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AEP delivered a total shareholder return of nearly 12 percent in 2016 and increased its quarterly dividend 5.4 percent. The company's transmission business contributed 54 cents per share to earnings in 2016, up 38 percent from 2015. "We are well-positioned as a premier regulated energy company that delivers strong financial results for our shareholders. The investments we're making in our core regulated businesses, along with our proven track record of cost discipline, will support our operating earnings growth rate of 5 percent to 7 percent," Akins said. Akins also discussed AEP's new logo and brand identity, which were unveiled in March. He praised the passion of the company's 17,600 employees in working to create a brighter future for the customers and communities AEP serves. "Our employees are committed to making sure our customers have the safe, reliable and increasingly clean energy they need to power their lives. Together, we are developing new and innovative energy solutions to meet our customers' expectations, strengthening our communities and redefining the future of energy," Akins said. In business items at the annual shareholders meeting, AEP shareholders elected 12 directors. Directors re-elected to the board are: Nicholas K. Akins, 56, of Dublin, Ohio; David J. Anderson, 67, of Greenwich, Conn.; J. Barnie Beasley Jr., 65, of Sylvania, Ga.; Ralph D. Crosby Jr., 69, of McLean, Va.; Linda A. Goodspeed, 55, of Marco Island, Fla.; Thomas E. Hoaglin, 67, of Columbus, Ohio; Sandra Beach Lin, 59, of Flower Mound, Texas; Richard C. Notebaert, 69, of Chicago; Lionel L. Nowell III, 62, of Marco Island, Fla.; Stephen S. Rasmussen, 64, of Columbus, Ohio; Oliver G. Richard III, 64, of Lake Charles, La.; and Sara Martinez Tucker, 61, of Dallas. Approximately 97 percent of shares voted to reapprove the material terms of AEP's senior officer incentive plan. Approximately 99 percent of shares voted ratified the firm of PricewaterhouseCoopers LLP as AEP's independent public accounting firm for 2017. Approximately 85 percent of shares voted indicated support for AEP's executive officer compensation program. Approximately 89 percent of shares voted in support of continuing to hold an advisory vote on executive compensation once a year. American Electric Power is one of the largest electric utilities in the United States, delivering electricity and custom energy solutions to nearly 5.4 million customers in 11 states. AEP owns the nation's largest electricity transmission system, a more than 40,000-mile network that includes more 765-kilovolt extra-high voltage transmission lines than all other U.S. transmission systems combined. AEP also operates 224,000 miles of distribution lines. AEP ranks among the nation's largest generators of electricity, owning approximately 26,000 megawatts of generating capacity in the U.S. AEP supplies 3,200 megawatts of renewable energy to customers. AEP's utility units operate as AEP Ohio, AEP Texas, Appalachian Power (in Virginia and West Virginia), AEP Appalachian Power (in Tennessee), Indiana Michigan Power, Kentucky Power, Public Service Company of Oklahoma, and Southwestern Electric Power Company (in Arkansas, Louisiana and east Texas). AEP's headquarters are in Columbus, Ohio. This report made by American Electric Power and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its Registrant Subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are: the economic climate, growth or contraction within and changes in market demand and demographic patterns in AEP's service territory; inflationary or deflationary interest rate trends; volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt; the availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material; electric load, customer growth and the impact of competition, including competition for retail customers; weather conditions, including storms and drought conditions, and AEP's ability to recover significant storm restoration costs; the cost of fuel and its transportation and the creditworthiness and performance of fuel suppliers and transporters; availability of necessary generating capacity and the performance of AEP's generating plants; AEP's ability to recover fuel and other energy costs through regulated or competitive electric rates; AEP's ability to build transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs; new legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances that could impact the continued operation, cost recovery, and/or profitability of AEP's generation plants and related assets; evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel; a reduction in the federal statutory tax rate that could result in an accelerated return of deferred federal income taxes to customers; timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance; resolution of litigation; AEP's ability to constrain operation and maintenance costs; AEP's ability to develop and execute a strategy based on a view regarding prices of electricity and gas; prices and demand for power generated and sold at wholesale; changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation; AEP's ability to recover through rates or market prices any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives; volatility and changes in markets for capacity and electricity, coal, and other energy-related commodities, particularly changes in the price of natural gas and capacity auction returns; changes in utility regulation and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP; the market for generation in Ohio and PJM and the ability to recover investments in Ohio generation assets; AEP's ability to successfully and profitably manage competitive generation assets, including the evaluation and execution of strategic alternatives for these assets as some of the alternatives could result in a loss; changes in the creditworthiness of the counterparties with whom AEP has contractual arrangements, including participants in the energy trading market; actions of rating agencies, including changes in the ratings of AEP debt; the impact of volatility in the capital markets on the value of the investments held by AEP's pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements; accounting pronouncements periodically issued by accounting standard-setting bodies; and other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events. To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/aep-investing-in-smarter-energy-grid-and-new-technologies-for-customers-shareholders-learn-at-companys-annual-meeting-300445230.html


California’s push to make aggregated distributed energy resources into transmission grid market players is the most developed in the country. But it’s still about a year from going live in a big way. It’s also facing some key challenges, like getting approval -- or at least “concurrence” -- from the utilities that run the distribution grids where these newly minted DER providers will carry out their megawatt-scale energy shifting acts. And then there’s the question of whether distributed energy resources (DERs) will be worth more at wholesale than they are under California’s new distribution grid values -- or whether those values can be stacked together. All of this uncertainty hasn’t stopped companies from applying for the job. Lorenzo Kristov, market and infrastructure principal at state grid operator CAISO, said at last week's California’s Distributed Energy Future 2017 conference in San Francisco that several companies have already submitted applications to become DER providers under the new program. “I’d imagine they’re in the process of developing their actual resources they’ll be providing in the market,” he said. Kristov didn’t name the companies involved. But a November 2016 report from CAISO to the Federal Energy Regulatory Commission does name four companies that have signed up for a “pro forma distributed energy resource provider agreement” -- the first step in becoming a distributed energy resource provider, or DERP. One was utility San Diego Gas & Electric, which proposed a 3- to 4-megawatt aggregation of energy storage sites across its territory -- the largest of the four proposed projects. SDG&E proposed a 2018 start date. Another was Apparent Energy, which said it was ready to launch in early 2017, working with Silicon Valley Power and Palo Alto’s municipal utility on two aggregations of 1 to 1.5 megawatts each. But a December report from Silicon Valley Power noted that Apparent “could not make a business case in SVP territory” at that time, although “as DG resources potentially grow and as the CAISO markets evolve, there could be potential.” A third was Galt Power, a participant in other North American transmission markets, which proposed working with energy developer Customized Energy Solutions. The companies are “in discussions with several entities seeking to aggregate renewables and small-scale storage.” Finally, there was Olivine, a scheduling coordinator that serves as an intermediary between CAISO and DER providers, which is “working with a number of clients, including municipalities, community choice aggregators, and resource owners.” Because every would-be DERP has to work through a scheduling coordinator, it’s hard to know which of Olivine’s clients might be involved in the company’s application. Olivine is also involved in the Demand Response Auction Mechanism, or DRAM, pilot program, which has so far put together more than 100 megawatts of DER resources from companies including Stem, Advanced Microgrid Solutions, EnergyHub, Ohmconnect and AutoGrid. CAISO’s report notes that Olivine is “considering the addition of distributed energy resources and the potential conversion of storage and electric vehicle assets currently participating as demand response resources,” indicating that some of these DRAM clients could also be eyeing their potential as DERPs. CAISO just published its “new resource implementation process” on its DERP website this week, opening up the potential for more applications. Last summer, after years of effort, CAISO got federal approval for its new distributed energy resource provider tariff. It allows for DERPs to submit aggregations of between 500 kilowatts and 10 megawatts that can meet the requirements for its day-ahead and hourly energy markets, or its faster-responding ancillary services markets. Since then, California’s efforts have helped jump-start bigger changes. In October, FERC issued a ruling that opened the option of aggregated DERs for the rest of the country’s independent system operators (ISOs) or regional transmission organizations (RTOs), opening a vast new potential market. That’s only potential, though. It can take years for FERC orders like these to make their way through grid operator technical working groups and stakeholder proceedings and into real-world markets. No other region is as far along as California right now, although mid-Atlantic grid operator PJM has opened a discussion, or a “problem statement” in its terminology, and Texas grid operator ERCOT, which is outside FERC’s jurisdiction, has held an on-again, off-again discussion on the subject. Applying for DERP status is only the first step in a multi-stage process, Kristov noted. CAISO’s recently released “new resource implementation process” includes a 43-item list of requirements involving interconnection, metering, telemetry, topology and other such technical details. Once those are completed, it will take months more to process and verify each aggregation, he said. In the meantime, CAISO is busy working with the California Public Utilities Commission and utilities in the state on another challenge -- getting more visibility between transmission and distribution grids. “The ISO only sees the system down to the transmission-distribution interface,” or the transmission substations that connect the state’s high-voltage grid with the distribution grid. “Even if we have telemetry to some of the devices, we don’t have the distribution system data," said Kristov. That can cause problems in two directions, Kristov said. For the distribution utility, there’s the prospect of half a megawatt or more of load suddenly dropping away or coming on-line under CAISO dispatch, causing local grid instability. FERC’s order this fall specified that distribution utilities have the right to review the composition of these DER aggregations. To solve that problem right now, CAISO requires each DERP to “obtain concurrence from the applicable utility distribution company (UDC) or metered sub-system (MSS)” to alleviate concerns, involving a utility-by-utility process that takes up to 30 business days. In the other direction, CAISO needs to worry about distribution grid topologies, or states of network interconnection, he said. California’s transmission system is pretty stable topologically -- it doesn’t see major switches and shifts in the flow of power. “But in distribution, they’re having changes in topology all the time, they’re switching circuits,” he said, and “that can affect whether a DER can respond to a dispatch or not.” Both of these problems could be addressed by better visibility and data-sharing between utilities and CAISO, he noted. “The ISO could provide those dispatch instructions to the distribution company, and the distribution company could know...‘Oh, that’s where it is; it’s going to happen 5 minutes from now -- will that cause a problem for us?’” California’s utilities are arguably ahead of many in the country in terms of visibility into their distribution grids, with widely deployed smart meters and multiple pilot projects integrating DERs into the software and control systems that run their low-voltage networks. But they’ve still got a long way to go, as evidenced by the multibillion-dollar grid modernization investments utilities are asking the CPUC to approve for the coming years. The state’s big investor-owned utilities are also mapping out their distribution grids to find the value of DERs as part of their multibillion-dollar annual capital investment budgets, under the CPUC’s distribution resources plan and integration of distributed energy resources proceedings. This process will create valuable data for CAISO as well as the utilities, Kristov noted. Indeed, the value of DERs for local grid needs may well exceed the value they can realize on wholesale energy and ancillary services markets, he said. “DER substituting for distribution assets is probably more promising than DER substituting for transmission assets,” explained Kristov -- an observation backed up by a Lawrence Berkeley National Laboratory analysis of the state’s future energy needs. At the same time, CAISO does see great value in DERs that can help it manage the "duck curve" imbalances that solar power is causing on California’s grid, he said. “That problem can be solved very well at the distribution level.” But “not all the value has been clearly monetized in terms of services to be able to do that.”


News Article | April 19, 2017
Site: www.aweablog.org

Wind power became the largest source of renewable generating capacity and supplied record amounts of wind energy to many parts of the country. Strong wind project construction, a growing manufacturing sector, and the increasing need for wind turbine technicians and operators allowed the industry to add jobs at a rate nine times faster than the overall job market, as wind employment grew to a record 102,500. Technology advances resulted in more productive turbines, with recent generations achieving average capacity factors over 40 percent, all while costs continued to fall. And the industry saw the installation of the country’s first offshore wind project off the coast of Rhode Island. Here are the top 11 wind industry trends in 2016: 2. WIND #1 SOURCE OF RENEWABLE GENERATING CAPACITY: Wind energy passed hydroelectric power to become the number one source of renewable generating capacity in 2016. With federal policy stability secured, the U.S. wind industry installed 8,203 megawatts (MW) in 2016 and the industry now has 82,143 MW installed overall, enough wind power for the equivalent of 24 million American homes. 3. GENERATION RECORDS SET: Wind energy delivered over 30 percent of the electricity produced in Iowa and South Dakota in 2016. Kansas, Oklahoma, and North Dakota generated over 20 percent of their electricity from wind, while 20 states now produce more than 5 percent of their electricity from wind energy. ERCOT, the main grid operator for most of Texas, and SPP, which operates across parts of 14 states, competed for new wind power penetration records throughout 2016, both topping 50 percent wind energy on several occasions. 4. U.S. MANUFACTURING SECTOR GROWTH: Wind energy continues to fuel the domestic manufacturing sector, with over 500 factories across 41 states producing components for the U.S. wind industry in 2016. Domestic wind-related manufacturing jobs grew 17 percent to over 25,000 as three new factories began supplying the wind industry and five plants expanded production. 5. TECHNOLOGY BOOSTS PRODUCTIVITY: Technological advances allow wind turbines to reach stronger, steadier winds, and more sophisticated control systems are increasing the amount of electricity modern wind turbines generate. Wind turbines built in 2014 and 2015 achieved capacity factors over 40 percent during 2016. At the same time, the cost of wind energy dropped over 66 percent between 2009 and 2016. 7. RECORD WIND ENTERS QUEUE: 67 gigawatts of newly proposed wind projects were added to interconnection queues in 2016, the largest since the addition of 67.3 GW in 2009. This brings total wind capacity in the queues to 136.8 GW, the highest level in five years. 10. WIND REDUCES EMISSIONS AND SAVES WATER: Operational wind projects avoided 393 million pounds of sulfur dioxide and 243 million pounds of nitrogen oxide. These pollutants create smog and trigger asthma attacks, so reducing them save $7.4 billion in public health costs last year. Meanwhile, operating wind projects avoided the consumption of 87 billion gallons of water, equivalent to 266 gallons per person in the U.S.


News Article | May 25, 2017
Site: www.aweablog.org

Grid reliability, security and diversity: Another way wind works for America “What happens when the wind doesn’t blow or the sun doesn’t shine?” That’s a common question from those wanting to understand how grid operators integrate renewable energy. Fortunately, the experts who keep the lights on every day find they can reliably handle large amounts of wind and solar energy. Grid operators have always balanced major shifts in supply and demand. Factories, air conditioners and appliances turn on and off in waves, varying by time of day and season. Major spikes occur from events as simple as halftime during a football game, when millions of refrigerator doors open. Large coal, gas, and nuclear power plants can also break down unexpectedly, suddenly removing significant amounts of electricity from the system. Meanwhile, spread across 41 states, the output of America’s 53,000 utility-scale wind turbines stays relatively constant. Changes are slow and predictable based on weather forecasting, and are mostly canceled out by far greater variations in demand and other supply. It’s generally more expensive for grid operators to accommodate the abrupt loss of a large conventional generator, because that requires keeping fast-acting backup resources “spinning” 24/7. A prime example occurred during 2014’s Polar Vortex weather event. The bitter cold and loss of gas supply forced many conventional power plants to shut down abruptly. At the same time, high demand for home heating sent natural gas prices and electricity prices skyrocketing. However, wind turbines kept reliably generating electricity, saving Great Lakes and Mid-Atlantic consumers over $1 billion in two days. The U.S. has enough installed wind power to supply the equivalent of 25 million homes. So utilities and grid operators have already had ample opportunity to figure out how to integrate wind energy. Xcel Energy’s Colorado Balancing Authority already runs on 20 percent renewable energy. ERCOT in Texas got 15 percent of its electricity from wind in 2016. The Southwest Power Pool (SPP), grid manager across parts of 14 states, is nearing 20 percent wind year-round — and just peaked at 54 percent wind earlier this year. PJM, the country’s largest grid operator, recently found it could handle over 75 percent wind power reliably. “Ten years ago we thought hitting even a 25 percent wind-penetration level would be extremely challenging, and any more than that would pose serious threats to reliability,” said Bruce Rew, SPP’s vice president of operations. “Now we have the ability to reliably manage greater than 50 percent. It’s not even our ceiling.” Wind power remains on track to supply 10 percent of U.S. electricity by 2020, adding diversity, security and reliability to our electric grid. The men and women keeping our lights on already know wind works, and by helping ensure the country’s grid stays secure, wind works for all Americans.


News Article | May 25, 2017
Site: www.prweb.com

Cohesive Solutions has successfully completed a complex upgrade of IBM Maximo for a large Central Texas-based electric utility. The project was unique given its heavy emphasis on assessing organizational capabilities and practice standards for asset management along with the development and road-mapping of initiatives that focus on process improvement and maintenance optimization. The client sought a path and provider to transform their existing Enterprise Asset Management program while maintaining all of the vital services they provide Texans every day. This utility contributes reliable power to the Electric Reliability Council of the greater Texas (ERCOT) market. They ensure power is delivered through more than 5,000 miles of transmission lines, and work to increase/preserve the water supply for more than a million people. To meet the challenge of this complex environment, the client enlisted Cohesive Solutions following a competitive selection process. Cohesive has just completed the project by leading the users through an upgrade of Maximo V7.1 to Maximo V7.6, which includes several business process surveys, including an infrastructure analysis, performance improvement review, integrations with PeopleSoft, Datasplice and Workforce. The upgrade from Maximo V7.1 to Maximo V7.6 provides improved system stability, increasing functionality and securing future upgrade viability. Cohesive also served in a Change Management advisory role to help them absorb the change that was the result of the upgrade. “The technological demands our nation’s utility providers face are greater than ever. It is rewarding and encouraging to see our clients keep pace with advancements in Maximo and gain efficiencies through business process improvements. The result will be increased quality and reliability of service to their customers,” said Ross Poole, Project Manager, Cohesive Solutions. About Cohesive Solutions Cohesive Solutions, is a leading enterprise asset management consultant, certified Gold Level IBM Business Partner and systems integrator. Cohesive Solutions provides business transformation and consulting services that enable organizations to achieve higher asset ROI as well as deliver a unique EPM solution, Propel, that unlocks hidden potential while aligning business performance goals. Since 1990 Cohesive Solutions has provided world class services to North American organizations. Learn more at Cohesivesolutions.com.


News Article | May 29, 2017
Site: www.greentechmedia.com

With duck curves on the prowl and curtailment on the rise, there are dangers stalking utility-scale solar's natural habitat. Solar developer 8minutenergy wants to ward off these threats with large-scale energy storage. The company spent the past year quietly picking up staff with years of experience developing storage at California utilities, and recently revealed the new practice, with a pipeline of 1 gigawatt already in place. That quantity, though not yet finalized, dwarfs the 221 megawatts deployed across the U.S. last year. 8minutenergy worked its way up to 10th place on GTM Research's list of U.S. utility-scale solar developers. Now the team wants to incorporate storage into its expertise with wrangling land rights, interconnection and utility offtakers. Initial geographical targets include California, the Southwest, ERCOT and the Southeast. "It's really kind of an ideal storm with much lower prices, so these systems are much more cost-effective," said Steve McKenery, vice president of storage solutions. "We can do a solar-plus-storage project now at less than the cost of a new combustion gas turbine. That was not the case a few years ago." The company likes to focus on solar projects with 100 megawatts or more, to capture economies of scale. Going forward, a typical 100-megawatt PV project might come with 100 megawatts/400 megawatt-hours of storage. In fact, for the last year or so, all 8minutenergy developments have been designed to incorporate storage if desired; having land rights and interconnection already taken care of can speed up the storage deployment process. The primary market will be pairing storage alongside new solar projects. This captures the ITC for the storage, and makes the solar generation dispatchable. That serves the offtaker by guaranteeing clean power for several hours of peak demand, but it also serves to future-proof 8minutenergy's core product against increasing curtailment rates in California. If the company can deliver on that gas turbine-beating promise, it could open up lucrative capacity market revenue. There's also value to offer utilities in offsetting gas consumption for spinning reserves, said Carl Stills, vice president for storage integration. In a previous job working on storage at the Imperial Irrigation District, he saw how utilities spend thousands of dollars a day on gas to maintain spinning reserves. Storage can remain ready for instantaneous response without burning fuel. Storage on a major solar farm also serves a utility by increasing utilization of transmission infrastructure. "Utilities that build transmission lines out for solar areas really use the capacity for that eight hours a day," Stills said. "If you want to expand that out to include storage, if the price is right, you now are able to load up that line and optimize your transmission capacity. The clustering effect is huge." The company is also competing for standalone storage contracts where it serves a particular customer need. "We can utilize our land and interconnection status that we have on 8minutenergy-developed projects to have a place to build the storage project and interconnect it to the grid fairly quickly and at a competitive price," McKenery said. In the developer role, 8minutenergy will stay technology- and vendor-agnostic. The initial focus is on lithium-ion batteries from proven, bankable suppliers like LG Chem and Samsung SDI. The company maintains its own internal test facility, though, to verify the marketing claims of alternative solutions, like flow batteries and flywheels. "Lithium-ion is the technology for the next three to five years," McKenery said. "Beyond that, who knows? I hope somebody is able to come up with a better product for half the price." The storage team is examining ways to integrate batteries into the solar plan most efficiently. One idea is to employ DC-to-DC architecture, which would feed the solar output into the batteries before going through an inverter to reach the grid. This could potentially save on equipment costs and reduce round-trip efficiency losses compared to an AC architecture. The addition of energy storage expertise generates a new basis of competition among the small group of companies operating at the 100-megawatt PV scale, said Colin Smith, a utility-scale solar analyst at GTM Research. "This is what the industry's now demanding. If you look at it from an evolutionary standpoint, this is the landscape putting new forces and pressure on companies to change," he said. "It's become a forced differentiator in the industry."


News Article | May 24, 2017
Site: www.prnewswire.com

The Heart of Texas Wind Project, located approximately 125 miles northwest of Austin, will utilize Goldwind GW 121/2.5MW wind turbines. "RES is pleased to work with Goldwind again to sign the Heart of Texas sales transaction," said Brian Evans, Chief Development Officer of RES in the Americas. "This wind project will bring economic benefits to the Lone Star State, thus helping us meet our mission of providing a low carbon future for all." Goldwind Capital, a subsidiary of Xinjiang Goldwind Science & Technology Co., Ltd., provided bridge financing to acquire the project and is in the process of arranging a financing package in partnership with top-tier financial institutions that will include construction and tax equity financing and a long-term ERCOT fixed price hedge for power production. In April 2017, Goldwind received tax equity financing commitments from Berkshire Hathaway Energy and Citi for the approximately $250m Rattlesnake Wind Project. Goldwind Americas, headquartered in Chicago, is a world leading wind turbine technology and energy solutions provider. A wholly-owned subsidiary of Xinjiang Goldwind Science & Technology Co., Ltd (SZSE: 002202) (HK: 2208), Goldwind's revolutionary Permanent Magnet Direct Drive (PMDD) technology is shaping a new standard in wind energy. Goldwind Americas offers a full suite of innovative renewable energy solutions, including equipment sales, service, and capital. To learn more, visit www.goldwindamericas.com. To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/goldwind-americas-acquires-second-160mw-project-in-deal-with-res-300463210.html


News Article | May 9, 2017
Site: www.prnewswire.com

AEP already operates Conesville Plant and Dynegy operates Zimmer Plant so there will be no employment impact from the transaction. AEP now owns 92 percent, or 1,461 MW, of Conesville Plant. Dayton Power & Light owns the remaining 129 MW of Conesville Unit 4. AEP's other competitive generation assets in Ohio include 595 MW of Cardinal Plant, 603 MW of Stuart Plant and the 48 MW Racine Plant. Stuart Plant is expected to be retired by June 1, 2018. American Electric Power is one of the largest electric utilities in the United States, delivering electricity and custom energy solutions to nearly 5.4 million customers in 11 states. AEP owns the nation's largest electricity transmission system, a more than 40,000-mile network that includes more 765-kilovolt extra-high voltage transmission lines than all other U.S. transmission systems combined. AEP also operates 224,000 miles of distribution lines. AEP ranks among the nation's largest generators of electricity, owning approximately 26,000 megawatts of generating capacity in the U.S. AEP supplies 3,200 megawatts of renewable energy to customers. AEP's utility units operate as AEP Ohio, AEP Texas, Appalachian Power (in Virginia and West Virginia), AEP Appalachian Power (in Tennessee), Indiana Michigan Power, Kentucky Power, Public Service Company of Oklahoma, and Southwestern Electric Power Company (in Arkansas, Louisiana and east Texas). AEP's headquarters are in Columbus, Ohio. This report made by American Electric Power and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its Registrant Subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are: economic growth or contraction within and changes in market demand and demographic patterns in AEP service territories; inflationary or deflationary interest rate trends; volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt; the availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material; electric load and customer growth; weather conditions, including storms and drought conditions, and AEP's ability to recover significant storm restoration costs; the cost of fuel and its transportation and the creditworthiness and performance of fuel suppliers and transporters and the cost of storing and disposing of used fuel, including coal ash and spent nuclear fuel; availability of necessary generating capacity and the performance of AEP's generating plants; AEP's ability to recover fuel and other energy costs through regulated or competitive electric rates; AEP's ability to build transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs; new legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances that could impact the continued operation, cost recovery, and/or profitability of AEP's generation plants and related assets; evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel; a reduction in the federal statutory tax rate that could result in an accelerated return of deferred federal income taxes to customers; timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance; resolution of litigation; AEP's ability to constrain operation and maintenance costs; AEP's ability to develop and execute a strategy based on a view regarding prices of electricity and gas; prices and demand for power generated and sold at wholesale; changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation; AEP's ability to recover through rates any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives; volatility and changes in markets for capacity and electricity, coal, and other energy-related commodities, particularly changes in the price of natural gas; changes in utility regulation and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP; AEP's ability to successfully and profitably manage competitive generation assets, including the evaluation and execution of strategic alternatives for these assets as some of the alternatives could result in a loss; changes in the creditworthiness of the counterparties with whom AEP has contractual arrangements, including participants in the energy trading market; actions of rating agencies, including changes in the ratings of AEP debt; the impact of volatility in the capital markets on the value of the investments held by AEP's pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements; accounting pronouncements periodically issued by accounting standard-setting bodies; and other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events. To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/aep-and-dynegy-complete-ownership-transfer-for-co-owned-plants-300454639.html


HOUSTON--(BUSINESS WIRE)--Renewable Power Direct, the national green energy marketer, has structured a third renewable electricity agreement for Iron Mountain Incorporated (NYSE: IRM), a leading provider of storage and information management services. The new transaction, which will supply a portion of Iron Mountain’s current electric needs in Pennsylvania and New Jersey, builds on two earlier supply deals that RPD has handled for Iron Mountain in Texas and the Mid-Atlantic states during the past 12 months. RPD’s renewable retail supply model complements an array of sustainability strategies utilized by Iron Mountain to meet their corporate goals, which include PPAs and On-site Solar. RPD’s innovative supply model layers in a “green block” of wholesale energy under the current terms of their existing retail electric supply agreement, sourcing the physical energy from EDP Renewable’s Meadow Lake Windfarm III in Indiana. EDP Renewables also provides Iron Mountain with renewable energy credits for meeting their corporate sustainability goals. Mark Mancino, RPD’s Vice-President of Sales, commented, “We are happy to be working in collaboration with Iron Mountain, their retail supplier and their energy consultant to provide another cost-effective solution to meet applications that call for shorter supply terms and discrete volumes matching Iron Mountain’s specific needs.” “One of the first challenges of our sustainable energy strategy is finding ways to beat the conventional wisdom that growing our business means bigger environmental impacts,” said Kevin Hagen, director of corporate responsibility at Iron Mountain. “Renewable Power Direct is invaluable in helping us find innovative ways to reduce our climate and environmental impacts.” About Iron Mountain Iron Mountain Incorporated (NYSE: IRM) is a leading provider of storage and information management services. The company’s real estate network of more than 69 million square feet across more than 1,100 facilities in 37 countries allows it to serve customers around the world. And its solutions for records management, data management, document management, and secure shredding help organizations to lower storage costs, comply with regulations, recover from disaster, and better use their information. Founded in 1951, Iron Mountain stores and protects billions of information assets, including business documents, backup tapes, electronic files and medical data. Visit www.ironmountain.com for more information. About Renewable Power Direct, LLC RPD is a unique U.S. renewable energy marketer serving corporate and industrial buyers. It is the only supplier offering variable term (2-7 year), fractional physical capacity (plus RECs) from utility-scale wind and solar facilities. Blocks of energy capacity may be purchased in 1 MW or greater increments. Fortune 500 energy buyers have chosen these contracts for green data centers, production facilities and corporate headquarters from California (CAISO) to Texas (ERCOT) to the Mid-Atlantic (PJM). RPD’s national sales team is based in Houston; the company also has offices in Washington D.C. For more information visit www.renewablepowerdirect.com.


News Article | May 10, 2017
Site: www.theenergycollective.com

Wind generators accounted for 8% of the operating electric generating capacity in the United States in 2016, more than any other renewable technology, including hydroelectricity. Wind turbines have contributed more than one-third of the nearly 200 gigawatts (GW) of utility-scale electricity generating capacity added since 2007. The increase in wind development in the United States over the past decade reflects a combination of improved wind turbine technology, increased access to transmission capacity, state-level renewable portfolio standards, and federal production tax credits and grants. More than half of U.S. wind capacity is located in five states: Texas, Iowa, Oklahoma, California, and Kansas. In three states—Iowa, Kansas, and Oklahoma—wind makes up at least 25% of in-state utility-scale generating capacity. Several states with the highest wind capacity are located in the Midwest, a region with favorable wind resources. As of December 2016, nine U.S. states had no operational utility-scale wind facilities: Alabama, Arkansas, Florida, Georgia, Kentucky, Louisiana, Mississippi, South Carolina, and Virginia. Texas alone accounts for almost a quarter of total U.S. wind capacity, and electricity generated by these turbines made up 13% of Texas’s total electricity output in 2016. At particularly windy times, wind can provide a much larger share of Texas’s electricity generation. For instance, in the early hours of March 23, 2017, wind output on the Electric Reliability Council of Texas (ERCOT) grid in Texas accounted for up to 50% of the electricity generation mix, the highest wind penetration level seen in the ERCOT electric system to date. Although wind makes up about 8% of total U.S. electricity generating capacity, wind generators provided a smaller share (5%) of total U.S. electricity generation in 2016 because wind turbines have relatively low capacity factors. Capacity factors, which measure actual output over a certain period as a percent of the total mechanical ability of the turbine to generate given sufficient wind, average between about 25% and 40% for wind generators and vary based on seasonal patterns and geographic location. The average wind generating facility in the United States consists of about 50 turbines. However, the Alta Wind Energy Center in Kern County, California, is the largest wind power site in the United States with 586 turbines and a combined 1,548 megawatts (MW) of capacity across several separate projects. Until late 2016, all U.S. wind capacity was on land. The first U.S. offshore wind project, Block Island Wind Farm, began commercial operation off the coast of Rhode Island in December 2016 with a generating capacity of 29.3 MW. Two other offshore wind projects off the coasts of Ohio and Virginia are not yet under construction but are seeking regulatory approvals.

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