NRG Doubles Down

By Ted Caddell

Does NRG Energy know something the rest of the electric industry doesn’t? Some on Wall Street seem to think so.

After a week in which it scooped up more than a half-million retail energy customers from Dominion Resources and won approval for its acquisition of bankrupt Edison Mission Energy, NRG shares hit a 52-week high Friday.

Already the nation’s largest independent power producer, NRG will vault past Southern Co. to become the second-largest generator overall with the addition of Edison Mission’s 8,000 MW.

The Edison Mission purchase will add 5,062 MW to NRG’s 13,445 MW generating portfolio in PJM, giving it about 10% of PJM’s installed capacity, ranking it third behind Exelon Corp. and PPL. It also added 2,421 MW in the California ISO, with smaller amounts in MISO, ERCOT and non-RTO regions.

The purchase of Dominion Resources’ retail electric business, announced March 11, will bring it more than 600,000 customers in Illinois, Maryland, New Jersey, Ohio, Connecticut, New York, Massachusetts and Texas. NRG already has 2 million retail electric customers throughout the country served by its retail providers Reliant, Green Mountain Energy, Energy Plus and NRG Residential Solutions.

NRG expects to close on the acquisition by the end of this month. Neither company has disclosed the value of the deal.

NRG’s acquisitiveness is a stark contrast to the strategies of other large generators such as Dominion, Duke Energy and First Energy, which have announced a shift away from competitive retail markets in favor of regulated operations.

NRG, which has been built from a series of acquisitions and owns no legacy utilities, doesn’t have the option of falling back on a rate base.

Still, at a time when other generators are talking about selling or shuttering assets because of low capacity and energy prices, NRG’s decision to double down is a notable counterargument.

Turning Point?

Are we seeing a turning point in the fortunes of competitive generators?

Yes, say analysts at Credit Suisse, who last Friday raised their rating on Exelon to “outperform” and boosted their price target to $35 from $23. “We believe expectations and fundamentals for competitive power have found a bottom, with the potential for a long awaited recovery to take form over the next 12 months,” the company said.

Exelon shares closed yesterday at $32.93, up $1.57 (5%) over Thursday’s close. (NRG shares closed yesterday at $30.36, pulling back slightly from the 52-week high of $30.93.)

Exelon, which owns the largest generation fleet in PJM, could see its market share shrink if it follows through with threats to close one or more nuclear plants. (See Exelon in Lobbying Push to Save Ill. Nukes.)

PJM energy prices rose 10% last year as natural gas prices jumped 40%. (See State of the Market: PJM Passes, with Provisos) PJM’s efforts to limit the volume of imports and demand response that clears in the capacity market could also boost generators’ fortunes.

But most analysts are still labeling Exelon a sell or hold. So NRG’s bullishness carries with it risks.

The Street.com, which rates NRG a “hold,” said the company’s strong revenue growth and cash flow is offset by weak profit margins and decreases in net income and return on equity.

Goldman Sachs upgraded NRG to “buy” from “neutral” on Thursday, saying the company’s cash flow gives it the flexibility to buy back stock and debt, as well as make additional acquisitions.

NRG History

NRG is well aware of the risks. Born as an unregulated subsidiary of Minneapolis-based Xcel Energy, it fell into bankruptcy in May 2003 after several years of aggressive growth as a result of falling power prices and a decrease in energy trading following the implosion of Enron.

It emerged from Chapter 11 in December 2003, headed by a new CEO David Crane, who remains in charge today.

In late 2005, NRG purchased Texas Genco, the former generation arm of Reliant Energy, from a group of private equity firms. In 2009, it rebuffed a takeover bid by Exelon shortly after acquiring Reliant’s retail operations.

It added renewable power retailer Green Mountain Energy to its portfolio in 2010.

In 2012, it added GenOn Energy, the offspring of Reliant spinoff RRI Energy and Atlanta-based Mirant Corp., and one of the largest independent power producers in the U.S.

Last August it expanded into demand response with the purchase of Energy Curtailment Specialists.

Retail-Generation Synergies

Julien Dumoulin-Smith, a utility analyst at UBS Securities LLC, said the Dominion purchase makes sense for NRG as a way to find a market for its generation.

“When you are thinking about the retail markets, the reality is, if you are a large player, you want to be backstopped by a large generation portfolio,” he said. In terms of retail energy, NRG “has wanted to expand from its core base in Texas to the Northeast for a while. This achieves that.”

NRG spokeswoman Melissa Hensley suggested that the acquisition was part of a long-term play by the company, which hopes to see more markets open to retail competition.

“This acquisition supports NRG’s strategy of growing its retail footprint,” she said in an interview Friday. “Additionally, NRG strongly believes in competitive markets. We want to ensure customers continue to be served through these markets, and we want to be an example for other markets that hope to open up to competition.”

Although Hensley wouldn’t say how many of those 600,000 new customers are in the PJM territory, she said about 80%, or 480,000, are in the Northeast, with the rest in Texas.

In contrast, Dominion has shifted its strategy to focus on regulated earnings. Since 2006, it has been selling off commodity-based operations, such as oil and gas exploration, and production and merchant generation, to concentrate on regulated businesses.

In January it announced its intent to exit the unregulated retail energy business, which had stalled in the last two years, with its customer count falling to 2.1 million, a 2% drop, since 2010.

It highlighted the challenges of the business in its 10-K filing for 2013, noting that it was competing against incumbent utilities with “the advantage of longstanding relationships with their customers and greater name recognition.”

Dominion will retain its nearly 2.4 million customers served by its regulated utility, Dominion Virginia Power.

Renewables

A bankruptcy judge in Chicago approved the sale of the Edison Mission assets to NRG for $2.6 billion. Edison Mission and subsidiary Midwest Generation filed for bankruptcy protection in December 2012, blaming low power prices, high fuel costs and expensive mandated coal plant retrofits. The deal is expected to close April 1.

The acquisition included 1,700 MW of wind, giving NRG more than 2,900 MW of wind and solar in operation or under construction.

That is one of the important points behind NRG’s acquisition, according to Dumoulin-Smith. “This plays into their desire to consolidate into the renewable sector,” he said. “This is something they really wanted to do.”

The Edison Mission generation assets are spread throughout the U.S., in California, Nebraska, Pennsylvania, Texas, Iowa, New Mexico, Minnesota, Illinois, Wyoming, West Virginia, Oklahoma, Utah and Iowa.

PJM Impact

With the EME acquisition, NRG will have about 18,500 MW of generation in PJM, leapfrogging AEP, Dominion and FirstEnergy in the RTO rankings.

The Edison Mission acquisition will boost NRG’s “economic capacity” market share in PJM from 6.8% to 9.4% during the high demand periods in the summer, according to an analysis the company filed with FERC in seeking approval for the purchase.

In CAISO, its post-merger share will grow to 8.3% from 7.3% during the peak winter periods, according to the analysis.

In MISO — the only other FERC-jurisdictional market in which NRG and EME had overlapping assets — NRG’s market share will increase to about 3.1% of total capacity, from 2.9%.

Market Monitor Seeks Mitigation

PJM’s Market Monitor expressed concern that NRG generation near a transmission constraint on the MISO-PJM seam — the Lanesville 345/138 kV transformer — could exert market power. The Monitor also cited a potential increase in market power in the PJM regulation market.

The Monitor asked the commission to require NRG to make cost-based offers in the regulation market and to continue to offer the same units and quantities historically offered into the regulation and Lanesville energy market.

The commission rejected the Monitor’s request for mitigation, saying that transmission upgrades have eliminated Lanesville as a constraint.

Because the Monitor’s analysis found market power screen failures in the regulation market for only 189 hours of the year (2%), “and many of these hours are non-contiguous and are spread over many time periods, we find there are no competitive concerns,” the commission said.

March 25, 2014

FERC: Six Months to Move Gas, Electric Schedules

By Ted Caddell

The Federal Energy Regulatory Commission set a six-month deadline for the natural gas and electric industries to better align their daily schedules, adding urgency to changes already proposed by RTO and pipeline representatives.

In a Notice of Proposed Rulemaking (NOPR), FERC said Thursday it wants to start the natural gas operating day earlier, move the Timely Nomination Cycle later and give natural gas shippers more times per day to react to rapid demand changes.

The FERC proposal (RM14-2) largely parallels a “strawman” proposal by the Natural Gas Council, except for the commission’s call to move the start of the gas day to 4 a.m. Central Time (CT) from the current 9 a.m. CT start. The Council, a group of natural gas suppliers and pipeline operators, rejected an earlier start time, saying it would cause safety and contractual problems.

FERC also issued two other orders aimed at addressing natural gas shortfalls in times of high demand.

“This past winter has highlighted the critical and growing interdependence of natural gas pipelines and electricity markets,” Acting Chairman Cheryl LaFleur said. “Today’s orders take steps to recognize and address that interdependence to optimize the use of our gas and electric networks for the benefit of all customers.”

In February, RTO Insider reported that the Natural Gas Council had tentatively agreed after meetings with officials of PJM and other RTOs to move their nominating schedules to later in the day. PJM officials said they would seek to move the RTO’s day-ahead schedule forward. (See Pipelines, PJM to Align Daily Schedules.)

The strawman proposal would:

Extend the Timely Nomination deadline to 1 p.m. CT (from the current 11:30 a.m.);
Provide two intraday cycles during the business day with firm bumping rights; and
Add a third, evening intraday cycle for early morning gas flow with no bumping rights.

Conflict over Gas Day Start

Current Gas Schedule vs. Natural Gas Council 'Strawman' (Source: Natural Gas Council) — Current Gas Schedule vs. Natural Gas Council ‘Strawman’ (Source: Natural Gas Council)

Unlike FERC’s proposal, however, the strawman proposal by the Gas Council would retain the 9:00 a.m. CT start of the gas day.

The council said it “thoroughly considered” changes to the start of the gas day, looking at three earlier starts (12 midnight, 3 a.m., 6 a.m. CT) and one later (12 noon CT).

It said nighttime starts “raise significant safety concerns” and could make shipper imbalances more difficult to manage. It also noted that some existing contracts are based on the start of the gas day and that different start times would “have vastly different impacts by region.”

As a result, the Council said its consensus was that the gas day must remain unchanged.

FERC’s NOPR would begin the gas day at 4 a.m. CT, the beginning of the morning electric ramp in the East, and before the morning electric ramp in other regions of the country. The change would ensure that generators in all regions would enter the morning electric peak with new daily gas nominations.

“This should largely eliminate the concern that some gas-fired generators will be unable to run during a substantial part of the morning ramp period, because they have burned through their nominated gas before the start of the next gas day,” the commission said. “… As a consequence, gas-fired generators should be less likely either to incur imbalances on pipelines or inform electric transmission operators that they are unavailable.”

Timely Nomination Deadline

The Gas Council said moving the Timely Nomination deadline to 1 p.m. would give generators a greater opportunity to participate in the timely nomination cycle, during which most pipeline capacity is confirmed. It also would increase the value of firm transportation and reduce forecasting errors, the Council said.

This matches the change FERC proposes.

The tradeoff: a 20% to 30% increase in hours for schedulers and traders. In addition, pipelines and LDCs would have less time to confirm and schedule, and producers and customers would have less time to react.

Intraday Changes

The Council said providing two “bumpable” intraday cycles during business hours would help generators manage intraday variations in load and changes in dispatch orders. This, too, would increase staffing costs and create operational challenges on particularly active days.

The proposed third intraday cycle would have a 9 p.m. deadline, with gas flowing at midnight.

This would reduce the gap between the last scheduling opportunity and the end of the gas day to 12 hours, making it easier for generators to arrange for fuel supplies at the beginning of the electric day and avoid derates during the morning ramp.

The Council said that because of limited liquidity in the evening, this cycle may be primarily used to move gas into or out of storage. It, too, would require increased staffing.

To ensure that schedulers and traders can end their day knowing that their gas will flow, the late cycle would not allow bumping.

The Gas Council said it was eager to reach consensus with FERC and electric industry stakeholders, fearing that the alternative would be “contentious and time consuming with substantial uncertainty as to outcome.”

FERC proposed to move from two to four standard intraday nomination cycles, which would occur at 8 a.m., 10:30 a.m., 4 p.m. and 7 p.m., but is predicated upon a 4 a.m. start to the gas day.

180-Day Deadline

The NOPR provides 180 days for the natural gas and electric industries to reach consensus on standards through the North American Energy Standards Board.

FERC issued a separate order investigating RTO and ISO day-ahead scheduling practices. It also issued a rule to show cause, requiring interstate natural gas pipeline operators to revise their tariffs to allow posting offers to purchase released pipeline capacity.

At Thursday’s FERC meeting, Commissioner John R. Norris applauded efforts to improve coordination between the two industries.

“I recognize that finding solutions is particularly challenging for the natural gas industry which faces a greater share of the burden with respect to necessary changes,” Norris said in a statement. “I support today’s order because I believe a more formal process with a specific timeline for action is needed now to bring together all segments of the gas and electric industries to find solutions to gas-electric issues facing our industry.”

Norris said the orders will ensure the existing pipeline infrastructure is optimized “before investing additional funds in new infrastructure.”

But the Gas Council said additional pipeline capacity was also needed, saying the “central issue of how to expand gas infrastructure, particularly in the Northeast, will not be solved by scheduling issues.”

March 25, 2014April 11, 2024

State Briefs

Bill Would Put Wind Farm Authority in State Hands

State Sen. John Sullivan has introduced a bill to transfer responsibility for siting and regulating wind turbines from counties to states. Local governments would be able to conduct public hearings on proposed wind farms, but the state Department of Agriculture would handle all permitting and other processes.

Sullivan wants to eliminate inconsistency in requirements and in county resources to handle the facility proposals.

Counties object to the idea, as does the wind power industry. Wind on the Wires Public Policy Manager Erick Borgia noted that similar legislation has been introduced, unsuccessfully, in the past.

More: National Wind Watch

500 kW Solar Farm is First For a Cooperative in State

Illinois Rural Electric Cooperative christened its four-acre, 500 kW solar facility south of Winchester – the first utility-scale photovoltaic solar energy system for a co-op in the state. The $1.8 million installation was helped by a $416,000 grant from the U.S. Department of Agriculture’s Rural Energy for America Program and a $500,000 grant from the Illinois Department of Commerce and Economic Opportunity’s Renewable Energy Business Development Program.

“We couldn’t have undertaken this project without federal and state assistance,” co-op President Robert Brown said.

More: The Telegraph

Constellation Wins Deal To Supply Suburban Group

Constellation, Exelon’s retail arm, has won a three-year power supply contract for a large suburban Chicago municipal consortium, a group of seven led by the villages of Buffalo Grove and Arlington Heights. The arrangement involves 95,000 households and small businesses.

The deal, to provide power at 6.5 cents/kWh, is expected to beat Commonwealth Edison’s default price, which is to rise in June from the current 6.02 cents to more than 7 cents. ComEd is an Exelon company as well.

Not every community in the consortium has the same rate or arrangements. Arlington Heights rates, for example, will be 6.62 cents/kWh, because its supply is green energy.

More: Line-Man.com; Chicago Tribune

Batavia Executes Rate Hike Attributable to Prairie State

Burdened like a number of other communities by the $5 billion cost of the Prairie State Energy Campus, the Batavia City Council voted to raise its sales tax by 0.5% and its residential electricity rates 6.5% in both 2014 and 2015, with a $4 increase in the monthly customer charge. Different increases will apply to commercial and industrial customers. The council agreed to add a provision that would sunset the sales tax increase in three years.

The troubled coal plant saw its construction costs double, from $2.5 billion to $5 billion, because of design changes and construction overruns.

More: Chicago Tribune

INDIANA

Court Upholds Decision On Edwardsport Rates

The state Court of Appeals affirmed utility regulators’ 2012 decision to raise electricity rates 16% to pay for Duke Energy’s $3.5 billion Edwardsport coal gasification plant. Citizen and environmental groups challenged the Utility Regulatory Commission’s decision, citing huge cost overruns, and questioned the quality of regulatory oversight.

The court acknowledged the plant suffered the cost overruns but said the URC took that into account. The Citizens Action Coalition said it might appeal the ruling.

More: Indianapolis Star

Pence Pressed For, Against Ending Efficiency Program

Honeywell and Ingersoll Rand, companies with energy-efficiency business interests, have joined environmental groups in urging Gov. Mike Pence to veto a bill that would kill the state’s Energizing Indiana program. Pence has until March 27 to decide whether to sign the bill, which would defund the program at the end of the year.

The Indiana Manufacturers Association initiated efforts for the bill, arguing the program costs business too much with little return. The Indiana Energy Association, a utility group, did not instigate the bill but says it supports it.

More: Seattle Post-Intelligencer; Midwest Energy News

Proposal for 5 MW Wind Farm Eyed in Monroe

Solar Zentrum has proposed a 5 MW solar farm on land owned by Monroe County in southern Indiana. County officials have agreed to move the idea forward. The property is near a power transfer station. Duke Energy Indiana recently published a solicitation for 5 MW of solar.

More: The Elkhart Truth; Duke Energy

KENTUCKY

Enviros to Sue LG&E Over Ash Pond Discharges

The Sierra Club and Earthjustice have filed an intent to sue Louisville Gas & Electric for what they say are Clean Water Act and permit violations at the Mill Creek power plant’s coal ash pond.

Evidence from a hidden camera across the Ohio River from the Louisville facility shows a constant gushing of ash wastewater, not an occasional discharge as the permit allows, according to the groups. A Kentucky Energy and Environment Cabinet spokesman said the discharge does comply with the permit.

More: LEO Weekly

House Panel OKs Big Sandy Bill Over Ky. Power Protest

A House committee approved legislation to force the Public Service Commission to reconsider its order allowing Kentucky Power to close the Big Sandy coal plant. Kentucky Power, a unit of American Electric Power, would replace its power by buying a half-interest in the Mitchell plant in West Virginia.

Majority Floor Leader Rocky Adkins supports the measure, as does House Speaker Greg Stumbo. For Adkins and other lawmakers, it is a matter of coal industry jobs, possibly even if keeping Big Sandy open would mean a 30% rate increase to pay for environmental controls. Kentucky Power President Greg Pauley opposed the bill.

More: Daily Independent

MARYLAND

PSC Flooded With Rate Complaints

The Public Service Commission saw a nine-fold increase in complaints about high electric bills in February as the impact of the frigid winter hit customer bills. “We’re averaging about 35 to 40 new complaints a day,” said Obi Linton, who directs the agency’s office of external relations.

Customers with variable-rate contracts got a double whammy. They used more power and discovered just how variable their rates are.

More: The Baltimore Sun

RGGI Elects New Chair And Executive Board

Kelly Speakes-Backman, a member of the Maryland Public Service Commission, is the new chairman of the Regional Greenhouse Gas Initiative, succeeding Kenneth Kimmell of the Massachusetts Department of Environmental Protection. She and newly elected board members will serve through the end of the year.

More: RGGI

MICHIGAN

DTE 818 MW Solar Plant Will Be Company’s Biggest

The 19th solar power project in southeast Michigan, and DTE’s largest solar project so far at 818 kW, is being assembled near I-96 in Lyons Township. The $3.5 million facility should be finished by May, DTE said. Michigan utilities are required to get 10% of supply from renewables by 2015.

More: Detroit Free Press

NEW JERSEY

BPU Rejects Fishermen’s Energy; Bill is Too High

The state Board of Public Utilities killed the only offshore wind project yet to be considered by the agency, a pilot to build a 25 MW wind farm about three miles off Atlantic City.

Last summer, the board rejected a proposed settlement between Fishermen’s Energy Atlantic City and the New Jersey Division of Rate Counsel that would have allowed the project to go forward. The proposal resurfaced during hearings before the agency this winter.

The commissioners questioned the financial viability of the project and agreed with staff that it would be too costly to ratepayers. Clean energy advocates said the decision sends the wrong signal to other offshore developers. New Jersey has a goal of developing 1,100 MW of offshore wind capacity by 2020.

More: NJSpotlight

BPU Approves JCP&L Storm Recovery Cost Settlement

The Board of Public Utilities approved a settlement allowing Jersey Central Power & Light to recover about $736 million from customers to pay for the cost of responding to a series of extreme storms. When those costs — mostly attributable to Superstorm Sandy — will show up on ratepayer bills is still uncertain.

For the utility, the approval of the settlement may cushion the impact of a pending decision in a separate rate case before the agency. Both the BPU staff and the Division of Rate Counsel are seeking to cut the utility’s rates by more than $200 million, a step some say would trim customers’ bills by one-third.

More: NJSpotlight

NORTH CAROLINA

Grand Jury Begins as Duke Ash Pond Issues Proliferate

A federal grand jury was convened to probe the Feb. 2 spill from Duke Energy’s coal ash pond at the Dan River generating station. At least 23 subpoenas were issued in the investigation, which is looking into the state Department of Environment and Natural Resources’ oversight of the ash ponds.

The DENR reopened the much-criticized settlement it reached last year with Duke over ash ponds near Charlotte and Asheville. Environmentalists had been calling the settlement a sweetheart deal.

As Duke outlined its intentions for dealing with ash ponds throughout the state, the DENR said it would put new conditions into a permit for the company’s Asheville plant.

More: America Now; Carolina Public Press; Los Angeles Times

Review Plan for New Lee Plant, Group Urges NCUC

The citizens group NC WARN wants the North Carolina Utilities Commission to review Duke Energy’s plan for a 750 MW combined cycle plant at its existing Lee site near Anderson, S.C., although the commission lacks explicit jurisdiction to do so. The commission could review it as part of Duke’s integrated resource plan or it could open a separate docket, NC WARN said.

The plant will serve North Carolina customers, but there has been no showing it is needed or the minimum $750 million cost is justified, according to the group.

Duke acknowledged that the NCUC has discretionary authority to review the plan, but noted that the commission would review the costs, anyway, in a future rate case. The company said the plant was necessary to ensure supply as it retires old coal facilities.

More: Power Engineering

OHIO

Cincinnati Deal Allows Green, Fossil Choices

Cincinnati residents will be able to choose between green and fossil fuel power under a compromise between the city manager and council members. Since 2012, the city had purchased 100% of its electricity from non-fossil sources under an aggregation program. But this year the city negotiated a new two-year deal with First Energy Solutions that would obtain power from fossil fuel sources, saving residents $5.63 a year.

That brought pushback from several council members. In response, the city manager said that First Energy would let city residents choose whether they wanted green energy or fossil fuel power. Customers also will be able to opt out of the city’s aggregation purchase entirely.

More: Cincinnati Business Courier

Hearing Moves Davis-Besse Along on License Extension

The Nuclear Regulatory Commission will hold a public hearing today at Camp Perry on FirstEnergy’s request for a 20-year operating license extension for the Davis-Besse nuclear plant. The hearing will focus on a draft environmental impact statement the NRC released in February.

The EIS is to be finalized by September. The plant’s current 40-year license is to expire April 22, 2017.

More: The Blade

PENNSYLVANIA

PUC Making It Easier For Customers to Switch

The Pennsylvania Public Utility Commission plans to shorten the time it takes for customers to switch suppliers. The agency has drafted regulations that would require electric distribution companies to complete a customer’s switch in three business days instead of the 11 to 14 days it takes now. The change is in response to nearly 5,000 complaints and 12,000 expressions of concern from customers about this winter’s extreme price increases.

Utilities would be required to implement the changes within six months of the new regulations becoming final. Cost recovery for implementation would be addressed in each utility’s next base rate proceeding.

The PUC also has solicited comments on proposed regulations that will provide customers more detailed electric supplier disclosure statements and more timely information on “contract renewal” and “change in terms” notices.

More: Public Utility Commission; The Morning Call

VIRGINIA

Duke Ash Spill Resonates; Locals Express Confidence

Virginia Gov. Terry McAuliffe said Duke Energy assured him it would repair any damage to the state from the coal ash pond spill into the Dan River in North Carolina, upriver of Danville, Va. Most activity surrounding the spill has to do with North Carolina, but Danville, whose water supply comes from the river, is across the border.

McAuliffe visited Danville, expressing confidence that its water was safe. Local leaders also declared their water safe, commended Duke for its handling of spill repercussions and said they were tallying their costs for dealing with the ash-contaminated river water for submission to the company.

More: The New York Times; Richmond Times-Dispatch

SCC Approves Rate Adjustment for APCo

The State Corporation Commission approved a request by Appalachian Power Co. to recover $48.6 million in increased costs associated with transmission services provided to the utility, slightly less than the $49.9 million APCo had sought in December.

The Transmission Rate Adjustment Clause will become effective in May, raising the average residential customer bill by about $3.88, or 3.5%.

More: State Corporation Commission

Offshore Wind Project Moves to Public Hearing

The federal Bureau of Ocean Energy Management has scheduled an April 3 public hearing as it prepares an environmental assessment for the Virginia Offshore Wind Technology Advancement Project. The project, an effort of the state and Dominion Virginia Power, proposes two 6 MW wind turbines 27 miles offshore from Virginia Beach on platforms designed to withstand hurricane-force winds.

If approved, it would be operational by 2017. The project got $4 million from the U.S. Department of Energy.

More: PilotOnline.com

March 25, 2014

Company Briefs

Exelon has agreed to buy ETC ProLiance Energy, which supplies natural gas to commercial and industrial customers, generators and utilities. The Indianapolis-based ProLiance, which serves customers in eight Midwest states, will become part of Exelon competitive retail unit Constellation. ProLiance is a unit of ETC Marketing of Dallas. The transaction is expected to close in the second quarter.

More: Exelon

Exelon Nuclear Teams Up With AMEC for Projects

London-based engineering and project management company AMEC has teamed up with Exelon Nuclear Partners to explore opportunities in new markets. According to AMEC, the partnership will focus on new and existing reactor marketplaces, providing engineering, consulting, project management and operations support service. “It supports our strategy to grow our nuclear capability and will create a formidable entity to target major projects in new and exciting markets such as the Middle East and mainland Europe,” said Clive White, president of AMEC’s Clean Energy Europe business, citing his company’s synergy with Exelon’s “unrivalled operational experience.” AMEC said the companies also would explore opportunities in renewables, transmission and distribution, and that they have already identified some possible projects.

More: AMEC

Mercuria in $3.5B Deal To Buy JPMorgan Unit

JPMorgan Chase, which for months was looking for a buyer for its physical commodities trading unit, has agreed to sell it to Swiss trading firm Mercuria Energy Group for $3.5 billion. It is unclear whether Blythe Masters, head of Global Commodities at the bank, will be going to Mercuria. Masters came under scrutiny last year when the Federal Energy Regulatory Commission charged the bank with manipulating California’s energy markets. In a document that became public, FERC said Masters had made false and misleading statements under oath. FERC, however, did not pursue action against her and ultimately approved a settlement with the company, with JPMorgan paying $410 million in fines and disgorged profits. (See Analysis – JP Morgan Settlement: A Verdict on Electric Markets?)

More: The New York Times; BloombergBusinessweek

March 25, 2014

ODEC, NCEMC Win Dominion Undergrounding Dispute

FERC upheld an earlier ruling that Old Dominion Electric Cooperative (ODEC) and North Carolina Electric Membership Corporation (NCEMC) shouldn’t have to help pay for $173.4 million in undergrounding for three projects in Virginia that Dominion Resources’ Virginia Electric and Power Co. included in its 2010 Annual Transmission Revenue Requirement.

Incremental ATRR costs are borne by all wholesale transmission users of the grid. ODEC and NCEMC argued in their original complaint that it was not just and reasonable for wholesale transmission customers outside Virginia to bear the cost of undergrounding when it is done for aesthetic concerns and has no impact on reliability.

The three projects were: a 230 kV line to the new Hamilton Substation in Northern Virginia, with two miles of undergrounding ($32.9 million); the DuPont Fabros project, a 0.71 mile double-circuit 230 kV underground transmission line and substation in Loudon County ($9.8 million); and the Garrisonville project, a five-mile, double-circuit 230 kV transmission line in Stafford County, Va. ($131 million).

ODEC and NCEMC said that the projects’ costs were either recoverable from Virginia ratepayers, or hadn’t been proven to be necessary for system reliability, and therefore should not have been included in Dominion’s ATRR.

ODEC serves more than 550,000 customers in Virginia, Maryland and Delaware. NCEMC serves 950,000 households and businesses in North Carolina.

“We find that wholesale transmission customers outside of the Commonwealth of Virginia should not be responsible for costs that are a direct result of legislation and VSCC pilot projects intended to benefit citizens of the Commonwealth of Virginia,” the commission wrote in an order last week (EL10-49).

The commission said a trial would be set to determine the amount of refunds due to ODEC and NCEMC, but it urged the parties to seek a settlement.

March 25, 2014

UPDATE — State of the Market: PJM Passes, with Provisos

By David Jwanier and Ted Caddell

WASHINGTON — The 2013 PJM State of the Market was, to quote that noted economist Yogi Berra, mostly “déjà vu all over again.”

The 2012 report had called for substantial changes to the capacity market, demand response and the treatment of uplift. The 2013 report, which was unveiled by Market Monitor Joe Bowring during a press briefing March 13 in Washington, identifies shortcomings in the same areas.

The results of five of six markets — Energy, Capacity, Synchronized Reserve, Day-Ahead Scheduling Reserve and FTR Auctions — were judged competitive, as in 2012, along with the Regulation Market, which was judged not competitive for most of 2012.

Capacity Market

While the Capacity Market remains competitive, the 444-page report by Monitoring Analytics labeled the aggregate market structure and local market structure as not competitive, as in most prior years since 2007. (See sidebar, PJM 2013 by the Numbers.)

Bowring’s recommended changes for the market were no surprise either. Among them: requiring that all resources be physical; making all demand response a year-round product subject to must-offer rules; and requiring all imports be pseudo tied.

Alternatives to internal generation must be “full substitutes,” not the currently “inferior products” that are suppressing capacity prices, Bowring said.

“If demand response is going to be in the capacity market … it should be available every hour and it should be treated as a real product. It is a real product,” he said. The report calls for classifying all demand response as Economic and eliminating Limited and Extended Summer DR.

Bowring said DR providers can build such generation “substitutes” by aggregating resources into portfolios, a requirement he acknowledged would make DR more expensive.

Generation at Risk

Under current rules, Bowring said, DR and imports are suppressing capacity prices, particularly in western PJM. Add in low natural gas prices, which have caused LMPs to fall, and the result is 87 generators, totaling 14,597 MW of capacity, at risk of retirement. That is in addition to the 24,933 MW currently planning to close.

The 87 generating units — combustion turbines, coal, gas, oil and dual-fuel plants — were unable to cover avoidable costs in 2013 or didn’t clear the 2015/2016 or 2016/2017 base capacity auctions.

Although the report did not assess the viability of PJM’s existing nuclear fleet, Bowring said he was not surprised by reports that Exelon Corp. is threatening to close three of its nuclear generating stations in Illinois. (See Exelon in Lobbying Push to Save Ill. Nukes.)

Bowring said although he lacked data to calculate the current nuclear fleet’s operating costs, no new nuclear plant could be profitable under current prices. “The net revenues are only covering 30% or so of costs,” he said.

At the other end of the spectrum, revenues for solar generation in the PSEG zone were double their fixed costs, due largely to state and federal subsidies.

Uplift

Energy uplift increased by $231 million, or 36%, in 2013. The two main culprits were reactive services, with an increase of $263.5 million, and black starts, which were up $78.2 million. Balancing and day-ahead charges dropped.

The report says PJM should increase its transparency by having operators record the reasons for dispatching out-of-merit generators and identifying the units that are receiving uplift payments.

Ten generating units — less than 1% of all units — received 38% of all uplift in 2013, but PJM confidentiality rules prohibit these units from being identified.

“All uplift payments should be public information. They are [currently] totally non-transparent,” Bowring said. “No one in the market really understands what’s going on.”

Identifying the causes of uplift and the generators receiving payments would allow competition to reduce those costs, he said.

In addition, the report says up-to congestion trades should be required to pay uplift charges like other virtual transactions.

Interchange Ramp

Bowring was adamant in his opposition to a proposal floated by PJM officials earlier this month that would allow operators to reduce interchange ramp limits to reduce price volatility. (See Ramp Limits Cause Stir at MIC.)

“In our view, we see nothing wrong with [price] swings. It’s what happens in markets. [PJM] operators should not be concerned with price volatility,” Bowring said.

Competitive Concerns

Joe Bowring presenting the 2013 State of the Market Report

While the Monitor found all market results were competitive, it expressed concern over the potential for anticompetitive behavior by generators, particularly those owned by holding companies that are also transmission owners.

The report recommends that PJM consider rules to ensure that incumbent generation owners cannot use Capacity Injection Rights (CIRs) to hamper entry by competitors.

Under current rules, companies that retire generation retain CIRs for one year and have the ability to sell them.

The Monitor said stakeholders should decide whether CIRs are considered property rights of generation owners or should revert to the system upon a plant’s retirement. Companies lacking CIRs face higher interconnection costs than those possessing them.

The Monitor also recommended that interconnection studies, currently performed by incumbent transmission owners, be outsourced to an independent party. The current practice “could result in a conflict of interest when transmission owners have generation interests,” the Monitor said.

State of the Market Report 2013 High Priority Recommendations (Source: Monitoring Analytics LLC)

Rich Heidorn Jr. contributed to this article.

March 25, 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 (9:10-9:20)

Manual 14A: Generation and Transmission Interconnection Process — The committee will be asked to endorse revisions to Attachments F and G regarding generator modeling requirements for wind turbines.

3. PJM SETTLEMENT, INC. (9:20-9:35)

The committee will be asked to endorse revisions to PJM’s Tariff and Operating Agreement to clarify agreements and transactions to which PJM Settlement, Inc. is not a party.

4. ESUITE APPLICATION NAME CHANGES (9:35-9:50)

The committee will be asked to endorse Tariff and OA revisions to effectuate the eSuite application name changes (i.e., changing eSchedules and EES to InSchedule and ExSchedule, respectively), as well as updates to the Regional Transmission and Energy Scheduling Practices for the deployment of ExSchedule. These changes are being requested in part due to the new Coordinated Transaction Scheduling (CTS) between PJM and NYISO. (See NYISO Scheduling Product Wins FERC OK.)

5. CONE REVIEW TIMING (9:50-10:05)

The committee will be asked to endorse Tariff and OA revisions related to the timing of the CONE (Cost of New Entry) periodic review. This would move the dates for the various stages of the triennial review up by two months. The Members Committee will also be asked to endorse these revisions (agenda item #5).

Members Committee

3. COORDINATED TRANSACTION SCHEDULES (CTS)/EXPORT CREDIT REQUIREMENTS (1:25-1:40)

The committee will be asked to endorse proposed Tariff revisions associated with Coordinated Transaction Schedules and export transactions. Among other things, the revisions clarify that transactions established directly by and between PJM and a neighboring balancing authority for the purpose of maintaining reliability are not subject to export transaction screening. (See NYISO Scheduling Product Wins FERC OK.)

4. SEASONAL VERIFICATION TESTING TRANSITION (1:40-2:00)

The committee will be asked to endorse proposed Tariff revisions to add a near-term transition mechanism to address changes to Manual 21: Rules and Procedures for Determination of Generating Capability. This transition mechanism allows certain generation owners to provide revised summer capability test results for the last three summers by April 1, in exchange for forgiveness of potential ICAP shortfalls for the 2014/15 delivery year. (See Transition Period OKd for Seasonal Verification Rules.)

March 25, 2014

Federal Briefs

Environmentalists’ efforts to dampen the Obama administration’s support for natural gas are not meeting a warm reception. White House adviser John Podesta, former president of the liberal and environmentalist think tank Center for American Progress, told reporters that opposing all fossil fuels “is a completely impractical way of moving toward a clean-energy future.”

His remarks came a day after the Sierra Club and others urged President Obama to reject calls to speed up permits to export liquefied natural gas, because gas production and export works against the administration’s climate change plan — an agenda Podesta said he spends about half his time working on.

“I think we remain committed to developing the resource and using” natural gas, he said, “and we think there’s an advantage, particularly in the electricity generation sector, to move it forward.”

More: Politico

White House Launches Climate Data Initiative

The White House launched an effort to leverage the government’s data resources to stimulate innovation and private-sector entrepreneurship to support climate-change preparedness.

The Climate Data Initiative will include launch of a website to make federal data more accessible and useful. It will focus initially on coastal flooding and sea level rise, and already includes more than 100 high-quality datasets and tools to be used to help communities prepare for the future. The site will be expanded to include other information, including energy infrastructure data. The National Aeronautics and Space Administration and the National Oceanic and Atmospheric Administration launched an “innovation challenge” to encourage deployment of visualizations and simulations to help the understanding of, and solutions to, coastal vulnerability.

In addition, the White House identified numerous private-sector initiatives being undertaken to create resources and events aimed at enabling responses to climate change impacts.

More: White House

Court OKs Particulate Rules

A federal appeals court upheld the Environmental Protection Agency’s 2009 and 2012 particulate matter new source performance standards (NSPS) for fossil fuel-fired boilers, rejecting most of industry’s challenges. It affirmed the EPA’s requirement for periodic visual opacity inspections for power plants that do not use continuous monitoring systems and the agency’s decision not to approve state law-based defenses to civil penalties for violations. Only unavoidable malfunctions will constitute a defense to alleged violations.

The court deferred ruling on all challenges to the regulation because some are still pending in reconsideration requests at EPA. These include requirements for testing condensable particulate matter and provisions for frequency of testing.

More: Dorsey & Whitney

GridEx Gave Participants Useful Value, NERC Says

Nearly all of the participants in November’s GridEx II reliability preparedness exercise found it useful for identifying opportunities to improve their readiness, which they deemed insufficient, the North American Electric Reliability Corp. said in a report. NERC’s two-day readiness exercise included 2,000 companies and organizations faced with challenges to both physical security and cybersecurity. A third exercise is planned for next year.

Among things NERC recommended to improve preparedness is a review of the Defense Production Act and other laws to determine if there is a need for legislation that would facilitate recovery following a severe event. The report also said some industry regulations “would constrain the operation of certain generators, and specific relief provisions should be considered before a severe event.”

NERC also recommended continued enhancement of information sharing; expansion of the Electricity Sector Information Sharing Analysis Center conference call capabilities; clarification of ES-ISAC subject matter experts’ functions; and clarification of reporting roles. It also recommended evaluating an expansion of recovery programs such as the Spare Transformer Equipment Program.

More: Homeland Security News Wire

House Committee to Grill Fish & Wildlife on Birds

The House Natural Resources Committee plans to question the chief of the U.S. Fish and Wildlife Service March 26 about what some members contend is selective enforcement of bird protection laws that shows wind farms more lenience than on other kinds of facilities. The committee earlier subpoenaed numerous internal agency documents on the subject.

Only one wind power company, Duke Energy, has been prosecuted for killing eagles and other birds. Duke pleaded guilty in December and will pay a $1 million penalty for bird deaths at two Wyoming wind farms.

More: Fox News; Natural Resources Committee

House Panel Targets EPA’s Choice of CCS Technology

The House Energy and Commerce Committee launched an investigation into the Environmental Protection Agency’s rule limiting carbon emissions from new coal-fired plants. The committee’s Republican leadership, longtime opponents of the agency’s drive against coal plant emissions, demanded documents and names involved in EPA’s decision to set standards that require use of carbon capture and storage (CCS) technology.

Provisions of the Energy Policy Act of 2005 bar the agency from setting standards based on technology used in government-funded projects, the committee members say. Coal defenders say CCS technology has not been proven in real-world use. The EPA says its rule does not violate EPAct because the technology is proved elsewhere and its standards are achievable.

More: Energybiz; National Journal

FERC Licenses Pilot Tidal Project in Puget Sound

The Federal Energy Regulatory Commission issued a 10-year pilot license to Public Utility District No. 1 of Snohomish County, Washington, for the proposed 600 kW Admiralty Inlet Pilot Tidal Project to be located in the Puget Sound. In issuing the license, FERC determined the project would not adversely affect an undersea Trans-Pacific fiber optic communication cable nearby.

FERC’s action authorizes the PUD to evaluate the environmental, economic and cultural effects of hydrokinetic energy. The pilot license contains measures to protect fish, wildlife and other features and infrastructure.

Acting FERC Chairman Cheryl LaFleur called the project “an innovative attempt to harness previously untapped energy resources.”

More: Federal Energy Regulatory Commission

March 25, 2014

FERC Refines Bulk Electric System Definition

The Federal Energy Regulatory Commission last week approved a revised definition of the bulk electric system (BES) that refines the exclusions for radial facilities and local networks.

The commission’s order (RD14-2) approved changes drafted by the North American Electric Reliability Corp. in response to FERC and industry concerns over how NERC was identifying facilities that are subject to its mandatory reliability rules.

In Orders 773 (December 2012) and 773-A (April 2013), FERC approved a new definition of BES facilities, eliminating regional discretion and establishing a “bright-line” threshold including most facilities operating at or above 100 kV. (See Seeking “Bright Line,” FERC Leaves BES Appeal Rules Unclear.)

Although the new definition supersedes the Order 773 definition in total, it will “result in minimal changes to the elements included in the bulk electric system,” FERC said.

NERC said the revised rules respond to the technical and policy concerns raised in the prior orders by adding “clarity and granularity that will allow for greater transparency and consistency in the identification of elements and facilities that make up the bulk electric system.”

The changes, effective July 1, 2014, mostly affect inclusion I4 (dispersed power producing resources) and exclusions E1 (radial systems), E3 (local networks) and E4 (reactive power devices).

In addition, there are minor clarifications to inclusions I1 (transformers), I2 (generating resources) and I5 (static or dynamic reactive power devices). No changes were made to the core definition, inclusion I3 (black start resources) or exclusion E2 (behind the meter generation). (See Bulk Electric Systems (BES) Inclusions and Exclusions.)

Exelon Corp., the American Public Power Association, the Transmission Access Policy Study Group (TAPS) and Public Utility District No. 1 of Snohomish County submitted filings supporting NERC’s revisions. APPA and Snohomish praised the new definition for its focus on core facilities that present the greatest risks of reliability failure.

FERC rejected requests from several other intervenors, including the American Wind Energy Association (AWEA) and the Electricity Consumers Resource Council (ELCON), for changes in NERC’s proposal.

AWEA and First Wind Holdings LLC had asked the commission to modify inclusion I4 to exclude individual power producing resources. The commission said the purpose of inclusion I4 is to include all forms of variable generation. “As we noted in Order No. 773, there are geographical areas that depend on these types of generation resources for the reliable operation of the interconnected transmission network,” the commission said. “… Nothing in the AWEA and First Wind pleadings have convinced us that our determinations in Order No. 773 need to be revisited.”

FERC cited a 2009 NERC report on variable generation that concluded that “[d]istributed variable generators, individually or in aggregate (e.g. small scale photovoltaic), can impact the bulk power system and need to be treated, where appropriate, in a similar manner to transmission connected variable generation.”

The commission said wind farms larger than 75 MVA can affect reliability if all of its wind turbines trip offline simultaneously after small fluctuations in voltage or frequency. “Because variable generation can impact the interconnected transmission network, we anticipate that wind plant owners whose facilities meet the inclusion I4 criteria who seek to exclude individual wind turbines from the bulk electric system through the exception process will be infrequent,” the commission wrote.

In other reliability actions last week FERC also:

Approved five standards requiring generators owners and, in some cases, transmission owners to provide verified data for certain power system planning and operational studies. The rules are intended to improve the accuracy of the studies and the coordination of protection system settings.
Proposed revisions to an existing standard on Transmission Relay Loadability and a new standard on Generator Relay Loadability designed to prevent generators from tripping offline unnecessarily during a system disturbance.
Denied rehearing of Order No. 791, which approved version 5 of the Critical Infrastructure Protection standards.

March 21, 2014

Appellate Court Skeptical of Order 1000 Challengers

By Rich Heidorn Jr.

WASHINGTON – An appellate court panel last week grilled attorneys seeking to overturn FERC’s Order 1000, expressing skepticism over challenges to the agency’s jurisdiction and claims that allowing competition in transmission development will harm reliability.

The three-judge panel for the D.C. Circuit Court of Appeals was less aggressive in questioning FERC’s attorneys, interrupting them less frequently than they did in sparring with lawyers seeking to overturn the order.

“I’m having trouble understanding where this steps on your prerogatives,” Judge Nina Pillard said in response to the attorney for the Alabama Public Service Commission, who contended the order would render state transmission planning “meaningless.”

“It doesn’t require much of you,” she said earlier, in response to objections from Southern Co., citing what she called the order’s “very flexible and open-ended requirements.”

Judge Thomas B. Griffith questioned the South Carolina Public Service Authority’s contention that the commission lacked authority to allow non-incumbent transmission developers equal footing with incumbents in obtaining funding through regional cost allocation processes.

“It seems to be in the wheelhouse of [FPA section] 206,” Griffith said.

Judge Judith Ann Wilson Rogers also seemed unpersuaded by the challengers.

John L. Shepherd Jr., representing Public Service Electric and Gas, noted that Congress has resisted efforts to extend FERC’s natural gas pipeline siting and construction-approval authority to electric transmission. FERC’s removal of incumbents’ right of first refusal (ROFR), he said, was “a radical mandate that Congress did not authorize FERC to impose.”

Judge Rogers responded that nothing in the order gives FERC authority to decide what gets built or who does it.

Rogers and her colleagues frequently cited a Brattle Group report commissioned by Edison Electric Institute that estimated a need for nearly $300 billion in new transmission facilities by 2030. Brattle found that more than $180 billion in transmission would not be built due to shortcomings in pre-Order 1000 transmission planning and cost allocation rules.

Faced with such evidence, Rogers said, “I’m trying to understand why Congress would tell FERC to … sit on its hands.”

Judge Pillard agreed: “It would be, arguably, irresponsible for a regulator not to require planning in advance,” she said.

Attentive Audience

The three-hour oral argument drew a rapt crowd of about 100 spectators — including numerous FERC officials, PJM Assistant General Counsel Pauline Foley and LS Power’s Sharon Segner — to the grand, wood-paneled courtroom at the E. Barrett Prettyman U.S. Courthouse a few blocks from the Capitol.

Order 1000, issued in July 2011, changes the process for planning and paying for new regional and interregional transmission lines. It also allows independent developers to compete with traditional utilities in building new lines.

The court is considering complaints from those who allege the commission overstepped its authority and those who say it didn’t go far enough in ensuring that transmission will be sufficient to satisfy public policy initiatives, such as state renewable portfolio standards.

The main threat to the order comes from challengers in the Southeast and West who allege the commission exceeded its authority under the Federal Power Act in requiring public utility transmission providers to participate in regional transmission planning, and eliminating incumbent transmission providers’ monopoly on building and running transmission.

The order is also being challenged for its cost allocation provisions, which require that those who benefit from new regional transmission facilities share in their costs while ensuring that the costs of interregional projects not be assigned involuntarily.

Repeated Interruptions

Harvey L. Reiter, of Stinson Leonard Street, spoke first on behalf of the Sacramento Municipal Utilities District, South Carolina Public Service Authority and the Large Public Power Council, which are among those challenging FERC’s jurisdiction.

Reiter was repeatedly interrupted by the panel, which featured appointees from the last three administrations: Rogers (Clinton), Griffith (George W. Bush) and Pillard (Obama).

The pattern was repeated with Andrew W. Tunnell of Balch & Bingham, the Birmingham, Ala., law firm for Southern Co.

Tunnell said the order is “based on speculation” and not on any proof that the current rules are harming transmission. “If there really was a problem it would have come out in the rulemaking process.”

He cited a Department of Energy study praising the Southeast’s transmission planning.

“FERC is going to break what works … and replace it with a very bureaucratic and litigious process,” Tunnell said. “That means you’re not going to have a more efficient transmission planning process, you’re going to have less.”

Public Policy

The judges seemed to show a bit more sympathy for the arguments of the American Public Power Association and the National Rural Electric Cooperative Association (NRECA), who contend Order 1000 didn’t go far enough to protect public policy interests.

While the order requires that load serving entities (LSEs) have input into transmission planning, it “doesn’t require that their advice be heeded,” said the group’s attorney Randolph Lee Elliott, of McCarter & English.

Judge Pillard questioned FERC about the groups’ concerns. “If the parade of horribles came to pass, that’s tough luck?” she asked FERC attorney Beth G. Pacella.

Judge Griffith joined in. “Doesn’t the law require more than that they be part of the process? To meet their needs, not just talk about their needs? It’s not just process. It’s process that leads to a certain result.”

Pacella acknowledged that the order “doesn’t require that [public power] needs be met.” But, she said, parties whose needs are not met by the planning process can file a section 206 complaint to seek a FERC finding that the planning process “is no longer just and reasonable.”

Rebuttal

On rebuttal, Tunnell said FERC should have stopped in 2007, when it issued Order 890, which created a process of voluntary regional transmission planning. “FERC didn’t give voluntary transmission planning a chance,” he said. FERC began the Order 1000 rulemaking while “the ink was still wet” from Order 890 and the commission was considering Southern’s 890 compliance filing, he said.

Tunnell said Order 1000 will “undermine our vertical integration” and with it, its benefits: quicker storm restoration and economies of scale in operations and maintenance. “Transmission planning doesn’t address that,” he said.

“I think we’re all surprised to hear that,” shot back Judge Rogers.

“It’s changing the whole paradigm,” Tunnell insisted. “Transmission is a natural monopoly.”

State Jurisdiction on Planning

Luke D. Bentley IV, attorney for the Alabama Public Service Commission, led off the second of three sessions, this on cost allocation.

Bentley cited a list of state statutes governing transmission planning. FERC did not respond in their brief, “because they can’t,” Bentley said. Order 1000, he continued, would “relegate states to mere stakeholders in the planning process.”

“Yes for interstate transmission,” responded Judge Pillard. “That’s Con[stitutional] Law 101.” FERC balanced federal and state interests, she said, “in a relatively flexible way.”

FERC attorney Lona T. Perry said the commission’s order stops at the state border: “Any project that gets approved in the regional planning process that doesn’t get the requisite state approvals for construction and siting doesn’t get built,” she said.

Jonathan D. Schneider of Stinson Leonard Street, and attorney for the South Carolina Public Service Authority and the Large Public Power Council, said the case isn’t about cost allocation but “about a new funding mechanism that the commission thinks is better,” and that it would force utilities to fund independent transmission developers.

Judge Griffith, questioning FERC Attorney Robert M. Kennedy, observed, “There’s a significant difference between inducement and coercion.”

Kennedy said the commission was simply enforcing “long-standing, well established” principles that assign transmission costs to beneficiaries.

“We’re not imposing a relationship. We’re recognizing a relationship that exists” because of the physics of the transmission system, Kennedy said.

Right of First Refusal

The final session focused on the order’s reversal of previous FERC policy that allowed incumbent utilities rights of first refusal to add new transmission in their franchised territories.

Shepherd, of Skadden Arps, said the ruling unfairly gives non-incumbents the rights to cherry pick transmission projects they’d like to build without the obligation to serve all customers that public utilities face. “It’s not competition, it’s predation,” he said.

FERC’s Perry said that if ROFR prevails, independent developers would only be allowed to participate as merchants, without utilities’ ability to build cost of service projects. She said the commission found no reason to believe that transmission run by independents will be less reliable than that of incumbents.

Comic Relief

The intensity of the argument was briefly broken at the end of the three-hour session, when FERC relinquished some time on rebuttal to Patton Boggs’ Mike Engleman, attorney for LS Power, an independent transmission developer with much at stake in the ROFR battle.

Engleman’s move to the podium surprised one of the judges, who began addressing a different lawyer.

“That’s OK, much of the room doesn’t want me here,” Engleman said, prompting the courtroom to burst into laughter.

Engleman said LS Power spends tens of thousands of dollars on every project but often walks away empty-handed.

“There are rules in multiple regions that say, ‘You can’t play in our sandbox,’” Engleman said.

Shepherd had the last word, picking up on Southern’s claim that non-incumbent transmission developers pose a reliability risk.

“If these guys [attach to] your system and break it, you [the incumbent] have to fix it.”

[Editor’s Note: As a member of the FERC Office of Enforcement, the author of this story testified against Southern Co. in 2003 (docket no. ER03-713) and in 2006 publicly challenged a settlement negotiated between Southern and the commission’s chief of staff (EL05-102).]