News Article | May 9, 2017
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
News Article | May 9, 2017
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
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.
News Article | May 16, 2017
U.S. Secretary of Energy Rick Perry in April requested a study to assess the effect of renewable energy policies on nuclear and coal-fired power plants. Some energy analysts responded with confusion, as the subject has been extensively studied by grid operators and the Department of Energy’s own national labs. Others were more critical, saying the intent of the review is to favor the use of nuclear and coal over renewable sources. So, are wind and solar killing coal and nuclear? Yes, but not by themselves and not for the reasons most people think. Are wind and solar killing grid reliability? No, not where the grid’s technology and regulations have been modernized. In those places, overall grid operation has improved, not worsened. To understand why, we need to trace the path of electrons from the wall socket back to power generators and the markets and policies that dictate that flow. As energy scholars based in Texas — the national leader in wind — we’ve seen these dynamics play out over the past decade, including when Perry was governor. There has been a lot of ink spilled on why coal is in trouble. A quick recap: Natural gas is plentiful and cheap. Our coal fleet is old and depreciated. Energy use in the U.S. has flatlined, so there’s less financial incentive to build big new power plants. Part of Perry’s review is aimed at establishing how wind and solar, which are variable sources of power, are affecting so-called baseload sources — the power plants that provide the steady flow of electricity needed to meet the minimum demand. Posing the question whether wind and solar are killing baseload generators, including coal plants, reveals an antiquated mindset about power markets that hasn’t been relevant in many places for at least a decade. It would be similar to asking in the late 1990s whether email was killing fax machines and snail mail. The answer would have been an unequivocal “yes” followed by cheers of “hallelujah” and “it’s about time” because both had bumped into the limits of their utility. How quickly 1990s consumers leaped to something faster, less impactful and cheaper than the older approach was a sign that they were ready for it. Something similar is happening in today’s power markets, as customers again choose faster, less impactful, cheaper options — namely wind, solar and natural gas plants that quickly boost or cut their output — as opposed to clinging to the outdated, lumbering options developed decades before. Even the Department of Energy’s own analysis states that “many of the old paradigms that govern the (electricity) sector are also evolving.” Wind and solar are making older generators less viable because their low, stable prices and emissions-free operation are desirable. And they aren’t hurting grid reliability the way critics had assumed because other innovations have happened simultaneously. Let’s use the case study of Texas to illustrate. Since Texas has its own grid, known as the Electricity Reliability Council of Texas or ERCOT, and has installed more wind capacity than the next three wind-leading states combined, the Texas experience shows what variable renewables like wind power do to the grid. In competitive markets like ERCOT, companies that run power plants place bids into an auction to provide electricity at a certain time for a certain price. A bid stack is jargon for “a stack of bids” — or the collection of all these bids lined up in order by price — in auction-based markets (such as Texas). Markets use bid stacks to make sure that the lowest-cost power plants are dispatched first and the most expensive power plants are dispatched last. This market-based system is designed to deliver the lowest-cost electricity to consumers while also keeping power plant owners from operating at a loss. Throughout the day, the market price for electricity (in $/Megawatt-hour) changes as demand changes. The cost of natural gas also affects the price of electricity. As the price of natural gas drops, each of the natural gas power plants drop in price. That’s no surprise: When it costs less for them to operate, they can bid a lower price into the market and move earlier in the line. When gas drops into to the range of US$3 to $3.50 (per million BTU) and lower, it begins to displace coal as a less expensive source of electricity. This scenario reflects today’s reality: gas is cheap so grids are using it for more of our electricity than coal. How do renewables affect the bid stack? Renewable sources such as wind, solar and hydro have no fuel costs — sunlight, wind and flowing water are free. That means their marginal operational cost is near zero; the cost is essentially the same to operate one megawatt of wind as compared to the cost of operating 10 megawatts of wind since generators don’t need to buy fuel. That means as more wind and solar farms are installed, more capacity is inserted at the cheapest end of the bid stack. This insertion pushes out other generators such as nuclear, natural gas and coal, causing some of them to no longer be dispatched into the grid — that is, they don’t supply power into the grid (or get paid). So as more renewables are installed, power markets dispatch fewer conventional options. And, because the marginal cost of these new sources is almost free, they substantially lower the cost for electricity. This is great news for consumers (all of us) as our bills decrease, but bad news for competitors (such as coal plant owners) who operate their plants less often and are paid less when the plants do operate. What does all this mean? Natural gas and renewables are affecting coal in two ways. Natural gas is a direct competitor with coal because both can be dispatched — turned on — when a grid operator needs more power. That is helpful for grid reliability. But, as the cost of natural gas has fallen, coal has become less competitive because it is cheaper to operate a natural gas power plant. The effect of renewables is slightly different: Wind and solar power are not dispatchable, so they cannot be turned on at a moment’s notice. But, when they do turn on, during windy evenings or sunny days in Texas, they operate at very low marginal cost and thus operate very competitively. Research at UT Austin shows that while installing significant amounts of solar power would increase annual grid management costs by $10 million in ERCOT, it would reduce annual wholesale electricity costs by $900 million. The result of all this is that renewables compete with conventional sources of power, but they do not displace nearly as much coal as cheap natural gas. In fact, cheap gas displaces, on average, more than twice as much coal than renewables have in ERCOT. Nuclear’s problems are largely self-inflicted. In short: The price to build nuclear is high, so we don’t build many nuclear plants these days. Since we don’t build, we don’t have the manufacturing capability. Since we don’t have the manufacturing capability, the price to build nuclear is high. Since the price to build nuclear is high, we don’t build nuclear these days…so on and so forth. Today, cheap gas, having already beaten up on coal, is a threat to new nuclear power plants and less efficient, older plants. New natural gas combined cycle power plants can be built for about one-sixth the cost of a new nuclear plant, is almost twice as efficient and you can build them in smaller increments, making them easier to finance. Because wind energy comes and goes with the weather, it makes grid operators nervous. But wind forecasting has improved dramatically, giving more confidence to those who need to keep the lights on. And, interestingly enough, the requirements for reserve capacity (backup power for when wind power dips) to manage the grid smoothly went down, not up, over the past few years in Texas, despite rapid growth in wind during Governor Perry’s tenure. That is, the costs for managing variability in the grid decreased. Why has there been little disruption to the reliability of the Texas grid? Because alongside rapid growth in wind installations was a market transformation in ERCOT. While Secretary Perry was governor, the Texas market went from a coarse, slow market to a fine-tuned, fast market. Innovating the market to one that is dynamic and fully functioning made it easy to include more wind into the system. It’s also a sign of how advanced technologies enable us to reinvent the grid toward one that is cheaper, cleaner and more reliable. But there is still more to do — information technology coupled with integrated hardware can help. Consider this: There are 7.7 million smart meters in Texas, most of them residential. We’ve estimated that installing 7 million controllable thermostats for just the households in Texas would cost $2 billion. Residential air conditioning is responsible for about 50 percent of peak demand in Texas in the summer. That means about 30 gigawatts of peak demand in Texas is just from residential air conditioners. By dynamically managing our air conditioning loads — that is, adjusting thermostats to lower overall demand without impacting people’s comfort — we could reduce peak demand by 10 to 15 GW. That means we might not need $10 billion to $15 billion worth of power plants. Spending $2 billion to avoid $15 billion is a good deal for consumers. In fact, you could give the thermostat away for free and pay each household $700 for their trouble and it would still be cheaper than any power plant we can build. In the end, Secretary Perry has posed good questions. Thankfully, because of lessons learned while he was governor of Texas, we already have answers: despite concerns to the contrary, incorporating wind and solar into the grid along with fast-ramping natural gas, smart market designs and integrated load control systems will lead to a cleaner, cheaper, more reliable grid. Joshua D. Rhodes, Postdoctoral Researcher of Energy, University of Texas at Austin; Michael E. Webber, Professor of Mechanical Engineering and Deputy Director of the Energy Institute, University of Texas at Austin; Thomas Deetjen, Graduate Research Assistant, University of Texas at Austin, and Todd Davidson, Research Associate, Energy Institute, University of Texas at Austin This article was originally published on The Conversation. Read the original article.
News Article | May 18, 2017
An alliance of clean energy groups has opted not to wait for the Department of Energy to finish its 60-day study on baseload energy resources before weighing in on the research, which could influence energy markets all across the country. “We thought, 'Let’s not wait. Let’s file a -- we made up a word -- a pre-buttal,'” said Abby Ross Hopper, the CEO of Solar Energy Industries Association (SEIA), speaking yesterday at GTM’s Solar Summit. “I am concerned about [the study],” she said. “I am concerned it will be a predicate for other things that could be harmful to our industry.” Energy Secretary Rick Perry requested the study in a memo on April 14, with his staff due to report back 60 days from April 19. The research is intended to “explore critical issues central to protecting the long-term reliability of the electric grid,” and to analyze "market-distorting effects of federal subsidies that boost one form of energy at the expense of others.” Perry wrote that the study will inform Trump administration policies. Language in the memo praises baseload power -- specifically coal, natural gas, nuclear and hydropower -- and criticizes the “erosion” of these resources, which raised concerns that the study would be against renewables like solar and wind. The focus on baseload energy, coupled with the short timeline, as well as Perry’s recent remarks that the federal government may need to “intervene” at the state level to support baseload energy in the name of national security, have only intensified the concern that the DOE report could have a predetermined outcome. Senator Chuck Grassley, a Republican from Iowa, laid out that precise concern in a letter to Secretary Perry this week, and requested more information on how the study is being conducted. “I am concerned that a hastily developed study, which appears to predetermine that variable, renewable sources such as wind have undermined grid reliability, will not be viewed as credible, relevant or worthy of valuable taxpayer resources,” Grassley wrote. “In fact, at least one similar study has already been conducted by the DOE’s National Renewable Energy Laboratory. It’s my understanding that study took two years to complete.” Electricity sector stakeholders fear the department will advocate for policies that undermine renewable energy resources before consulting with industry experts and thoroughly reviewing existing research -- which shows that reliable grid management is achievable with a high degree of variable resources, and that wind and solar are not the primary drivers of the changing resource mix. On April 28, SEIA along with Advanced Energy Economy (AEE), American Council on Renewable Energy (ACORE) and the American Wind Energy Association (AWEA) collectively sent a letter to Secretary Perry requesting the DOE allow for public comment on the report. The letter noted that it is “customary” for agencies developing reports that provide policy recommendations to allow stakeholders to submit comments on a draft, prior to the report being finalized. The DOE has not sent a reply. “We are disappointed that we didn’t get a response. But more importantly, we’re disappointed the report doesn’t appear to include a public open comment process,” said Arvin Ganesan, vice president of federal affairs at Advanced Energy Economy, in an interview this week. “The reason this is really important is because this report has the potential to change markets and is nationally significant.” And so this week, the alliance of clean energy organizations each submitted materials to the DOE on their own accord, hoping to inform the energy markets study. “The question that’s being asked is a fair one,” said Hopper, but the answers already exist. “There are a large number of studies that have looked at this very question, many of them done by the DOE, and many of them done by the national labs,” she said. Update: DOE spokeswoman Shaylyn Hynes responded to Axios regarding the study on May 5. "The findings will be released to the public (including stakeholders) once the study is completed this summer," she said. "The Secretary looks forward to receiving input from all parties once that occurs." Here are three major takeaways from the SEIA, AEE, AWEA and ACORE reports. It is true that wind and solar benefit from certain beneficial policies -- specifically, the Production Tax Credit for wind and the Investment Tax Credit for solar at the federal level, as well as renewable energy mandates at the state level. These measures have helped the renewables sector grow, but clean energy groups insisted that regulatory burdens, mandates, tax and subsidy policies are not responsible for forcing the premature retirement of baseload conventional power plants. First of all, the incentives for renewables are relatively small. Wind and solar energy account for less than 5 percent of total federal cumulative energy incentives, while nuclear and fossil fuels account for more than 85 percent of cumulative energy incentives, according to ACORE, which cited research by the U.S. Treasury, the Joint Committee on Taxation, the DOE, DBL Investors and others. The ACORE brief also noted that only four major energy tax preferences are permanent: three are for fossil fuels and one is for nuclear energy, according to a 2012 Congressional Budget Office report. Renewables do not have this benefit. Federal tax credits for wind and solar are already scheduled to sunset over the next four years. It’s worth noting that baseload energy groups (like the nuclear industry) have still argued that they’re at a policy disadvantage. And there is a legitimate debate taking place in the electricity sector on how state-level policies interact with regional wholesale markets. The point clean energy groups are making is that renewable energy isn’t the only type of energy resource to benefit from favorable policies. Market dynamics may be changing, but it’s not because of renewable energy subsidies on their own. “You have to look at the entire market and how various provisions and policies are used to prop up various resources,” said AEE's Ganesan. “I don’t think you can say a tax policy or renewable portfolio standards are driving any sort of power plant retirements when every technology has its own set of policies incentivizing it.” Furthermore, renewables are becoming cost-competitive without subsidies. According to Lazard’s annual analysis, the unsubsidized levelized cost of energy for utility-scale wind and solar power declined by 64 percent and 81 percent, respectively, from 2008 to 2015. SEIA pointed out that the unsubsidized levelized cost of utility-scale solar now ranges from $46 to $92 per megawatt-hour, which is on par with wholesale electricity from new wind and natural gas plants. Residential solar, which competes against retail electricity prices, is now also competitive in most markets. While solar and wind have started to become more competitive with traditional energy resources in recent years, the abundance domestic shale gas has been the primary driver of the changing energy mix. Natural-gas prices have fallen from an average price of $8.86 per million BTU in 2005 (with a spike above $12 per million BTU in 2008) to an average of $3.20 per million BTU for the last five years. AEE referenced a March 2016 report from Moody’s that found natural gas prices have been “by far…the most dominant effect on the unregulated power sector,” especially as “gas-fired power plants often serve as the marginal plant during times of peak power demand.” The R Street Institute, a free market think tank, conducted a similar analysis focused on the nuclear industry that found low and stable natural gas prices “are setting new standards for what electricity should cost.” Low natural-gas prices are encouraging grid operators to dispatch this capacity at increasing rates, to where it now has the largest market share of all the generating technologies. Also, natural gas often sets the clearing price of electricity in wholesale power markets. For example, in the Midcontinent Independent System Operator (MISO), natural gas set the price of electricity in the market 75 percent of the time, while coal set the price 23 percent of the time and wind only 1 percent of the time. A recent Columbia University report put some numbers around it, finding “increased competition from cheap natural gas is responsible for 49 percent of the decline in domestic U.S. coal consumption. Lower-than-expected electricity demand is responsible for 26 percent, and the growth in renewable energy is responsible for [only] 18 percent.” The Energy Information Administration’s numbers show that coal use in the U.S. declined sharply as natural gas use spiked. Renewable energy stakeholders also pointed out that the U.S. electric grid are not only capable of handling current levels of wind and solar penetration, but that the grid actually becomes more resilient because of these resources. The California Independent System Operator, for instance, found that renewables combined with modern controls have the ability to provide a range of grid reliability services that are “comparable to, or better than, conventional resources.” In the materials AWEA submitted to the DOE this week, the group highlighted that high penetrations of wind generation have maintained or improved electric reliability on the grids where they’re located. Texas’ ERCOT territory, for instance, which has the most wind capacity of any U.S. power system, has seen its electricity reliability increase while adding large amounts of wind. The market’s CPS1 score (a widely used reliability metric that measures how electricity supply and demand are kept in balance) has improved as wind deployments have increased. On a related note, researchers at the University of Texas at Austin have shown that the growth of wind energy in ERCOT territory has not caused a significant increase in the need for the frequency regulation reserves that are used to keep electricity supply and demand in balance. The DOE has also studied the reliability issue, as Senator Grassley indicated. In 2012, government researchers found that 25 percent to 50 percent renewable energy penetration did not trigger any concerns on any reliability metric, and that renewables could go as high as 80 percent penetration with existing technology. It may well be time to update this study, as Secretary Perry has requested. Renewable energy stakeholders just want to ensure the DOE is taking all relevant data into account.
News Article | May 22, 2017
Today Red Clay Consulting, a Gold Level Oracle Partner, has announced it has completed the successful upgrade of American Electric Power’s meter data management system from Oracle Utilities Meter Data Management (MDM) version 1.6 to the platform’s new version 220.127.116.11. The upgrade project was aimed at converting historical usage and customer data into the latest MDM version to meet AEP and market requirements. The effort was completed in approximately six weeks and successfully converted nearly 2 million active AMI meters and corresponding customer data across four unique AEP operating companies and five states. The new MDM version will allow AEP to better serve their clients and further enable smart meter technology within the company. According to Paul Marnell, Managing Partner at Red Clay Consulting, “This was an outstanding conversion from LODESTAR to the newest version of Oracle Utilities MDM for American Electric Power. Red Clay and AEP successfully partnered to make this project a success, while supporting all market and settlement requirements for the Texas ERCOT market. With this implementation, we have added to an impressive delivery record stretching more than ten years of implementing these products. AEP was an exceptional partner, and I’m thrilled we could once again deliver a successful project.” About Red Clay Consulting Red Clay, a leading consultancy for utilities, delivers seamless integrations of leading software systems. Industry experience, technical expertise, and an unyielding commitment to client success combine to deliver turnkey solutions that maximize value. As a Gold Level member of the Oracle Partner Network (OPN), Red Clay Consulting is the preferred choice among utilities for software integration and managed services. Red Clay’s unparalleled experience, expertise, and execution fuel project success. To learn more about Red Clay, visit: http://www.redclay.com. About AEP 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 also 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. Trademarks Oracle and Java are registered trademarks of Oracle and/or its affiliates.
News Article | April 17, 2017
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
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 3, 2017
The integration of renewables into the grid is becoming an increasingly acute problem, writes Fereidoon Sionshansi, editor of newsletter EEnergy Informer. According to Sionshansi, this is especially true in energy-only markets that have no capacity mechanism of any sort. But market interventions in the form of subsidies are not the answer. Joe Bowring of independent consultancy Monitoring Analytics has an alternative: offering capacity against a minimum price. Courtesy EEnergy Informer. It is becoming increasingly clear that the market designs of 1980s is not fit for today’s electricity markets, let alone those of the next decade. Among the main reasons is the growing penetration of renewables in many markets, which operate at zero marginal cost, and which typically bid their output in wholesale markets at zero, or even negative, prices while taking the market clearing price (MCP), usually set by the most expensive thermal unit dispatched to meet demand. This phenomenon has resulted in persistently declining wholesale energy prices in some markets – and declining profits for some thermal generators. Moreover, even highly efficient peaking plants, which are increasingly needed as backup to maintain network’s reliability, are not getting dispatched frequently enough and/or for long enough number of hours to remain profitable. These conditions discourage investment in new capacity while forcing many of the less efficient units out of the market. In a few cases, the grid operators have had to intervene in the market to prevent such unprofitable or marginally profitable units from shutting down, because that may make the network vulnerable at times when sufficient solar or wind generation is not available to meet demand. The problem tends to be more acute in energy-only markets, where generators are only paid when they are dispatched, not to keep excess capacity around for reliability purposes, such as in the PJM market in the U.S., which covers all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. These issues are gaining considerable attention in a number of markets where the problem can no longer be ignored, and the topic is no longer of interest just among academics and scholars. In an increasing number of cases, the market operators, regulators or politicians have had to intervene in the market by – for example – subsidizing certain critical fossil or nuclear units to prevent them from shutting down. In some cases, certain critical thermal units are designated as reliability-must-run (RMR), as in the Californian market (CAISO). California does not have a formal capacity market but maintains adequate capacity through a mandatory administrative process using bilateral contracts. Much of the state’s thermal generation has been built under bilateral cost of service contracts, which – one can argue – are essentially indistinguishable from RMRs. Such units are typically paid out of the usual market merit order because they are deemed critical to maintaining the network’s reliability either because of their location on the transmission lines, or proximity to critical load centers, or because the network needs the spinning reserves to maintain voltage or frequency. Plants designated as RMR no longer participate in daily wholesale auctions since they get paid regardless of getting dispatched. Clearly, if too many units are paid out of the market merit order, and too many renewable generators bid at zero or negative costs, life becomes difficult if not unsustainable for the remaining thermal units, especially those with less flexible operating characteristics. In its latest annual state of the market (SOM) report, Joe Bowring of Monitoring Analytics, the independent market monitor for PJM, warned that proposals to subsidize unprofitable generating resources – including a handful of unprofitable nuclear units – present “a very real threat” to the competitiveness of wholesale electricity markets. The subsidies in question come in the form of zero-emission credits (ZEC) for otherwise uneconomic nuclear plants, which were included as part of New York’s Clean Energy Standard and are intended to aid the state’s transition away from fossil fuels and into renewables. Bowring points out that while NY is not in the PJM market, nevertheless these nuclear subsidies will still negatively affect PJM markets. He is also concerned about similar ZEC legislation in Illinois to subsidize Quad Cities nuclear plant, preventing it from shutting down. In his 2016 SOW report, Bowring said, “Economists everywhere agree that … the most cost-effective way to do that (i.e., preventing unprofitable nuclear units from shutting down) is to have a carbon price…..,” adding, “It’s certainly not by picking (and subsidizing) individual power plants that are low carbon.” Monitoring Analytics, whose job is to monitor the performance of the PJM market against a hypothetical functional market with no abuse of market power, no price manipulation, no gaming, no artificial or strategic withholding of energy or capacity, no out-of-market subsidies such as ZECs, or other types of manipulation or interference – is concerned that such interference, in the form of specific subsidies for specific market participants, will ultimately affect the market outcome. In addition to performing its market monitoring function, Monitoring Analytics mitigates against exercise of market power while proposing market design changes to enhance competition. In discussing the topic with EEnergy Informer, Bowring pointed out that markets such as the PJM, that include a capacity mechanism, “can accommodate increasing shares of renewables without too much difficulty,” adding, “Markets like ERCOT (the Electric Reliability Council of Texas) can also work fine if they correctly define scarcity pricing rules and recognize that the energy-only construct is riskier.” Bowring believes that “the market fundamentals are just fine. Market interventions, for example, in the form of subsidies, however, distort markets and create the need for more subsidies.” Uneconomic units, he says, “should be allowed to retire. Fuel diversity has increased or remained flat over the last 10 years.” Bowring points out that no market interventions have occurred in PJM, allowing substantial coal retirements and offsetting gas additions to take place entirely driven by price signals. How would Bowring propose to address some of the issues confronting markets moving forward? He said, “Our proposal is to implement an existing unit MOPR (Minimum Offer Price Rule) which would prevent subsidized units from offering capacity in the PJM capacity market at less than a competitive level.” The latest SOM report, which comes in 13 sections and 2 massive volumes, is available for download at Monitoring Analytics website. It has much more to offer, including a comprehensive list of recommendations. This article was first published by EEnergy Informer and is republished here with permission. Fereidoon Sionshansi is author and editor of many books on technological and policy developments in the utility sector. Hi’s upcoming book Innovation and Dirsuption at the Grid’s Edge, to be published in June 2017.
News Article | April 25, 2017
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. 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