Idaho Power Company is a regulated electrical power utility. Its business involves the purchase, sale, generation, transmission and distribution of electricity in eastern Oregon and southern Idaho. It is a subsidiary of IDACORP, Inc. The company's 24,000-square-mile service area generally follows the area around the Snake River and its tributaries.Idaho Power owns and operates 17 hydroelectric dams and 2 natural gas power plants. IPC also owns shares of three coal-fired power plants.In 2007, electricity sold by IPC was 33% hydroelectric, 39% thermal and 28% was purchased from other generation companies. Wikipedia.
News Article | May 11, 2017
The meeting also will be webcast at idacorpinc.com, available to both shareholders and non-shareholders. Webcast login information will be posted on the IDACORP, Inc. website the morning of the meeting. Presentation slides will be available on the website before the meeting begins. Following the meeting, all Annual Meeting webcast materials will be available on the company's website for a period of 12 months. IDACORP, Inc., Boise, Idaho-based and formed in 1998, is a holding company comprised of Idaho Power Company, a regulated electric utility; IDACORP Financial, a holder of affordable housing projects and other real estate investments; and Ida-West Energy, an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978. Idaho Power began operations in 1916 and employs approximately 2,000 people to serve a 24,000 square-mile service area in southern Idaho and eastern Oregon. With 17 low-cost hydroelectric projects as the core of its generation portfolio, Idaho Power's more than 535,000 residential, business and agricultural customers pay some of the nation's lowest prices for electricity. To learn more about IDACORP or Idaho Power, visit idacorpinc.com or idahopower.com. To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/idacorp-inc-annual-meeting-of-shareholders-scheduled-for-may-18-2017-300456152.html
News Article | May 15, 2017
The Trump administration’s obsession with the coal industry has driven many of its early energy and environmental policy initiatives—with the Energy Department’s thinly veiled baseload power plant review just the latest in a string of efforts to buttress the troubled sector. But none of these policies are going to change coal’s central problem: The utility industry, far and away its largest customer, is steadily moving away from the black rock. This transition won’t happen overnight, but the direction is clear, as a close review of recent utility executive statements and company publications clearly demonstrates. Consider the message delivered by Allen Leverett, president and CEO of Milwaukee-based WEC Energy Group, in the company’s latest annual report: “I also believe that some form of carbon emission regulation is ultimately inevitable. As the regulation of carbon emissions takes shape, our plan is to work with our industry partners, environmental groups and the state of Wisconsin to reduce carbon dioxide emissions by approximately 40 percent below 2005 levels by 2030. “In 2016, about half of the electricity we delivered to our customers was derived from low- or no-carbon sources such as natural gas, nuclear fuel, wind farms and hydroelectric facilities. However, we want to continue to make progress in this area. Relatively flat electricity demand growth, coupled with natural gas and coal economics, has driven us to re-evaluate our generation portfolio. Taken as a group, I want any changes that we make to reduce costs, preserve fuel diversity and keep us on a path to reducing our carbon emissions.” In other words, there will be no new coal generation in the WEC fleet, and the company’s reliance on the fuel, currently around 50 percent of its needs, is going to drop. In particular, the company has plans to build new natural gas-fired generation in the Upper Peninsula of Michigan and close its five-unit, 359 megawatt Presque Isle facility there, which now burns roughly 1.2 million tons of coal annually according to the company, whose two electric utility subsidiaries serve more than 1.5 million customers in Wisconsin and the UP of Michigan. Or consider the comments made by Lynn Good, chairman, president and CEO of Duke Energy, during the Charlotte, N.C.-based company’s annual meeting earlier this month: To get to that point, the company, one of the nation’s largest electric utilities serving roughly 7.4 million electric customers across six states and controlling approximately 52,000 MW of generating capacity, plans to boost natural gas-fired generation to 35 percent of its generation portfolio during the next 10 years and raise renewable output to about 10 percent, Good told the meeting. Earlier, in releasing the company’s 2016 sustainability report, Good discussed another point that is driving many utility leaders (but that has been totally absent from any Trump administration talk)—customer expectations. “As technology and customers’ expectations evolve, Duke Energy is responding by investing in innovative new solutions to power the lives of our customers with reliable, affordable and increasingly clean energy,” Good said. “How we generate energy is more important than ever before and we’re making long-term investments that will deliver a lower-carbon future.” And then there is this nugget offered up by Nicholas Akins, chairman, president and CEO of American Electric Power, at the company’s annual meeting in late April: The chart below from the Columbus, Ohio-based company’s April investor meeting makes Akins’ point crystal clear—coal is certainly still a part of the mix, but the growth at AEP, which serves some 5.4 million electric customers across 11 states, will be in natural gas and renewables, just like at every other utility in the country. Looking to the South, the picture is the same. In its just-released 2016 sustainability report, New Orleans-based Entergy points out that the amount of coal on its system, small by comparison to AEP and other Midwest utilities, has dropped from 11 percent to 7 percent in just two years, while the amount of lower-emitting natural gas-fired generation has jumped from 28 percent to 41 percent of its system needs. In addition, while not yet a major part of its generation, renewables are gaining ground. “Technology advances are making renewable energy as well as certain distributed energy resources increasingly cost-competitive,” the company, which has 2.9 million electric customers in four states, wrote in its report (which is available here either for online reading or as a downloadable pdf). “Entergy is exploring utility-scale renewable opportunities as well as potential applications for distributed energy resources as part of our ongoing modernization efforts.” Asked directly about the administration’s coal rescue efforts, Entergy CEO Leo Denault told Arkansas Online’s David Smith that they didn’t matter. “Our desire is to be an environmentally responsible company,” Denault said. “Whatever the administration does, that doesn’t change our point of view.” Head west and you hear exactly the same refrain. In its draft 2017 integrated resources plan, submitted in late April, Albuquerque-based PNM Resources outlined a future that would close its remaining coal-fired generating units by 2031. Echoing the customer-centered comments made by Duke’s Good, Pat Vincent-Collawn, chairman, president and CEO of PNM Resources, said: Under the terms of the plan, PNM, which serves roughly 510,000 customers throughout New Mexico, would close Units 1 and 4 of the coal-fired San Juan generating station by the end of 2022, instead of 2036 as in the utility’s previous IRP. The four-unit station has a total generating capacity of 1,684 MW; PNM owns 783 MW of the total and operates all four units. Units 2 and 3 have a capacity of 837 MW of which PNM owns 418 MW; they are being closed at the end of this year to comply with regional haze requirements under the Clean Air Act. A bulwark of the utility’s generation fleet since it was completed in the 1970s, San Juan is no longer economically competitive the company’s draft IRP concludes: “The most significant finding of the IRP is that retiring PNM’s…share of SJGS [San Juan Generating Station] in 2022 would provide long-term cost savings for PNM’s customers…. The results of the IRP illustrate that energy needs are changing and replacing coal supply with renewable energy and more flexible generators will save money in the long run.” The draft IRP (which is available here) also indicates that it would be economic for the utility to “exit” its 13 percent stake in the 1,540 MW Four Corners coal-fired plant when its existing coal supply agreement expires in 2031; PNM’s previous IRP included a post-2036 date for closing/exiting from this facility. “This action would eliminate coal from PNM’s generating fleet,” PNM wrote. And much like its larger neighbors to the east, regardless of the Trump triumph, PNM is planning for the eventual imposition of carbon controls. “The near-term outlook for explicit carbon costs has been altered by the 2016 presidential election,” the utility noted in the draft IRP. “Implementation of the Clean Power Plan is on hold for judicial review and the key provisions are being unwound by the EPA under a new executive order. Nonetheless, PNM is continuing to model a cost for each ton of CO emitted in each portfolio’s projected operation. PNM expects that a replacement for the CPP is likely to be implemented at some point in response to continued international calls that carbon emissions should be addressed.” Finally, even in deep-red Idaho to the north, Boise-based Idaho Power is steadily trimming its reliance on coal-fired electric generation. Just two years ago, coal accounted for 35.7 percent of its generation mix, today it is less than 25 percent—and about to fall even further. Earlier this month the utility, which serves approximately 535,000 customers in Idaho and parts of eastern Oregon, filed a settlement agreement with the Idaho Public Utilities Commission under which it would seek to close the 522 MW, two-unit North Valmy coal-fired generating station by 2025. Under the terms of Idaho Power’s proposal Unit 1, totaling 254 MW, would be shut in 2019 while Unit 2, totaling 268 MW, would be closed no later than 2025; earlier the utility had planned to run the units to 2031 and 2035, respectively. Idaho Power co-owns the facility with Nevada Energy and now must reach an agreement with its utility neighbor, but since NV Energy had previously said it hoped to close the units by 2025 as well the two companies should be able to hammer out a plan for shuttering the coal plant by that date. The specifics may remain up in the air at the moment, but the end result is clear—the plant is going to close, likely sooner than later. No matter where you look, the picture is the same: Electric utilities are taking a close look at coal and finding that it no longer makes economic sense. The Trump administration may not be willing (or able) to admit this, but it is obvious to everyone else—particularly those making the investments decisions in the electric utility industry In a post 18 months ago about nuclear power (read it here), I wrote that believing in the economics of large nuclear requires utilities to believe in impossible things; the same can be said today of the Trump administration and its promise to restore coal’s lost luster.
News Article | May 4, 2017
"Economic activity remains strong in Idaho Power's service area, with new customers coming online and existing large-load customers building new facilities. Employment levels are growing and we continue to receive high levels of interest from companies seeking to expand or site in our service area. "For the full year, we continue to project Idaho Power's use of additional accumulated deferred investment tax credits under the Idaho regulatory settlement to be less than $10 million," added Anderson. IDACORP is reaffirming its full year 2017 earnings guidance in the range of $3.90 to $4.05 per diluted share. A summary of financial highlights for the quarter ended March 31, 2017 is as follows (in thousands except per share amounts): The table below provides a reconciliation of net income attributable to IDACORP for the three months ended March 31, 2017, from the three months ended March 31, 2016 (items are in millions and are before related tax impact unless otherwise noted). IDACORP's net income increased $7.4 million for the first quarter of 2017 compared with the first quarter of 2016. The increase was driven primarily by a $6.9 million increase in Idaho Power's net income. At Idaho Power, an increase in sales volumes on a per-customer basis contributed $9.1 million to operating income in the first quarter of 2017 compared with the first quarter of 2016, but was largely offset by a $6.1 million decrease in revenues from the application of the FCA mechanism. Temperatures in Idaho Power's service area were colder than normal in the first quarter of 2017 and were significantly colder than first quarter 2016 temperatures. The cold weather resulted in increased residential sales volumes on a per-customer basis and caused an increase in the proportion of residential sales in higher rate categories under Idaho Power's tiered rate structure. These higher tiered rates drove a $1.5 million increase to operating income. Customer growth further drove higher sales volumes, lifting operating income by $2.7 million, as the number of Idaho Power customers grew by 1.9 percent over the prior twelve months. In addition to these changes in general business revenues, Idaho Power benefited from a $2.8 million increase in third-party use of electric property, wheeling, and other revenue due to a new long-term wheeling agreement as well as an increase in Idaho Power's Open Access Transmission Tariff rates, which was effective in October 2016. Partly offsetting these increases, other operating and maintenance expenses were $2.2 million higher, compared with the same period in the prior year. Weather affected the timing and amount of certain operating and maintenance expenses during the quarter. The increase in income tax expense was principally the result of higher income before income taxes, partially offset by an increase in additional ADITC amortization. Based on Idaho Power's current expectations of full-year 2017 results, Idaho Power recorded $1.9 million of additional ADITC amortization under its Idaho regulatory settlement stipulation during the first quarter of 2017 compared with $0.5 million in the first quarter of 2016. Idaho Power currently expects to use less than $10 million of additional ADITC for the full-year 2017. 2017 Annual Earnings Guidance and Key Operating and Financial Metrics IDACORP is reaffirming its earnings guidance estimate for 2017. The 2017 guidance incorporates all of the key operating and financial assumptions listed in the table that follows (in millions, except per share amounts): More detailed financial information is provided in IDACORP's Quarterly Report on Form 10-Q filed today with the U.S. Securities and Exchange Commission and posted to the IDACORP Web site at www.idacorpinc.com. IDACORP will hold an analyst conference call today at 2:30 p.m. Mountain Time (4:30 p.m. Eastern Time). All parties interested in listening may do so through a live webcast on the company's website (www.idacorpinc.com), or by calling (800) 242-0681 for listen-only mode. There is no passcode required; simply request to be connected to the "IDACORP, Inc." call. The conference call logistics are also posted on the company's website and will be included in the company's earnings news release. Slides will be included during the conference call. To access the slide deck, register for the event just prior to the call at www.idacorpinc.com/investor-relations/earnings-center/conference-calls. A replay of the conference call will be available on the company's website for a period of 12 months and will be available shortly after the call. IDACORP, Inc. (NYSE: IDA), Boise, Idaho-based and formed in 1998, is a holding company comprised of Idaho Power, a regulated electric utility; IDACORP Financial, a holder of affordable housing projects and other real estate investments; and Ida-West Energy, an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978. Idaho Power began operations in 1916 and employs approximately 2,000 people to serve a 24,000-square-mile service area in southern Idaho and eastern Oregon. With 17 low-cost hydroelectric projects as the core of its generation portfolio, Idaho Power's more than 535,000 residential, business and agricultural customers pay some of the nation's lowest prices for electricity. To learn more about IDACORP or Idaho Power, visit www.idacorpinc.com or www.idahopower.com. In addition to the historical information contained in this press release, this press release contains (and oral communications made by IDACORP, Inc. and Idaho Power Company may contain) statements, including, without limitation, earnings guidance, that relate to future events and expectations and, as such, constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, outlook, assumptions, or future events or performance, often, but not always, through the use of words or phrases such as "anticipates," "believes," "continues," "estimates," "expects," "guidance," "intends," "potential," "plans," "predicts," "projects," "targets," or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements are not guarantees of future performance and involve estimates, assumptions, risks, and uncertainties. Actual results, performance, or outcomes may differ materially from the results discussed in the statements. In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes to differ materially from those contained in forward-looking statements include the following: (a) the effect of decisions by the Idaho and Oregon public utilities commissions, the Federal Energy Regulatory Commission, and other regulators that impact Idaho Power's ability to recover costs and earn a return; (b) the expense and risks associated with capital expenditures for infrastructure, and the timing and availability of cost recovery for such expenditures; (c) changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power's service area and the loss or change in the business of significant customers, and their associated impacts on loads and load growth, and the availability of regulatory mechanisms that allow for timely cost recovery in the event of those changes; (d) the impacts of economic conditions, including inflation, the potential for changes in customer demand for electricity, revenue from sales of excess power, financial soundness of counterparties and suppliers, and the collection of receivables; (e) unseasonable or severe weather conditions, wildfires, drought, and other natural phenomena and natural disasters, which affect customer demand, hydroelectric generation levels, repair costs, and the availability and cost of fuel for generation plants or purchased power to serve customers; (f) advancement of generation or energy efficiency technologies that reduce loads or reduce Idaho Power's sale of electric power; (g) adoption of, changes in, and costs of compliance with laws, regulations, and policies relating to the environment, natural resources, and threatened and endangered species, and the ability to recover resulting increased costs through rates; (h) variable hydrological conditions and over-appropriation of surface and groundwater in the Snake River Basin, which may impact the amount of power generated by Idaho Power's hydroelectric facilities; (i) the ability to acquire fuel, power, and transmission capacity under reasonable terms, particularly in the event of unanticipated power demands, lack of physical availability, transportation constraints, or a credit downgrade; (j) accidents, fires (either at or caused by Idaho Power's facilities), explosions, and mechanical breakdowns that may occur while operating and maintaining Idaho Power's assets, which can cause unplanned outages, reduce generating output, damage the companies' assets, operations, or reputation, subject the companies to third-party claims for property damage, personal injury, or loss of life, or result in the imposition of civil, criminal, and regulatory fines and penalties; (k) the increased power purchased costs and operational challenges associated with purchasing and integrating intermittent renewable energy sources into Idaho Power's resource portfolio; (l) disruptions or outages of Idaho Power's generation or transmission systems or of any interconnected transmission system may cause Idaho Power to incur repair costs and purchase replacement power at increased costs; (m) the ability to obtain debt and equity financing or refinance existing debt when necessary and on favorable terms, which can be affected by factors such as credit ratings, volatility in the financial markets, interest rate fluctuations, decisions by the Idaho or Oregon public utility commissions, and the companies' past or projected financial performance; (n) reductions in credit ratings, which could adversely impact access to capital markets, increase costs of borrowing, and would require the posting of additional collateral to counterparties pursuant to credit and contractual arrangements; (o) the ability to enter into financial and physical commodity hedges with creditworthy counterparties to manage price and commodity risk, and the failure of any such risk management and hedging strategies to work as intended; (p) changes in actuarial assumptions, changes in interest rates, and the return on plan assets for pension and other post-retirement plans, which can affect future pension and other postretirement plan funding obligations, costs, and liabilities; (q) the ability to continue to pay dividends based on financial performance and in light of contractual covenants and restrictions and regulatory limitations; (r) changes in tax laws or related regulations or new interpretations of applicable laws by federal, state, or local taxing jurisdictions, the availability of tax credits, and the tax rates payable by IDACORP shareholders on common stock dividends; (s) employee workforce factors, including the operational and financial costs of unionization or the attempt to unionize all or part of the companies' workforce, the impact of an aging workforce and retirements, the cost and ability to retain skilled workers, and the ability to adjust the labor cost structure when necessary; (t) failure to comply with state and federal laws, regulations, and orders, including new interpretations and enforcement initiatives by regulatory and oversight bodies, which may result in penalties and fines and increase the cost of compliance, the nature and extent of investigations and audits, and the cost of remediation; (u) the inability to obtain or cost of obtaining and complying with required governmental permits and approvals, licenses, rights-of-way, and siting for transmission and generation projects and hydroelectric facilities; (v) the cost and outcome of litigation, dispute resolution, and regulatory proceedings, and the ability to recover those costs or the costs of operational changes through insurance or rates, or from third parties; (w) the failure of information systems or the failure to secure data, failure to comply with privacy laws, security breaches, or the direct or indirect effect on the companies' business or operations resulting from cyber attacks, terrorist incidents or the threat of terrorist incidents, and acts of war; (x) unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs, or the failure to successfully implement new technology solutions; and (y) adoption of or changes in accounting policies and principles, changes in accounting estimates, and new U.S. Securities and Exchange Commission or New York Stock Exchange requirements, or new interpretations of existing requirements. Any forward-looking statement speaks only as of the date on which such statement is made. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. Readers should also review the risks and uncertainties listed in IDACORP, Inc.'s and Idaho Power Company's most recent Annual Report on Form 10-K and other reports the companies file with the U.S. Securities and Exchange Commission, including (but not limited to) Part I, Item 1A - "Risk Factors" in the Form 10-K and Management's Discussion and Analysis of Financial Condition and Results of Operations and the risks described therein from time to time. IDACORP and Idaho Power disclaim any obligation to update publicly any forward-looking information, whether in response to new information, future events, or otherwise, except as required by applicable law. To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/idacorp-inc-announces-first-quarter-results-reaffirms-2017-earnings-guidance-300451283.html
Conner J.T.,Idaho Power Company |
Tonina D.,University of Idaho
Earth Surface Processes and Landforms | Year: 2014
Two-dimensional (2D) hydrodynamic models have been increasingly used to quantify aquatic habitat and stream processes, such as sediment transport, streambed morphological evolution, and inundation extents. Because river topography has a strong influence on predicted hydraulic conditions, 2D models require accurate and detailed bathymetric data of the stream channel and surrounding floodplains. Besides collection of mass points to construct high-resolution three-dimensional surfaces, bathymetries may be interpolated from cross-sections. However, limited information is available on the effects of cross-section spacing and the derived interpolated bathymetry on 2D model results in large river systems. Here, we investigated the effects of cross-section spacing on flow properties simulated with 2D modeling at low, medium and high discharges in two morphologically different reaches, a simple (almost featureless with low sinuosity) and a complex (presenting pools, riffles, runs, contractions and expansions) reach of the Snake River (Idaho, USA), the tenth largest river in the United States in terms of drainage area. We compared the results from 2D models developed with complete channel bathymetry acquired with multibeam sonar data and photogrammetry, with 2D model results that were developed using interpolated topography from uniformly distributed transects. Results indicate that cross-sections spaced equal to or greater than 2 times the average channel width (W*) smooths the bathymetry and suppresses flow structures. Conversely, models generated with cross-sections spaced at 0.5 and 1 W* have stream flow properties, sediment mobility and spatial habitat distribution similar to those of the complete bathymetry. Furthermore, differences in flow properties between interpolated and complete topography models generally increase with discharge and with channel complexity. © 2013 John Wiley & Sons, Ltd.
Xue L.,U.S. National Center for Atmospheric Research |
Hashimoto A.,Meteorological Research Institute |
Murakami M.,Meteorological Research Institute |
Rasmussen R.,U.S. National Center for Atmospheric Research |
And 5 more authors.
Journal of Applied Meteorology and Climatology | Year: 2013
A silver iodide (AgI) cloud-seeding parameterization has been implemented into the Thompson microphysics scheme of the Weather Research and Forecasting model to investigate glaciogenic cloudseeding effects. The sensitivity of the parameterization to meteorological conditions, cloud properties, and seeding rates was examined by simulating two-dimensional idealized moist flow over a bell-shaped mountain. The results verified that this parameterization can reasonably simulate the physical processes of cloud seeding with the limitations of the constant cloud droplet concentration assumed in the scheme and the two-dimensional model setup. The results showed the following: 1) Deposition was the dominant nucleation mode of AgI from simulated aircraft seeding, whereas immersion freezing was the most active mode for ground-based seeding. Deposition and condensation freezing were also important for groundbased seeding. Contact freezing was the weakest nucleation mode for both ground-based and airborne seeding. 2) Diffusion and riming on AgI-nucleated ice crystals depleted vapor and liquid water, resulting in more ice-phase precipitation on the ground for all of the seeding cases relative to the control cases.Most of the enhancement came from vapor depletion. The relative enhancement by seeding ranged from 0.3% to 429% under various conditions. 3) The maximum local AgI activation ratio was 60% under optimum conditions. Under most seeding conditions, however, this ratio was between 0.02% and 2% in orographic clouds. 4) The seeding effect was inversely related to the natural precipitation efficiency but was positively related to seeding rates. 5) Ground-based seeding enhanced precipitation on the lee side of the mountain, whereas airborne seeding from lower flight tracks enhanced precipitation on the windward side of the mountain. © 2013 American Meteorological Society.
Xue L.,U.S. National Center for Atmospheric Research |
Tessendorf S.A.,U.S. National Center for Atmospheric Research |
Nelson N.,U.S. National Center for Atmospheric Research |
Rasmussen R.,U.S. National Center for Atmospheric Research |
And 4 more authors.
Journal of Applied Meteorology and Climatology | Year: 2013
Four cloud-seeding cases over southern Idaho during the 2010/11 winter season have been simulated by the Weather Research and Forecasting (WRF) model using the coupled silver iodide (AgI) cloud-seeding scheme that was described in Part I. The seeding effects of both ground-based and airborne seeding as well as the impacts of model physics, seeding rates, location, timing, and cloud properties on seeding effects have been investigated. The results were compared with those from Part I and showed the following: 1) For the four cases tested in this study, control simulations driven by the Real-Time Four Dimensional Data Assimilation (RTFDDA) WRF forecast data generated more realistic atmospheric conditions and precipitation patterns than those driven by the North America Regional Reanalysis data. Sensitivity experiments therefore used the RTFDDA data. 2) Glaciogenic cloud seeding increased orographic precipitation by less than 1% over the simulation domain, including the Snake River basin, and by up to 5%over the target areas. The local values of the relative precipitation enhancement by seeding were ;20%. Most of the enhancement came from vapor depletion. 3) The seeding effect was inversely related to the natural precipitation efficiency but was positively related to seeding rates. 4) Airborne seeding is generally more efficient than ground-based seeding in terms of targeting, but its efficiency depends on local meteorological conditions. 5) The normalized seeding effects ranged from 0.4 to 1.6 under various conditions for a certain seeding event. © 2013 American Meteorological Society.
McKinney E.,Idaho Power Company |
Daniel Arjona J.,Idaho Power Company
IEEE Power and Energy Society General Meeting | Year: 2014
A process for identifying specific opportunities for a utility's implementation of microgrids is presented in the form of a process performed at an investor-owned electrical power utility in the Intermountain West. The paper provides the conditions, criteria, and constraints by which the study was conducted, it identifies specific scenarios and locations within the service territory by way of general conditions of viability, it addresses other possible scenarios and locations that are unique to the Company, and it provides a cost comparison example. © 2014 IEEE.
Papic M.,Idaho Power Company |
Ciniglio O.,Idaho Power Company
IEEE Power and Energy Society General Meeting | Year: 2014
Modern power systems are designed to withstand n-1 and credible n-2 outages. The ability of a system to survive major disturbances was not comprehensively addressed by system planers. Most large blackouts happening throughout the world involve a sequence of cascading outages that are complex and require adequate methodologies and tools to be addressed properly. Cascading outages expose transmission planners and operation engineers to new challenges, including identifying means to minimize the cascading vulnerability impacts. This paper presents a comprehensive, practical approach to identify and analyze the multiple contingencies that lead to cascading outages in Idaho Power's network. The primary focus of this paper is to identify the system's most vulnerable places and double outages that lead to widespread power disruptions and cascading, evaluate their consequences, and identify possible remedial actions to prevent cascading or mitigate its effect. The suggested approach is a further enhancement of the present study approach used by Idaho Power in performing North American Electric Reliability Corporation (NERC) compliance studies. Understanding the effects of cascading on vulnerabilities of Idaho Power's system is needed to determine when a disruption of service is likely to occur and to take appropriate steps to reduce the associated risk. Understanding cascading outages and being able to predict the associated risks is becoming an integral part of planning and operation studies by Idaho Power. In this paper, a model of the actual Idaho portion of the Western Electricity Coordinating Council (WECC) system was used. The results of the cascading analysis for five base cases are presented. © 2014 IEEE.
News Article | February 23, 2017
BOISE, Idaho, Feb. 23, 2017 /PRNewswire/ -- IDACORP, Inc. (NYSE: IDA) recorded fourth quarter 2016 net income attributable to IDACORP of $33.2 million, or $0.66 per diluted share, compared with $31.8 million, or $0.63 per diluted share, in the fourth quarter of 2015. IDACORP reported 2016...
News Article | March 8, 2016
Coal is loaded into a truck at the Jim Bridger Mine, owned by energy firm PacifiCorp and the Idaho Power Company, outside Point of the Rocks, Wyoming March 14, 2014. Coal companies are responsible for spent mines and they typically use cash, bonds or other financing to cover future cleanup costs. But some of the largest producers use self bonds, which are not backed by concrete collateral, to insure such costs. Regulators worry those costs could fall to taxpayers if the companies fail.The coal industry has roughly $3.6 billion in future cleanup costs covered by self bonds and the Government Accountability Office should review the program, the lawmakers wrote. U.S. Senators Maria Cantwell of Washington and Dick Durbin of Illinois are seeking an "audit of self-bonding" in the coal industry and a review of how the oil, gas and mineral sectors protect taxpayers from cleanup costs. The Government Accountability Office is an independent, non-partisan investigative arm of Congress. Interior Department Secretary Sally Jewell told Congress last month that self-bonding was "a very significant problem and a risk to the taxpayer" in light of coal industry woes and bankruptcies for Arch Coal and Alpha Natural Resources. The coal industry has been hurt by oversupply, competition from natural gas and weak export demand. Arch and Alpha have sought to jettison cleanup liabilities in bankruptcy court and Jewell said officials would not tolerate such maneuvers. While federal officials conceived self-bonding decades ago, coal-producing states are largely left to administer a program that some still defend. Last week, Illinois told the Interior Department it would allow Peabody Energy Corp to continue to self bond about $100 million in future cleanup costs. If Illinois and other coal-producing states were to revoke Peabody's self bonds, the cash-strapped company might need private financing to underwrite about $1.38 billion in liabilities not now backed by collateral. Peabody reported about a $2 billion loss last year and has struggled to sell some western mines to raise cash.