs and ISOs will no longer have to submit market power screens under proposed changes to the Federal Energy Regulatory Commission’s market-based rate (MBR) regulations.

The change is one of dozens included in FERC’s first major overhaul of the MBR rules since their creation in 2007.

The commission’s Notice of Proposed Rulemaking (RM14-14) would streamline several MBR rules while adding some new requirements. FERC said current rules create some paperwork burdens that outweigh their benefits.

Here’s a guide to what’s in the 143-page NOPR, including applicable paragraph numbers.

What’s Added

Rows to the indicative screen format for sellers to specify simultaneous transmission import limit (SIL) values as well as long-term firm purchases and remote capacity from outside the study area. Screens must be filed in “a workable electronic spreadsheet format.” (paragraph 13)
Solar to the definition of energy-limited generation resources, which use a five-year average capacity factor. Resources that do not have five years of historical data may use regional capacity factor estimates from the Energy Information Administration (EIA). (15)
A redefinition of uncommitted capacity to include all long-term firm purchases of capacity or energy in their indicative screens and asset appendices, regardless of whether the seller has operational control over the generation capacity supplying the purchased power. FERC said the change will help size the market correctly and will establish consistent treatment of long-term firm transactions. (16)
A provision that asset appendices must be in an electronic spreadsheet format. Some headings will be changed for clarity. Some filing instructions are changed. (19)
A requirement that sellers provide an organizational chart as descriptions of their affiliates and upstream owners when filing initial applications, updated market power analyses and notices of change in status involving new affiliations. The chart would be similar to that required from applicants under section 203 of the Federal Power Act. (22)

What’s Subtracted

The requirement that MBR sellers in RTOs, who use FERC-approved monitoring and mitigation, submit market power screens. (11)
The requirement that generation owners submit indicative screens if all of the capacity owned or controlled by them and their affiliates in a balancing authority area is fully committed. (11)
The requirement that MBR sellers file quarterly land acquisition reports and provide information on their control of sites for development of new generation capacity. (17)
The requirement that changes in status below a 100-MW threshold have to be reported. Going forward, long-term firm purchases of capacity or energy will be included in the calculation. (18)

What Else is Changed

Broadens the default geographic market for independent power producers (IPPs) with generation capacity located in a generation-only balancing authority area (BAA). Instead of being limited to the home balancing authority area, the IPP’s default market would include all balancing authority areas directly interconnected to the IPP’s home BAA. (12)
Provides an updated region map and three-year filing schedule for market power analyses from Category 2 sellers. (20)
Adds a distinction between power marketers (which should include all affiliated generation in a region) and power producers (which would include only affiliated generation capacity that is located in the same region as the power producer’s generation assets) for the determination of seller category. FERC is proposing the change “based on the fact that a power marketer is assumed to have no home market, while it is assumed that a majority of a power producer’s sales will be in market(s) in which it owns generation assets.” (21)
Sellers should include all load associated with the balancing authority area(s) within the study area, including non-affiliated load in Submittal 1. Row 8 will be amended to read “Adjusted Historical Peak Load.”

Submittal 1 requires sellers to use FERC Form No. 714 load values or explain the source of the data used. FERC is seeking comment on the appropriate source of historical peak load data. (26)

June 24, 2014

MRC/MC Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:30)

Members will vote on endorsing revisions to Manual 01: Control Center and Data Exchange Requirements and Manual 14D: Generator Operational Requirements that incorporate requirements for installation of SynchroPhasor Measurement Units (“PMU”) at new generation interconnections. Related Tariff changes were approved by members last June and approved by the Federal Energy Regulatory Commission in February. The requirements apply to interconnection customers entering the new services queue on or after Oct. 1, 2012 with facilities with a maximum output of 100 MW or greater. (See Members Approve PMU Requirement.)
Members will be asked to endorse changes to Manual 01: Control Center and Data Exchange Requirements and Manual 14D: Generator Operational Requirements governing rules for members wishing to purchase access to the PJMNet data feed. (See Final OK for Membership Inquiry, PJMNet.)

3. Designated Entity and Interconnection Coordination Agreements (9:30-9:45)

Members will be asked to approve the proposed Designated Entity Agreement (DEA) and Interconnection Coordination Agreement (ICA) developed by the Regional Planning Process Task Force (RPPTF).

The documents define the duties, accountabilities and obligations of companies designated to build and operate transmission projects awarded under the competitive rules of FERC Order 1000. They include project scope, planning criteria, development schedules, project milestones and terms and conditions. The committee will also be asked to sunset the RPPTF.

FERC ordered PJM to file the DEA for commission approval by July 14. (See: 147 FERC ¶61,128).

4. MOPR Unit Specific Review (9:45-10:00)

PJM’s chief economist Paul Sotkiewicz will seek MRC approval for a joint PJM-Independent Market Monitor proposal to improve unit-specific reviews under the Minimum Offer Price Rule (MOPR). The proposal is intended to develop more standardized assumptions and reduce PJM-IMM discretion. It would require use of nominal levelized values, a 20-year asset life and a residual value of zero. It would also bar inclusion of sunk costs.

The proposal received the support of 72% of participants in a poll by the Capacity Senior Task Force. An alternative by PSEG Energy Resources & Trade won 64% support and may be brought to a vote if the PJM-IMM proposal fails. PSEG says it would use the best available evidence of the developer’s costs, while the PJM-IMM proposal would provide developers incentives to understate costs. The PSEG proposal also makes the main cost element publicly available, unlike the PJM-IMM plan, under which key cost items are confidential and cannot be challenged by other stakeholders. (See comparison in MOPR Unit Specific Review Matrix.)

5. RPM Supply Curve Transparency (10:00-10:15)

The MRC will vote on a proposal supported by Exelon and opposed by the Market Monitor to create more informative supply curves from capacity auctions. The measure was approved by the Market Implementation Committee with only 54% support, short of the two-thirds sector-weighted vote it will need to clear the MRC.

Stakeholders had approved a problem statement by Exelon on the issue without opposition last June. But support for the change eroded after Market Monitor Joe Bowring signaled his opposition, saying it could reveal sensitive data about price-quantity offers and cause collusion among generators. Load representatives opposing the change cited Bowring’s concerns and news reports indicating Exelon had helped boost clearing prices in the May auction by offering 4,255 MW of nuclear capacity at the maximum price allowed. (See Load Balks at Supply Curve Fix in Response to Auction Strategies.)

6. Forward Price Projection Performance (10:15-10:30)

PJM’s Becky Carroll will ask for MRC approval to proceed with implementation of the new Coordinated Transaction Schedule (CTS) product for trading between PJM and the New York ISO. CTS, which is intended to reduce uneconomic power flows between the two regions, could be implemented as soon as November if the MRC votes to endorse the accuracy of the scheduling tool that would be used to optimize the cross-border transactions. PJM officials told members in March that the Intermediate Term Security Constrained Economic Dispatch (IT SCED) tool is accurate within $5/MWh more than two-thirds of the time. (See PJM Price Forecasts: Close Enough for Power Trading?)

7. TO Data Feed (10:30-10:45)

The committee will be asked to approve a revised issue charge for the Transmission Owner Data Feed Task Force (TODFTF) to include consideration of generator real-time reactive capability data. Members approved creation of the task force in April to consider an easier method for transmission owners to access real-time generator data, an effort intended to improve situational awareness and emergency response.

During initial task force discussions, stakeholders shared concerns about TOs having access to generator-characteristic data in addition to real-time telemetry. Exelon responded that generator real-time reactive capability data is necessary for accurate state estimator and contingency analyses. Exelon will present the revised issue charge. (See Members to Consider Easier Sharing of Real-Time Generator Data.)

8. Cost Development Subcommittee (CDS) Sunset (10:45-11:00)

The committee will be asked to sunset the subcommittee, which was created in 2011 to develop standard procedures for calculating the costs of products or services provided to PJM when those products or services are required to be provided at a cost-based rate.

9. FTR/ARR Senior Task Force (FTRSTF) (11:00-11:15)

The MRC will be asked to approve the proposed FTRSTF charter. The MRC approved the creation of the task force in May to determine the causes of financial transmission rights underfunding and whether changes to current FTR and auction revenue rights (ARR) processes could improve funding levels. (See New Task Force to Target FTR Underfunding.)

10. Cap Review Senior Task Force (CRSTF) (11:15-11:30)

The committee will be asked to approve the proposed charter for the CRSTF, which was created to consider changing the current $1,000/MWh offer cap. (See Effort to Lift Offer Cap Advances After Debate.)

Members Committee

3. Regional Planning Process Senior Task force (RPPTF) (1:25-1:40)

Members will be asked for approval of Operating Agreement (OA) and Tariff revisions governing multi-driver transmission projects, which are intended to lower costs for public policy transmission projects under FERC Order 1000. (See States Still Miffed with TOs’ `Multi-Driver’ Cost Allocation.)

4. Designated Entity and Interconnection Coordination Agreements (1:40-2:00)

The MC will vote on the proposed Designated Entity Agreement (DEA) and Interconnection Coordination Agreement (ICA). See MRC item #3 above.

5. Frequently Mitigated Unit Adders (2:00-2:15)

The committee will be asked to approve a joint proposal from PJM and the Independent Market Monitor to reduce payments to frequently mitigated units (FMUs). The Tariff changes were approved by the MRC in May. (See PJM-IMM Limits on FMU Adders Prevail.)

6. Operating Agreement Errata (2:15-2:20)

Members will be asked to revise OA Schedule 11 to correct a typo that refers to “Section 16” as “schedule 16.”

June 24, 2014

FERC to Tackle RTO Uplift, Price Formation

The Federal Energy Regulatory Commission will convene workshops beginning this fall to consider rule changes regarding uplift, price caps and other issues affecting price formation in PJM and other RTOs and ISOs.

The commission said its inquiry was prompted by comments made at recent technical conferences on capacity markets and the grid’s response to the recent severe winter.

The workshops will consider ways to address limitations in RTO market software that prevent RTOs from modeling all system parameters, such as voltage constraints and generator operating constraints. “While these limitations are to some extent inherent in the complexity of the electric system, staff believes it is worth exploring whether there may be opportunities for RTOs and ISOs to improve their energy and ancillary services price formation processes,” FERC staff said in a presentation announcing the initiative (AD14-14).

Acting Chair Cheryl LaFleur said ancillary service markets are growing in importance because of the need to balance the increasing volume of intermittent resources.

The first of three workshops will be in early September and will focus on uplift, which can mute price signals. “Sustained patterns of specific resources receiving a large proportion of uplift payments over long periods of time raise additional concerns that those resources are providing a service that should be priced in the market or opened to competition,” the commission said.

Subsequent sessions will focus on:

Offer price mitigation and offer price caps. RTO rules designed to limit generator market power assume the ability of resources to fully reflect their marginal costs in their bids, but $1,000/MWh price caps in PJM and elsewhere prevented some operators from doing so during the gas price spikes in January. “To the extent existing rules on marginal cost bidding do not provide for this, bids and resulting energy and ancillary service prices may be artificially low,” the commission said.
Scarcity and shortage pricing. RTOs may dispatch emergency demand response and order voltage reductions to avoid reserve deficiencies, actions often tied to administrative pricing rules designed to reflect scarcity. “To the extent that actions taken to avoid reserve deficiencies are not priced appropriately or not priced in a manner consistent with the prices set during a reserve deficiency, the price signals sent when the system is tight will not incent appropriate short- and long-term actions by resources and loads,” the commission said.
Unpriced operator actions. RTO operators regularly commit uneconomic resources to ensure reliability or respond to un-modeled system constraints. “To the extent RTOs/ISOs regularly commit excess resources, such actions may artificially suppress energy and ancillary service prices,” the commission said.

Commissioner Philip Moeller predicted the discussion over price caps will be “contentious and long.” In response to a question from Moeller, Jamie L. Simler, director of the Office of Energy Policy and Innovation (OEPI), acknowledged it was “fairly unlikely” that the commission would be able to craft new rules before next winter.

OEPI staffer Mary Cain said one of the goals of the workshops will be to identify best practices among RTOs.

In May, stakeholders approved PJM’s short-term plan for capturing reserve costs in energy prices. (See Effort to Lift Offer Cap Advances After Debate.)

June 24, 2014

State Briefs

Gov. Names City Exec For PSC Seat

Gov. Jack Markell nominated Wilmington’s economic development director to the Public Service Commission last week. Harold Gray would take the seat of former commission member Arnetta McRae, who left the PSC in 2011. Her seat has remained vacant since then, and plans to reduce the five-member body to a three-member commission were shelved. Gray is a former member of the state Environmental Appeals Board and was an officer with United Way of Delaware. He was president and CEO of TehniData America, an IT consulting company.

More: The News Journal

DISTRICT OF COLUMBIA

Pepco, DOT File for Undergrounding Lines

Pepco and the District Department of Transportation last week asked permission to move more electric lines underground in a project that would take up to a decade and cost $1 billion. The plan would result in an increase to the average residential electric bill of $1.50 a month in the first year and up to $3.25 a month after seven years. Moving the lines underground is expected to reduce the number and length of service interruptions.

More: The Washington Post

ILLINOIS

ICC Set To Hear 345-kV Line Route

Ameren Transmission Co. completed public comment sessions on its proposed 345-kV transmission line on June 12 and will make recommendations to the Commerce Commission later this summer on the route from Peoria to Galesburg. Ameren says the line is needed to serve an increase in wind and other renewable energy sources in the state.

More: Peoria Public Radio

MICHIGAN

Gov. Signs Law Allowing Coal Ash for Construction

Gov. Rick Snyder signed a law allowing coal ash to be used in cement and asphalt last week. The law will also protect those who store coal ash and other byproducts from legal liability if proper procedures are followed. Snyder said the law will help keep waste disposal costs low and support the environment.

More: Mining Journal

OHIO

New Rules Threaten Future Wind Farms

Just days after signing a bill freezing the state’s renewable energy standards, Gov. John Kasich signed House Bill 483, vastly increasing the setbacks required at wind farms. The setbacks, which increased from 550 feet to about 1,300 from the base of wind turbine bases to the nearest home, will drastically cut the number of turbines at proposed wind farms. Wind energy proponents were upset, with some saying that the new regulations could spell the end of new wind energy projects in Ohio.

The bill “basically zones new wind projects out of Ohio,” said Eric Thumma, director of policy and regulatory affairs for Iberdrola Renewables Inc. Thumma said the practical effect of the new regulations would cut the number of turbines at one project from 50 to seven and from 75 to three at another. “The economics are not going to work if you have such reduced projects,” he said. The new regulations were put in place in response to complaints about wind turbine noise and visual pollution.

More: Midwestern Energy News

New Pipeline Sends Gas To Indiana, Illinois

Rockies Express Pipeline said its new 24-inch natural gas pipeline will start delivering gas from the state’s Utica shale gas fields to Indiana and Illinois this week. The Seneca lateral in southeast Ohio sends gas from the MarkWest Energy Partners Seneca processing plant to the main pipeline, and from there to markets in the west. Construction of additional compressor stations could allow gas to be sent as far as Missouri, pipeline owners say.

More: Columbus Business First

PENNSYLVANIA

New Well Fees Mean Millions for State

The state Environmental Quality Board has approved a final rule hiking the fees for unconventional well permits, a move that will result in about $4.7 million in additional revenue for the state, according to the state Department of Environmental Protection. “Under the Corbett administration, there has been a strategic, proactive approach to the oversight of this industry,” DEP Secretary and EQB Chairperson E. Christopher Abruzzo said. “The efforts to date have been unprecedented, and this fee increase will give us the ability to continue to grow and strengthen our program along with the growing industry.” The increased revenue will be used on additional staff and information technology projects to aid regulators in monitoring the increase in drilling.

More: Fierce Energy

PUC Eyes Settlement with Electric Company for Slamming

The Public Utility Commission is seeking public comment on a proposed settlement with an electric marketer for switching customers’ electric providers without full permission. The PUC proposes to fine ResCom $59,000 and require it to abide by “Do Not Call” lists. The company would also be required to file quarterly reports with the commission. The settlement arose after three ResCom customers complained to the commission that their service provider was switched without their permission.

More: Pennsylvania Public Utility Commission

State Agencies Target Five Energy Suppliers for Slamming

The Bureau of Consumer Protection and the Office of Consumer Advocate are targeting five electricity suppliers for a variety of alleged fraudulent tactics, including switching customers without their knowledge and overcharging them.

The joint complaints were filed before the Public Utility Commission, Attorney General Kathleen G. Kane announced on Friday. The complaints seek the revocation of the licenses of Energy Services Providers Inc. d/b/a Pennsylvania Gas & Electric; IDT Energy Inc.; Respond Power LLC; Hiko Energy LLC; and Blue Pilot Energy LLC.

Among the allegations are that the suppliers promised low or “competitive” rates if customers switched, and then charged them up to 300% more than they had been paying. Other customers complained that they were switched without their consent, a practice known as “slamming.” In addition to license revocation, the complaints seek civil penalties and refunds for the customers.

More: CBS Philly

VIRGINIA

Dominion Faces Opposition to Jamestown Tx Tower Path

Photo simulation of planned James River towers (Source: Save the James Alliance)

Dominion’s plan to build a transmission line across the James River within sight of Jamestown Island and other historic sites is facing opposition from groups who say it would be a blight. The company is seeking permits from the U.S. Army Corps of Engineers to build 17 towers, some as tall as 295 feet, for the four-mile river crossing. Historic preservationists say the project would be a shocking sight among the area’s historic places. “I’m hard-pressed to find a worse place for Dominion to build this power line,” said Rob Nieweg, field director with the District of Columbia office of the National Trust for Historic Preservation. Dominion has argued that the project is necessary to ensure the reliability of service to the area.

More: CBS Local

WEST VIRGINIA

Meter Reading Law Means Higher Bills

FirstEnergy subsidiaries Mon Power and Potomac Edison amended their rate hike requests to include $7.5 million for monthly meter readings. The new filings, prompted by a recent PSC order, boosts the combined rate increases to about $103 million. The commission ordered both companies to ensure each customer’s meter is read monthly. Both companies have already started hiring and training enough new meter readers to comply with the order.

More: Market Watch

June 24, 2014

FERC Splits over ROE

The Federal Energy Regulatory Commission unanimously agreed last week to change the way it calculates return on equity (ROE) rates for electric utilities, moving to a two-step process it has long used for natural gas and oil pipelines that incorporates long-term growth rates.

But the panel split 3-1 over its first application of the new formula, tentatively setting the ROE for New England transmission owners at three-quarters of the top of the “zone of reasonableness,” a departure from the prior practice that used the midpoint in the range.

The case resulted from a complaint filed in 2011 by New England state officials and others that challenged the New England TOs’ 11.14% base ROE as unreasonable. The commission’s ruling (EL11-66-001) sets the ROE at 10.57% for the New England TOs, which include Northeast Utilities, Central Maine Power Co., National Grid and NextEra.

(Although the commission chose a higher position within the range, the New England TOs’ ROE was reduced because the new formula reduced the top end of the zone.)

The commission also ordered hearing and settlement judge procedures in five pending challenges to electric utility ROEs, saying they should be resolved within the new framework. These include a December 2012 complaint that sought to reduce the New England TOs’ ROE to 8.7% (EL13-33) and cases involving Florida Power Corp.(EL12-39), Duke Energy Florida (EL13-63 & EL12-39) and Southwestern Public Service Co. (EL12-59 and EL13-78 & EL12-59).

FERC Staff, Consumers Rebuffed

In setting the ROE at the 75^th percentile of the zone of reasonableness, the commission majority sided with the TOs and rejected arguments by FERC trial staff and consumer representatives, who had argued for continuing the commission’s traditional use of the zone’s midpoint.

Acting Chair Cheryl LaFleur, a former executive vice president and acting CEO of National Grid, sided with the two Republican commissioners, Philip Moeller and Tony Clark, saying the change was justified because of the unusually low current interest rates.

Commissioner John Norris — a Democrat like LaFleur — issued a partial dissent, saying that while he agreed that the companies deserved an ROE increase, there was insufficient evidence to support setting the rate so high.

“This order tilts the balance too far,” Norris said in a statement during the commission’s public meeting. “They will clearly be celebrating in the corporate boardroom of Northeast Utilities today.”

New Formula

The order changes the methodology for electric utility ROEs from a one-step discounted cash flow (DCF) model to the same two-step DCF the commission has used for natural gas and oil pipeline ROEs. While the one-step methodology relies on only short-term growth rates, the two-step process includes short-term and long-term growth rate estimates.

The commission said the two-step process will produce a narrower zone of reasonableness because long-term growth rates are more stable than short-term growth rates and because the two-step methodology does not calculate a high-end and low-end cost of equity estimate for each company in the relevant proxy group.

The two-step methodology “is less likely to produce the anomalous results that can result from combining high and low dividend yields with high and low short-term projections of dividend growth to produce two estimates for each proxy company,” the commission said. “The end result is often a zone of reasonableness that is defined by two widely divergent growth rates that do not engender much confidence in the reliability of the estimates.”

The commission ordered a paper hearing to determine whether growth in gross domestic product should be the indicator for long-term growth rates, as it is in natural gas and oil pipeline proceedings. Using the GDP indicator, the commission tentatively set the zone of reasonableness as 7.03% to 11.74%.

The previous zone ranged from 7.3% to 13.1%. Thus, although the commission chose a higher position within the range, the reduced top end resulted in a decrease from the New England TOs’ previous ROE, which also included a post-hearing adder.

Clearing the Backlog

In announcing the ruling at last week’s commission meeting, LaFleur said that she had made acting on a backlog of ROE cases a high priority when she was appointed acting chair in November. “I established specific goals for addressing the ROE cases, including that any resolution would be fair to customers and investors, principled and sustainable, and represent a consensus of my colleagues. While we did not achieve unanimous agreement on all points, I believe that we have met these goals,” she said.

LaFleur said the grid’s shift from coal to natural gas and renewables “will require the construction of a significant amount of transmission in the coming years. I anticipate that this order, along with our recent compliance orders on Order No. 1000 will help provide some certainty to that process.”

Norris: `Troubling Precedent’

Norris praised LaFleur for pushing the commission to act on the ROE disputes, which he said “had been languishing too long.”

But he said the order sets a “troubling precedent” and may subject consumers to unjustly high rates in the future.

He said he would have ordered a paper hearing because there was insufficient evidence to support setting the rate at the 75^th percentile.

“Regrettably, today’s order tilts the balance in favor of the New England transmission owners without further recourse and fails to adequately give a voice to consumer interests,” he wrote in his dissent.

“Looking beyond today’s order, my broader concern is that the precedent established through this adjustment could become the new norm that would potentially ratchet up and lock in substantially higher ROEs in future cases. I am further troubled by today’s order in light of recent commission decisions on Order No. 1000 compliance filings that have served to protect incumbent transmission owners from competition in the development of new transmission. Simply put, not only will incumbent transmission owners be more insulated from competition, they will also be the primary beneficiaries of the new precedent established in this proceeding that could provide for substantially higher ROEs.”

Treasury Bond Update Eliminated

The commission’s order also ends its practice of using U.S. Treasury bond yields to make a final ROE adjustment, which reflect changes in capital market conditions after the close of the record in a rate hearing. Instead, the commission’s decision will be based on the latest financial data available in the hearing record.

The D.C. Circuit Court of Appeals had ordered the commission to revisit the issue in a ruling on a 2008 ROE case involving Southern California Edison Co. The court said FERC should consider evidence that U.S. Treasury bond yields and corporate bond yields might be inversely related. The commission acknowledged that “there is not necessarily a one-to-one correlation between U.S. Treasury bond yields and public utility returns on equity.”

June 24, 2014

PPL-Riverstone Spin-Off Shuffles GenCo Rankings

Will PPL shareholders be better off now that the company has decided to spin off its generation?

Wall Street seems far from convinced, with the company’s stock price virtually unchanged since the deal with investment firm Riverstone Holdings LLC was announced. (Though you would have earned a tidy 13.5% return had you bought when rumors of the spin-off began bubbling up in early February.)

But there’s no doubt the tax-free deal creating Talen Energy will shuffle the generator rankings. The new company will have more than 15,000 MW of generation, ranking fifth nationally in competitive generation (behind NRG, Exelon, Calpine and Next Era) and third among independent power producers.

Within PJM, it will rank sixth with more than 12,000 MW of generation, behind AEP, Exelon, Dominion, NRG and FirstEnergy. Its 1,883 MW in Texas will give it presence in the Electric Reliability Council of Texas (ERCOT). PPL said Talen anticipates needing to divest about 1,000 MW of generation to achieve regulatory approval, but it wouldn’t say what plants might be affected.

Meanwhile, Exelon and other integrated utilities are rumored to be considering PPL’s pure-play strategy. The rationale: By concentrating on regulated operations, utilities will be more attractive to shareholders seeking steady earnings and dividends, while more risk-tolerant investors can ride the highs and lows of merchant generation.

Welcoming Volatility

In announcing the deal, PPL Corp. CEO Bill Spence made repeated references to the volatility of the generation markets in PJM and ERCOT and said Talen would be poised to take advantage of it.

PPL, meanwhile, will be left with a “100% rate-regulated business model [that] provides earnings and dividend growth potential.” He said PPL expects “substantial” growth in the rate base in the coming years.

PPL shareholders will own 65% of Talen, with Riverstone holding 35%. The company will be listed on the New York Stock Exchange.

Coal and Natural Gas

Both Riverstone and PPL come with substantial coal generation — both about 40% of their portfolios. The company will also have a 40% share of natural gas, with 15% of its portfolio in nuclear and the remainder in oil (3%) and renewables (2%).

The combination, according to PPL Corp. CEO Bill Spence, will make Talen a “highly competitive player, operating very attractive assets, in the right regions” with “a significant proportion [of generation] with low or no carbon dioxide output.”

The new company will assume PPL Energy Supply’s 10,000 MW of generation, primarily in Pennsylvania, which includes its 90% stake in the Susquehanna nuclear generating station (pending approval by the Nuclear Regulatory Commission), 292 MW of hydro in Pennsylvania and 677 MW of coal-fired generation in Montana. It does not include 11 Montana hydro facilities, whose sale to NorthWestern Corp. was announced in 2013 and is nearing closing.

The Riverstone fleet includes three coal- and natural gas-fired plants in Maryland, five natural gas- or oil-fired plants in New Jersey, one natural gas plant in York, Pa., a natural gas-fired plant in Dartmouth, Mass., and five natural gas-fired plants in Texas. Combined, they produce 5,345 MW.

Not Included

Not included in the generation spinoff are the approximately 8,000 MW of generation PPL owns and operates in Kentucky. “The Kentucky generating plants are part of the rate bases of PPL’s Louisville Gas & Electric and Kentucky Utilities subsidiaries,” PPL spokesman George Lewis said Friday. “The Talen Energy transaction involves only merchant generating plants owned by PPL.”

The regulated delivery business in the United Kingdom – where PPL has 7.8 million electric customers – also will be unaffected by the transaction, Lewis said.

Lewis said Talen Energy headquarters “will be in Pennsylvania, but the specific location has not been chosen yet.” Marketing the generation will be done by PPL Energy’s existing marketing operation, he said.“Talen Energy will have an asset-focused energy marketing operation to get the greatest value for electricity generated by Talen Energy plants,” he said.

Layoffs Expected

Paul Farr, president of PPL Energy Supply, will become president and CEO of Talen at the closing of the deal. Jeremy McGuire, PPL’s vice president of strategic development, will be Talen’s chief financial officer.

“There will be job reductions across PPL as a result” of the transaction, he said. “The number of positions and the timing of the reductions will be determined during the transition process over the next nine to 12 months.”

Regulatory Approvals

Lewis said the partners anticipate completing the transaction by the middle of 2015. Approvals will be necessary from the Federal Energy Regulatory Commission, the Federal Trade Commission, the Department of Justice, the Nuclear Regulatory Commission and the Pennsylvania Public Utility Commission.

The NRC, which has to approve any transfer of Susquehanna’s operating license to the new company, will meet with PPL July 2 to discuss its plans. The meeting, from 10 a.m. to noon, will cover the new owner’s financial and technical qualifications, among other areas. Members of the public will be able to call in to the meeting to participate. The NRC approval process could take up to a year, an agency spokesman said.

June 24, 2014

Rebuffed by Courts, CPV Seeks FERC End-Around

Utilities in New Jersey and Maryland are fighting an attempt by a generation developer to enforce contracts that federal courts last year ruled invalid.

Competitive Power Ventures filed requests June 2 asking the Federal Energy Regulatory Commission to declare just and reasonable the contracts that would provide funding for CPV’s generating plants in Woodbridge, N.J., (ER14-2105) and Waldorf, Md. (ER14-2106).

CPV filed the requests with FERC on the same day that the Fourth Circuit Court of Appeals unanimously upheld a district court ruling throwing out the Maryland contracts (PPL EnergyPlus, LLC, et al. v. Nazarian, Civil Action No. MJG-12-1286). The court declared that the contracts violated FERC jurisdiction and were thus “illegal and unenforceable.”

CPV Woodbridge Construction (Source: Competitive Power Ventures)

CPV hopes to build a 661-MW combined cycle generator funded by 20-year “contracts for differences” with Baltimore Gas and Electric Co., Delmarva Power & Light Co. and Potomac Electric Power Co. The electric distribution companies (EDCs) were ordered to sign the contracts after CPV won a competitive solicitation by the Maryland Public Service Commission for construction of a new generating plant in the Southwest MAAC zone.

CPV also won a 2011 solicitation by the New Jersey Board of Public Utilities that resulted in 15-year “standard offer capacity agreements” (SOCA) with Rockland Electric Co., Public Service Electric and Gas Co., Jersey Central Power & Light Co. and Atlantic City Electric Co. tied to CPV’s 663-MW combined-cycle Woodbridge generation plant, now under construction.

Those contracts were struck down in October by the U.S. District Court in New Jersey (PPL EnergyPlus, LLC, et al. v. Hanna, Civil Action No. 11-0745). As in the Maryland case, the New Jersey contracts were ruled in violation of the Constitution’s Supremacy Clause and thus “void ab initio, invalid and unenforceable except for the termination provisions which any party may implement or defend.” The BPU appealed the ruling to the Third Circuit Court of Appeals.

The EDCs subject to the contracts filed protests on June 12 opposing CPV’s FERC filings. Also joining the protests were PPL, Calpine, Essential Power LLC and Lakewood Cogeneration LP. As a result of the court rulings, the protestors said, the contracts “do not exist.”

CPV’s “tactic of not only asking the commission to accept the purported `agreements’ for filing, but also to make a just and reasonable determination, is particularly curious and ill-advised in light of these preemption rulings,” the protestors wrote.

CPV Senior Vice President Braith Kelly said the company made the FERC filings to protect its interests in case it does not prevail on appeal. “If these are in fact FERC jurisdictional contracts that means FERC can rule on them,” he said in an interview.

CPV said the contracts do not threaten FERC’s jurisdiction, as the courts ruled, because they are “simply … financial settlements” based on capacity market prices and “do not require or in any way involve the delivery of capacity or energy to the EDCs.”

Contracts Explained

Under the Maryland contracts for differences, if CPV’s PJM energy and capacity revenues are less than the amount specified in the contracts, the EDCs will pay CPV the difference; if the revenues exceed the amount specified in the contracts, CPV would pay the EDCs the difference.

The New Jersey contracts are similar. CPV will receive the benchmark price it bid into the state solicitation minus revenues it receives through PJM’s capacity market. If the plant’s capacity market revenue is less than the benchmark price, the EDCs will pay CPV the difference; if capacity revenues exceed the benchmark, CPV pays the EDCs.

CPV said that while it appeals the court rulings, it was submitting the contracts to FERC “solely for the limited purpose of requesting that the commission review and determine that the rates in the SOCAs are just and reasonable and otherwise comport with the standards for rates in jurisdictional contracts under FPA Section 205.”

Other State Solicitations

CPV says the state initiatives that resulted in the contracts were “no different than the solicitations routinely mandated by state commissions for the procurement of energy to serve those loads that have not selected competitive suppliers,” called basic generation service (BGS) in New Jersey and standard offer service (SOS) in Maryland.

A FERC ruling that the CPV contracts are not just and reasonable and cannot be enforced “would call into question the reasonableness of rates charged by any jurisdictional seller participating in the BGS or in any similar state-mandated solicitations,” CPV wrote in support of the New Jersey contracts.

The fact that the EDCs entered into the contracts “under protest” is irrelevant, CPV said, because the state’s solicitation “resulted in no less an arms-length transaction than the BGS solicitations where the NJ BPU also mandated the procurement of electricity on terms it required.”

Because the contracts resulted from a competitive process, CPV said they meet the Allegheny and Edgar standards the commission applies in evaluating whether contracts awarded by EDCs to affiliates are just and reasonable.

FERC Position in Dispute

The protestors pointed to the Department of Justice’s amicus brief in the New Jersey case, which said the state-ordered contracts have a “price-suppressing and distortive effect on PJM’s wholesale capacity market prices.”

Kelly acknowledged FERC was a signatory to Justice’s brief. But he said the commission’s true position was spelled out in its approval of PJM’s revised minimum offer price rule (“MOPR 2”), which was designed to prevent state-supported generation from undercutting auction prices.

CPV said its New Jersey generator, which is about 20% complete, offered and cleared in each of the three base capacity auctions since 2012 under MOPR. The company did not disclose whether the Maryland project, for which it is attempting to secure financing, had cleared.

“In adopting MOPR 2 and doing away with the state exemption and defending that in the 3rd Circuit, FERC stated very clearly that these projects were economic,” Kelly said. “The change in the MOPR was designed to ensure these projects – these specific projects – did not adversely affect the market.”

A BPU spokesman declined to comment on the impact of a potential FERC decision on the appellate court case.

June 18, 2014

UPDATE: LaFleur to Remain Acting FERC Chair for up to 1 Year in Senate Deal with White House; Bay Wins Floor Vote

WASHINGTON — Cheryl LaFleur will likely remain acting chair of the Federal Energy Regulatory Commission for another year under a deal with the White House that won a Senate floor vote for Norman Bay.

A Senate panel voted June 18 to approve Bay’s appointment to FERC in a deal that will keep LaFleur in her leadership role for nine months after Bay’s confirmation by the full Senate.

The Senate Energy and Natural Resources Committee voted 13-9 to confirm Bay and 21-1 to grant LaFleur a second five-year term. With a floor vote not expected until September, LaFleur could remain in the top spot until June 2015.

LaFleur had sailed through her confirmation hearing May 20 while Bay was forced to defend his limited policy experience and his running of the commission’s enforcement division. The Department of Energy Organization Act gives the Senate authority to confirm members of FERC but gives it no say over which one of the commissioners is appointed chair by the president.

The president’s concession was enough to win the support of West Virginia Democrat Joe Manchin today but not that of ranking member Lisa Murkowski (R-Alaska) and most of her Republican colleagues. Murkowski said she wanted the president to remove the “acting” designation from LaFleur’s chairmanship so that she had full authority to act in a leadership role.

“I have not been given the assurance that she would be given the full authority as the chairman,” Murkowski said before casting her “no” vote.

Experience Questioned

Earlier in the hearing, Murkowski noted that lights in the Capitol were dimmed to conserve energy and said “there might be rolling brownouts this afternoon” as temperatures hit the 90s. She also cited FERC’s role in ensuring the grid’s reliability in the face of increasing environmental regulations on fossil fuel-fired generators.

“We need the best of the best running the commission,” Murkowski said.

While praising Bay as “a learned man,” she said the FERC chairmanship was not the place for “on-the-job training.”

Bay, who has served as director of FERC’s Office of Enforcement since 2009, is a former federal prosecutor and law school professor. Unlike most FERC commissioners in the last decade, he has never served as a state utility regulator.

Of the 15 FERC commissioners who have served since 2000, 10 served as commissioners or staffers at state regulatory agencies prior to their appointments. Four of the others worked in energy-related posts in state or federal legislative committees or executive agencies; one was a former utility executive.

The last five chairmen served a median of 30 months before becoming chair. Only one, Patrick H. Wood III, served less than a year on the panel before his promotion.

Murkowski and others also raised the issue of gender politics, questioning why Obama announced his intention to appoint the less experienced Bay directly into the chairmanship, “particularly when we have a woman … as the acting head of this commission. By all reports [LaFleur’s] been doing a good job,” Murkowski said. LaFleur is the only woman on the commission.

Among those who had expressed concern over Bay’s limited energy policy experience was Manchin, who helped sink the bid of Obama’s previous nominee, former Colorado regulator Ron Binz.

That sparked a flurry of negotiations over the last several days among the White House, Murkowski and Energy committee Chair Mary Landrieu (D-La.), which resulted in the president’s concession not to appoint Bay chairman immediately.

The lone vote against LaFleur apparently came from Vermont Sen. Bernie Sanders, an independent who caucuses with the Democrats. Sanders said he was not opposed to LaFleur’s second term but was protesting the delay in Bay’s ascension. “I think Mr. Bay would be an outstanding chair,” he said.

The committee’s vote sends the Bay and LaFleur nominations to the full Senate, where Bay has the backing of Senate Majority Leader Harry Reid (D-Nev.). In an interview with The Wall Street Journal June 8, Reid said bluntly, “I don’t want [LaFleur] as chair.”

Reid told the Journal he was concerned LaFleur would not adequately enforce market manipulation rules or support building transmission for renewable energy. Reid also said he feared LaFleur would undo initiatives of former chair Jon Wellinghoff, a Nevadan allied with Reid who retired last year.

“This is not the outcome Sen. Reid would have preferred but he accepts the compromise negotiated by Sen. Landrieu and he will move forward with confirming the nominees,” a Reid spokeswoman told The National Journal after the vote.

Enforcement Criticism

The criticism over Bay’s management of FERC’s Office of Enforcement was sparked by members of the energy bar, led by former FERC general counsel William Scherman. In a 49-page article in the Energy Law Journal, Scherman accused Bay of driving Wall Street banks out of energy trading with heavy-handed enforcement tactics. Several senators continued to probe the issue in post-hearing questions to Bay and LaFleur.

In her answers, LaFleur acknowledged differing with Bay and her fellow commissioners on procedural matters regarding seven investigations, including four in which the subjects were represented by Scherman. While LaFleur characterized the disagreements as “procedural” and not substantive, the disclosures did lend some credibility to Scherman’s critique.

June 16, 2014

PSEG Wins $300M Artificial Island Project

PJM planners today recommended Public Service Electric and Gas be awarded the contract to fix the Artificial Island stability problem with a new 500-kV line from Hope Creek, N.J. to Red Lion, Del. at a cost of about $300 million.

The planners recommended PSE&G construct the 18-mile line and upgrades to its Hope Creek 500-kV station. Pepco Holdings Inc. will upgrade its Red Lion 500-kV station at the other end of the line under the recommendation.

The stability fix for Artificial Island — home of the Salem and Hope Creek nuclear plants — is PJM’s first competitive transmission project under the Federal Energy Regulatory Commission’s Order 1000.

The competition attracted 26 proposals from five utilities and three independent developers, led by PSE&G with 14 alternatives. In May, planners identified a shortlist of 10 proposals, including the 500-kV proposal by PSE&G and a similar project by Dominion Virginia Power.

The two projects — which had been in the middle of the pack in cost and did poorly in their original forms in an analysis of risk factors and technical concerns — had their standings improve dramatically when PJM reevaluated them after eliminating a second tie line between the two nuclear plants.

The revised Dominion and PSE&G proposals got top scores in the analysis and also saw their costs reduced by $34 million and $43 million, respectively. PJM estimated either project would cost between $211 million and $256 million, the same range it assigned to a 230-kV proposal by LS Power that had been the cheapest proposal prior to the change. (See Dominion, PSE&G Proposals Gain in Artificial Island Race.)

The estimates do not include an additional $80 million for a static VAR compensator (SVC), which PJM added to all of the proposals. In total, the winning project is expected to cost $291 million to $337 million.

Paul McGlynn, general manager of system planning, said that planners chose the 500-kV proposal because it provided greater transmission capacity than the 230-kV alternatives and would use an existing Delaware River crossing rather than a new southern crossing employed by the 230-kV proposals. PJM said the river crossing “represents the greatest component of schedule risk” for all proposals.

McGlynn said planners chose PSE&G over Dominion because PSE&G is a party to the Lower Delaware Valley (LDV) Transmission Service Agreement, which controls an existing 500-kV right of way in New Jersey that the new line will largely parallel. Although PSE&G will need expand the right of way for 8.5 miles, Dominion would have needed to acquire the right of way for the entire route, PJM said.

The planners will recommend the Board of Managers include the project in the Regional Transmission Expansion Plan at the board’s July 22 meeting. McGlynn said PJM will accept comments on the recommendation through July 16.

The winning project is a modification of PSE&G’s proposal (#7K), which was originally proposed at a cost of $1.066 billion. PJM planners reduced the cost by eliminating a 500-kV line between New Freedom and Deans, making changes to breaker configurations and eliminating the second tie line between the two nuclear plants. Eliminating the second tie line also eliminated the need for the 500-kV line to cross another 500-kV line, which would have created a risk of a multiple facility trip.

The SVC will be added at PSE&G’s New Freedom switching station. PJM added the SVC despite opposition from PSEG Nuclear LLC, the operator of the nuclear plants, which said SVCs have never been used to correct “transient angular stability.” PSEG Nuclear said the SVC would pose “unknown and potentially challenging regulatory risks,” including an “in-depth review” by the Nuclear Regulatory Commission.” (See Contestants Make Last Pitch for Artificial Island Prize.)

PJM acknowledged that the selected route faces land-permitting challenges because it will cross the Supawna Meadows National Wildlife Refuge, the Alloway Creek Watershed Wetland Restoration Site and the Abbotts Meadow and Mad Horse Creek Wildlife Management Areas. The New Jersey Board of Public Utilities said PJM’s analysis of the 500-kV option underestimated likely public opposition.

Sharon Segner, vice president at LS Power, said afterward that she was “profoundly disappointed” by PJM’s decision and predicted PSEG will be unable to win approvals to build the line across the New Jersey wetlands and wildlife areas.

McGlynn said the project’s cost allocation will be “very similar” to the allocation outlined in May, which spread the cost among two dozen transmission zones and merchants. The Jersey Central Power & Light zone would be responsible for about 27% of the project, with the Atlantic City Electric zone picking up almost 20%. No other zone was as high as 8%.

FERC Order 1000 eliminated incumbent utilities’ federal right of first refusal (ROFR) on new transmission projects, opening the business to competition from independent transmission developers.

Others submitting proposals in addition to PSE&G, Dominion and LS Power were Transource Energy, a partnership between American Electric Power and Great Plains Energy (owner of Kansas City Power & Light Co.); FirstEnergy Corp.; Atlantic Wind Connection; and a partnership between Pepco Holdings Inc. and Exelon Corp.

June 10, 2014

Planning Assumptions Debunked by Winter Outage Study

PJM will likely change its planning assumptions based on an analysis that found a strong correlation between wind chill indices and generator outages.

“Planning studies currently assume that forced outages are random and occur at a constant rate throughout the four seasons,” PJM’s Tom Falin told the Planning Committee last week. However, the analysis of generation outages from winters 2007/08 through 2012/13 found that the lower the wind chill, the more gas-fired capacity is lost to forced outages, including gas curtailments.

“We used to [consider] all unit forced outage rates as independent of each other, but we saw in January that they clearly are not. If you can’t get gas for one unit, you can’t get it for all units,” Falin said.

The analysis identified 9,244 MW of “chronically curtailed” gas plants — those that were curtailed an average of at least 12 hours per year. Jerry Bell of PJM explained that 2013/14 data was left out of the study because “we didn’t want to poison [the data] with the most recent winter.”

Under a worst-case scenario, which assumes the loss of all existing gas plants that were curtailed at least once over the last six winters and all “at-risk” future units (those likely to be “chronically curtailed” based on their pipeline supply), PJM could be forced to operate without 42,700 MW of gas capacity.

The analysis showed variability across zones. The ComEd zone, for example, had more than 2,600 MW of “chronically curtailed” gas generation while the JCPL zone had just 41 MW.

PJM officials said they will likely change their planning assumptions to recognize the increased risk of gas outages during extreme cold. The analysis may also result in new rules regarding the firmness of winter fuel supplies and calculation of winter Capacity Emergency Transfer Objectives and Capacity Emergency Transfer Limits.

“Clearly, the range of potential solutions is different for next winter than it is for 2019/20,” Vice President of Planning Steve Herling said. “Everything is on the table right now.”

Carl Johnson, of the PJM Public Power Coalition, said it may be necessary to develop both RTO-wide and zonal solutions. “In addition to studying why units were out, we should study why units weren’t out,” he said.