Company Briefs

Five 170-foot-tall concrete foundations that will support the nation’s first offshore wind farm have been completed in Houma, La., and are starting their barge journey to the Deepwater Wind construction site off Block Island, R.I.

The 1,500-ton foundations, which will support five 6-MW turbines manufactured by Alstom, are expected to arrive off Block Island in mid-July, according to Deepwater Wind CEO Jeffrey Grybowski. The turbines are scheduled to be installed in mid-2016, with the project expected to be operational by the end of that year. National Grid has agreed to buy the wind farm’s output under a 20-year contract.

More: Associated Press

Facebook Powering New Texas Data Center Entirely with Wind

Facebook announced that its new data center in Fort Worth, Texas, will run entirely on wind energy. The Fort Worth facility will be the third Facebook server center to be powered entirely on renewable energy. The other two are in Altoona, Pa., and Lulea, Sweden.

Facebook said it is working with Citi Energy, Alterra Power and Starwood Energy to tie 200 MW of wind energy to the Texas grid, and then to the data center. It said the wind facility will cover a 17,000-acre site about 100 miles from Fort Worth. Facebook says that it aims to produce 50% of its power needs from renewable energy by 2018.

Facebook’s news follows separate announcements from tech giants Google and Amazon.com that they plan to step up commitments to renewable energy.

More: EcoWatch

Brattle Report Puts Nuclear Industry’s GDP Input at $60 Billion a Year

A report commissioned by a nuclear promotional group said U.S. atomic power contributes about $60 billion annually to the country’s gross domestic product.

The report by the Brattle Group, commissioned by the trade organization Nuclear Matters, said the industry accounts for 475,000 full time jobs and provides 19% of U.S. electricity. The report said the industry provides about $10 billion in federal taxes and $2.2 billion in state taxes.

More: Nuclear Street

More than Half of Large Businesses Generating Some of Own Power

A Deloitte survey shows that more than half of about 600 large businesses in the U.S. are able to generate some of their energy on-site. Two years ago, only about a third of the companies generated some of their power.

The study showed that the largest companies – those with $500 million in annual revenue or more – are investing more in energy management, ranging from on-site generation to energy efficiency. The majority of the on-site power is still provided by diesel generators, but it is increasingly likely to include renewables such as solar or wind.

More: Columbus Business First

Coal Company Pans Song Lyrics – in Lawsuit

Peabody Energy, in asking a federal judge in Wyoming to dismiss a lawsuit filed by protesters who were jailed after demonstrating at a shareholders meeting, also wants the judge to purge the lawsuit of the famous John Prine protest lyrics that mention the company’s name.

Thomas Asprey and Leslie Glustrom, who were jailed after demonstrating at a 2013 Peabody shareholders meeting, cited the lyrics from Prine’s 1971 song “Paradise” in the lawsuit. Peabody said the lyrics tarnish its name.

The lyrics include the refrain about the company’s mining practices in Muhlenberg County, Ky.:

And Daddy won’t you take me back to Muhlenberg County

Down by the Green River where paradise lay?

“Well, I’m sorry my son, but you’re too late in asking

Mister Peabody’s coal train has hauled it away”

More: Associated Press

Environmentalists Say Dominion’s Coal Ash Plans Inadequate

A coalition of environmental groups says Dominion Virginia Power’s plan to close its 11 coal ash ponds doesn’t do enough to prevent toxic materials from seeping into nearby rivers, and they’ve asked the state to step in.

The environmentalists have asked the Virginia Department of Environmental Quality to halt Dominion’s plans to remove the coal ash if it shows pollutants are escaping. “Dominion’s proposal to cap in place will not stop heavy metals and other toxic pollutants from leaking out of the sides and bottom of coal ash ponds right into water bodies used to kayak, fish and swim,” said Emily Russell of the Virginia Conservation Network.

Company officials say the procedure for closing the ponds and moving the material to prepared disposal sites meets all state and federal regulations, and tests show the method is safe.

More: Richmond Times-Dispatch

Ameren Reaches Settlement on Missouri Coal Ash Plan

Ameren Missouri has settled a series of lawsuits dating back more than five years over its coal ash disposal plan, allowing the power generator to go forward with construction of a coal ash landfill at its Labadie power plant that it says is crucial to the plant’s continued operation.

The settlement with Franklin County and the Labadie Environmental Organization requires Ameren to construct 5-foot berms to keep any ash or ash residue out of the Missouri River floodplain. The company also agreed not to bring in ash from other sites, or to use coal ash in the construction of the berms.

More: St. Louis Post-Dispatch

Maine Wind Farm Construction Begins

Construction has started on Maine’s largest renewable energy project, a $420 million wind farm in Bingham that will have a capacity of 185 MW.

Developer SunEdison said it had secured $360 million in financing for the 56-turbine farm, which will increase the company’s total wind generation capacity in Maine to 552 MW. The Bingham project’s output will be sold to Eversource, National Grid and Unitil.

More: Portland Press Herald

Pump Malfunction Forces Indian Point Unit Shutdown

A water pump malfunction forced the shutdown of Entergy’s Indian Point Unit 3 on Wednesday. Control room operators shut down the nuclear reactor after they found that one of the unit’s condensate pumps automatically stopped while the unit was operating at full power, causing the steam generator’s water levels to fluctuate, according to Entergy.

The condensate pumps, which are part of the system that feeds water into the plant’s steam generators, are located away from the nuclear side of the plant, Entergy said. Operators safely shut down the reactor, the company said. The shutdown did not affect Unit 2, which is still operating at full power.

Entergy did not say when it expects to resume operations.

More: Poughkeepsie Journal

Solar Development Grows in Missouri

Ameren is planning a 15-MW solar farm on a 70-acre site in eastern Missouri. The project would be twice the size of Ameren’s first utility-scale solar facility near St. Louis. Ameren’s application with the Missouri Public Service Commission did not detail costs.

The state’s renewable energy standard has stoked interest in renewable projects, as utilities are required to generate a portion of their electricity from non-carbon sources. Developers also are racing to build projects before a federal tax credit for renewable energy falls from 30% to 10% at the end of next year.

More: St. Louis Post Dispatch

Batteries Included, Some Assembly Required

Indianapolis Power & Light has broken ground on the first utility-scale battery storage project in MISO’s 15-state territory.

The AdvancionTM Energy Storage Array will provide 20 MW of interconnected energy storage. The facility, which will provide additional stability to IPL’s system, is due to go online in the first half of 2016.

IPL’s parent, AES, pioneered the use of grid-connected lithium-ion batteries in 2008, in Indianapolis. AES has 86 MW of energy storage projects in operation worldwide and has announced an additional 260 MW of interconnected battery-based storage.

More: Indianapolis Power & Light

Talen Energy to Expand; Eyes AEP

Talen Energy, the independent power producer formed by the spinoff of PPL’s generating assets and competitive producer Riverstone Holdings, is looking to grow. The Allentown, Pa., company holds about 15,000 MW of generation, primarily in the PJM region and some in Texas.

“We’re as open to buying coal as gas as nuclear,” CEO Paul Farr told Reuters. But he said its fuel mix is more likely to become more “gassy” while gas prices remain low. He did say, however, that Talen is looking at American Electric Power’s coal generation holdings in Ohio. AEP has been signaling a willingness to unload its coal assets there.

More: Reuters

Minnesota Power Shutting Down 2 Coal Units at Taconite Harbor

Minnesota Power announced last week that it will retire two coal-fired units at its Taconite Harbor plant in Schroeder, part of a larger plan to shift the company’s generation portfolio from coal.

The company’s commitment will be included in its “integrated resource plan” due to be filed with the Public Utilities Commission in September. Minnesota Power’s fuel-mix currently has about 75% coal-fired generation and 25% renewables. That will change over the next 15 years to about a third coal, a third natural gas and a third renewables.

“It’s a balanced portfolio of energy sources,” said Al Rudeck, vice president of strategy and planning. “We think it’s the best plan, and the most affordable plan, for our customers.” Environmentalists applauded the announcement.

More: Midwest Energy News

July 13, 2015

FirstEnergy to Spin off its Last Utility-Managed Tx Assets

By Suzanne Herel

FirstEnergy would spin off the transmission assets of Jersey Central Power & Light, Metropolitan Edison and Pennsylvania Electric into a new subsidiary under a plan it has submitted to regulators, saying the move would allow it to more cheaply and efficiently upgrade its grid (EC15-157).

With the formation of the new company, Mid-Atlantic Interstate Transmission (MAIT), all 24,000 miles of the Akron, Ohio-based company’s system would be managed by transmission affiliates.

The plan must be approved by New Jersey and Pennsylvania regulators and the Federal Energy Regulatory Commission. The company made no formal announcement of the proposal except for a June 19 filing with the Securities and Exchange Commission.

“When you have a separate transmission-only company, typically it carries a more favorable credit rating, so it can borrow money for less, and that results in lower costs for customers,” FirstEnergy spokesman Doug Colafella said. “It’s an arrangement that really allows a company to make the significant investments in transmission that we’re looking at. It also allows our separate utilities to stay focused on the distribution system and respond quickly to customer needs.”

FirstEnergy already operates American Transmission Systems (ATSI) in Ohio and northwest Pennsylvania and Trans-Allegheny Interstate Line Co. (TrAILCo) in western Pennsylvania.

The spinoff falls in line with FirstEnergy’s “Energizing the Future” initiative, announced in 2012, to enhance its high-voltage transmission system.

FirstEnergy expects to invest $2.5 billion to $3 billion over the next five to 10 years on upgrades in the JCP&L, Met-Ed and Penelec zones, Colafella said.

The company estimates that streamlining the projects through one company with a higher credit rating will save $135 million in interest over the 30-year life of $1.5 billion in projects, according to FirstEnergy’s filing with the New Jersey Board of Public Utilities.

“Consolidating all of the operating companies’ transmission assets in a stand-alone transmission company can reduce investors’ perception of financial risk, strengthen the credit profile of the transmission function and, in that way, provide improved access to capital and reasonable rates,” it said.

Ron Morano, a spokesman for JCP&L, said that being relieved of the task of operating its transmission system will allow the company to better focus on customers’ needs.

“For Jersey Central, it enables a more timely investment on new transmission projects,” he said.

Under the plan, MAIT would own and operate all transmission assets of the three utilities, which would lease to the transmission subsidiary their real estate and real property rights.

Colafella said the spinoff would not affect transmission-related jobs at the utilities.

“It won’t have any impact on employees day-to-day,” he said. “It’s more of an accounting arrangement.”

It is, however, expected to lead to the creation of about 200 FirstEnergy jobs in New Jersey and Pennsylvania, he said, and the projects should provide work for roughly 600 engineering, project management and construction jobs in those states.

July 13, 2015June 15, 2023

MISO Proposes Earlier Day-Ahead Market Close

By Chris O’Malley

CARMEL, Ind. — MISO will propose closing the day-ahead market one hour earlier during Daylight Savings Time and reducing the clearing time by an hour in response to the Federal Energy Regulatory Commission’s final rule on gas and electric schedules.

MISO officials said their proposal — Alternative 3 — was an effort to balance reliability and market efficiency concerns with stakeholder preferences. Most stakeholders preferred no changes.

FERC Order 809 moved the timely nomination cycle deadline for scheduling gas transportation from 11:30 a.m. to 1 p.m. CT (from 12:30 p.m. to 2 p.m. ET) and added a third intraday nomination cycle. The commission ordered RTOs to adjust the posting of their day-ahead energy market and reliability unit commitment process results “sufficiently in advance” of the revised gas cycles or explain why it is not suitable for their markets.

Three Alternatives

The RTO rejected Alternative 2, which officials said was most in line with Order 809 but was opposed by most stakeholders. In addition to reducing the clearing time by one hour, it would have aligned the day-ahead market with the timely gas nomination cycle by closing the day-ahead two hours earlier during DST and one-hour earlier during standard time. Only 18% of stakeholders supported the change.

Alternative 3 won a bare majority with 53% support, making it the second choice to the status quo Alternative 1, which was backed by 78%.

Alternatives 2 and 3 got much of their support from gas-dependent members in Zones 8 and 9 (Louisiana, Arkansas and eastern Texas).

“I know not everybody is going to agree with [the choice] given the voting that took place. I hope that everybody can understand how we got there and [that] it makes sense,” Joseph Gardner, MISO’s vice president for forward markets and operations services, told the Market Subcommittee last week in announcing the decision.

Gardner told stakeholders MISO will have to make a partial show-cause filing to defend the choice to FERC. MISO also will ask FERC to delay the implementation of the new hours to November 2016 rather than next April as required by FERC.

More Units to Call On

Gardner said Alternative 3 had several benefits. Moving the market before the Intraday 2 gas nominations could free up about 5,000 MW more than under the current approach.

“From a reliability perspective, by moving our timeframe up by shortening our window, we bring more units into the mix. That basically allows more units to be considered as part of the normal day-to-day process, in terms of getting them online [and] in terms of committing them economically,” he said.

MISO estimates that natural gas-fired generation could rise to 50% of its generation pool in 2016/2017 as coal-fired plants are shuttered in response to the Environmental Protection Agency’s Mercury and Air Toxics Standards. EPA’s proposed Clean Power Plan is expected to spur gas use further.

From a market efficiency standpoint, Gardner pointed to the value of being able to trade during the “most liquid” time of the day “and then having that price discovery and know[ing] what price to put into the day-ahead market. So that’s a consideration, too, as to why we didn’t go with Alternative 2.”

Not Ideal for Some

The change may be hard for some stakeholders to swallow. Gardner acknowledged that many have indicated that they found ways to manage their gas supply risks and thus didn’t support moving up the day-ahead schedule.

Marc Nielsen of Alliant Energy said his company plans to add additional gas-fired generation and already conducted a great deal of modeling. “We supported Alternative No. 1. We’re able with our gas supply resources to handle things perfectly as they are now,” he said.

Gardner said he recognized Alliant’s concern. “I hope people can understand how we ended up here,” he said. “It’s been a long journey.”

But the tone among stakeholders at the Market Subcommittee was mostly supportive.

“I appreciate you guys looking at your processes and working toward also shortening the [market clearing] time. I think that was a big step, too, so thank you,” Ameren’s Jeff Moore told Gardner.

Moore asked whether Gardner thought FERC would be amenable to MISO’s choice.

“I think we have a much better chance of succeeding [than sticking with the status quo], but we still are going to have to make a good argument,” Gardner said.

PJM and SPP also will propose changes to their schedules in compliance filings due July 23. (See PJM to Propose Earlier Day-Ahead Schedule and SPP Moving to 9:30 Day-Ahead Close.)

No Schedule Changes for NYISO, ISO-NE

NYISO and ISO-NE are not considering any schedule changes in response to the Federal Energy Regulatory Commission’s April order on gas-electric coordination.

FERC Order 809 moved the timely nomination cycle deadline for scheduling gas transportation from 11:30 a.m. to 1 p.m. CT (12:30 p.m. to 2 p.m. ET). It also added a third intraday nomination cycle (RM14-2).

“We are not contemplating market timing changes at this point in time and believe the additional 1.5 hours for generators to arrange day-ahead gas purchases will be helpful to reliability,” NYISO spokesman Ken Klapp said.

ISO-NE, which shifted its day-ahead market schedule two years ago to align with the natural gas trading day, said it is already in compliance with the FERC rule.

— William Opalka

July 13, 2015

PJM to Propose Earlier Day-Ahead Schedule

PJM confirmed last week that it will seek to move the deadline for submitting day-ahead offers up 90 minutes, from noon to 10:30 a.m. ET.

Adam Keech, director of wholesale market operations, told the Operating Committee that the RTO will post day-ahead results as soon as they are complete — but no sooner than 12:30 p.m. — up from the current 4 p.m. The reliability assessment and commitment (RAC) run rebid window will be open until 2:15 p.m., up from the current 6 p.m.

Keech said PJM will seek to complete the RAC run assignments before the 3 p.m. deadline for the second intraday gas nomination cycle.

“We’re going to commit as much as we can by 3 p.m., recognizing that if system conditions change we’re going to need to make supplemental commitments,” Keech said.

The RTO’s explanation last week clarified the changes it outlined to the Markets and Reliability Committee on June 25. PJM officials acknowledged the lack of consensus among stakeholders on the changes but said they were necessitated by the Federal Energy Regulatory Commission’s April order moving the timely nomination cycle deadline for gas to 2 p.m. ET from 12:30 p.m. and adding a third intraday nomination cycle. (See PJM Moving on Day-Ahead Schedule Changes.)

Keech said PJM officials are considering changes to their algorithms as well as faster computer servers as a way to meet their goal of reducing the market-clearing time to three hours from four. He said FERC’s requirement that the RTO allow hourly pricing updates means it will have to process more data during the clearing process. (See “PJM Won’t Be Ready for Flexible Generator Offers by November” in PJM Markets and Reliability Committee Briefs.)

PJM told FERC in a report last week that it will implement hourly offers by Nov. 1, following consultations with stakeholders (EL15-73).

— Rich Heidorn Jr.

July 13, 2015June 15, 2023

SunEdison Making $2B Bet on Wind in Midwest, Canada

By Tom Kleckner

Uncertainty over renewable tax credits and competition from low-priced natural gas may be discouraging some wind power investors — but not SunEdison’s TerraForm Power.

Established by SunEdison to own and operate its solar farms, TerraForm has since expanded its focus to wind and other clean-power assets, seeking long-term contracts that generate steady revenues for additional investments.

In the year since its July 2014 initial public offering, TerraForm has added 2 GW of wind assets to its portfolio. Last week, TerraForm made its biggest splash yet, joining with SunEdison to acquire a 930-MW energy portfolio for $2 billion from Invenergy Wind.

Just the week before, TerraForm and SunEdison announced they had finalized the acquisition of another 521-MW portfolio of operating wind farms in Idaho and Oklahoma from Atlantic Power. In January, the two companies closed a similar 521-MW package of wind and solar assets from First Wind Holdings.

The Deal

TerraForm said it intends to acquire net ownership of 460 MW of Invenergy’s wind plants, with the remaining 470 MW to be acquired by a “warehouse” facility, a financing mechanism that will be sponsored by SunEdison and third-party equity investors.

The initial acquisition includes the 187-MW Rattlesnake farm in Texas, the 196-MW California Ridge project in Illinois and the 78-MW Raleigh wind farm in Ontario. The warehouse facility includes the three Prairie Breeze wind farms totaling 279 MW in Nebraska and the 190-MW Bishop Hill, Ill., facility.

The deal is expected to close in the fourth quarter, subject to the approval of the Federal Energy Regulatory Commission and the Public Utility Commission of Texas.

Bucking a Trend

The companies are upping their stake in wind at a time in which other developers have scaled back.

Second-quarter investments in U.S. wind projects were $9.4 billion, down 4% from the first quarter and 21% from 2014’s second quarter, according to the American Wind Energy Association. Bloomberg New Energy Finance reported that global clean energy investment dropped 28% in the second quarter versus a year earlier. The U.S. entered 2015 with 65.9 GW of installed wind, AWEA says.

Yieldco Strategy

TerraForm is seeking value by “aggregat[ing] a highly fragmented industry,” CEO Carlos Domenech said.

The company’s strategy is based on the use of “yieldcos,” an increasingly popular method of holding renewable energy assets. Yieldcos allow developers to raise capital at lower costs by selling — or dropping — completed projects to the yieldco and using the proceeds to fund new projects.

“The thinking with warehouse assets is that as you drop or acquire assets into the warehouse, you’ll be tranching those assets,” SunEdison CFO Brian Wuebbels explained in a conference call last week. “Equity investors, debt investors, us … we all want to know the quality of the assets we’re putting into the warehouse. Getting an investor to put down $2 billion into an empty warehouse without having an idea of the particular asset’s performance would be creating [higher] costs. … By having definitive, high-quality assets, we can drive down the cost of capital.”

The assets being acquired from Invenergy have a weighted average remaining contract life of 19 years.

UBS Securities noted only 93 MW will be under construction upon the deal’s close, easing concerns about developmental risk. The deal also diversifies the portfolio of SunEdison, the world’s largest renewable energy development company.

Invenergy

For Invenergy, a privately held company, the sale will provide capital to invest in more projects, CEO Michael Polsky told Bloomberg. “It’s a new phenomenon. It’s helped to proliferate renewable energy.”

sunedison — SunEdison’s TerraForm Power is acquiring 930 MW of wind capacity from Invenergy, including the Prairie Breeze (top) and under-construction Prairie Breeze II farms (bottom), both in Nebraska.

Domenech said he expects that TerraForm’s “ongoing partnership” with Invenergy will result in additional acquisitions in the future.

Invenergy bills itself as North America’s largest independent wind power generation company, with 51 wind farms in the U.S., Canada and Europe totaling more than 4.4 GW.

The company, which is selling 10% of its total contracted portfolio to TerraForm, will retain a 9.9% stake in the U.S. assets being sold, providing operation and maintenance services for the facilities.

Cash Flow

TerraForm and SunEdison say the assets they are purchasing should generate average unlevered cash available for distribution (CAFD) of $141 million annually over the next 10 years, a levered cash-on-cash return of about 8.4%.

Private equity investors have expressed “a lot of interest in the warehouse,” Wuebbels said.

In announcing the deal, TerraForm raised its 2016 dividend target 26% to $1.70/share from $1.53 and projected a 20% compound annual growth rate from its current first-quarter dividend “driven by the increased visibility and growth provided by this transaction.”

Market Reaction

Shares in both SunEdison and TerraForm stock rose following the sale announcement Monday, with TerraForm shares up 4.4% for the week.

Travis Hoium, a columnist for The Motley Fool, was less impressed, warning that yieldcos’ appeal could fade if they turn out to be based on overly aggressive assumptions.

“Adding $141 million in cash available for distribution may sound like a lot, but the $2 billion price tag is steep for that kind of return. Remember that the cash flow from projects has to cover the depreciating value of a wind turbine over time as well as pay for debt that will be used to acquire the assets, so the return for shareholders may not be as attractive as it seems. … Unless TerraForm Power can re-up contracts for equal or greater electricity prices well beyond the current contracts, the company may not even earn its cost of capital back.”

July 13, 2015

NYPSC Staff Narrows Transmission Alternatives

By William Opalka

Seven projects proposed by transmission developers for the mid-Hudson region have cleared an initial screening by the staff of the New York Public Service Commission.

Those projects scored well enough on staff’s efficiency and environmental ratings to warrant further study, according to an interim report filed on July 6 (12-T-502, et al).

The PSC has sought to jump-start transmission development in the counties north of New York City to alleviate congestion and deliver power from underutilized upstate generation resources to the higher demand areas of the state. (See Tx Plan to Open NY Choke Points Without New ROWs.)

The staff scored 21 proposed projects from four developers. Incumbent transmission owners that formed New York Transco — Central Hudson Gas & Electric, Consolidated Edison, New York Power Authority, New York State Electric & Gas, Niagara Mohawk Power, Orange and Rockland Utilities and Rochester Gas & Electric — have four projects on the list. NextEra Energy Transmission New York has one project and Boundless Energy NE has two.

One developer, North American Transmission Corp., did not receive any favorable recommendations.

“These remaining scenarios are the most promising from an electric system benefit perspective and are significantly more environmentally compatible primarily because they are all designed to use existing rights-of-way,” the report said.

One late development will further impact the proposals. Competitive Power Ventures said on June 12 that it has closed financing for its proposed 720-MW combined-cycle plant in Orange County. Because CPV had not been included in the commission’s original analysis, staff will need to remodel power flows.

“The study is also to include an analysis of alternatives to a transmission facility and to address the issue of whether there is sufficient public need for a transmission facility as a matter of public policy,” the report said.

July 13, 2015

FERC Orders $15 Million Penalty in PJM Market Manipulation Case

By Rich Heidorn Jr.

Federal regulators ordered a Florida energy trader to pay $15 million in penalties and repay almost $1.3 million in profits for making riskless up-to-congestion trades in PJM to cash in on line-loss rebates.

The Federal Energy Regulatory Commission imposed the penalty July 2 against City Power Marketing, of Fort Lauderdale, Fla., and its founder K. Stephen Tsingas (IN15-5), ruling that they were guilty of market manipulation and making false and misleading statements to commission investigators.

The commission ordered City Power to pay $14 million and Tsingas to pay $1 million in civil penalties and disgorgement of $1,278,358 in unjust profits, plus interest.

Chairman Norman Bay, who headed the Office of Enforcement during the City Power investigation, did not participate in the order.

The commission said City Power cashed in on line-loss rebates — or marginal loss surplus allocations (MLSA) — through three types of UTC transactions: “round-trip” trades that canceled each other out; trades between import and export pricing points of the same PJM interface with equivalent prices (SOUTHIMP-SOUTHEXP); and trades between two PJM nodes that historically had a very small price spreads (NCMPAIMP-NCMPAEXP).

The commission concluded that City Power created the false impression that it was trading to arbitrage price differences “when, in fact, it was engaging in trades solely to collect MLSA payments to the detriment of other market participants.”

“As we have noted, trades that are pre-arranged to cancel each other out and involve no economic risk are wash trades, which are inherently fraudulent,” the commission said.

The order also concluded that Tsingas attempted to mislead investigators by denying the existence of incriminating instant messages between him and a business partner, Timothy Jurco.

The allegations against City Power are virtually identical to those FERC made in its case against Rich and Kevin Gates and their Powhatan Energy Fund.

On May 29, the commission ordered the Gates brothers and their associates to pay $34.5 million in penalties and disgorged profits. If the Gates brothers don’t pay up within 60 days, as they insist they won’t, FERC will have to file a complaint in U.S. District Court to force payment. (See FERC Orders Gates, Powhatan to Pay $34.5 Million; Next Stop, Federal Court?)

FERC also may face challenges collecting from Tsingas and his company, which said in April that FERC’s investigation forced Tsingas to lay off all of his employees and “destroyed” the company. (See UTC Trader: Firm was Ruined by ‘Unfair’ FERC Prosecution.)

FERC investigators contend Tsingas’ net worth is at least $10 million, including “a waterfront mansion” in Fort Lauderdale worth $3 million, a yacht, a house in Greece and several autos.

Tsingas told FERC his net worth is “roughly $1 million” and that his “yacht” is a nine-year-old, 32-foot outboard boat “without a cabin or a shower” and that his “mansion” is a simple three-bedroom house.

Attorneys for Tsingas and City Power did not respond to a request for comment.

July 13, 2015

ISO-NE, NEPOOL Oppose Demand Curve Change

By William Opalka

The New England Power Pool Participants Committee urged federal regulators last week not to short circuit its stakeholder process in ordering zonal sloped demand curves for the next Forward Capacity Auction.

NEPOOL joined ISO-NE in asking the Federal Energy Regulatory Commission to reject a request by generators to force the RTO to develop a zonal sloped demand curve design for FCA 10 in February (ER14-1639).

The New England Power Generators Association made the request June 22 after ISO-NE backed off from its commitment to introduce a new curve for FCA 10, saying that making a change now would create reliability concerns. The generators asked FERC to reiterate a previous order that directed the RTO to continue efforts to eliminate administrative pricing in zones that are short of generation resources or suffer from transmission constraints. (See NEPGA: Order Sloped Demand Curve in FCA 10.)

ISO-NE withdrew its support for the change just before NEPOOL was scheduled to vote on it. At NEPOOL’s June Planning Committee meeting, only 42% of stakeholders backed the sloped curve.

NEPOOL told FERC that although some of its members feel “frustration” with ISO-NE for reversing course despite “substantial progress,” it wants any changes to result from the stakeholder process.

“NEPOOL takes no position under these circumstances on whether an order to implement sloped zonal demand curves generally is appropriate or justified,” it wrote. NEPOOL’s preference is to develop consensus in its own stakeholder process for “many interrelated issues,” it said.

The Electric Power Supply Association also weighed in on the issue last week, expressing support for NEPGA and chastising the RTO for its reversal. “EPSA does not believe that the commission intended the ISO-NE to receive a free pass on this issue,” it wrote.

In its reply to NEPGA, filed July 2, ISO-NE said the generators’ motion should be dismissed on procedural and substantive grounds.

“NEPGA’s proposed zonal demand curve design using potential FCA 10 capacity zone boundaries shows dramatically worse performance,” it said.

NEPGA had asked for a Section 206 proceeding, but the RTO said “it falls far short of what is required under the commission’s rules to initiate a proceeding.”

July 13, 2015June 15, 2023

SPP Moving to 9:30 Day-Ahead Close

By Tom Kleckner

SPP’s Markets and Operations Policy Committee will vote this week on a recommendation to move the deadline for day-ahead market offers up 90 minutes to 9:30 a.m. CT.

The proposal, which has cleared four lower stakeholder groups, would have day-ahead results posted at 2 p.m. CT, up from 4 p.m. It also shortens the reoffer period to 45 minutes, with reliability unit commitment (RUC) offers due at 2:45 and results posted by 5:15.

The changes to SPP’s operating tariff are intended to comply with the Federal Energy Regulatory Commission’s Order 809, which moved the timely nomination cycle deadline for gas to 1 p.m. CT from 11:30 a.m. and added a third intraday nomination cycle. The commission ordered RTOs to adjust the posting of their day-ahead energy market and reliability unit commitment process results “sufficiently in advance” of the revised gas cycles, or explain why it is not suitable for their markets. (See SPP Trying to ‘Balance the Risk’ on Gas-Electric Schedules.)

‘Incremental’ Improvement

The revised timeline would not provide day-ahead market results before the 1 p.m. CT nomination deadline, but it would provide 30 minutes before the Intraday 2 nomination. RUC results would be available 45 minutes before the 6 p.m. evening gas nomination.

The proposal has already been endorsed by majorities in the Gas Electric Coordination Task Force (4-2 with two abstentions); the Market Working Group (7-5-5); Regional Tariff Working Group (14-2-3); and Operating Reliability Working Group (9-1-1).

The task force’s recommendation termed the changes “an incremental improvement over the existing timeline for improving coordination between the market results and the Timely and Evening nominations.” The group also said the changes will allow for day-ahead market and reliability unit commitments to be provided before the evening nomination and sufficient time in the morning for “price formation” before the day-ahead market closes.

SPP estimates it will take approximately $1.5 million and 14 months to implement the current changes, which would require FERC’s approval of the tariff changes and new software implementation. RTO officials’ long-term goal is to post day-ahead market results before the timely gas nomination.

Opposition in the North

The change was opposed by several members in SPP’s north, where cold weather affects natural gas supplies during critical time frames, including Lincoln Electric and the Omaha and Nebraska public power districts.

In stating its opposition, Nebraska Public Power District said SPP and its members should have taken their timeline concerns to FERC before developing a revision request. “Spending $1.5 million and not [getting] what we need … actually could make it worse for the market overall,” NPPD said.

NPPD and City Utilities of Springfield also said the change would hurt forecast accuracy, particularly for wind generation.

Springfield noted that SPP has a large share of intermittent wind generation — making forecasts especially important —while experiencing fewer gas constraints than eastern RTOs.

“The greatest benefits of [the change] impact less than 10 days a year (3%) at the detriment of the remaining 355 days,” Springfield said. “SPP has a relatively small percentage of gas generation in their average stack and a ~40% capacity benefit margin, which provides needed cushion in the current construct.”

July 13, 2015June 15, 2023

Northern Additions Boost SPP Membership to 90

SPP used social media recently to announce its membership had hit 90 with the addition of three cooperatives and an investor-owned utility that joined the RTO as part of the Integrated System.

East River Electric Power Cooperative is a wholesale supply cooperative serving 24 rural electric co-ops and one municipally owned electric system with a total of more than 92,000 homes and businesses. The cooperative has a 40,000-square-mile service area covering 63 primarily rural counties in eastern South Dakota and western Minnesota.
Northwest Iowa Power Cooperative is a generation and transmission cooperative supplying wholesale power to seven distribution co-ops serving more than 30,000 members and consumers. It covers 6,500 square miles in western Iowa.
Corn Belt Power Cooperative, another G&T cooperative, provides energy to nine distribution co-ops and a municipal co-op in 41 counties in northern Iowa.
NorthWestern Energy is an investor-owned utility providing electricity and natural gas to about 692,600 customers in Montana, South Dakota and Nebraska. It owns and operates wind, water, natural gas and coal-fired generation and delivers electricity to more than 416,100 customers.

SPP began coordinating transmission for the Integrated System on June 1. Full membership is expected in October. SPP has members from 14 states and 48,537 miles of transmission; the newest members will give SPP approximately 60,000 miles of transmission, stretching from northwest Louisiana, across the Great Plains to western Montana.