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Monthly Archives: December 2016

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Judge: Duke Energy doesn't owe $350 million for scuttled nuclear plant

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CHARLOTTE, N.C. (AP) — A federal judge has ruled Duke Energy doesn’t have to pay $350 million sought by Westinghouse Electric Co. over scuttled plans to build a nuclear plant in Florida.

The ruling on Dec. 22 by U.S. District Judge Max Cogburn says Duke Energy owes $34 million in fees and interest for ending the contract for Westinghouse to design and build the Levy County plant.

But Cogburn ruled the additional $352 million sought by Westinghouse fell outside of agreed-upon termination costs in that contract. He said that amounted to development costs for nuclear power technology from a separate agreement that Duke Energy lawfully exited.

The Levy County deal was struck in 2008 by Progress Energy, which Duke later bought. The contract was formally ended in 2014 after problems with federal licenses.

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Southern Co. unit strikes wind power development agreement

Category : Uncategorized

As part of the company’s renewable development strategy, Southern Co. unit Southern Power announced a joint development agreement with Renewable Energy Systems Americas to develop and construct about 3,000 MW across 10 projects with commercial operation dates between 2018 and 2020.

Additionally, Southern Power has signed agreements to purchase wind turbine equipment from both Siemens and Vestas for use at the facilities.

“Southern Power has a long-standing history of partnering with major equipment manufacturers and developers while growing one of the nation’s largest wholesale green energy portfolios,” said Southern Power President and CEO Buzz Miller. “We now have priority access to a robust, visible development pipeline and a supply chain for turbines from two premier technology providers, reinforcing our focus on wind energy investments over the next several years.”

The wind turbine equipment purchased from both Siemens and Vestas will be used to secure current tax benefits for the identified projects. RES will serve as the lead developer and balance-of-plant provider for projects that are expected to use the equipment. This strategic arrangement allows for Southern Power to serve as co-developer for future projects.

This transaction further distinguishes Southern Power from other wholesale energy companies and expands upon its business strategy of growing its business through the acquisition, development and construction of generating assets substantially covered by long-term contracts.

Southern Power owns more than 3,000 MW of renewable generation across 35 solar, wind and biomass facilities either announced, acquired or under construction. In total, the Southern Co. system has added or announced more than 4,000 MW of renewable generation since 2012.

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NEI asks incoming Trump administration to promote nuclear power

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Despite the Obama administration’s commitment to curb carbon dioxide (CO2) emissions from the power sector, there have been many nuclear plant retirement announcements in recent years.

Now the Nuclear Energy Institute (NEI), is asking the incoming Donald Trump administration to take steps to both improve the economic prospects of the existing domestic fleet and improve the chances for new nuclear reactors.

The energy sector has always been heavily shaped by government policy, NEI said in its policy memorandum to the Trump administration.

Several key policies are needed in the immediate future and in the longer term to ensure the benefits of nuclear power for the long-term, NEI said.

Government at all levels should rewrite policy to have federal agencies buy nuclear power when they buy other forms of zero carbon energy.

The previous administration’s Executive Order 13693, a clean air strategy which requires the federal government to buy more renewable energy, should be rewritten by the White House to allow nuclear energy to participate, NEI said.

NEI also states should be encouraged to have renewable portfolio standards (RPS) become clean power standards.

NEI said the Federal Energy Regulatory Commission (FERC): Existing reactors must be recognized for all the benefits they bring to the electric system, through the following changes:

·      FERC should clarify that its requirement for “just and reasonable” rates that are not “unduly discriminatory or preferential” implies compensation for all of these benefits: high reliability and availability, increased grid resiliency due to operability under all weather conditions and no need for continuous fuel supply, and virtually zero emissions.

·      FERC should work with the Independent System Operators and Regional Transmission Organizations to ensure that the competitive markets fully value all the attributes of existing nuclear plants, and the services they provide to the grid.

·      FERC should address flaws in the structure of the markets it governs. Among these, the system makes “uplift” payments to generators that are not economic but are needed to assure reliability, but the cost of those payments does not enter into the price paid to other producers, including reactors.

·      The agency should make clear that generation sources that by their nature tend to stabilize electricity prices and limit the risks from fuel price volatility should be compensated for protecting consumers by improving the diversity of the system.

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Diablo Canyon nuclear plant cited for cooling system problem

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SAN LUIS OBISPO, Calif. (AP) — Federal regulators have cited the Diablo Canyon nuclear power plant for a problem that may have knocked out a reactor cooling system for a year-and-a-half.

The Tribune of San Luis Obispo says the Nuclear Regulatory Commission issued a “white finding” on Thursday. That color-coding means the problem created a low-to-moderate safety risk at the Central California nuclear plant.

During a test in May, workers found that an emergency cooling system for one of the two reactors wasn’t working — and may not have been operating since it was last checked in October 2014.

The problem was traced to an improperly installed switch.

A spokesman says the plant operator, Pacific Gas & Electric, has corrected the problem and it plans to appeal the NRC finding.

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Arizona Commission overhauls rules for net metering, distributed generation

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The Arizona Corporation Commission voted 4 to 1 on Dec. 21 to restructure how distributed generation is compensated and paid for in Arizona.

The commission said in a news release that the move to replace net metering is laying the foundation to invigorate renewable energy technologies while providing equity to all customers.

The decision comes after a three-year investigation into the value and cost of solar power which included input from a broad coalition of solar power, utility, consumer advocates and customers.

Under net metering policy adopted in 2009, customers were given full retail credit for the power they generate and can sell back the excess at wholesale. Those rules will be grandfathered for the existing customers.

The new methodologies will take into account wholesale rates which reflect what utilities pay for solar energy from large plants. Both methods will be established in rate cases and updated annually and promote a gradual change in export rate not to change more than 10 percent from year to year.

Customers with DG systems that are subject to the new DG export rate will have that rate locked in for 10 years. Further, the order permits persons who purchase a home with a DG system subject to the 10-year rate to “inherit” the remaining years of that locked in rate.

“Existing solar customers can rest assured that their investment is safe,” said Commissioner Andy Tobin. “Our decision recognizes those customers while taking the next step by determining rates which take into account advancements in solar and other renewable technology which helps us push forward proactively,” Tobin said.

Commissioner Bob Burns dissented from the decision. “In my view, this decision did not get to where I needed it to be in order to support it. Future solar customers should have their solar export rate grandfathered for 20 years, not 10 years, just like what was approved for existing customers,” Burns said.

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ESC Harrison kicks off permitting for 640 MW, gas-fired project in West Virginia

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ESC Harrison County Power applied Nov. 22 at the West Virginia Department of Environmental Protection for an air permit allowing it to construct, install, and operate a new natural gas fired combined-cycle combustion turbine power plant, to be located near the city of Clarksburg, Harrison County, West Virginia.

The application was recently posted to the department’s website. ESC said it would like DEP air permit approval by October 2017 to provide sufficient time for financing, equipment ordering, fabrication, construction, and installation, and achieving commercial operation by June 2020. This project would have a nominal gross electrical generating capacity of 640 MW.

The project site is zoned for industrial use, and provides multiple strategic advantages that will allow the plant to produce low-cost baseload electricity, the application said. The proposed primary point of interconnection is a direct 138-kV interconnection to the FirstEnergy/Allegheny Power existing Glen Falls 138-kV substation, situated about two miles north of the project site. Plant output will be sold into the PJM Interconnection regional electric grid.

This new plant requires pre-construction approval of an air permit under the federal Prevention of Significant Deterioration (PSD) program and under the DEP’s regulations. The emission sources associated with the project are:

·      One General Electric Frame 7HA.02 advanced combined-cycle turbine, with a heat recovery steam generator equipped with duct burners, both firing pipeline quality natural gas;

·      One auxiliary boiler with a maximum heat input of 77.8 million British Thermal Units per hour (MMBtu/hr) which will burn pipeline quality natural gas;

·      One fuel gas heater with a maximum heat input of 5.5 MMBtu/hr which will burn pipeline quality natural gas;

·      One 2,000-kW emergency generator fueled by ultra-low-sulfur diesel (ULSD) fuel;

·      One 315 horsepower (hp) emergency fire water pump fueled by ULSD; and

·      Diesel fuel, lubricating oil, and aqueous ammonia storage tanks.

Cooling of the plant’s steam driven electric generator will be achieved using a dry air cooled condenser.

Electricity will be generated using the one combined-cycle turbine, with a design maximum heat input of about 3,496.2 million British Thermal Units per hour (MMBtu/hr), on a higher heating value basis. The turbine will drive a generator to produce electricity. The electricity generated by the turbine will be routed through a local electrical substation and sold on the grid. The highly efficient combined-cycle turbine (HCCT-1) will be equipped with an inlet evaporative cooling system used at higher ambient temperatures to increase the density of the combustion air, thereby increasing fuel and mass flow and, in turn, power output. The air density increase will be accomplished by evaporating water into the inlet air, which will decrease air temperature and correspondingly increase air density.

The project includes the installation of DB to produce additional steam in the HRSG for additional power output from the steam turbine generator. The maximum duct firing level is expected to be 1,001.3 MMBtu/hr on a HHV basis. The fuel for the DBs will be the same as for the turbine: pipeline-quality natural gas. Steam generated in the HRSG is routed to a steam driven turbine with a dedicated electric generator.

The turbine will be equipped with dry low-NOx combustors. These combustion controls, along with Selective Catalytic Reduction systems, will control emissions of nitrogen oxides from the turbine. An oxidation catalyst will be used to control carbon monoxide and volatile organic compounds emissions from the turbine. The SCR and oxidation catalyst will be incorporated into the HRSG, at locations where the emission control reactions optimally occur.

SCR involves the injection of aqueous ammonia with a concentration of less than 20 percent by weight into the turbine /DBs exhaust gas stream. Ammonia reacts with NOx in the turbine exhaust gas stream, reducing it to elemental nitrogen and water vapor. The aqueous ammonia will be stored on-site in one storage tank with a capacity of about 35,000 gallons.

The turbine/DB will have its own exhaust stack, which is expected to have a height of 205 feet above grade. For permitting and emissions estimating purposes, this application assumes that the turbine /DBs will operate 8,760 hours per year.

Notable is that the attorneys for ESC Harrison County Power filed a Nov. 14 notice with the West Virginia Public Service Commission that ESC Harrison intends to file no sooner than 30 days from the date of this notice an application for a siting certificate for this project. That application had not been filed as of Dec. 20.

This project was also the subject of a May 2016 study from PJM. For this project, which has PJM queue #AA2-119, the connection to ESC Harrison’s facilities will be provided through a direct connection to the 138-kV bus in the Glen Falls substation. The intent of this System Impact Study is to determine a plan, with approximate cost and construction time estimates, to connect the subject generation interconnection project to the PJM network at a location specified by the power project developer. It is a mid-point in a queue process that eventually leads to an Interconnection Service Agreement. The project entered the queue in April 2015.

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Duke Energy completes sale of international business in Brazil

Category : Uncategorized

Duke Energy completed the previously announced sale of its international business in Brazil to China Three Gorges Corp. for nearly $1.2 billion enterprise value.

The company is exiting the Latin American market to focus on its domestic regulated business, which was further bolstered by the acquisition of Piedmont Natural Gas.

Duke Energy announced the sale of its Brazil assets to China Three Gorges Corp. and the sale of its remaining Latin American assets — in Peru, Chile, Ecuador, Guatemala, El Salvador and Argentina — to I Squared Capital in Oct. 2016. The I Squared Capital sale was completed on Dec. 20, 2016.

“Today marks a significant milestone in the strategic transformation of our company,” said Duke Energy chairman, president and CEO Lynn Good. “We completed these transactions ahead of schedule and are now fully focused on growing our regulated businesses in 2017 and beyond, including the natural gas platform.”

The transactions with China Three Gorges Corp. and I Squared Capital are expected to generate available cash proceeds of nearly $1.9 billion, excluding transaction costs and subject to working capital adjustments, which will be used to reduce Duke Energy holding company debt. Existing federal tax attributes will result in no immediate U.S. tax impacts.

China Three Gorges Corp. is acquiring Duke Energy assets consisting of 10 hydroelectric generation plants — eight plants totaling 2,057 MW on the border between Sao Paulo and Parana states; and two plants totaling 33 MW on the Sapucai Mirim River in Sao Paulo state.

Duke Energy’s 25 percent equity investment in National Methanol Company – a Saudi Arabian regional producer of methanol and methyl tertiary butyl ether (MTBE), a gasoline additive – is not included in the sales to China Three Gorges Corp. and I Squared Capital.

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Indiana OKs upgrades at Duke Energy Indiana's Markland Hydro Station

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Greater energy output, new equipment and improved reliability are just some of the advantages of the upgrade and modernization project approved by state regulators for Duke Energy Indiana’s Markland Hydro Station near Florence, Ind., along the Ohio River.

The Indiana Utility Regulatory Commission approved the project on Dec. 14, following a settlement agreement that was reached with the Indiana Office of Utility Consumer Counselor.

“We are pleased with the commission’s decision that allows us to keep the Markland Hydro Station operating for many more years,” said Melody Birmingham-Byrd, state president of Duke Energy Indiana. “The low-cost, carbon-free power generated at Markland is an important part of our diversified portfolio of generation sources.”

“The agreement that received commission approval in this case is the result of good-faith negotiations between the OUCC and Duke Energy,” said Indiana Utility Consumer Counselor David Stippler. “The order ensures that Duke Energy’s customers will continue to benefit from this renewable energy source that has served them dependably for many years, while doing so at a reasonable cost.”

The station’s three hydroelectric generators, turbines and associated equipment, which have been in service for nearly 50 years, will be upgraded and modernized one at a time, beginning in 2017. The total project is expected to take about four years and will cost about $152 million. After the project is completed, the station’s energy output will increase by about 10 percent.

Duke Energy Indiana’s operations provide about 7,100 MW of owned electric capacity to about 810,000 customers in a 23,000-square-mile service area, making it the state’s largest electric supplier.

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Retired nuke plant cleanup may be speeded up

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VERNON, Vt. (AP) — The company that is looking to buy the closed Vermont Yankee nuclear plant says it hopes to demolish it and clean up the site more than 30 years sooner than its current owner had planned.

NorthStar Group Services Inc. recently told state regulators it hopes to finish the job by 2026, more than 30 years sooner than current owner Entergy Corp.

NorthStar and Entergy Corp. say NorthStar and its partners have experience in decommissioning projects and can handle the job efficiently.

NorthStar told regulators it can demolish the Vernon reactor for about $430 million less than Entergy Nuclear’s estimate of $1.24 billion, the Rutland Herald reported.

“In short, a company like Entergy is the right owners for an operating nuclear plant, but NorthStar is the right owner for a decommissioning plant,” Scott State, the CEO of NorthStar, said in testimony filed at the board.

NorthStar said it expects the costs to include $511.1 million for demolition and clean up, $287.8 million for the handling and storage of the high-level radioactive fuel waste, and $12.6 million for returning the Vernon property to “green field” status.

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EDF Renewable Energy to sell 300 MW in wind power projects

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Southern Co. unit Southern Power has closed on purchase and sale agreements to buy 100 percent ownership interest in the 174 MW Salt Fork Wind Project and the 126 MW Tyler Bluff Wind Project from EDF Renewable Energy. Both projects have achieved commercial operation.

The Salt Fork Wind Project, located in Donley and Gray Counties, Texas, consists of 87 wind turbines manufactured by Vestas. The electricity and associated renewable energy credits generated by the facility will be sold under separate, long-term contracts. The city of Garland has signed a long-term power purchase agreement for 150 MW, and Salesforce has signed an agreement for 24 MW.

The Tyler Bluff Wind Facility, located in Cooke County, Texas, consists of 52 wind turbines manufactured by Siemens. The majority of the facility’s output is covered by an agreement with Procter & Gamble, allowing the company to offset 100 percent of the electricity needed for all its North American based Fabric & Home Care plants where products such as Tide, Downy and Febreze are manufactured.

“The EDF RE team is pleased to forge a new business relationship with Southern Power through these transactions. We are confident that our expertise as a developer, construction manager and operator complements Southern Power’s strategy to grow its wholesale business through the acquisition of renewable assets covered by long-term contracts,” commented Raphael Declercq, Vice President of Portfolio Strategy. “The sale of a portion of our assets represents an integral part of our business model to maintain a balance between growing our own portfolio while continuing to help fund the development of new projects.”

EDF Renewable Services, the operations and maintenance subsidiary of EDF RE, will provide balance-of-plant services for the projects.

EDF Renewable Energy is one of the largest renewable energy developers in North America with 8 gigawatts of wind, solar, storage, biomass and biogas projects developed throughout the U.S., Canada, and Mexico.

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