The Federal Energy Regulatory Commission last week rejected a request to hold a technical conference to review the impact of the commission’s November 2013 order allowing the sharing of non-public operational information between interstate gas pipelines and electric transmission providers.
The commission said (RM13-17-001) that while it invites feedback on the effectiveness of the new communications standards in Order 787, there was no need for a technical conference requested by the Natural Gas Supply Association (NGSA).
FERC also rejected a request by Enable Gas Transmission LLC and Enable Mississippi River Transmission LLC to revise Order 787’s no-conduit rule, which prohibits recipients of non-public operational information from disclosing the information to a third party.
Order 787 allows interstate pipelines such as Enable to seek a waiver of the no-conduit rule if the fact that they share operational employees with local distribution companies (LDCs) or other affiliates makes compliance difficult.
Enable said that under the pre-Order 787 rules, employees its interstate pipelines share with their intrastate and gathering affiliates were already being exposed to sensitive non-public, operational information as part of their regular activities without ill-effect. Enable asked the commission to revise the rule to allow disclosures to third parties, other than marketing function employees, for reliability and planning.
But the commission ruled that “rather than attempting to craft a generic regulation, the best course would be to proceed on an individual case-by-case basis through waivers.” The commission noted that it had received only three waiver requests to date and had granted all of them (the Enable pipelines, National Fuel Gas Supply Corp. and Empire Pipeline Inc.).
“As demonstrated by these orders, we find that the waiver process is a reasonable means … to address compliance issues involving shared employees,” the commission said.
Enable’s waiver order (RP14-453) allows employees shared by Enable pipelines and their affiliated intrastate and gathering systems to receive non-public operational information as long as they don’t take part in marketing functions or share it with workers in those functions.
The California ISO won approval last week to expand its real-time energy imbalance market (EIM) beyond state borders, with PacifiCorp and NV Energy slated to become the first to join.
With the Federal Energy Regulatory Commission’s approval of CAISO’s proposal (ER14-1386) and related PacifiCorp Tariff changes (ER14-1578), the expanded market is set to begin Oct. 1. NV Energy, which sits between PacifiCorp’s two main service regions, plans to join the market by October 2015 under an implementation agreement approved by FERC earlier this month (ER14-1729).
PacifiCorp and NV Energy say they expect economic efficiencies, improved renewable integration and increased reliability from their collaboration with CAISO. With the expansion, the EIM would serve most of Nevada, Utah and Wyoming, along with California and portions of Washington, Oregon and Idaho.
That has some in the West asking the question: Will CAISO’s expanded footprint grow into something more than a simple imbalance market?
Not an ‘RTO West’
FERC Commissioner John Norris said last week the market could bring “a lot of efficiencies” to the 38 independently operated balancing authorities in the western interconnection. But he hastened to add, “This isn’t an effort to push those balancing areas into an ‘RTO West.’”
Indeed, CAISO will not assume operational control over the generation or transmission facilities of PacifiCorp. The utility will also remain responsible for maintaining its reliability, including meeting operating reserve and capacity requirements; scheduling; curtailing transmission; and manually dispatching resources out-of-market to maintain reliability. The company is not planning to join CAISO as a member or to participate in its ancillary service and day-ahead energy markets. There will be no exit fee for EIM participants that leave the market.
But the American Public Power Association is worried nonetheless that CAISO’s market may “morph into a regional transmission organization.”
APPA says RTOs have not lived up to their promises of reducing costs. Instead, the group says, they have created higher profits for merchant generators and high administrative and operational costs for consumers.
‘Scope Creep’
“Scope creep” is the concern of public power members, said Elise Caplan, manager of APPA’s Electric Market Reform Initiative, in an interview yesterday. While the imbalance market itself is not problematic, Caplan said the concern is that the scope would grow to include financial transmission rights and mandatory capacity markets, “which have given our members a lot of headaches.
“Our concern is you start with an EIM and that’s where you get to,” she said.
FERC’s actions, such as the April 2011 orders that took away the self-supply exemption, “makes a lot of our members nervous that they will lose their jurisdiction over what that market looks like,” she added.
NWPP Initiative
Caplan said no APPA members are considering joining the CAISO market, although some are participating in discussions to create an EIM with the Northwest Power Pool (NWPP). “They’re looking at doing their own thing,” including ways to “wall it off” from FERC jurisdiction, Caplan said.
NWPP issued a study last year finding the benefits of an EIM outweighing costs and that no Northwest entity, including the Bonneville Power Administration, would be a net loser. The power pool is currently researching the cost of implementing security constrained economic dispatch (SCED).
Among those in discussions with NWPP is the Western Area Power Administration (WAPA), which serves 15 states in the central and western U.S. with power from 56 hydropower plants operated by federal agencies.
WAPA decided not to join the CAISO market following a study by the Argonne National Laboratory, which concluded it was not well suited for the EIM, in part because federal resources are contractually committed to customers and because water delivery obligations and environmental operating limits reduce WAPA’s ability to respond to market price signals. The study also predicted high startup costs.
“At this time it doesn’t make economic sense to join that market,” WAPA spokesman Randy Wilkerson said.
WAPA-SPP
However, WAPA’s Upper Great Plains region, which sells power in Iowa, Minnesota, Montana, Nebraska and the Dakotas, is planning to join the Southwest Power Pool. SPP’s board last week approved Tariff revisions to accommodate WAPA’s entry, which is projected to be complete in October 2015.
Heartland Consumers Power District and Basin Electric Power Cooperative also are joining SPP.
WAPA’s facilities in the Eastern Interconnection will be fully integrated with SPP, which launched its Integrated Market March 1. The Integrated Market added a day-ahead market and transmission congestion rights to SPP’s real-time imbalance function. Facilities in the Western Interconnection “wouldn’t be fully integrated, at least at the start,” Wilkerson said.
The Argonne study found that while the CAISO EIM was not a good fit for WAPA, it could benefit entities inside WAPA’s balancing areas (BAs) that have flexible resources or excess capacity for bidding into the market, including those with variable energy resources and those that frequently run high-cost peaking resources. Thus, the study said, there was a risk of a “reshuffling of entities within BAs” regardless of whether WAPA joins or not.
Scope
California’s EIM will allow participants to buy and sell energy in five-minute increments. Supporters say the market will improve congestion management and situational awareness as well as reduce the costs of balancing the increasing volume of variable resources in the West. The Western Electricity Coordinating Council estimates renewable energy will more than double from 2010 levels by 2022.
PacifiCorp and CAISO conducted a study that projects annual consumer benefits of $21 million to $129 million from the EIM. Start-up costs for PacifiCorp will be $2.1 million.
PacifiCorp serves about 1.8 million customers in two BAs: PacifiCorp East (Idaho, Utah and Wyoming) and PacifiCorp West (Washington, Oregon and California). NV Energy, the product of the 1999 merger of Nevada Power Co. and Sierra Pacific Power Co., provides electricity and natural gas to 1.3 million customers in Nevada. NV Energy was acquired by PacifiCorp’s parent, Berkshire Hathaway Energy, last year.
Market Explained
FERC’s unanimous orders last week modified some aspects of CAISO’s and PacifiCorp’s proposals. The commission rejected CAISO’s proposal that its Board of Governors would decide whether to implement market power mitigation at the interties, saying any such mitigation would be subject to commission approval. The commission also ordered CAISO to make informational filings on the presence of structural market power in PacifiCorp BAs due to intertie transmission limits.
The order also requires the ISO to create a mechanism for EIM resources to avoid being dispatched into California, where they would be liable for the state’s greenhouse gas regulation costs.
PacifiCorp’s transmission customers will have the option of bidding into the EIM or continuing to serve their loads through self-supply or bilateral trades.
Transmission and generator interconnection customers who do not participate in the EIM will be billed based on the locational marginal prices resulting from the EIM to settle imbalances.
PacifiCorp will use firm transmission rights voluntarily offered by transmission customers to enable EIM transfers between its BAs and CAISO.
The commission rejected PacifiCorp’s proposal to require generating resources in the company’s BAs to purchase additional transmission service from PacifiCorp in order to participate in the EIM, saying this would result in a double-charge to loads and conflict with CAISO’s proposal to use reciprocal transmission rates.
Pepco Atlantic City District Energy System (Source: Pepco)
Pepco’s Midtown Thermal Control Center, which provides heating, cooling and electricity to some of Atlantic City’s biggest casino-hotels, was awarded the International District Energy Association’s Annual Innovation Award. The 16,200-ton multiple-chiller district cooling plant cuts energy consumption while providing essential climate control services to casino-hotels such as the Trump Plaza, Caesar’s Palace and the Atlantic City Convention Hall.
The $106 million facility produces 54,000 tons of cooling, 700,000 pounds per hour of heating and 5.7 MW of generation. It has a central generating station and several satellite generators; five miles of steam, chilled water and condensate piping; and a fiber-optic control system. The center has shown energy savings of 30% for its clients since going into operation in October.
Exelon, Pepco Continue Regulatory Approval Process
Exelon and Pepco Holdings Inc. filed applications with regulatory agencies in Delaware, New Jersey and the District of Columbia, continuing the approval process for Exelon’s purchase of the D.C.-based utility. “The filings we are making today describe in detail how our proposed merger will serve the public interest,” Chris Crane, Exelon president and CEO, said last week.
Crane said Exelon’s emergency-response experience will improve service for Pepco customers, who have long complained about their utility company’s long restoration times and regular rate hikes. Crane promised Exelon will set, and meet, tougher reliability targets by 2020 if the deal is approved. Exelon announced its proposed purchase of Pepco for $6.8 billion in May. The company has already filed an application with the Virginia State Corporation Commission and plans to file with the Maryland Public Service Commission in August.
Huntoon Hangs Shingle as Regulatory Law Specialist
Steve Huntoon
Steve Huntoon, who spent the past three decades practicing energy regulatory law with companies such as PECO, Florida Power & Light Co., Dynegy and Conectiv, has opened his own law firm in the District of Columbia. Energy Counsel LLP will specialize in energy regulatory issues, especially those before the Federal Energy Regulatory Commission. Huntoon is the former president of the Energy Bar Association. Most recently he was senior attorney at Florida Power & Light Co.
A bill mandating the closure of all 33 of Duke Energy’s ash ponds cleared three North Carolina committees last week and could come to a vote on the Senate floor this week. The bill calls for full coal ash removal at four power plants near waterways: Riverbend, near Charlotte; Dan River, scene of the massive coal ash spill in February; Asheville; and Sutton in Wilmington.The remainder of Duke’s coal ash ponds would be closed after a prioritization review by a new, nine-member Coal Ash Management Commission. The bill requires Duke to pay all cleanup costs and levies a new regulatory fee that would go toward hiring 25 more employees for the state Department of Energy and Natural Resources.North Carolina officials also warned Duke Energy last week to fix what it said were “numerous gushers, drips and stains” at a coal ash dam at its Weatherspoon plant in Lumberton. State Attorney General Roy Cooper said last week that lawmakers should ensure that the costs for cleaning up coal ash ponds are borne by Duke, not the public.
NextEra Energy Inc.’s wholly owned subsidiary, NextEra Energy Partners LP, announced terms of its initial public offering. The company, which will operate 10 wind and solar energy projects, wants to raise $325 million by offering 16.3 million shares of stock at a price of $19 to $21.
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)
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.)
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)
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.”
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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 75th 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 75th 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.”
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.
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 Woodbridge Construction (Source: Competitive Power Ventures)
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.
