Western Area Power Administration
Western Area Power Administration
The Western Area Power Administration markets and delivers hydroelectric power and related services within a 15-state region of the central and western U.S. It is one of four power marketing administrations within the U.S. Department of Energy having the role to market and transmit electricity from multi-use water projects to retail power distribution companies and public authorities. Its transmission system carries electricity from 55 hydropower plants operated by the Bureau of Reclamation, United States Army Corps of Engineers and the International Boundary and Water Commission. Together, these plants have a capacity of 10,600 megawatts. WAPA is headquartered in the Denver, Colorado suburb of Lakewood, Colorado.WAPA built several parts of the important Path 15 corridor that connects power grids in the Southwest and Pacific Northwest . Recently, WAPA helped remedy a transmission bottleneck near Los Banos, California. That bottleneck was one of the reasons for the California electricity crisis in 2000-01. Another important transmission corridor WAPA built was Path 66, paralleling Path 15.WAPA also owns and operates many electric power substations like the Mead substation to distribute power within the region.WAPA and its energy-producing partners are separately managed and financed. In addition, each water project maintains a separate financial system and records. Wikipedia.
News Article | December 16, 2016
LITTLE ROCK, AR--(Marketwired - December 16, 2016) - On Dec. 7, America commemorated the 75th anniversary of the bombing of Pearl Harbor. Nine days later, an organization in Little Rock, Ark., will likewise celebrate 75 years of existence. On Dec. 16, 1941, in support of the American war effort, 11 electric utilities agreed to pool their resources to keep power flowing to Jones Mill -- an aluminum production facility outside Malvern, Ark. President Franklin Roosevelt's wartime goal to produce 50,000 airplanes per year had created the need for huge quantities of aluminum, and Jones Mill's operation would require 120 megawatts of power -- exceeding its home state's installed capacity of 100 MW at the time. From the utilities' partnership, Southwest Power Pool (SPP) was formed, and the new organization was successful in pooling power to support the plant. After the war, SPP continued as a leader providing safe, reliable power to U.S. homes. SPP today is a regional transmission organization (RTO): a not-for-profit, federally regulated service organization that ensures the reliable operation of a portion of the nation's power grid on behalf of its member companies, with more than 50,000 MW in capacity. SPP describes itself as the air-traffic controller of the power grid. Air-traffic controllers do not own the airports in which they operate or the planes they direct but are responsible for ensuring air travelers depart, fly and land safely. Similarly, SPP does not own the power stations it directs or the transmission lines across which electricity flows in its footprint, but it partners with generators, transmission owners, municipalities, power marketers, state and federal agencies, electric cooperatives and others to ensure the cost-effective and reliable delivery of power across a 14-state region. Though SPP works at the wholesale level and thus doesn't directly serve end users and ratepayers, it does benefit them. A recent study conducted by SPP and validated by the Brattle Group showed transmission investments in the SPP region had, on average, a benefit-to-cost ratio of 3.5-to-1. That means every dollar spent to build or upgrade transmission lines throughout SPP's region will ultimately produce $3.50 in electricity production cost savings and other benefits. In addition to planning transmission infrastructure, SPP facilitates the sale and purchase of electricity through its Integrated Marketplace, a wholesale electric market. SPP's marketplace launched in 2014 and has since reduced the cost of electricity in the organization's region by more than $1 billion. These and other services provide net benefits to SPP's members in excess of $1.4 billion annually at an overall benefit-to-cost ratio of more than 10-to-1. For the typical end-use customer using 1,000 kWh per month that means $68 of benefits a year at the cost of just 62 cents monthly. Or, put another way, without the services SPP provides its members, a ratepayer's $100 electric bill would be $105.65. Throughout its 75 years, SPP has evolved and grown from an affiliation of 11 companies with a common goal in 1941 to an organization employing about 600 professionals in support of nearly 100 member companies across a region spanning from the Canadian border in the north to Louisiana in the south and from southeastern Missouri to northwestern Montana. SPP attributes its legacy of success to the strength of its stakeholder relationships. In the foreword to a book published this year chronicling SPP's history, its President and CEO Nick Brown said, "Reliability is job one for SPP. We exist to help our members keep the lights on, today and in the future. We do so not through hard work, innovation or efficiency, though each is a necessary component of our success. For SPP, reliability is accomplished through strong, healthy relationships with those we serve." Because of the strength of those relationships, its legacy of success and deliberate focus on continuous improvement and building consensus among its members, SPP has every reason to think its future is just as bright as its history. Southwest Power Pool, Inc. manages the electric grid and wholesale energy market for the central United States. As a regional transmission organization, the nonprofit corporation is mandated by the Federal Energy Regulatory Commission to ensure reliable supplies of power, adequate transmission infrastructure and competitive wholesale electricity prices. Southwest Power Pool and its diverse group of member companies coordinate the flow of electricity across 60,000 miles of high-voltage transmission lines spanning 14 states. The company is headquartered in Little Rock, Ark. Learn more at www.spp.org. Acciona Wind Energy USA, LLC; American Electric Power (AEP Oklahoma Transmission Company, Inc.; AEP Southwestern Transmission Company, Inc.; Public Service Company of Oklahoma, Southwestern Electric Power Company); Arkansas Electric Cooperative Corporation; Basin Electric Power Cooperative; Board of Public Utilities of Kansas City, Kansas; Boston Energy Trading and Marketing, LLC; Calpine Energy Services, L.P.; Cargill Power Markets LLC; Central Power Electric Cooperative, Inc.; Cielo Wind Services, Inc.; City of Coffeyville; City of Independence, Missouri; City Utilities of Springfield; Clarksdale Public Utilities Commission; Cleco Power, LLC; Corn Belt Power Cooperative; CPV Renewable Energy Company, LLC; Dogwood Energy, LLC; DTE Energy Trading, Inc.; Duke Energy Transmission Holding Company, LLC; Duke-American Transmission Company, LLC; Dynegy Power Marketing, Inc.; East River Electric Power Cooperative, Inc.; East Texas Electric Cooperative, Inc.; EDP Renewables North America LLC; El Paso Marketing Company, LLC; Enel Green Power North America, Inc.; Entergy Asset Management; Entergy Services, Inc.; Exelon Generation Company, LLC; Flat Ridge 2 Wind Energy, LLC; Golden Spread Electric Cooperative, Inc.; Grain Belt Express Clean Line LLC; Grand River Dam Authority; Harlan Municipal Utilities; Heartland Consumers Power District; Hunt Transmission Services, LLC; ITC Great Plains, LLC; Kansas City Power & Light Company (KCP&L Greater Missouri Operations Company); Kansas Electric Power Cooperative, Inc.; Kansas Municipal Energy Agency; Kansas Power Pool (KPP); Lafayette Utilities System; Lea County Electric Cooperative, Inc.; Lincoln Electric System; Louisiana Energy and Power Authority; Luminant Energy Company, LLC; Mid-Kansas Electric Company, LLC; Midwest Energy, Inc.; Midwest Gen, LLC; Missouri Joint Municipal EUC; Missouri River Energy Services; Mountrail-Williams Electric Cooperative; Municipal Energy Agency of Nebraska; Nebraska Public Power District, NextEra Energy Resources, LLC; NextEra Energy Transmission, LLC; Noble Americas Gas & Power Corp; Northeast Nebraska Public Power District; Northeast Texas Electric Cooperative, Inc.; Northwest Iowa Power Cooperative; NorthWestern Energy; NRG Power Marketing, LLC; OGE Transmission, LLC; Oklahoma Gas and Electric Company; Oklahoma Municipal Power Authority; Omaha Public Power District, Plains and Eastern Clean Line LLC; Prairie Wind Transmission, LLC; Public Service Commission of Yazoo City; Public Service Company of Oklahoma; Rayburn Country Electric Cooperative; Shell Energy North America (US), L.P.; South Central MCN, LLC; Southwestern Electric Power Company; Southwestern Power Administration; Sunflower Electric Power Corporation; Tenaska Power Services Co.; Tex-La Electric Cooperative of Texas, Inc.; The Central Nebraska Public Power & Irrigation District; The Empire District Electric Company; Transource Energy, LLC; Transource Missouri, LLC; Tri-County Electric Cooperative, Inc.; Tri-State Generation and Transmission Association, Inc.; Westar Energy, Inc. (Kansas Gas and Electric Company); Western Area Power Administration - Upper Great Plains Region; Western Farmers Electric Cooperative; Williams Power Company, Inc.; Xcel Energy (Southwestern Public Service Company, Xcel Energy Southwest Transmission Company, LLC); XO Energy SW, LP.
News Article | December 16, 2016
This post made possible by the tireless efforts of ILSR intern Abbigail Feola. She dug up the data, identified the story worth sharing, and wrote the following piece below. Historically, the purpose of both municipal and cooperative utility agencies has been to bring energy services to communities that for-profit corporations thought unprofitable to serve. This philosophy of self-reliance shifted the focus from profit margins towards social goods, and persists today. Municipal utilities are owned by and located in the cities they serve; their primary interest is not the welfare of their investors, but of their city or town. Likewise, cooperatives are owned and run by their members, people with strong social, environmental, financial, and cultural stakes in the activities of the cooperative. But the ways in which municipal and cooperative utilities procure power undermine this ethic of community service and self-reliance. Most municipal utilities have long-term contracts to purchase power from joint action agencies, and cooperative utilities from generation and transmission cooperatives. Utilities pursue these long-term contracts to obtain favorable interest rates and credit ratings from the finance industry. Even the National Rural Electric Cooperative Association states, “Since the wholesale power contract serves as the basic foundation for G&T [generation and transmission cooperative] financing, and since a multiplicity of stakeholders (such as lenders, regulators, or trustees, for example) have approval rights on any modifications to the contracts, it is nearly impossible to side-step the provisions of all-requirements wholesale power contracts in accessing and using power from sources other than the G&T.” In other words, financiers give better deals for financing big, new power plants when the local utilities are legally obligated to buy the power on a very long-term contract. Click here to see an example of one of the long-term contracts The more restrictive and longer the term, the less costly it will be to fund energy infrastructure. But the result of this system is a major restriction of utilities’ abilities to operate flexibly and independently. In many cases, small, local utilities are tied into contracts for increasingly-expensive fossil-fuel power for decades, even when they may have options to procure local, renewable electricity at low cost, or with additional local economic benefits. The loss of local authority, flexibility, and freedom can be solved in whole or part by shifting decision-making authority back to the local level, including expanding options for self-supply. To understand the current state of the industry and how it could be changed, ILSR contacted various cooperative and municipal utilities, the latter under the Data Practices Act, to collect information on their contract lengths and the costs of electricity paid by utilities. The findings show that decades-long contracts and past and current heavy investments in dirty energy are dramatically limiting utilities’ use of cost-efficient and environment-friendly power sources. The electric industry has always made enormous investments, in the billions of dollars, to generate and transmit electricity. Rising investments in transmission and distribution technology, among other factors, have contributed to rising electricity costs. Prior to the last 10 years, rising energy demand allowed utilities to spread these costs over greater sales. But in the past decade, costs have risen while general demand for electricity (measured in kilowatt-hours, or kWh) has been either unchanging or declining. The result is higher costs for consumers. For example, Great River Energy, one of Minnesota’s largest generation and transmission cooperatives, made massive investments in coal plants over the past decade, resulting in rising electric costs. (x)These include nearly 500 million dollars spent constructing the Spiritwood coal-fired plant, which was shut down due to lack of demand. The Southern Minnesota Municipal Power Agency has a similar cost problem. Due to the low costs of wind and natural gas power and the inflexible operating system of its coal plant Sherco 3, according to its 2015 annual report, it is having difficulty recovering the costs of operating the coal plant. Costs are also rising to comply with environmental regulations, rules that utilities have known about for decades. U.S. environmental policy has steadily been progressing towards stricter air quality control since the 1963 Clean Air Act. This trend continues today, as represented by the impending Clean Power Plan (CPP), a shift towards renewable and carbon-free energy sources which Minnesota has already begun putting into action. Because of their past heavy investments in coal (in some cases mandated by the federal government) and current investments in natural gas, municipal and cooperative utilities are at a disadvantage. For example, 78% of the Southern Minnesota Municipal Power Agency’s (SMMPA’s) power is from the coal-fired plant Sherco Unit 3, which was built in 1987. Already, utilities have submitted plans to close Sherco units 1 and 2 in 2023 and 2026, respectively. Unit 3 may not be far behind. These stricter governmental regulations mirror shifting consumer preferences and changing economics. Clean energy technologies (such as wind and solar) are currently outpacing coal in economic efficiency, and are projected to continue to do so, as the price of coal continues to rise. For the North Dakota and Minnesota generation and transmission company Minnkota, rising coal prices were responsible for ten million dollars (or 11% of the total cost increases) of the company’s rising operating costs in just one fiscal year. Such cost increases caused electric prices to rise by 60%. Such rising costs are symptomatic of the continuing conflict between large power providers (with huge sunk costs into aging and costly power plants) and the autonomy and flexibility of local utilities. Increases in demand for renewable and distributed generation, accompanied by unpredictably rising costs of coal and other fossil fuels, make long-term contracts that support centralized generation increasingly burdensome. These lengthy and demanding power purchase contracts are increasingly a millstone around the necks of utilities in the sea of rising costs and dropping sales. Power agencies or generation and transmission cooperatives require decades-long contracts to ensure that they recover their costs for building massive new power plants. These restrict utilities’ choices in power supplies for the duration of the contract; a very, very long duration. The Northern Municipal Power Agency, for instance, has contracts with its members extending as far as 2055, including with the cities of Chaska, Anoka, and Moorhead. The Minnesota Municipal Power Agency, Western Area Power Administration, and the Southern Minnesota Municipal Power Agency all also have contracts extending through 2050. The majority of Great River Energy’s contracts end in 2045 (source: conversation with utility representatives). Not only are such contracts unreasonably lengthy, but generation companies can and often make attempts to stretch them out even further than was originally agreed. For instance, the Florida Municipal Power Association (FMPA) auto-renews its 30-year contracts with its members each year. Many of these contracts are “all-requirements,” mandating that utilities buy the entirety of their power supply from the power agency or generation and transmission cooperative (or the maximum amount that the company can supply). These contracts keep local utilities tied to large investments in dirty power sources, and prevent them from increasing the role of locally-owned and/or locally-procured power generation. Of the twenty-eight cooperative utilities contracted with Great River Energy, twenty were all-requirements, with a five percent allowance for locally owned energy. Other utilities featured smaller allowances or none at all, as was the case with all the Minnesota municipal utilities whose data was available. Although most local municipal and cooperative utilities are tied into long-term contracts, a few had the foresight to avoid being tied down. The Southern Maryland Electric Cooperative (SMECO), which has no contracts with a generation and transmission cooperative, has installed or is in the process of installing a total of 15.5 MW of solar. In 2002, the Kauai Island Utility Cooperative (KIUC) purchased the utility from for-profit Connecticut-based Citizens Communications. Due to the import costs of coal, gas, and other resources on the island, Kauai has faced unique pressures in finding alternative sources of energy. KIUC has set a goal of 50% renewable energy by 2023, and in 2016 reached the mark of 38% renewable energy. The municipal utility in Denton, TX, reached 40% renewable energy supply in 2015. And after the expiration of its contract in 2012, the town of Georgetown, TX, signed contracts for 100% wind and solar electricity to start in 2017. Other municipal utilities are taking similar, self-initiated steps towards renewable generation. The town of Minster in Ohio has utilized its partial-requirements contract to build a solar/storage system consisting of a 3 MW array and a 7 MW battery, which is owned by Half Moon Ventures. Rochester Public Utilities (RPU), the largest municipal utility in Minnesota (footnote 1), has opted not to renew its 1978 contract with the Southern Minnesota Municipal Power Agency (SMMPA) when it expires in 2030. Concordantly, Rochester has set a goal of 100% renewable energy by 2031. Encouraging member leadership and participation in renewable generation is a major part of RPU’s plan: the proclamation states that “[a]t the heart of a successful 100% renewables strategy, it is fundamental to allow open participation in the development and financing of energy infrastructure….” Rochester’s new arrangement interweaves its freedom to choose with renewable energy accessibility, with each motivating the other. Farmers Electric Cooperative is an Iowa cooperative utility that generates 1,500 Watts of renewable power per customer, more than any other utility and more than double the next utility’s solar capacity per customer. Customers with their own solar arrays receive between 12.5 cents (the retail price) and 20 cents per kWh produced, depending on the amount produced and how it compares to their own consumption. The cooperative has also constructed a 750 kW solar array; only 20% of their power comes from coal. This success has been possible because only 30% of FEC’s power is sourced with long-term contracts; the rest is purchased from local generation sources on the spot market. Since few cooperative or municipal utilities can exit their long-term contracts easily, flexibility in the short term may require cooperation with their generation and transmission cooperative or power agency. Such cooperation can allow utilities to reap the benefits of economies of scale and coordinated action without sacrificing the needs and desires of their members and communities. For example, generation and transmission cooperative Great River Energy recently helped twenty of its member cooperatives construct small solar arrays in their communities. On the other hand, GRE constructs and owns these arrays and may be able to use that ownership in future contract extension negotiations. In another case, three local Minnesota utilities — the Freeborn-Mower Electric Co-operative, People’s Cooperative Services, and Tri-County Electric Cooperative — jointly built a solar array that sells power to Dairyland, their generation and transmission cooperative. As economies of scale are usually optimized around the 500 kW to 1 megawatt for solar arrays, planning around designing solar to connect to the distribution network can save wholesale power utilities and their members time and money. Cooperation between local utilities can also achieve cost savings. The Michigan Energy Optimization Collaborative was created by eight cooperatives and four municipal utilities in response to a 2008 law mandating an annual 1% reduction in electricity usage. The Collaborative has streamlined and lowered the cost of compliance through rebates for energy efficient appliances, energy audits, and agricultural programs. With more local negotiating power behind negotiations with power providers, cooperatives are more able to increase renewable energy and efficient usage — or, as in the case of the town of Niles, to break out of a contract early. Niles, a town of 7,000 people located in Indiana, estimates that it has been spending 20-30% above the market cost of power in its current contract. This spurred Niles to partner with ten other utilities to end their contracts with Indiana Michigan Power six years early — in 2020, instead of 2026. By joining forces, these utilities are managing to renegotiate their contract with a large power agency that may have run roughshod over a single utility’s attempt to renegotiate. The International Co-operative Alliance (ICA), an organization founded in 1895 which works to unite cooperatives worldwide, lists autonomy and independence as key principles through which cooperatives can fulfill their commitments to their members. It does so with good reason. The achievements of utilities such as Rochester Public Utilities and the smaller Farmers Electric Cooperative show the abilities of local utilities to act in financially and environmentally wise manners when freed from lengthy, restrictive contracts. The cases of I&M-contracted utilities joining forces to leave their contracts early, as well as three Minnesota utilities’ joint project to sell renewable power back to their power provider, show the successes and potentials of cooperation between local utilities to take on widespread problems. Local utilities, including their members, must continue to work against financial and legal entrapment by power agencies and generation and transmission cooperatives. Despite these mentioned successes, there remains much work to be done for the majority of local utilities, still chained to contracts with steadily increasing costs and few means to mitigate them. For timely updates, follow John Farrell on Twitter or get the Energy Democracy weekly update. Under the Minnesota Statutes Chapter 13, the Data Practices Act, members of the public have rights to access public data free of charge (in certain forms) and in a timely and accessible manner. These rights include the right to have public data explained and presented in an accessible form; to see and have copies of summary data; and many others, including the most basic and essential right to view public data unless there is a law classifying that data as protected, trade secret, or otherwise non-public. While cooperatives are not subject to the Data Practices Act, municipal utilities, as government organizations, are. Unfortunately, we found that there was little to no compliance with this act among municipal utilities. Despite Data Practices Act requests sent to multiple positions (including city clerks, general utility contact addresses, utilities staff members, city council members) associated with more than twenty-five municipal utilities in Minnesota, we received only six responses. The Data Practices Act was explicitly cited in the majority of these communications, and the reasons for rejection included not knowing the inquirer’s political beliefs. We regret this inaccessibility and hope that compliance with the Data Practices Act in the future would allow more thorough research on the energy industries in Minnesota. Here is a link to download the municipal utility contracts that we obtained. It’s worth noting that the barriers we faced may not be unique to Minnesota. Nebraska public utilities are claiming such information is a “trade secret.” Buy a cool T-shirt or mug in the CleanTechnica store! Keep up to date with all the hottest cleantech news by subscribing to our (free) cleantech daily newsletter or weekly newsletter, or keep an eye on sector-specific news by getting our (also free) solar energy newsletter, electric vehicle newsletter, or wind energy newsletter.
News Article | September 14, 2016
The 20-year struggle to create a cohesive Western power grid has entered a new phase, with a strong push by the California Independent System Operator (CAISO) to expand membership to other utilities in the West. CAISO brought together over 800 stakeholders from across the region in Sacramento last week to talk about regionalization. While speakers agreed that the engineering rationale and cost benefits are clear, the political process creates a formidable obstacle to achieving the dream. “The topography of the western grid follows the power flows, but the politics follows all kinds of weird things,” lamented Michael Picker, chair of the California Public Utilities Commission. Advocates of grid expansion are inspired by the success of the energy imbalance market (EIM), which has saved $88 million since it began in 2014. The EIM allows member utilities -- currently the three California IOUs plus Pacificorp and NV Energy -- to share resources to balance the grid. More utilities are scheduled to join over coming years, including Idaho Power and Arizona Public Service. But spurred by legislation (SB350), CAISO is pushing for a more comprehensive regional partnership, extending the market to cover day-ahead bids. This regional system operator (RSO) would facilitate wholesale competition across the region, similar to regional markets in the East. A big driver for the RSO is the growth of wind and solar across the region. Wind and solar made up 14.2 percent percent of California’s supply last year, and are among the least costly sources of new generation. All states except Wyoming and Idaho have renewable energy goals, with both California and Oregon expanding their own targets to 50 percent. A bigger grid would be a low cost way to integrate renewables, by spreading out the variability and tapping the best resources, as well as a way to capture operating efficiencies in general. But the technical benefits of a regional grid will have to overcome the political barriers Governor Jerry Brown was a surprise guest at the symposium, telling the crowd that California is committed to climate action, but acknowledging the difficulties of regional action. “We will continue innovating in this state,” he told the crowd. “We think we’ll get to 50 percent renewables sooner than 2030. To make it work we need a grid that is highly sophisticated.” “It’s true that different states have different needs and perspectives, but the efficiency of a wider grid is unmistakable,” he said. “I hope you can work all that out." The issue is that the CAISO board is appointed by Governor Brown with the advice and consent of the state senate. An expanded regional system operator would include utilities from across the region, and their state regulators will expect to have a say in management The idea reveals the anxieties of stakeholders both in California and in other states. Mark Schiavoni, with Arizona Public Service, pointed to the lingering effects of the 2000-2001 power crisis. “Regulators and politicians fear that California will control my state, and we won’t allow that to happen,” he said. “There are a lot of people with long memories.” Other market models also inspire trepidation. PJM officials have been making presentations in the region to educate people about the market -- to mixed reactions, apparently. “In my neck of the woods PJM is the antichrist,” said Doug Hunter with Utah Associated Municipal Power Systems. This prompted another panelist to ask “if PJM is the antichrist, what is California?” Hunter replied, “It’s potentially the good witch of the West.” A fear from Californians is that an RSO would provide new markets for existing coal plants, undermining California’s climate goals. Travis Ritchie of the Sierra Club said a regional market will make lowest cost the dominant goal, rather than carbon reductions. “I don’t think that’s what California wants,” he said. “I don’t think California will be comfortable putting at risk all the things we’ve done. We’ve done policies that have taken a lot of money and sweat and tears to get right.” But Carl Zichella of NRDC disagreed. “These markets really put the squeeze on legacy plants,” he argued. “The only thing keeping these coal plants alive is a bilateral contract.” Being exposed to competition from lower cost wind and solar would hasten their demise, said Zichella. Steven Greenlee, a spokesman for CAISO, pointed out two additional issues that have to be addressed. First, how will new RSO members pay for the grid? Transmission access charges are paid by generators to use the grid and pay off past investments. Hunter from Utah confirmed this concern. “Our biggest concern is paying for overheads and costs,” he told the audience. “It could quadruple the transmission access charge in Utah.” Resource adequacy is a second concern. California doesn’t have a capacity market to guide future year investments, like PJM and New England have. Instead, it requires regulated utilities to procure 100 percent of load, plus a 15 percent reserve margin. There is no mechanism in CAISO for acquiring future capacity, and therefore no mechanism for the RSO. CAISO has open dockets now on both these issues. The governance issue raised enough concern in the legislature that Gov. Brown announced in August he would go slower, with a possible vote in January. The regional grid concept is hardly new. It began with INDEGO -- the independent grid operator -- that was discussed by 21 Western entities over 20 years ago. “Implementation problems and tariff design disputes led to the official demise of the plan,” according to a 1998 study. Next came RTO West in the late 1990s, just in time for the great Western power crisis in 2000. As prices exploded due to market manipulation by Enron and others, anything related to California and competition became toxic. The idea was revived in 2003 as Grid West, in response to a strong push from FERC for standard market design, championed by then-chair Pat Wood. But the scars from the crisis were too fresh, and a push from the feds was seen as a top-down power grab, and fared poorly in the independent West. There are some major differences this time, according to Doug Larsen, former executive director of the Western Interstate Energy Board. Previous attempts started from scratch, and would have cost hundreds of millions of dollars for software and systems. “This time the CAISO has already developed everything,” said Larsen. “That’s why the EIM was successful -- it was plug and play for new participants.” A second major difference is the maturity of wind and solar power. “They have changed the realities, and more is coming,” he said. “There are real operational reasons to join now, not just a theoretical benefit.” The RSO is not the only option on the table. Seven utilities -- including Xcel, Western Area Power Administration and Basin Electric -- are discussing terms for a Mountain West Transmission Group, a regional entity that would create uniform transmission tariffs in Colorado, Wyoming, and neighboring states. And parties in the Pacific Northwest have been talking about a pooled operation since 2012, through the Northwest Power Pool’s Market Assessment and Coordination Committee. Their footprint includes 14 of the 38 balancing authorities in the Western Interconnect.
Davis J.L.,Fish and Parks |
Barnes M.E.,Fish and Parks |
Wilhite J.W.,Western Area Power Administration
North American Journal of Fisheries Management | Year: 2013
This study evaluated the efficacy of two potential zero-withdrawal anesthetics, Benzoak (20% benzocaine; 50, 60, and 75 mg/L) and Aqui-SE (50% eugenol; 50, 60, and 75 mg/L) compared with tricaine methanesulfonate (MS-222; 55, 80, and 100 mg/L), to anesthetize Rainbow Trout Oncorhynchus mykiss for PIT tag implantation surgery. In general, higher doses resulted in faster induction time to stage 4 anesthesia (defined by the cessation of reflex activity). At 204 s, the time to stage 4 anesthesia was slowest using MS-222 at 55 mg/L, followed by 50 mg/L of either Benzoak and Aqui-SE, which in turn were significantly slower to induce this level of anesthesia than were Benzoak or Aqui-SE at 60 or 75 mg/L or MS-222 at 80 mg/L. At 100 mg/L, MS-222 had the quickest time, 57 s, to stage 4 anesthesia. Time to recovery was longest for Rainbow Trout exposed to any concentration of Aqui-SE and shortest for MS-222, and recovery times from Benzoak were intermediate. Although Rainbow Trout length and weight varied significantly among the treatments, time to anesthesia and recovery were more dependent on the anesthetic and concentration used. In our opinion, doses of either Benzoak or Aqui-SE of greater than 60 mg/L will induce rapid anesthesia and provide relatively quick recovery times for adult Rainbow Trout. Received July 27, 2012; accepted January 10, 2013. © 2013 Copyright Taylor and Francis Group, LLC.
News Article | December 13, 2016
DENVER--(BUSINESS WIRE)--Following eight years of comprehensive federal environmental review, the Bureau of Land Management, U.S. Department of the Interior has signed its Record of Decision approving the TransWest Express Transmission Project. The TWE Project is a high-voltage, direct current (HVDC) electric transmission system being developed by TransWest Express LLC to directly and efficiently access diverse renewable energy supplies while reducing greenhouse-gas emissions. This significant energy infrastructure will strengthen the resiliency and reliability of the western U.S. electric grid by adding 3,000 megawatts of “backbone” transmission capacity between the Desert Southwest and Rocky Mountain regions. A Record of Decision is the final step for agencies in the Environmental Impact Statement process. The ROD was signed today in San Diego by Janice M. Schneider, Assistant Secretary, Land and Minerals Management, U.S. Department of the Interior. A Notice of Availability of the ROD for the TWE Project will be published in the Federal Register. BLM’s ROD follows the May 1, 2015, publication of the TWE Project Final EIS, which BLM and Western Area Power Administration prepared as joint lead federal agencies. The Final EIS reflected years of detail-driven environmental analysis, public input and collaboration among 50 federal, state and local cooperating agencies. BLM and WAPA each issue a separate ROD to document the agency’s decision pursuant to its unique purpose and need, including any required conditions and stipulations. The BLM ROD approves issuing a right-of-way grant for the TWE Project on BLM-managed land, which represents about 60 percent of the 730-mile route. TransWest has committed to hundreds of project-specific mitigation measures, best management practices and conservation actions designed to avoid, minimize and mitigate potential impacts of this infrastructure project to the environment. “The Western U.S. needs new interregional transmission infrastructure like the TWE Project, which will allow California and other Desert Southwest utilities to directly access high-capacity Wyoming wind to balance and diversify their generation portfolios in a cost-effective manner,” said Bill Miller, president and CEO of TransWest, an independent transmission developer. “Today’s important federal permitting milestone further advances the TWE Project’s progress and brings this critical infrastructure project one step closer to construction – creating employment opportunities across the West." The project’s construction is estimated to create up to 1,500 direct construction jobs each year for an estimated three-year construction period. With a shared commitment to creating employment opportunities and strengthening the Western electric grid, the Ute Indian Tribe of the Uintah and Ouray Reservation, the International Brotherhood of Electrical Workers, and the International Union of Operating Engineers have signed partnering agreements with TransWest for construction of the TWE Project. The TWE Project will extend from south-central Wyoming, to the site of a potential interconnection near Delta, Utah, and then to the Marketplace Hub near Hoover Dam in southern Nevada, which provides interconnections to the California, Nevada and Arizona grids. The EIS and other related documents are available on BLM’s website. TransWest’s right-of-way application for the TWE Project was filed with the BLM on Dec. 12, 2008. The Draft EIS was published July 3, 2013.
Biggins D.E.,U.S. Fish and Wildlife Service |
Biggins D.E.,U.S. Geological Survey |
Miller B.J.,U.S. Fish and Wildlife Service |
Miller B.J.,Wind River |
And 3 more authors.
Journal of Mammalogy | Year: 2011
Black-footed ferrets (Mustela nigripes) likely were extirpated from the wild in 19851986, and their repatriation depends on captive breeding and reintroduction. Postrelease survival of animals can be affected by behavioral changes induced by captivity. We released neutered Siberian polecats (M. eversmanii), close relatives of ferrets, in 19891990 on black-tailed prairie dog (Cynomys ludovicianus) colonies in Colorado and Wyoming initially to test rearing and reintroduction techniques. Captive-born polecats were reared in cages or cages plus outdoor pens, released from elevated cages or into burrows, and supplementally fed or not fed. We also translocated wild-born polecats from China in 1990 and released captive-born, cage-reared black-footed ferrets in 1991, the 1st such reintroduction of black-footed ferrets. We documented mortality for 55 of 92 radiotagged animals in these studies, mostly due to predation (46 cases). Coyotes (Canis latrans) killed 31 ferrets and polecats. Supplementally fed polecats survived longer than nonprovisioned polecats. With a model based on deaths per distance moved, survival was highest for wild-born polecats, followed by pen-experienced, then cage-reared groups. Indexes of abundance (from spotlight surveys) for several predators were correlated with mortality rates of polecats and ferrets due to those predators. Released black-footed ferrets had lower survival rates than their ancestral population in Wyoming, and lower survival than wild-born and translocated polecats, emphasizing the influence of captivity. Captive-born polecats lost body mass more rapidly postrelease than did captive-born ferrets. Differences in hunting efficiency and prey selection provide further evidence that these polecats and ferrets are not ecological equivalents in the strict sense. © 2011 American Society of Mammalogists.
Biggins D.E.,U.S. Fish and Wildlife Service |
Biggins D.E.,U.S. Geological Survey |
Hanebury L.R.,U.S. Fish and Wildlife Service |
Hanebury L.R.,Western Area Power Administration |
And 3 more authors.
Journal of Mammalogy | Year: 2011
Ecologically equivalent species serve similar functions in different communities, and an ecological surrogate species can be used as a substitute for an equivalent species in a community. Siberian polecats (Mustela eversmanii) and black-footed ferrets (M. nigripes) have long been considered ecological equivalents. Polecats also have been used as investigational surrogates for black-footed ferrets, yet the similarities and differences between the 2 species are poorly understood. We contrasted activity patterns of radiotagged polecats and ferrets released onto ferret habitat. Ferrets tended to be nocturnal and most active after midnight. Polecats were not highly selective for any period of the day or night. Ferrets and polecats moved most during brightly moonlit nights. The diel activity pattern of ferrets was consistent with avoidance of coyotes (Canis latrans) and diurnal birds of prey. Similarly, polecat activity was consistent with avoidance of red foxes (Vulpes vulpes) in their natural range. Intraguild predation (including interference competition) is inferred as a selective force influencing behaviors of these mustelines. Examination of our data suggests that black-footed ferrets and Siberian polecats might be ecological equivalents but are not perfect surrogates. Nonetheless, polecats as surrogates for black-footed ferrets have provided critical insight needed, especially related to predation, to improve the success of ferret reintroductions. © 2011 American Society of Mammalogists.
News Article | November 10, 2016
Bureau of Reclamation Commissioner Estevan López announced today the selection of Max Spiker as Senior Advisor for Hydropower and Electric Reliability Officer. Reclamation is the second largest generator of hydropower in the country; its 53 power plants annually generate an average of 40 billion kilowatt hours of electricity, enough to meet the demand of 3.5 million homes. "The availability of hydropower from Reclamation facilities is key to the stability of the electric transmission system in the Western United States and supports the development of renewable energy throughout the West," Commissioner López said. "Max’s extensive experience from all levels of power operations and management, including working collaboratively with Reclamation’s customers, stakeholders and industry, will be a great asset to Reclamation as it ensures the reliable generation of clean renewable electricity into the future." As senior advisor, Spiker will coordinate implementation of corporate partnership efforts involving Reclamation's power functions and serve as the liaison on intergovernmental initiatives associated with hydropower delivery and be responsible for Reclamation's overall compliance with Federal Energy Regulatory Commission Mandatory Bulk Electric System Reliability Standards. He will also coordinate activities in collaboration with the U.S. Army Corps of Engineers, Bonneville Power Administration, Western Area Power Administration and the Tennessee Valley Authority. Since 2013 Spiker has been the power resources manager where he worked with Reclamation offices in managing Reclamation's hydropower operation and maintenance program, reliability compliance program and renewable energy program. He joined Reclamation's Power Resources Office in 2010 as the operation and maintenance program manager where he provided policy direction and oversight. He previously held multiple positions including mechanical journeyman at Hoover Dam, facility manager at Green Mountain Dam, Estes Lake and Marys Lake power plants, facility manager of the Colorado - Big Thompson Project and power manager of the Upper Colorado Region where he managed the power program on the upper Colorado River and its tributaries, including Glen Canyon Dam, Flaming Gorge Dam and the facilities on the Gunnison River. Spiker has more than 28 years of experience with Reclamation. He graduated from Weber State University in 1988 with an Associate of Science degree in Construction Technology. He begins his new responsibilities this week.
Biggins D.E.,U.S. Geological Survey |
Hanebury L.R.,Western Area Power Administration |
Fagerstone K.A.,U.S. Department of Agriculture
Western North American Naturalist | Year: 2012
Intensive radio-tracking during AugustDecember enabled us to collect detailed information on digging behaviors of a small sample of black-footed ferrets (Mustela nigripes) occupying colonies of white-tailed prairie dogs (Cynomys leucurus). A sample of 33 prairie dogs, also radio-tagged, progressively ceased aboveground activity during late summer and fall, presumably as they descended into burrows to hibernate. Most of the time ferrets spent digging was in NovemberDecember when >95% of the radio-tagged prairie dogs were inactive, suggesting that digging was primarily to excavate hibernating prey. Although 43.9% of the burrow openings were estimated to be in large mounds, which are common on colonies of white-tailed prairie dogs, all of a sample of 17 deposits of soil (diggings) made by ferrets were excavated at small mounds or nonmounded openings. The average duration of 23 nocturnal sessions of digging by ferrets was 112.2 minutes. A digging session consisted of multiple bouts of soil movement typically lasting about 5 min, and sessions were separated by pauses above- or belowground lasting several minutes. Bouts of moving soil from a burrow involved round-trips of 12.530.3 s to remove an average of 35 cm3 of soil per trip. These digging bouts are energetically costly for ferrets. One female moved 16.8 kg of soil an estimated 3.3 m during bouts having a cumulative duration of 178 minutes, removing a soil plug estimated to be 178 cm long. Increasing evidence suggests that some behaviors of ferrets and prairie dogs are coevolutionary responses between this highly specialized predator and its prairie dog prey.
News Article | November 14, 2015
The South Dakota Public Utilities Commission has approved a construction permit for a 103-megawatt wind farm about 10 miles northeast of Newell. The Willow Creek Wind Energy Facility to be built by Wind Quarry LLC will include 45 wind turbines and will interconnect to a 115-kilovolt transmission line owned by the Western Area Power Administration.