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Home My WebLink About2009_annualreportdraft.pdfIPUC Annual Report 2009 1 | P a g e The Honorable C.L. “Butch” Otter Office of the Governor Statehouse Boise, ID 83720‐0034 Dear Governor Otter: It is my distinct pleasure to submit to you, in accordance with Idaho Code §61‐214, the Idaho Public Utilities Commission 2009 Annual Report. Idaho customers of major electric and gas utilities are learning that, unfortunately, we are not immune to the upward pressures on utility rates occurring nationwide. All of the investor‐owned electric utilities we regulate experienced rate increases during 2008. Gas customers, on the other hand, experienced significant decreases, thanks to lower prices on the wholesale market. Idaho Power Company had two major rate adjustments in 2009 on Feb. 1 and June 1. The rate case completed in late January resulted in an average 4 percent increase after an appeal. Most significant about this case was the implementation of tiered rates. We continue to get customer comment regarding tiered rates (addressed in more detail on pages 14 and 15 of this report) and we are reviewing those for possible changes. The larger rate increase for Idaho Power customers came later on June 1 with the yearly Power Cost Adjustment, a 10.2 percent increase. Three other adjustments, including the Fixed Cost Adjustment (FCA), an increase to the Energy Efficiency Rider and the first year’s installment of automated meters, were implemented on the same date, resulting in an overall rate increase of about 15.5 percent. As you know, the Power Cost Adjustment (PCA) is determined largely on the previous year’s water conditions and market conditions, a forecast of future market conditions and a true‐up of the previous year’s forecast. Idaho Power’s earnings do not increase when the PCA goes up, but it can still have a significant impact on customer rates. Fortunately it is updated every June 1, and in 2010 we are expecting a decrease. We are in the final year of a three‐year pilot for the Fixed Cost Adjustment. This adjustment is a mechanism intended to allow Idaho Power to recover its fixed costs when power sales decline due to the company’s investment in energy efficiency and conservation programs. We are still reviewing whether this program should be made permanent, as the company has requested. We want to make sure that “lost revenues” are actually attributable to the company’s investment in these programs and not because of other factors such as customer self‐initiated conservation or economic conditions. Avista Utilities filed a joint electric and natural gas rate increase in January. In July, the Commission approved a settlement that increased base rates by 5.7 percent, but because of a 4.2 percent reduction in the company’s annual Power Cost Adjustment, the net increase was 1.5 IPUC Annual Report 2009 2 | P a g e percent. On the gas side, the base rate increase was 2.1 percent, but customers did not pay more this year because of a reduction in the Purchased Gas Cost Adjustment. PacifiCorp, which does business in eastern Idaho as Rocky Mountain Power, filed a request for a 4 percent increase in September 2008 and was granted 3.1 percent effective April 18, 2009. This case was resolved by a settlement of the parties. In a separate case, the commission approved a yearly adjustment for PacifiCorp called an Energy Cost Adjustment Mechanism (ECAM). Similar to Idaho Power’s PCA, it allows rates to be adjusted up or down every April 1 to account for varying costs of power supply. On the brighter side, gas customers for Avista Utilities saw three decreases during the year to the Purchased Gas Cost Adjustment (PGA) portion of their bills that totaled about 33 percent. Intermountain Gas customers in southern Idaho saw a decrease of about 26.5 percent. One of the more significant developments of the year was the Commission’s approval of Idaho Power’s request for a certificate to build a 330‐megwatt natural gas plant near New Plymouth. The plant, called Langley Gulch, is expected to be operating by late 2012. Details are presented on pages 24 and 25. Idaho Power is in the third year of an approximate $71 million project to install automated meters throughout its service territory. This effort is an initial part of a future Idaho Power Smart Grid. Details are available on page 26. In early 2009, we completed a major energy affordability study. This was initiated in response to the now almost annual request for rate increases from utilities. We, along with consumer groups, sought to find ways to mitigate the impacts of these increases on customers as much as possible. A summary of our recommendations is available on pages 30‐32 of this report. A major project this year for Commission staff, working in coordination with the Office of Energy Resources, was the completion of a 120‐page report to the Legislature on our progress toward implementing the goals of the 2007 Energy Plan. A link to the report on our Web page is http://www.puc.idaho.gov/hot/EnergyPlan%20OER_PUC.pdf Our dedicated staff is working on several additional projects you will find outlined in the pages of this report. It has been a privilege and an honor to serve you and the citizens of Idaho. Sincerely, Jim Kempton President Idaho Public Utilities Commission IPUC Annual Report 2009 3 | P a g e Idaho Public Utilities Commission 472 West Washington Street Boise, Idaho 83702 Mailing Address: P.O. Box 83720 Boise, Idaho 83720‐0074 208/334‐0300 Web site: www.puc.idaho.gov Commission Secretary 334‐0338 jean.jewell@puc.idaho.gov Executive Administrator 334‐0330 Public Information Officer 334‐0339 gene.fadness@puc.idaho.gov. Utilities Division 334‐0368 Legal Division 334‐0324 Rail Section and Pipeline Safety 334‐0330 Consumer Assistance Section 334‐0369 Outside Boise, Toll‐Free Consumer Assistance 1‐800‐432‐0369 Idaho Telephone Relay Service (available statewide) Voice: 1‐800‐377‐1363 Text Telephone: 1‐800‐377‐3529 TRS Information: 1‐800‐368‐6185 With this report, the Idaho Public Utilities Commission has satisfied Idaho Code 61‐214; this is a “full and complete account” of the most significant cases to come before the commission during the 2009 calendar year. (The financial report on Page 8 covers Fiscal Year July 1, 2007 through June 30, 2008.) Anyone with access to the Internet may also review the commission’s agendas, notices, case information and decisions by visiting the IPUC’s Web site at: www.puc.idaho.gov. Commission records are also available for public inspection at the commission’s Boise office, 472 W. Washington St., Monday through Friday, 8 a.m. to 5 p.m. A nominal fee of 5 cents per page may be charged for the cost of copying, typically for 30 or more pages. The Idaho Public Utilities Commission, as outlined in its Strategic Plan, serves the citizens and utilities of Idaho by determining fair, just and reasonable rates for utility commodities and services that are to be delivered safely, reliably and efficiently. During the period covered by this report, the commission also had responsibility for ensuring all rail services operating within Idaho do so in a safe and efficient manner. The commission also has a pipeline safety section that oversees the safe operation of the intrastate natural gas pipelines and facilities in Idaho. IPUC Annual Report 2009 4 | P a g e The Commissioners Jim D. Kempton Commissioner Kempton began his service on the commission on Oct. 22, 2007. Kempton was appointed by Gov. C.L. “Butch” Otter to fill the unexpired term of Commissioner Paul Kjellander who was appointed to head the newly created Office of Energy Resources. On April 6, 2009, Commissioner Kempton was elected president of the commission. Before he was appointed to the commission, Kempton was one of two Idaho representatives on the Northwest Power and Conservation Council, appointed to that post by former Idaho Gov. Dirk Kempthorne. While on the council, he also acted as a natural resource cabinet member for Gov. Otter. Kempton, of Albion, was a member of the Idaho House of Representatives from 1991‐ 2000, where he served on the House Revenue and Taxation Committee and chaired the Transportation and Defense Committee. Earlier, he served for two years on the Environmental Affairs Committee. Kempton earned his bachelor's and master's degrees in physics from the University of Idaho. He was a fighter pilot in the United States Air Force and an assistant professor of physics at the United States Air Force Academy. He also worked in the Pentagon as Department of Defense liaison between the Secretary of Commerce and Secretary of Defense on international co‐production programs. His Pentagon assignments included Air Force research and development responsibilities in the F‐16 fighter program and coordinating Iranian Program Review briefings to the Secretary of the Air Force. He returned to Idaho in 1981 and was engaged in ranching until 1990, when he was elected to the Idaho Legislature. He is a former member of the "Idaho EPSCoR" Board, a National Science Foundation experimental program to stimulate competitive research. He and his wife, Susan, are the parents of two grown daughters. Marsha H. Smith Commissioner Smith is serving her fourth term on the commission. Her current term expires in January 2015. Smith, a Democrat, served as commission president from November 1991 to April 1995. Commissioner Smith is a past president of the National Association of Regulatory Utility Commissioners (NARUC), serves on the NARUC Board and is a past chair of NARUC’s Electricity Committee. She is an elected director of the Western Electricity Coordinating Council (WECC) Board of Directors and chairs the WECC Compliance Committee. She is also state co‐chair of the Steering Committee of the Northern Tier Transmission Group. She represents Idaho on the Western Interconnection Regional Advisory Body and chaired the Western Interstate Energy Board’s Committee for Regional Electric Power Cooperation from IPUC Annual Report 2009 5 | P a g e October 1999 Committee, the Harvard Electricity Policy Group, the Idaho State Bar and board president of the Log Cabin Literary Center. Smith received a bachelor of science degree in biology/education from Idaho State University, a master of library science degree from Brigham Young University and her law degree from the University of Washington. Before her appointment to the commission, Commissioner Smith served as deputy attorney general in the business regulation/consumer affairs division of the Office of the Idaho Attorney General and as deputy attorney general for the Idaho Public Utilities Commission. She was the commission's director of Policy and External Affairs and chair of the NARUC Staff Subcommittee on Telecommunications. A fourth‐generation Idahoan, Commissioner Smith has two sons. Mack A. Redford Commisisoner Redford was appointed to the commission in February 2007 by Gov. Butch Otter. During 2008 through April 2009, he served as president of the commission. His term expires in January 2013. At the time of his appointment, Commissioner Redford practiced law for the Boise‐based firm of Elam & Burke PA, specializing in commercial transactions, construction and engineering law, mediation, real estate and general business. Redford grew up in the Weiser and Caldwell areas, graduating from Caldwell High School. He received both his bachelor’s and law degree from the University of Idaho and in 1967 became a deputy in the Idaho attorney general’s office. In 1977, he became a deputy attorney general for the Trust Territory of the Pacific Islands, headquartered in Saipan, Northern Mariana Islands. The territory included a chain of 2,000 islands stretching from Hawaii to the Philippines. In 1981, Redford became general counsel for Morrison Knudsen Engineers and Morrison Knudsen International, a position that took him to Saudi Arabia where MK was building the King Khalid Military City. In 1990‐91, Redford was based in Folkestone, England, where he was legal counsel for the Channel Tunnel Contractors, the builders of the 31‐mile Channel Tunnel connecting England and France. It is the second‐largest rail tunnel in the world. In 1992, Commissioner Redford joined the Boise firm of Park & Burkett. In 1993, he was retained by the World Bank of the Government of Nepal as contract and claims counsel for the Arun Ill Hydroelectric Project. In 1996, he became general counsel for Micron Construction, which was later acquired by Kaiser Engineers. He joined Elam & Burke in 2001. Commissioner Redford and his wife, Nancy, are the parents of two children. IPUC Annual Report 2009 6 | P a g e IDAHO PUBLIC UTILITIES COMMISSION, 1913‐2008 Commissioner From To J. A. Blomquist May 8, 1913 Jan. 11, 1915 A. P. Ramstedt May 8, 1913 Feb. 8, 1917 D. W. Standrod May 8, 1913 Dec. 1, 1914 John W. Graham Dec. 1, 1914 Jan. 13, 1919 A. L. Freehafer Jan. 14, 1915 Jan. 31, 1921 George E. Erb Dec. 8, 1917 April 14, 1923 Everett M. Sweeley May 23, 1919 Aug. 20, 1923 J. M. Thompson Feb. 1, 1921 Dec. 20, 1932 Will H. Gibson April 16, 1923 June 29, 1929 F. C. Graves Sept. 7, 1923 Nov. 12, 1924 Frank E. Smith March 6, 1925 Feb. 25, 1931 J. D. Rigney July 2, 1929 Sept. 30, 1935 M. Reese Hattabaugh March 2, 1931 Jan. 26, 1943 Harry Holden March 27, 1933 Jan. 31, 1939 J. W. Cornell Oct. 1, 1935 Jan. 11, 1947 R. H. Young Feb. 1, 1939 March 19, 1944 B. Auger Feb. 1, 1943 March 9, 1951 J. D. Rigney March 30, 1944 April 30, 1945 W. B. Joy May 1, 1945 March 9, 1951 H. N. Beamer Jan. 17, 1947 Dec. 31, 1958 George R. Jones March 12, 1951 Jan. 31, 1957 H. C. Allen March 12, 1951 Feb. 28, 1957 A. O. Sheldon March 1, 1957 June 30, 1967 Frank E. Meek Feb. 1, 1957 Feb. 5, 1964 Ralph H. Wickberg Jan. 14, 1959 Feb. 23, 1981 Harry L. Nock May 1, 1964 Sept. 30, 1974 Ralph L. Paris July 1, 1967 Oct. 5, 1967 J. Burns Beal Dec. 1, 1967 April 1, 1973 Robert Lenaghen April 1, 1973 April 15, 1979 M. Karl Shurtliff Oct. 1, 1974 Dec. 31, 1976 Matthew J. Mullaney Jan. 2, 1977 Feb. 15, 1977 Conley Ward, Jr. March 7, 1977 Feb. 9, 1987 Perry Swisher April 16, 1979 Jan. 21, 1991 Richard S. High Feb. 24, 1981 April 30, 1987 Dean J. Miller March 16, 1987 Jan. 30, 1995 Ralph Nelson May 4, 1987 Feb. 12, 1999 Marsha H. Smith Jan. 21, 1991 Now Serving Dennis S. Hansen Feb. 1, 1995 Feb. 19, 2007 Paul Kjellander Feb. 15, 1999 Oct. 19, 2007 Mack Redford Feb. 19, 2007 Now serving Jim Kempton Oct. 22, 2007 Now serving IPUC Annual Report 2009 7 | P a g e Financial Summary FISCAL YEARS 2005 ‐ 2009 Description FY2005 FY2006 FY2007 FY2008 FY2009 Personnel Costs $3,561,082 $3,637,402 $3,467,401 $3,898,109 $4,072,505 Travel $154,345 $144,840 $146,491 $181,275 $136,859 Consultants $590 $40,518 $13,949 $16,041 $0.00 Subscriptions $21,574 $21,722 $28,321 $27.036 $22,883 Emp. Training $35,553 $34,424 $28,827 $33,190 $21,396 Postage $10,798 $8,408 $8,027 $7,174 $8,338 Telephone $32,517 $31,497 $28,007 $27,335 $27,910 Office Supplies $17,309 $14,709 $12,824 $17,697 $14,679 Office Rent $226,357 $115,468 $355,643 $236,497 $236,704 Maintenance $17,724 $8,652 $14,223 $15,817 $10,290 Insurance $1,407 $1,487 $2,702 $5,976 $6,380 Office Equip. $0.00 $0.00 $8,690 $5,279 $1,095 Computer Equip. $38,049 $22,874 $26,809 $15,934 $4,262 Commissioner Equip. $0.00 $3,973 $0.00 $0.00 $22,052 Other Equip. $0.00 $20,082 $0.00 $0.00 $0.00 Other Expenses $114,470 $108,604 $113,671 $122,130 $102,775 ========================================================================= Total Expenditures $4,231,955 $4,214,660 $4,255,596 $4,609,484 $4,688,128 Appropriations $4,612,300 $4,754,600 $4,545,300 $4,944,400 $5,236,800 ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ Unexpended Balance $380,345 $539,940 $289,704 $334,916 $548,672 IPUC Annual Report 2009 8 | P a g e Commission Structure and Operations Under state law, the Idaho Public Utilities Commission supervises and regulates Idaho’s investor‐owned utilities – electric, gas, telecommunications and water – assuring adequate service and affixing just, reasonable and sufficient rates. The commission does not regulate publicly owned, municipal or cooperative utilities. The governor appoints the three commissioners with confirmation by the Idaho Senate. No more than two commissioners may be of the same political party. The commissioners serve staggered six‐year terms. The governor may remove a commissioner before his/her term has expired for dereliction of duty, corruption or incompetence. The three‐member commission was established by the 12th Session of the Idaho Legislature and was organized May 8, 1913 as the Public Utilities Commission of the State of Idaho. In 1951 it was reorganized as the Idaho Public Utilities Commission. Statutory authorities for the commission are established in Idaho Code titles 61 and 62. Tell them no! One of the most frequent questions we get after a utility files a rate increase application is, “Why can’t you just tell them no?” For much of the last 90 years, public utility regulation has been based on the “regulatory compact” between utilities and regulators: In return for an exclusive franchise (territory) granted by regulators, utilities agree to serve all those requesting service; and in return for agreeing to invest capital in plant and facilities, utilities are given a reasonable opportunity to earn a fair return on that capital. In setting rates, the commission must consider the needs of both the utility and its customers. The commission serves the public interest, not the popular will. It is not in customers’ best interest, nor is it in the interest of the State of Idaho, to have utilities that do not have the generation, transmission and distribution infrastructure to provide safe, adequate and reliable electrical, natural gas and water service. This is a critical, even life‐saving, service for Idaho’s citizens and essential to the state’s economic development and prosperity. Unlike unregulated businesses, utilities cannot cut back on service as costs increase. As demand for electricity, natural gas and water grows, utilities must meet that demand. In Idaho recently, and across the nation, a continued increase in demand as well as a number of other factors have contributed to rate increases on a scale we have not witnessed before. It is not unusual now for Idaho’s three major investor‐owned electric utilities to file annual rate increase requests. In light of these continued requests for rate increases, the Commission walks a fine line in balancing the needs of utilities to serve customers and customers’ ability to pay. When a rate case is filed, our staff of auditors, engineers and attorneys will take up to six months to examine the request. If we find the added expense incurred by utilities was prudently incurred and needed to serve customers, we have no choice but to allow the utility to recover that expense. However we can, and often do, deny the utilities’ recovery of expenses if we are confident we have the legal justification to do so. All Commission decisions can be appealed to the state Supreme Court. Customers must be ensured of paying a reasonable rate and utilities must be allowed to recover their legitimate costs of serving their customers and earn a fair rate of return. IPUC Annual Report 2009 9 | P a g e The IPUC has quasi‐legislative and quasi‐judicial as well as executive powers and duties. In its quasi‐legislative capacity, the commission sets rates and makes rules governing utility operations. In its quasi‐judicial mode, the commission hears and decides complaints, issues written orders that are similar to court orders and may have its decisions appealed to the Idaho Supreme Court. In its executive capacity, the commission enforces state laws and rules affecting the utilities and rail industries. Commission operations are funded by fees assessed on the utilities and railroads it regulates. Annual assessments are set by the commission each year in April within limits set by law. The commission president is its chief executive officer. Commissioners meet on the first Monday in April in odd‐numbered years to elect one of their own to a two‐year term as president. The president signs contracts on the commission’s behalf, is the final authority in personnel matters and handles other administrative tasks. Chairmanship of individual cases is rotated among all three commissioners. The commission conducts its business in two types of meetings – hearings and decision meetings. Decisions meetings are typically held once a week, usually on Monday. Formal hearings are held on a case‐by‐case basis, sometimes in the service area of the impacted utility. These hearings resemble judicial proceedings and are recorded and transcribed by a court reporter. There are technical hearings and public hearings. At technical hearings, formal parties who have been granted “intervenor status” present testimony and evidence, subject to cross‐examination by attorneys and staff from the other parties and the commissioners. At public hearings, members of the public may testify before the commission. In 2009, the commission began conducting telephonic public hearings to save expense and allow customers to testify from the comfort of their own homes. Commissioners and other interested parties gather in the Boise hearing room and are telephonically connected to ratepayers who call in on a toll‐free line to provide testimony or listen in. A court reporter is present to take testimony by telephone, which has the same legal weight as if the person testifying were present in the hearing room. Commissioners and attorneys may also direct questions to those testifying. The commission also conducts regular decision meetings to consider issues on an agenda prepared by the commission secretary and posted in advance of the meeting. These meetings are usually held Mondays at 1:30 p.m., although by law the commission is required to meet only once a month. Members of the public are welcome to attend decision meetings. Typically, decision meetings consist of the commission’s review of decision memoranda prepared by commission staff. Minutes of the meetings are taken and decisions reached at these meetings are preliminary, becoming final only when issued in a written order signed by a majority of the commission. IPUC Annual Report 2009 10 | P a g e Commission Staff To help ensure its decisions are fair and workable, the commission employs a staff of about 50 people – engineers, rate analysts, attorneys, accountants, investigators, economists, secretaries and other support personnel. The commission staff is organized in three divisions – administration, legal and utilities. The staff analyzes each petition, complaint, rate increase request or application for an operating certificate received by the commission. In formal proceedings before the commission, the staff acts as a separate party to the case, presenting its own testimony, evidence and expert witnesses. The commission considers staff recommendations along with those of other participants in each case ‐ including utilities, public, agricultural, industrial, business and consumer groups. Administration The Administrative Division is responsible for coordinating overall IPUC activities. The division includes the three commissioners, two policy strategists, a commission secretary, an executive administrator, an executive assistant and support personnel. The two policy strategists are executive level positions reporting directly to the commissioners with policy and technical consultation and research support regarding major regulatory issues in the areas of electricity, telecommunications, water and natural gas. Strategists are also charged with developing comprehensive policy strategy, providing assistance and advice on major litigation before the commission, public agencies and organizations. (Contact Lou Ann Westerfield, 334‐0323 and Wayne Hart, 334‐0354, policy analysts.) The commission secretary, a post established by Idaho law, keeps a precise public record of all commission proceedings. The secretary issues notices, orders and other documents to the proper parties and is the official custodian of documents issued by and filed with the commission. Most of these documents are public records. (Contact Jean Jewell, commission secretary, at 334‐0338.) The executive administrator has primary responsibility for the commission’s fiscal and administrative operations, preparing the commission budget and supervising fiscal, administration, public information, personnel, information systems, rail section operations and pipeline safety. The executive administrator also serves as a liaison between the commission and other state agencies and the Legislature. (Contact Ron Law, executive administrator, at 334‐0331.) The executive assistant is responsible for public communication between the Commission, the general public and interfacing governmental offices. The responsibility includes news releases, responses to public inquiries, coordinating and facilitating commission workshops and public hearings and the preparation and coordination of any IPUC report directed or recommended by the Idaho Legislature or Governor. (Contact Gene Fadness, executive assistant, at 334‐0339.) IPUC Annual Report 2009 11 | P a g e Legal Division Five deputy attorneys general are assigned to the commission from the Office of the Attorney General and have permanent offices at IPUC headquarters. The IPUC attorneys represent the staff in all matters before the commission, working closely with staff accountants, engineers, investigators and economists as they develop their recommendations for rate case and policy proceedings. In the hearing room, IPUC attorneys coordinate the presentation of the staff’s case and cross‐examine other parties who submit testimony. The attorneys also represent the commission itself in state and federal courts and before other state or federal regulatory agencies. (Contact Don Howell, legal division director, at 334‐0312.) Utilities Division The Utilities Division, responsible for technical and policy analysis of utility matters before the commission, is divided into three sections. (Contact Randy Lobb, utilities division administrator, at 334‐0350.) The Accounting Section of seven auditors audits utility books and records to verify reported revenue, expenses and compliance with commission orders. Staff auditors present the results of their findings in audit reports as well as in formal testimony and exhibits. When a utility requests a rate increase, cost‐of‐capital studies are performed to determine a recommended rate of return. Revenues, expenses and investments are analyzed to determine the amount needed for the utility to earn the recommended return on its investment. (Contact Terri Carlock, accounting section supervisor, at 334‐0356.) The Engineering Section, which includes seven engineers, reviews the physical operations of utilities. Staff engineers determine the cost of serving various types of customers, design utility rates and allocate costs between Idaho and the other states served by Idaho utilities. They determine the cost effectiveness of conservation and co‐ generation programs, evaluate the adequacy of utility services and frequently help resolve customer complaints. The group develops computer models of utility operations and reviews utility forecasts of energy usage and the need for new facilities. (Contact Dave Schunke, engineering section supervisor, at 334‐0355.) The Telecommunications Section includes three analysts who handle issues involving telecommunications. (Contact Joe Cusick, section supervisor, at 334‐0333.) The Consumer Assistance Section includes six division investigators who resolve conflicts between utilities and their customers. Customers faced with service disconnections often seek help in negotiating payment arrangements. Consumer Assistance may mediate disputes over billing, deposits, line extensions and other service problems. Consumer Assistance monitors Idaho utilities to verify they are complying with commission orders and regulations. Investigators participate in general rate and policy cases when rate design and customer service issues are brought before the commission. (Contact Beverly Barker, administrator for the Consumer Assistance section, at 334‐0302.) IPUC Annual Report 2009 12 | P a g e Rail Section The Rail Section oversees the safe operations of railroads that move passengers and freight in and through Idaho and enforces state and federal regulations safeguarding the transportation of hazardous materials by rail in Idaho. The commission’s rail safety specialist inspects railroad crossings and rail clearances for safety and maintenance deficiencies. The Rail Section investigates all railroad‐crossing accidents and makes recommendations for safety improvements to crossings. As part of its regulatory authority, the commission evaluates the discontinuance and abandonment of railroad service in Idaho by conducting an independent evaluation of each case to determine whether the abandonment of a particular railroad line would adversely affect Idaho shippers and whether the line has any profit potential. Should the commission determine abandonment would be harmful to Idaho interests, it then represents the state before the federal Surface Transportation Board, which has authority to grant or deny line abandonments. (Contact Ron Law, rail section supervisor, at 334‐ 0331.) Pipeline Safety Program The pipeline safety section oversees the safe operation of the intrastate natural gas pipelines and facilities in Idaho. The commission’s pipeline safety personnel verify compliance of state and federal regulations by on‐site inspections of intrastate gas distribution systems operating in the state. Part of the inspection process includes a review of record‐ keeping practices and compliance with design, construction, operation, maintenance and drug/alcohol abuse regulations. Key objectives of the program are to monitor accidents and violations, to identify their contributing factors and to implement practices to avoid accidents. All reportable accidents will be investigated and appropriate reports filed with the U.S. Department of Transportation in a timely manner. (Contact Ron Law, pipeline safety program supervisor, at 334‐ 0331.) IPUC Annual Report 2009 13 | P a g e Electrical Power in Idaho Idaho residents consistently enjoy some of the least expensive electric service in the nation, according to surveys conducted by the National Association of Regulatory Utility Commissioners (NARUC), the Edison Electric Institute and the Energy Information Administration of the U.S. Department of Energy. Idaho Power Company 2008 Average Number of Customers/Avg. Revenue/kwh (Computed from data available in FERC Form 1 Annual Reports) 389,117 Residential Customers/$0.0671 75,605 Commercial Customers/$0.0521 114 Industrial Customers/$0.0365 Avista Utilities 2008 Average Number of Customers/Avg. Revenue/kwh (Computed from data available in FERC Form 1 Annual Reports) 103,795 Residential Customers/$0.0723 16,356 Commercial Customers/$0.0705 482 Industrial Customers/$0.0455 2008Average Number of Customers/Avg. Revenue/kwh (Computed from data available in FERC Form 1 Annual Reports) PacifiCorp/Rocky Mountain Power 55,818 Residential Customers/$0.0804 7,717 Commercial Customer/$0.0674 5,487 Industrial Customer/$0.0495 IPUC Annual Report 2009 14 | P a g e Summary of major electric rate cases Idaho Power Company had two major rate adjustments on Feb. 1 and June 1 and, at year’s end, the Commission was considering a settlement that would place a moratorium on future base rate cases through January 2012. The rate case completed in late January (IPC‐E‐08‐10) resulted in an average 4 percent increase after an appeal. Most significant about this case was the implementation of tiered rates. The larger rate adjustment for customers, however, came later on June 1 with the yearly Power Cost Adjustment, a 10.2 percent increase. Three other adjustments, including the Fixed Cost Adjustment (FCA), an increase to the Energy Efficiency Rider and the first installment of automated meters, were implemented on the same date, resulting in an overall increase of about 15.5 percent. A summary of these major rate change cases follows. Idaho Power gets 3.1 percent increase; 1.6 percent for residential customers Case No. IPC-E-08-10, Order No. 30722 January 30, 2009 Rates for Idaho Power Company customers will increased by an average 3.1 percent effective Feb. 1. Rates for residential customers increased an average 1.6 percent. In July 2008, Idaho Power asked for an overall average 9.89 percent increase, 6.31 percent increase for residential customers. The utility asked to increase annual revenue requirement by $66.6 million and was granted $20.87 million. The commission approved an 8.18 percent rate of return and 10.5 percent return on common equity. The company requested 8.55 percent and 11.25 percent respectively. The order established a year-round, three-tiered rate structure for residential customers to promote energy efficiency and provide cost-saving opportunities. The new non-summer residential rate of 5.58 cents per kilowatt-hour for the first 800 kWh of monthly use (the first tier) was actually less than the previous non- summer rate of 5.78 cents per kWh. Idaho Power proposed a two-tiered rate under which customers would pay a rate 20 percent higher than the first tier once their monthly consumption exceeded 600 kWh. Instead, the commission adopted a three- tiered rate of 5.58 cents per kWh for non-summer use up to 800 kWh; 6.2 cents per kWh for use between 801 and 2000 kWh and 7.13 cents for use of 2,001 kWh or more. During the summer months, the first tier is 5.78 cents, the second tier is 6.59 cents and the third tier, 8.17 cents. Idaho Power’s former summer rate was 5.78 cents on the first 300 kWh and 6.51 cents for use beyond that. IPUC Annual Report 2009 15 | P a g e The rates approved for the major rate classes (with the company’s original proposal in parenthesis) are as follows: Residential – 1.61 percent (6.3 percent) Small commercial – 0.42 percent (10.6 percent) Large commercial – 3.35 percent (15 percent) Industrial – 5.62 percent (15 percent) Irrigation – 6 percent (15 percent) In adopting a significantly smaller revenue requirement than the utility requested, the commission noted the deteriorating economic conditions since Idaho Power made its application to the commission last July. “The volatility of the market, and general financial distress on both a state and national level have triggered significant commission concern about ambitious financial projections based on 2007 customer growth” and then extrapolated by the company into 2008, the commission said. The commission said it expected Idaho Power to continue to demonstrate ongoing efforts to reduce operating costs and increase efficiencies. Because of the tough economic climate, the commission said all utilities’ fiscal responsibility will be “reviewed extensively and continually.” The commission disallowed some of Idaho Power’s proposed expenses. The utility proposed to include in its revenue requirement an increase of nearly $16 million in operation and maintenance expenses over 2007 levels based on anticipated growth in its service territory. The commission allowed $2.87 million, noting that this is an area where Idaho Power has the most discretion to control costs. The commission also deducted $11.2 million from the company’s proposed $91.4 million in net power supply costs (fuel to operate plants, power purchases from the wholesale market and other utilities and purchases from in-state small-power facilities). The commission disallowed the following amounts in these other categories: employee incentive compensation accounts ($3.2 million), legal services ($192,300) and employee purchase card expenses ($885,000). Idaho Power agreed with commission staff’s findings to reduce $1.4 million in depreciation expense and $2 million in payroll expense due to a lack of increase in employees during 2008. The company said it has responded to the economic slowdown by instituting a selective hiring freeze. The commission also is requiring Idaho Power to reimburse customers $3.26 million over five years. That is the amount credited to Idaho Power by federal agencies after it successfully challenged the amount of fees it had to pay the Federal Energy Regulatory Commission and other agencies during 1999-2006. In a departure from past practice, the commission allowed the utility to include a greater proportion of projected costs in rates to more closely align rates with the company’s expenses, thereby improving its credit rating and borrowing capacity. Typically, only actual, historical costs are included in rates. But because of the time it takes to process a rate case (about six months), the company often incurs expense that it cannot recover until months after new plant is in use. The commission allowed Idaho Power to include major plant addition in excess of $2 million that was to be completed by Dec. 31, 2008 and allowed it to include an escalation in some expense accounts where a specific trend could be identified. However, the commission did not allow as much in forecasted expense as Idaho Power wanted. The company’s ongoing construction needs also prompted the commission to include in rates an allowance for funds used during construction (AFUDC) totaling $6.8 million related to the Hells Canyon relicensing projects. Typically, AFUDC is not included in rates until a project is in use and benefitting customers. In 2006, the Idaho Legislature amended a 1984 statute that prohibited the commission from including those costs in rates except in extreme emergencies. The 2006 amendment said construction work in progress and plant held for future use can be included in rates if the commission makes an explicit finding that including those costs is in the public interest. Including the Hells Canyon costs is in the public interest, the commission said, because paying down some relicensing accounts now will mean smaller rate increases in the future because all prudently incurred IPUC Annual Report 2009 16 | P a g e relicensing costs will have to be included in future rates. Further, the commission said, “Idaho Power’s cash flow will improve, which will help maintain its credit strength to access funds for ongoing construction projects.” The commission said the relicensing effort, which is required by the Federal Energy Regulatory Commission and has cost $95.6 million through 2007, is unlike a typical construction project because it has been under way for nearly 10 years with no certain completion date. Further, Idaho Power is able to use the Hells Canyon complex hydroelectric projects during relicensing, thus benefiting customers. The commission also approved a request by the Community Action Partnership Association of Idaho (CAPAI) to require Idaho Power to provide $25,000 annually to each of the state’s five community-action regions for energy-efficiency education projects. The commission declined a request by CAPAI that Idaho Power increase funding for low-income weatherization. The commission said the utility is already actively involved in funding low-income weatherization projects. Idaho Power gets another 1 percent on reconsideration Case No. IPC-E-08-10, Order No. 30754 March 20, 2009 The Idaho Public Utilities Commission granted portions and denied portions of Idaho Power Company’s petition for reconsideration of a recently concluded rate case. On Jan. 30, the commission issued an order granting Idaho Power an average 3.1 percent rate increase. Idaho Power appealed some issues to the commission and the commission granted some of the company’s request. The result is a 1 percent increase in the overall rate. The average increase for all customer classes is now 4 percent. For residential customers, the increase goes from 1.6 percent to 3 percent. Counting the changes made in reconsideration, the commission approved $27.6 million in annual new revenue for the company, out of a total request of $66.6 million. The commission approved the following changes to its Jan. 30 order: • Nearly $6 million out of a total $141 million in annual payroll expense was not included in the final revenue requirement and should have been. • An error in the calculation of Operations and Maintenance Expense added another $546,221 to Idaho Power’s revenue requirement. The commission denied Idaho Power’s petition in these areas: • During 1999-2006, the Federal Energy Regulatory Commission over-charged Idaho Power about $3.27 million in regulatory fees. The company disputed the commission’s order that the over- billed amount be refunded to ratepayers, maintaining a refund to customers violates the legal prohibition against “retroactive ratemaking.” The commission denied Idaho Power’s request and ordered that customers be credited $653,202 in each of the next five years. • Idaho Power asked the commission to reconsider its decision to deny about $885,000 in revenue for Idaho Power needed to cover employee purchase-card expenses. The commission, denied the request, saying the company was not able to demonstrate why these kinds of employee purchases are a benefit to customers and, therefore, should not be included in rates. The commission also denied the Department of Energy’s petition to reconsider the cost-of-service model used to determine which costs should be assigned to each customer class. DOE participated in the case to represent the Idaho National Laboratory in eastern Idaho, one of Idaho Power’s largest customers. IPUC Annual Report 2009 17 | P a g e Commission approves four rate increases May 29, 2009 The Idaho Public Utilities Commission approved four rate adjustments , which, for most Idaho Power Co. customers, will increase overall rates by an average 15.5 percent. The largest of these is the annual Power Cost Adjustment, which is a 10.2 percent increase over the current overall rate. The other three adjustments include an increase in the Energy Efficiency Rider (2.25 percent), money for the installation of automated meters (1.8 percent) and the annual Fixed Cost Adjustment (1.3 percent). The commission is reluctant to approve any rate increases beyond what is necessary, especially during these economic times. However, the commission is convinced the reduced energy use that will result from the Energy Efficiency Rider, the Fixed Cost Adjustment and the installation of automated meters will keep customer rates lower than they otherwise would have been in future years. “… The commission must also keep an eye toward the future and maintain a proactive approach that will best serve long-term ratepayer interests.” Power Cost Adjustment IPC-E-09-11, Order No. 30828 Every year on June 1, customers receive either a one-year surcharge or credit to rates, depending on steamflows and market conditions from the previous year and a forecast of the following year’s conditions. The increase in the PCA is from 0.7864 cents per kWh to 1.4 cents per kWh. Idaho Power initially requested an average 11.4 percent increase but revised its request to 10.2 percent after a wet spring. Despite a wetter than normal spring, the overall precipitation for the season is only 81 percent of normal. The power cost surcharge covers expenses, not already included in base rates, which Idaho Power incurs to provide energy to its customers. These can include expenses related to Idaho Power buying power from the wholesale market or firing up its own natural gas peaker plants during times of high demand. None of the money collected in the surcharge goes to increase company earnings, but can be used only to pay off power supply and related expenses. “We remind customers frustrated by the rate increase that the PCA does not influence Idaho Power’s profits,” the commission said. This year is the third-largest PCA in its 16-year history. The methodology used last year to forecast this year’s power supply expenses “grossly underestimated” the company’s actual expenses, the commission said. A newer methodology used this year forecasts higher costs that should be closer to the actual costs the company will incur in the next year. Because of that, the commission anticipates a decline in the PCA next year even if projected stream flows are below normal. Because the PCA is high, both commission staff and the Industrial Customers of Idaho Power requested that some expenses be deferred or spread out over the next three years. Commission staff proposed allowing only half of the forecasted amount this year and including the remainder next year. That would have reduced the increase from 10.2 percent to about 6.1 percent. The Industrial Customers proposed the expenses be recovered over the next three years in equal annual installments. The commission, expressing concern about unknown future water and market conditions, said it was “reluctant to create a situation where customers are required to continue paying costs from this year on top of whatever increases may be required in future years.” Further, the commission said, collecting the full amount in one year assures the financial community that the company is able to recover reasonably incurred power supply costs. IPUC Annual Report 2009 18 | P a g e Energy Efficiency Rider IPC-E-09-05, Order No. 30814 The money raised from the 2.5 percent Energy Efficiency Rider is used to fund up to 20 programs that reduce customer demand on Idaho Power’s electric system. That demand reduction reduces the amount of electricity Idaho Power has to buy or generate, saving customers money in the long-run. On June 1, the rider increased from 2.5 percent to 4.75 percent of customer bills. The increase in the rider is primary due to a new commercial demand response program and a greater than anticipated participation in the Irrigation Peak Rewards Program, which will be capable of reducing Idaho Power’s peak loads in the summer by 200 megawatts. None of the funding from the rider can increase earnings for Idaho Power, but can be used only to fund energy efficiency and conservation programs. “Rate increases are never popular and are especially unwelcome in difficult economic times,” the commission said. “However, the information provided shows that energy efficiency programs have been effective in creating more efficient use of electricity by customers, and in reducing the peak demand on Idaho Power’s system. These results mean that higher rates to support construction of new generating facilities have been delayed or avoided altogether.” The rider was created in 2002, after the Western energy crisis of 2000-01. At that time, the commission directed Idaho Power to develop comprehensive demand-side management (DSM) and energy efficiency programs to help customers reduce bills and lessen Idaho Power’s dependency on the volatile wholesale market for electric supply. Energy efficiency programs in 2008 resulted in 107,484 megawatt-hours of energy savings, a 72 percent increase over the 2007 total of 62,544 MWh. DSM programs that reduce demand on Idaho Power’s system provided 58 megawatts of demand reduction in 2008 compared to 48 MW in 2007. (One megawatt is one million watts, enough electricity to power about 650 average homes and light 10,000 100-watt light bulbs.) “By encouraging energy efficiency programs through relatively modest increases in the rider, the commission is delaying, or avoiding altogether, larger rate increases necessitated by Idaho Power’s investment in generation resources,” the commission said. The Northwest Energy Coalition and the Idaho Irrigation Pumpers Association filed comments in support of the rider, although the coalition said the amount of the rider is “insufficient to capture all the cost- effective energy savings potential in Idaho Power’s service territory and to operate robust demand-response programs to reduce peak generation resource needs.” The coalition noted that “using electricity more efficiently is the quickest and least-cost approach to meeting customers’ power needs” because it reduces customer bills and reduces loads during peak periods when Idaho Power’s system is most stressed. Fixed-Cost Adjustment IPC-E-09-06, Order No. 30827 The Fixed Cost Adjustment was implemented in 2007, the first year of a three-year pilot program. The adjustment allows Idaho Power to recover fixed costs it loses when conservation programs result in lower power sales. Without a mechanism like the FCA, there is a financial disincentive for utilities to promote energy efficiency and conservation programs because they lose money when those programs are successful. The FCA allows Idaho Power to recover its already established fixed costs through a surcharge when it under-collects fixed costs because of reduced electrical use. Conversely, if the company over-collects fixed costs, customers receive a credit instead of a surcharge, as they did last year. IPUC Annual Report 2009 19 | P a g e Idaho Power under-collected $1.3 million in fixed costs from the residential class and $1.4 million from the small-commercial class, necessitating an increase of about 0.0529 cents per kWh, or a 0.82 percent overall increase. However, because last year’s FCA was a credit, the net change is 0.0986 cents per kWh or a 1.3 percent net increase. Advanced Metering Infrastructure IPC-E-09-07, Order No. 30829 Responding to a directive from the commission, Idaho Power has begun a three-year process to replace its existing meters with advanced metering infrastructure (AMI) that will eventually allow customers to monitor electric prices and adjust their use to take advantage of lower price-periods. Idaho Power estimates the project will cost $71 million over its three year phase-in process. In this application, Idaho Power sought the first installment, or $11.2 million for investments made between June 1, 2009, and May 31, 2010, which would have resulted in a 2.22 percent increase. However, the commission adopted its staff’s recommendation to include only costs through 2009, as more representative of the company’s actual investment. The resulting increase is 1.8 percent. “We are confident that such an approach will provide the necessary protection to ratepayers and ensure that the company is able to maintain adequate cash flow and access to sufficient capital to maintain a secure financial footing in the midst of the current economic downturn,” the commission said. The Snake River Alliance filed comments supporting the company’s application, but acknowledged that the meters’ benefits won’t be realized immediately. However, “eventual benefits will lead to real energy savings that will benefit all customers … through reduced energy bills and reduced need for additional investments in generation and transmission.” The commission is urging Idaho Power to "move forward with all deliberate speed" with installation beginning this year in the Boise area, then in 2010 in the Canyon and Payette regions and, finally, in 2011 in the Magic Valley, Pocatello and Salmon areas. Idaho Power is pursing federal stimulus dollars to help fund the project, which could eventually reduce ratepayer costs. Commission taking comments on rate moratorium Case No. IPC-E-09-30, Order No. 30960 December 10, 2009 At year’s end, the Commission was still considering an application by Idaho Power Company proposing adoption of a settlement that would place a moratorium on general rate case increases until January 2012 and give the company a better opportunity to earn its allowed rate of return. The settlement, agreed to by Idaho Power and a number of customer groups, would allow Idaho Power to use some of the reduction in the Power Cost Adjustment (PCA) surcharge that customers are expected to get next June. The PCA is a one-year surcharge or a one-year credit depending on the previous year’s water levels and market conditions. The PCA was a significant increase to customers in 2007 and 2008. The last year customers got a PCA credit was in 2006. The agreement would allow the company to convert up to $25 million of the first $50 million of anticipated PCA rate reduction to base rates. Customers are expected to benefit next June with a signification reduction, now estimated to be about $160 million. IPUC Annual Report 2009 20 | P a g e The agreement also allows the company to accelerate the use of the customer share of tax credits the company receives on its capital investments. Typically, the customer portion of the tax benefit is credited over the lifetime of the investment. Under the proposed settlement, Idaho Power would use the out years of the investment credit to buttress its earnings rather than asking for a general rate increase. The agreement limits the amount of the investment tax credit that can be accelerated to $45 million over three years. The accelerated tax credit would help the company earn up to a 9.5 percent return on equity over the years of the agreement. Without it, the company claims customer rates would increase significantly to bring the company up to its allowed return on equity (ROE) of 10.5 percent. Increasing the ROE adds millions to a general rate case request and is one of the more significant rate case expenses. Idaho Power proposes to share earnings with customers through rate reductions if the company’s ROE is higher than 10.5 percent. When the ROE is less than 9.5 percent, the company would be able to amortize the investment tax credits, but not to exceed $45 million. Idaho Power has not able to earn its authorized rate of return throughout this decade in either Idaho or Oregon jurisdictions. The moratorium would affect only changes in base rates. It does not include increases or decreases to the annual PCA, the annual Fixed Cost Adjustment or energy efficiency riders. Parties to the settlement include Idaho Power, the Industrial Customers of Idaho Power, the Community Action Partnership Association of Idaho, the Idaho Irrigation Pumpers Association, Micron Technology Inc., the U.S. Department of Energy and the Kroger Company. Commission staff is also a party to the agreement. The staff operates independently of the three commissioners who will decide the case. IPUC Annual Report 2009 21 | P a g e Avista Utilities, which serves 120,000 electric customers and 74,000 gas customers in north Idaho, filed a joint electric and natural gas rate increase in January. In July, the Commission approved a settlement that increased base rates by 5.7 percent, but because of a 4.2 percent reduction in the company’s annual Power Cost Adjustment, the net increase was 1.5 percent. On the gas side, the base rate increase was 2.1 percent, but customers did not pay more this year because of a reduction in the Purchased Gas Cost Adjustment. Idaho commission adopts Avista rate case settlement Case No. AVU-E-09-01 and AVU-G-09-01, Order No. 30856 July 17, 2009 Avista Utilities residential electric and gas customers will pay just slightly more than 1 percent more per month – about $1 – on each of their electric and gas bills as the result of four rate adjustments effective Aug. 1. The Idaho Public Utilities Commission announced two adjustments July 17 – a base rate increase and an electric and gas supply decrease – and later that month announced an increase in the company’s energy efficiency rider later. The fourth component, the resumption of the Residential Exchange Credit from the Bonneville Power Administration, resulted in a rate decrease. The July order adopted a settlement among various parties to the joint electric and gas rate case filed by Avista in January. The result of the rate case is an average 1.5 percent increase for electric customers (1.2 percent for residential customers) and no increase for gas customers. However, when including the increase in the energy efficiency rider announced later, the net result for residential gas customers is about a 1.2 percent increase. The settlement increased Avista Utilities’ annual electric revenue by $12.5 million and gas revenue by $1.93 million. Avista originally sought a $31.2 million increase in annual electric revenue and a $2.7 million gas revenue increase. Noting that the disputes among the parties to the rate case were “numerous and significant,” the commission congratulated the parties for “their diligent work on the settlement and their ability to resolve all the issues in this case.” The commission said the settlement represents “a significant reduction in the requested revenue increase, about 60 percent less than originally requested.” The permanent base electric rate increases by 5.7 percent, but because of a 4.2 percent reduction in the company’s annual Power Cost Adjustment (PCA), the net increase to all electric customer classes is 1.5 percent (1.22 percent for the residential class). Avista originally sought a 12.8 percent base electric increase that would have netted 7.8 percent with the PCA reduction. On the gas side, the permanent rate increase is 2.1 percent, but because of a decrease in the annual Purchased Gas Cost Adjustment (PGA) there was no net increase in gas rates for most customers. IPUC Annual Report 2009 22 | P a g e For a residential electric customer who uses about 1,000 kilowatt-hours per month, the net impact of all four adjustments was an increase of 98 cents, from $79.92 to $80.90, according to the company’s calculations. For a residential gas customer who uses 65 therms per month, the net impact of all four adjustments is about 91 cents a month. An average monthly bill increased from $72.97 to $73.88, according to Avista’s calculations. The commission conducted hearings and workshops in northern Idaho and received about 200 written comments. Many of those comments addressed the issue of company salaries. The settlement adopts the commission staff proposal “to reduce wages for executive and non-executive employees to reflect actual wage in 2009 and to eliminate any pro forma increase in 2010,” the order states. “For ratemaking purposes, the stipulation (settlement) also removed pay increases for the company’s executives in 2009 and 2010.” The parties in the case included Avista, commission staff, the Idaho Forest Group, Clearwater Paper Corporation, the Idaho Conservation League, the Idaho Community Action Network and the Community Action Partnership of Idaho. IPUC Annual Report 2009 23 | P a g e PacifiCorp, which does business in eastern Idaho as Rocky Mountain Power, filed a request for a 4 percent increase in September 2008 and was granted 3.1 percent effective April 18. This case was also resolved by a settlement of the parties. PUC approves Rocky Mountain Power rate settlement Case No. PAC-E-08-07, Order No. 30783 April 16, 2009 The Idaho Public Utilities Commission approved a settlement in the Rocky Mountain Power rate case that increases overall rates by an average 3.1 percent effective April 18. The rate increase varies by customer class. For residential customers, the increase is 3.53 percent. For a customer who uses the utility’s average of 850 kilowatt-hours per month, the increase is $2.38 per month in winter bills and $3.07 per month in summer bills. The increase to irrigation customers is 1.73 percent. In September 2008, Rocky Mountain Power, which serves 70,000 customers in eastern Idaho, asked for a 4 percent overall increase and a 4.73 percent increase for residential customers. The utility asked to collect an additional $5.87 million in annual revenue. The settlement approved by the commission authorizes $4.38 million in additional annual revenue. Parties signing the settlement include PacifiCorp (which does business as Rocky Mountain Power in eastern Idaho), the Idaho Irrigation Pumpers Association, the Community Action Partnership Association of Idaho and Public Utilities Commission staff, which operates separately from the commission. The settlement also authorizes the development and funding of an energy conservation education program for low-income customers. Further, the company agrees to include a tiered-rate rate design proposal for residential customers when it files its next rate case. Rocky Mountain Power maintained the increase is necessary to pay for growth in its electrical load, capital investment and operating cost increases beyond its control. The parties to the case agreed that Rocky Mountain’s purchase of the 500-megawatt Chehalis natural gas plant in Chehalis, Wash., was a prudent decision and in the public interest. Costs relating to buying and operating the plant were included in this case. The settlement is a compromise, with no party accepting all the methodology or adjustments made to arrive at the $4.38 million in added revenue requirement. However, all parties agreed the overall increase represents a fair, just and reasonable compromise of the issues raised and that the settlement is in the public interest. IPUC Annual Report 2009 24 | P a g e Other electric cases Certificate for Langley natural gas plant approved Case No. IPC-E-09-03, Order No. 30892 September 1, 2009 Idaho Power Company was granted a certificate to build a 330-megawatt natural gas-fired power plant four miles south of New Plymouth that is slated to begin operating in late 2012. Without the new Langley Gulch Power Plant, Idaho Power risks falling short of meeting customer demand in four years. “The company has a statutory obligation to provide electric service and, since 2004, has forecast a need for a baseload generation resource in 2012,” the commission said. Idaho Power will build the plant on 137 acres of undeveloped range land adjacent to Interstate 84, immediately southwest of Exit 9 in rural Payette County. Intervenors in the case, including the Industrial Customers of Idaho Power, the Idaho Irrigation Pumpers Association, the Idaho Conservation League and the Community Action Partnership Association of Idaho, said the project could be delayed because the rate of load growth has slowed with the economy. Further, they argued, Idaho Power could develop more energy efficiency and conservation programs. After reviewing the record, the commission said the public interest was not served by delay. The commission said the lead-in time to develop a plant (about three years) is too long, that the company is already aggressively pursuing cost-effective conservation programs and there is a demonstrated need for more generation. Using Idaho code adopted by the Legislature earlier in 2009, the commission granted the company “regulatory assurance” that it will receive recovery of its prudently incurred investment of $396.6 million in customer rates. Idaho Power sought preapproval assurance of $427.4 million. But the commission decided to separate costs that are known with greater certainty and competitively procured from amounts that are less certain. Idaho Power must file quarterly reports on the progress of the project and a budget update showing total amount spent and billed and remaining contract dollars. Idaho Power maintains that the commission’s regulatory assurance will make it easier to obtain capital from lenders at rates more favorable to customers. Approval of the project did not immediately impact rates. Idaho Power wanted to include Construction Work in Progress (CWIP) in customer rates annually as it moved forward with construction. The commission denied that request, but said it is open to considering CWIP as construction progresses. An advantage of CWIP to customers, the company maintained, is a quicker recovery of construction costs, thus avoiding financing costs that would be assessed to customers over several decades. The company’s long-range plan to meet customer growth, called an Integrated Resource Plan, initially called for a coal-fired resource, but with rising concerns about climate change, the company revised its plan to call for a natural gas-fired baseload resource. Idaho Power initiated a bid process that was reviewed by a third party. It received five valid proposals that represented 13 alternative sources, including a proposal by the company to build the plant itself. Idaho Power selected its own self-build plan, claiming it will have a revenue requirement impact of about $95 million less than the next competing proposal. IPUC Annual Report 2009 25 | P a g e Intervenors argued the bid process was flawed, because, among other reasons, the bid evaluator was hired by the company, the process was not transparent enough, there was not an independent scoring by the bid evaluator and the company refused to consider any “build-and-transfer” projects, which would allow a third party to build the plant and then turn it over to Idaho Power to operate. The commission acknowledged that the process could have been more transparent and that the “total universe of potential bidders was perhaps not realized.” However, the commission said, “Based on the evidence presented, we cannot conclude that a lower price and better project would have resulted” if the bid process had been better designed. Despite plant selection issues presented by the intervenors, it was apparent to the commission that the competitors were “sophisticated bidders and that the short list of projects were all competitive.” In a separate case, the Northwest and Intermountain Power Producers Coalition has asked the commission to examine the current bid process. In the order, the commission said, “The actual and perceived flaws in the RFP (Request for Proposals) process, we find, while not fatal to the company’s resource selection, clearly demonstrate a need for a separate proceeding to consider RFP competitive bidding rules and guideline.” While the intervenors advocated delay, several other parties submitting comments, including area cities, chambers of commerce and local businesses said additional energy infrastructure is needed and is a key element to attracting commerce and industry. Idaho Power maintained that if Langley Gulch is delayed, any new large customers seeking to locate plant here would be advised that the company does not have firm resources sufficient to serve loads on a year- round basis. Further, the company warned, a delay could mean energy curtailments after 2012 under adverse circumstances such as low water, high temperatures, outages at distant generating plants, loss of transmission capacity or a combination of any of those. Transmission costs are estimated to be about $25.4 million and will include construction of a new 18-mile 138-kV line from the plant to the Caldwell-Willis line, three miles from Caldwell Substation, and a 2.5- mile line from Ontario to Caldwell. The plant is anticipated to employ up to 120 during the two years of construction and 18 full-time once it is operational. Commission opens docket to pursue bidding guidelines Case No. IPC-E-10-03 November 2009 As a result of questions raised during the Langley Gulch case (see above), independent power producers, as well as group representing industrial and irrigation customers, filed a petition in November asking that the Commission consider establishing competitive bidding guidelines for the procurement of major generation projects by Idaho’s three major electric utilities. However, Rocky Mountain Power, which operates in eastern Idaho, and Avista Utilities in northern Idaho are already subject to guidelines established by other states in which they operate. Because those utilities currently use those guidelines for projects that serve Idaho, the original application was modified to include only Boise-based Idaho Power Company. The groups petitioning the commission contend that Idaho Power is free to issue bid requests that are “designed and administered completely without commission or other stakeholder input.” At year’s end, the case was still open. IPUC Annual Report 2009 26 | P a g e Commission OK's installation of automated meters Case No IPC-E-08-16, Order No. 30726 February 17, 2009 Idaho Power began in 2009 a three-year project to install automated meters throughout its southern Idaho service territory. Responding to an urgent directive from the Commission, the utility is replacing its existing meters with advanced metering infrastructure (AMI) that will allow customers to monitor electric prices and adjust their use to take advantage of lower price-periods. Idaho Power submitted a cost estimate of $71 million for the project and will absorb any costs above that. Rates did not immediately increase, but are being included in base rates as the meters are placed in service. (See pgs. 18-19 for first installment of AMI expense in base rates.) The commission also approved the company’s request to accelerate the depreciation time frame on its existing meters down to three years. The commission is urging Idaho Power to "move forward with all deliberate speed" with installation beginning this year in the Boise area, then in 2010 in the Canyon and Payette regions and, finally, in 2011 in the Magic Valley, Pocatello and Salmon areas. The advanced meters can be read from a remote location, negating the need for an Idaho Power representative to access customer properties. They can provide the company and individual customers with hourly meter readings and inform customers of current electric prices, potentially allowing them to manage their use and reduce their bills. Other benefits to customers and the company will include reduced operational costs associated with meter reading and improved meter reading accuracy, outage monitoring and theft detection. Customers can also be disconnected and reconnected from a remote location saving time and labor. There are also billing advantages such as fewer estimated bills, less re-billing and more flexible billing schedules. After the Western energy crisis of 2000-2001, the commission said advanced metering technology was becoming more necessary. At that time, the commission ordered Idaho Power to evaluate and report on advanced metering technology. In 2002, the commission ordered Idaho Power to complete installation of advanced metering by 2004, but financial and technical problems made it impossible for the company to meet that time frame. The commission eventually adopted a phased-in implementation and evaluation approach, with advanced meters installed in test areas such as Emmett. In an earlier order, the commission stated … "the potential benefits of advanced metering to ratepayers and the company are too great to delay … implementation indefinitely." The Idaho Conservation League endorsed adoption of the AMI program, saying it will encourage customers to be more efficient, which will lead to a decrease in overall electrical demand and reduce carbon dioxide emissions. AARP Idaho opposed the plan, saying more information should be obtained through a technical hearing before imposing the additional cost of AMI on customers. The commission said it is mindful of the large capital expense, but said it expects Idaho Power to "demonstrate its ongoing effort to reduce operating costs and increase efficiencies and reminds the company that in the current economic climate its fiscal responsibility will be reviewed extensively and continually." IPUC Annual Report 2009 27 | P a g e Idaho Power applies to make Fixed Cost Adjustment permanent Case No. IPC-E-09-28, Order No. 30948 December 8, 2009 Late in the year, Idaho Power Company asked the Commission to make permanent a pilot program that allows the utility to recover its fixed costs of delivering energy regardless of the impact energy efficiency and conservation programs have on energy sales. The Commission implemented the Fixed Cost Adjustment (FCA) in 2007 as a three-year pilot program. The adjustment, sometimes referred to as a “decoupling mechanism,” allows Idaho Power to recover its fixed costs of delivering energy as established in its most recent general rate case even if there is a reduction in energy sales and revenues because of energy efficiency and demand reduction efforts. Without a mechanism like the FCA, Idaho Power claims there is a financial disincentive for it to promote energy efficiency and conservation programs because energy sales may decline. The FCA allows Idaho Power to recover its established fixed costs through a surcharge when it under-collects fixed costs because of reduced electrical use. Conversely, if Idaho Power collects more than its established fixed costs, customers receive a credit instead of a surcharge. During the first year of the pilot, the FCA resulted in a credit of about 48 cents per month on an average residential bill. During the second year, customers were assessed a surcharge, or an increase of about 56 cents per month on an average residential bill. The FCA applies only to residential and small-business customers. Idaho Power claims that implementation of the FCA has been a major factor in the utility’s substantial increase in its level of investment in energy efficiency and conservation, from $11.5 million in 2006 to $21.2 million during 2008. That investment has resulted in significant increases in the number of megawatt-hours saved – a 29 percent increase after the first year and a 54 percent increase after the second year. According to the company’s figures, the megawatt-hours saved during 2006 was 70,766; during 2007, the total saved was 91,145; and during 2008, the total was 140,156. The case was still being reviewed at year’s end. Commission adopts changes to PCA calculations Case No. IPC-E-08-19, Order No. 30715 January 16, 2009 The Commission has approved changes in the way the annual Power Cost Adjustment (PCA) is calculated in hopes of decreasing the volatility in the rate adjustment, which can be either a one-year surcharge on customer bills or a one-year credit. The normal costs for supplying power to customers are recovered in a utility’s base rates. However, a utility may incur higher than normal costs from unusual circumstances, such as low-water conditions or higher than anticipated market conditions. In those circumstances, the commission approved a PCA process that enables Idaho utilities to recover higher than normal costs. Revenues from a PCA surcharge are used only to pay the increased power costs and do not increase company earnings. The PCA becomes effective June 1 every year. Because water conditions have been lower than normal and the market more volatile, customers have experienced wide variations in the PCA in recent years. The 2008 IPUC Annual Report 2009 28 | P a g e PCA was an average 10.7 percent increase for customers. In 2007, the surcharge was an average 14.5 percent increase. However, in 2006, there was an average 19.34 percent credit to customer rates. To address the fluctuations in the PCA, the commission directed Idaho Power Co., commission staff and representative of customer groups to participate in workshops. Customer groups participating included those representing commission staff, Idaho Power, irrigation customers, industrial customers, Micron and the U.S. Department of Energy. The workshops resulted in a settlement agreed to by all parties and later approved by the commission. Major components of the agreement include: 1) Since the 1992 inception of the PCA, 10 percent of the power supply costs above base rates were absorbed by the company and customers paid the remaining 90 percent in the form of the surcharge. Conversely, during those years when there was a credit, Idaho Power got 10 percent of the savings and customers received 90 percent. The settlement adopted by the commission changes that sharing mechanism to require customers to pay 95 percent of above-normal power supply expense. During years when there is a credit, customers would get 95 percent of the savings. The sharing mechanism was put in place to incent the company to make wise decisions when purchasing energy because the company would be responsible for 10 percent of the costs of those decisions. However, since 1992, the volatility in power supply expense scenarios has increased from about $100 million to $330 million. The settlement proposes, and the commission agrees, that with a 95/5 share, the company’s risk and possible loss would be about the same proportionately as it was under the 90/10 share. “We do find that power supply cost volatility has increased significantly since the PCA was implemented, and that with increased volatility , a sharing percentage of 5 percent still provides strong incentive for the company to make prudent power purchases,” the commission said. A further reason for the change to 95/5 is that after the 2000-01 Western energy crisis, the commission directed Idaho Power to develop a risk management policy that provides less discretion to Idaho Power when making its energy sales and purchases. 2) The settlement also adopts changes in the Load Growth Adjustment Rate, or LGAR. The LGAR acknowledges that Idaho Power’s revenues will increase between rate cases due to customer growth and changes in customer use. About $31.40 per megawatt-hour was subtracted from power supply expense to account for that growth. The settlement’s new methodology recognizes that the company also incurs additional power supply costs to serve new load between rate cases and has no opportunity to collect those costs. Therefore, the settlement reduces the LGAR to $28.14 per MWh. 3) A third component of the settlement makes changes to the formula for determining forecasted power supply expenses. The former methodology created unreasonably large true-ups between forecasted power supply costs and actual costs. The new method is designed to reduce that difference. 4) A fourth component allows Idaho Power to include third-party transmission expense in the PCA not already included in base rates. During 2007, third-party transmission costs were about $13 million. “We find that third-party transmission costs are incurred in conjunction with market purchase and sales and should be tracked through the PCA, like other variable power supply costs,” the commission said. Commission rules on building contractors’, highway districts’ petitions Case No. IPC-E-08-22, Order No. 30955 December 2, 2009 The Commission granted in part and denied in part a petition for reconsideration filed by area highway districts and, in the same case, denied a petition for reconsideration by the Building Contracts Association. Both parties then appealed to the state Supreme Court where the case is pending at the filing of this report. IPUC Annual Report 2009 29 | P a g e The petitions pertain to an order issued in July 2009 that approved increases and updates in Idaho Power’s “Rule H tariff,” which lists the charges that developers and new customers must pay for new line installations and service attachments. Idaho Power said it sought to update the tariff in an effort to shift a greater portion of the cost of new construction from existing customers to developers and new customers requesting the construction, The changes also allow Idaho Power to include new language in the tariff dealing with who pays for the relocation of utility facilities when private development forces the utility to relocate an existing distribution line in a public right-of-way. The Building Contracts Association objected to the new fees for line installations and service attachments for new customers, claiming they discriminate against new customers. The Ada County Highway District, the City of Nampa and the Association of Canyon County Highway Districts objected to new language in the tariff that, they said, intruded on their authority to determine who pays and when payments are made for utility facility relocation in public rights-of-way. Idaho Power proposed language that would have required developers, rather than Idaho Power customers, to pay for utility facility relocation in advance of the project’s completion when the developer is a private entity and not a transportation agency requiring relocation for public benefit. Building Contractors’ objection In its July order, the commission ruled that, effective Nov. 1, developers of subdivisions and multiple- occupancy projects will receive from Idaho Power a $1,780 allowance for each single-phase transformer installed within a new development and a $3,803 allowance for each three-phase transformer. The same allowance is provided for each single-phase and each three-phase service customer outside a subdivision. Developers will be responsible for any costs above the allowance. The increased allowance was adopted in place of an $800 per lot refund developers now get as customers move on to the lots and begin receiving electric service. However, developers can still get “vested interest refunds” for additional line installations inside a subdivision that were not part of the initial line installation. The commission agreed with Idaho Power that the new allowance should be based on the actual cost of most commonly installed facilities, rather than basing the allowance on the number of customers (lots), as was the case in the previous Rule H tariff. Basing the allowance on customers rather than the actual cost of the installed facilities could lead to allowances inside subdivisions that are greater than the cost of the facilities, the commission said. In its order, the commission said it is “addressing a fundamental principal of utility regulation: To the extent practicable, utility costs should be paid by those who cause the utility to incur the costs. If the ‘cost- causers’ do not pay, the electric rates for other customers will be higher.” The Building Contractors maintain the updated allowance “approves an inherently discriminatory rate structure” by imposing unequal charges for new customers receiving the same level of service as existing customers. The contractors say inflation, not customer growth, is the actual source of increased costs to extend utility facilities. The commission denied the Building Contractor’s petition in its entirety. Highway districts’ objections When utility line relocation is requested by local or state government for transportation or other public improvements, Idaho Power and its customers pay for the relocation. Idaho Power said it has no issue IPUC Annual Report 2009 30 | P a g e paying for utility relocations for public benefit, but objects to having its customers pay for what it deems to be private or third-party benefit. “Idaho Power customers in Pocatello do not benefit from roadway improvements for a new shopping center in Nampa, but they currently pay for relocation costs in excess of the public benefit in their rates,” Idaho Power stated in its response to the highway districts petition for reconsideration. The highway districts alleged that the new language requiring third-party reimbursement intrudes in the highway districts’ exclusive jurisdiction and is unconstitutional because it obligates local government entities, such as Local Improvement Districts (LIDs) to pay for utility relocation costs. They highway districts also objected to Idaho Power’s classification of LIDs, which are created by local governments to pay for physical improvements, as “third-party beneficiaries” that can be required by Idaho Power to pay for utility relocation when a private party benefits. Idaho Power did not contest public road agencies’ authority to require relocation of utility facilities at the utility’s expense when there is a public benefit. Idaho Power argued that once the utility complies with the relocation it can seek reimbursement from third parties benefitting from the relocation. Idaho Power said only the Public Utilities Commission has the authority to determine how utility costs should be allocated. In its findings, the commission disagreed with the company’s contention that LIDs are always third-party beneficiaries and thus must always be required to pay for utility relocation. The commission said it is reasonable for an LID to include relocation costs, but it declined to include language that compels reimbursement from LIDs. The commission also denied Idaho Power’s request to require advance payment from third parties who benefit from utility facility relocation. The highway districts said such a requirement could unduly interfere with a project’s timetable if the third party did not make timely payment. The commission said Idaho Power has other alternatives to ensure it receives reimbursement including its ability to participate in project development meetings at the onset of the project and its ability to terminate service is the developer refused to pay. In fact, the commission added a new section to the tariff that requires Idaho Power to participate in project design or development meetings to be in a better position to eliminate or minimize relocation costs to the maximum extent reasonably possible. That new section, the commission said, complies with a law passed by the Idaho Legislature this year with the intent of minimizing the cost of utility relocation where possible. The commission declined to grant the highway districts’ request that the new language be eliminated because the commission lacked jurisdiction. “The commission affirms that highway agencies have the authority to determine when Idaho Power must relocate its distribution facilities and whether any other party is responsible for paying for the road improvement costs,” the commission said. “However, once the highway agency determines that a private party (e.g., a developer) must shoulder all or a portion of the road improvement costs, then it is the Commission that establishes the costs for utility relocation.” The commission said that relocation of utility facilities is a utility service subject to commission jurisdiction. PUC backs legislation allowing proposed low-income programs Case No. GNR-U-08-01, Order No. 30724 February 4, 2009 The Commission is endorsing legislation that would allow utilities to propose “programs, policies and rates” that may assist low-income customers in their effort to pay energy bills. IPUC Annual Report 2009 31 | P a g e It is one of several recommendations made by the commission in response to energy affordability workshops recently conducted by commission staff, the utilities and several consumer groups. The commission directed the state’s major utilities to participate in the workshops in response to a “variety of factors contributing to significant upward pressure on electric and natural gas rates in Idaho.” Energy affordability has become a central issue for many Idaho residents and businesses, the commission said. A report summarizing the recommendations and conclusions from the workshops, as well as the positions of all the participating parties, is available on the commission’s Web site at www.puc.idaho.gov. Parties who participated in the study included commission staff, Idaho Power Company, Rocky Mountain Power, Avista Utilities, Intermountain Gas, the Northwest Industrial Gas Users, the Community Action Partnership Association of Idaho, AARP, the Idaho Community Action Network and the Snake River Alliance. The legislation the commission is recommending would change current statute, Idaho Code 61-315, that prevents public utilities from granting “any preference or advantage” to persons or corporations when it establishes rates. The commission said the change in the legislation should not compel Idaho utilities to offer low-income financial assistance programs, but should allow them to do so without violating current Idaho statute. “The legislation should allow the utilities flexibility in the programs to be proposed,” the commission said. The commission specifically pointed to a program offered by Avista Utilities, which operates in northern Idaho, but also has customers in Washington and Oregon. Avista’s Low-Income Rate Assistance Program, or LIRAP, provides funds to help low-income residents in Washington and Oregon pay their energy bills. In Washington, the money for the program is collected through a rider on all customer bills. In Oregon, LIRAP is funded by an assessment on natural gas bills. Offering more low-income programs at a state level may qualify Idaho for more federal funding under the federal Low-Income Home Energy Assistance Program or LIHEAP. During 2008, 101,000 Idaho households qualified for LIHEAP assistance, but only 32,843 of those households received assistance due to the lack of federal LIHEAP funding. LIHEAP’s Idaho allocation can be increased through a process called “leveraging”. The federal government withholds a percentage of LIHEAP money allocated to each state as an incentive for that state to first acquire non-federal funds for assistance to low-income households. Grants are awarded states that can provide more local funding. Other steps the commission is encouraging: Utilities should engage in greater education efforts to make more customers aware of the programs already available to help with paying energy bills and to offer weatherization and conservation steps that can be taken to decrease energy bills. “Education and funding regarding weatherization and conservation can be administered in conjunction with LIHEAP and LIRAP-type programs,” the commission said. Weatherization programs should be extended beyond single-family residential homes to also include apartment and condominium complexes, manufactured homes and rental housing. Utilities should advocate for the adoption of greater energy efficiency standards for new construction. Utilities should work with local lenders to provide opportunities for customers, including low-income customers, to move to higher-efficiency appliances. Several utilities offer rebates to customers who switch to higher-efficiency appliances. “Unfortunately, IPUC Annual Report 2009 32 | P a g e upgrading an appliance is a luxury that low-income customers cannot generally afford,” the commission said. The commission will continue to support the use of tiered-rates as a means to encourage greater energy efficiency and conservation. The recently concluded Idaho Power rate case implements a three-tiered rate structure with gradual increases to rates as use increases. The commission is encouraging utilities to be flexible in making payment arrangements “that are based on the customer’s unique circumstances and ability to pay.” However, the commission said, “Flexibility by the utility should not be mistaken for abandonment of debt.” Most Idaho utilities require customers they consider to be high-risk to pay deposits before they can receive electric or gas service. The utilities should periodically evaluate whether requiring some customers to pay connection deposits is cost-effective, the commission said. Idaho Power Co., for example, determined that administrative costs associated with a deposit mechanism did not justify continuing the program. The commission commended Avista Utilities for its “case management program” which assigns a case worker to provide individual, specialized attention to customers having problems paying their bills. Intermountain Gas is in the process of developing such a program. The commission said it won’t require all utilities to have a case management program, but encouraged utilities to be “flexible in responding to their customers’ needs.” PacifiCorp relies on renewable energy to meet future needs Case No. PAC-E-09-06, Acceptance of Filing September 17, 2009 The commission accepted a planning document filed by PacifiCorp that details how the utility intends to meet customer needs over the next decade. The utility serves customers in Washington, Oregon, Utah, Wyoming, California and in eastern Idaho, where, operating as Rocky Mountain Power, it has about 70,000 customers. PacifiCorp plans to add more than 1,423 megawatts of renewable energy and does not include any added coal generation in its plan. The commission requires that regulated electric utilities file an Integrated Resource Plan (IRP) every two years. Acceptance of the plan by the commission does not guarantee that it will approve every project proposed during the 10-year period. “The IRP, as we continue to note, is a utility planning document that incorporates assumptions and projections at a point in time. It is the ongoing planning process that we acknowledge, not the conclusion or results,” the commission said. PacifiCorp said it will begin to experience a capacity deficit in 2011 if steps are not taken soon to increase generation and reduce demand. The utility anticipates a growth rate of about 2.5 percent per year over the next decade. Further creating the need for more generation is the 2011 expiration of a major power purchase contract with the Bonneville Power Administration. The vast majority of the 1,423 MW in anticipated new renewable generation is expected to come from wind (1,313 MW) with the rest coming from geothermal (35 MW) and major upgrades to existing hydroelectric facilities (75 MW). IPUC Annual Report 2009 33 | P a g e On the conservation side, the utility plans to save just more than 900 MW from energy efficiency programs and another 105 to 325 MW from programs where the company remotely reduces demand from customers such as irrigators and industry during times of peak use. PacifiCorp also plans to add about 831 MW in gas- fired capacity between 2014 and 2016 and gain 170 MW of emissions-free capacity from coal plant turbine upgrades. The company could have been short on capacity as soon as 2010, but took steps to meet increased demand in 2008 by acquiring a 520-MW natural gas plant in Chehalis, Washington, and adding 175 MW of additional wind resources. PacifiCorp anticipates gaining access to more generation with the completion of its proposed Gateway transmission project, a joint project with Idaho Power Co. that will transport energy from eastern Wyoming, through southern Idaho (Gateway West) and through Utah (Gateway South). Commission staff, which operates independently of the commission, commended the company for a diverse mix of generation resources, while adhering to imposed and pending environmental regulation. Staff found it noteworthy that coal-fired generation does not appear in the company’s portfolio of future generation sources. Staff did express concern that the company anticipates a more than doubling of the wind integration cost assessed wind developers. The company’s 2007 IRP used a cost of $5.10 per megawatt-hour to integrate wind, but includes an $11.75 per MWh cost in the current IRP. Staff also said that costs included by the company to meet mandated renewable portfolio standards in other states were not adequately quantified. IPUC Annual Report 2009 34 | P a g e Renewable energy Commission orders Idaho Power to sell Green Tags Case No. IPC-E-08-24, Order No. 30743, Order No. 30018 May 21, 2009 Reversing an earlier decision, the commission ordered Idaho Power Co. to sell its 2007 and 2008 Green Tags and use the proceeds – estimated to be between $1.6 million and $1.9 million – to benefit ratepayers. A Green Tag, or Renewable Energy Credit, is issued to each utility for every megawatt-hour of electricity generated by an eligible renewable energy resource. An active market exists for the purchase and sale of Green Tags. Idaho Power’s Elkhorn Wind project in Oregon and its Raft River geothermal project in south- central Idaho generated more than 320,000 MWh of Green Tags for Idaho Power in 2007 and 2008. In January, the commission granted Idaho Power’s request to retire its Green Tags. Idaho Power wanted to retire the tags in anticipation of federal or state legislation that may require utilities to generate a specific amount of energy from renewable sources. By retiring the tags, Idaho Power said it could represent to renewable energy certification programs and to its customers that it is meeting customer expectations for increased use of renewable energy. The Industrial Customers of Idaho Power petitioned the commission for reconsideration, arguing the value associated with the Green Tags belongs to the ratepayers and should be sold to benefit customers. Further, the industrial customers argued, allowing the utility to retire the tags causes them to lose value in the wholesale market. The Idaho Conservation League and the Renewable Northwest Project argued that the commission should affirm its original decision to let the utility retire the tags. During reconsideration, Idaho Power modified its request, asking for authority to retire or “bank” the tags. Banking the tags would allow the company to stockpile tags now, when they are presumably less expensive to acquire, in anticipation of future mandatory renewable energy requirements. In its order, the commission said it found no compelling evidence that banking the tags will “lessen the company’s burden in meeting a federal future standard.” Idaho Power’s request to bank or shelve the tags rests only on speculation that they may be used in the future, the commission said. “Unless and until the federal government establishes renewable energy standards and corresponding guidelines, we find the most prudent disposition of these Green Tags, at this time, is their sale.” However, the commission said, this order does not foreclose an alternative treatment for Green Tag sales in the future. Utility reports more emissions credits; proceeds from previous credits used to expand energy efficiency education IPC-E-09-08, Order No. 30790 and Case No. IPC-E-08-11, Order No. 30760 May 1, 2009 The commission ruled that revenue from Idaho Power Company’s sale of sulfur dioxide emission allowances should be included in the utility’s annual Power Cost Adjustment to benefit customers. Idaho Power earned about $5.3 million from the sale of the allowances during 2008 and part of 2009, after deducting brokerage fees. At least 90 percent of the revenue from those sales will go to ratepayers. IPUC Annual Report 2009 35 | P a g e In 2007 and 2008, proceeds from the sale of emission allowances were deducted from the Idaho Power’s annual Power Cost Adjustment (PCA), reducing the size of that surcharge for customers. The commission late last week concluded a case that directs a portion the 2008 adjustment – $500,000 – to an expanded energy education program in Idaho Power’s territory. A 1990 amendment to the Clean Air Act established a national program for reducing acid rain. Sulfur dioxide (SO2) and nitrogen oxide (NOx) are the primary causes of acid rain. In the United States, about two-thirds of all SO2 and one-fourth of all NOx comes from thermal (coal and natural gas) electric generating plants. Idaho Power has an ownership interest in three coal-fired plants: Jim Bridger in Wyoming, North Valmy in Nevada and Boardman in Oregon. Under the federal program, thermal power plant owners are issued limited allowances for their plants’ sulfur dioxide emissions based on a specific plant’s past emissions and a nationwide cap placed on the total amount of SO2 that can be emitted. Each allowance authorizes the utility to emit one ton of SO2. At the end of each year, a utility generating unit must hold allowances equal to its allotted annual SO2 emissions. A utility that holds over its annual requirement is considered to have surplus allowances that can be sold on the open market or through auctions sponsored by the Environmental Protection Agency. Proceeds from previous case should go to energy efficiency education Case No. IPC-E-08-11, Order No. 30760 May 1, 2009 The commission chose a modified version of a proposal by Idaho Power as the best use of $500,000 for energy efficiency education. In the 2008 emissions credits case, the commission agreed with a recommendation from the Idaho Energy Education Project that a portion of $19.6 million in emissions credits be used for energy education. Proposals for an education program came from IEEP, Idaho Power Co. and a joint proposal by the Office of Energy Resources and the State Department of Education. The commission adopted the Idaho Power proposal, saying it is more focused on schools within its service territory and has smaller overhead and administrative costs. Idaho Power’s proposal includes expanding its existing program of energy education by increasing the number of energy audits for homes and schools as well as follow-up discussion of those audits. Idaho Power will distribute classroom energy kits to students to take home. Students will be taught how to read meters, including advanced meters that are being installed throughout Idaho Power’s territory. With meters the students take home, they will be able to calculate the energy use of home appliances. Students will also be invited to participate in audits of school buildings, including making recommendations for efficiency measures. The commission rejected a portion of Idaho Power’s proposal to add two more solar projects to the two existing projects in the Solar 4R Schools program. The commission said the $75,000 allocated for those projects would be better used in the home and school energy efficiency components of the program. The commission also directed Idaho Power to establish an advisory board to implement the energy education proposal. Its members will include some of the parties who participated in the case. The board will also assist Idaho Power in preparing a final report to the commission after the two-year project is complete. IPUC Annual Report 2009 36 | P a g e Commission reviews Avista conservation programs Case No. AVU-E-09-06 and AVU-G-09-04, Order No. 30918 October 7, 2009 The commission approved an application by Avista Utilities to increase the rider that electric and natural gas customers pay to fund conservation programs and to create a mechanism for a yearly adjustment each spring. The Commission’s decision did not result in an increase to the overall rates approved by the commission in its July 17 order and made effective on Aug. 1. That increase – an average 1.5 percent for electric customers and 1.2 percent for gas customers already included the proposed rider adjustments. The rider funds more than 30 programs in two categories called demand side management (DSM) and energy efficiency. DSM programs reduce customer demand on the company’s generation sources. Efficiency programs help customers use their electricity more efficiently. The commission approves riders for electric and gas utilities if they are found to be cost-effective for both customers and the utility. DSM and efficiency programs can save customers money in both the short term by direct customer participation and in the long term because they prevent or delay the utility from having to buy or build more expensive generation. Avista proposed to increase its electric rider from 2.24 percent to 3.27 percent of customer bills and the gas rider from 1.55 percent to 2.6 percent. Final approval of the rider would increased annual revenue by $5.4 million. However, increases in the rider cannot increase or decrease company earnings. Revenue collected from the rider can be used only to pay off a $2.36 million shortfall in the electric rider fund, a $1 million shortfall in the gas rider fund and to fund ongoing programs. Avista’s DSM and efficiency efforts are based on providing financial incentives or rebates for customer participation in more than 30 programs. Some of the programs include efficiency measures for appliances, compressed air systems, HVAC systems, industrial and commercial equipment, lighting and motors. The programs also include renewable technologies and sustainable building measures. Further, Avista has long encouraged the direct use of natural gas by its electric customers with rebates for the conversion of electric- to-natural gas space and water heater loads. According to the company’s application, Avista continues to exceed targets in electric and gas savings as the result of these programs for its Washington and Idaho customers. More than 110 average megawatts of demand-side management programs are now in place on the company’s total retail average load (during 2008) of 1,100 average megawatts. (A megawatt is one million watts, enough electricity to power about 650 average homes.) On the gas side, 1.9 million therms were saved during 2008, which was 136 percent of the company’s target. Of all the surcharge revenues collected from Washington and Idaho electric and gas customers, 72 percent were paid back to customers in direct incentives to participate in energy efficiency and demand-side management programs. This does not include the additional benefits such as technical analysis and education provided to customers by the company’s DSM staff. In the application, Avista also proposed to reduce large negative or positive adjustments to the rider by filing on or about Feb. 15 of each year for either an increase or a decrease to the rider. According to the company’s application, installing energy efficiency measures “is a direct action customers can take to respond to a period of increasing energy prices facing the Pacific Northwest and the country as a whole.” The application stated that Avista’s energy efficiency programs are being used by customers at unprecedented levels. IPUC Annual Report 2009 37 | P a g e PacifiCorp rates will be adjusted annually to account for power supply Case No. PAC-E-08-08, Order No. 30904 October 7, 2009 Rates for customers of Rocky Mountain Power will be adjusted either up or down every April 1 to account for varying costs of power supply needed to serve the utility’s eastern Idaho customers. The Commission adopted a negotiated settlement that allows a yearly rate adjustment called the Energy Cost Adjustment Mechanism, or ECAM, for PacifiCorp, which does business in eastern Idaho as Rocky Mountain Power. The ECAM will be either a one-year surcharge (increase) to customer bills or a one-year credit (decrease) depending on the company’s power supply expenses that are not already included in the fixed base rates paid by customers. A greater portion of PacifiCorp’s generation now comes from natural gas. The utility also gets about 30 percent of its generation from hydropower. Changing water conditions and volatility in the natural gas markets can cause fluctuations that sometimes result in power supply expense that is greater than that already included in base rates and sometimes in power supply expense that is less than that included in base rates. When those expenses are higher, customers will get a surcharge and when they are lower, a credit. The commission said the yearly adjustment is “supported by the volatility in the energy market and the changing character of the company’s resource portfolio.” “The commission finds that the designed ECAM will send better price signals to the company’s customers of the cost of power by adjusting their rates on a more current basis,” the commissioners said. A benefit to customers, even if the ECAM is a surcharge, is that a more timely recovery of power supply expenses should reduce for the frequency of filings by the company for general rate increases. As part of the agreement approving the ECAM, PacifiCorp agreed not to file a rate case before May 1, 2010. Another benefit to a yearly adjustment is lower borrowing costs for the company. PacifiCorp is in a period of increased investment, thus assurances to financial markets of timely recovery of expenses allows for financing at lower interest rates, benefitting both the company and its customers. To incent the company to be prudent in its power supply purchase decisions, the ECAM requires that shareholders pay 10 percent of the power supply expenses not already included in rates. The Idaho Irrigation Pumpers Association supported the settlement. Other utilities serving Idaho customers have annual rate adjustments similar to PacifiCorp’s ECAM. Idaho Power Company, which serves customers across southern Idaho, and Avista Utilities, which serves customers in northern Idaho, both have an annual Power Cost Adjustment, or PCA. PacifiCorp serves about 70,000 customers in eastern Idaho. IPUC Annual Report 2009 38 | P a g e PacifiCorp wants larger discount for non-firm wind generation Case No. PAC-E-09-07, Notice of Comment Deadline October 5, 2009 PacifiCorp, which does business as Rocky Mountain Power in eastern Idaho, is asking state regulators that it be allowed a larger discount from the price it must pay wind developers for their generation. Currently, PacifiCorp discounts $5.10 per megawatt-hour off the rate it pays some wind developers. The discount is intended to capture PacifiCorp’s cost of integrating wind generation into its electrical system. PacifiCorp is asking the Idaho Public Utilities Commission that it be allowed to discount $9.96 per MWh from the rate is must pay small-wind developers who qualify under the provisions of the federal Public Utility Regulatory Policies Act of 1978 (PURPA). Under PURPA, qualifying generators of small-power projects that generate up to 10 megawatts are paid a rate published by the commission. That rate, called an avoided-cost rate, is to represent the cost the utility avoids by buying output from the small-power project instead of generating the power itself or buying it from another power provider. PacifiCorp’s application does not apply to wind developers who enter into agreements with the utility to deliver output on a firm, hourly basis. The case was still pending at the time this report was completed. PUC approves demand reduction contract Case No. IPC-E-09-02, Order No. 30805 May 21, 2009 The Commission approved a five-year agreement between Idaho Power Company and Boston-based EnerNOC to reduce demand from commercial and industrial customers by at least 2 megawatts this year and by at least 50 megawatts in each 2012 and 2013. EnerNOC, selected in a bid process, will implement and operate the program. According to Idaho Power, the total five-year cost for the program is $12.2 million, varying from about $315,000 this year to about $3.5 million in the fifth year. Costs associated with the program will be recovered from the Energy Efficiency Rider funds. Commercial and industrial customers who volunteer to participate would be asked to reduce their energy loads for two to four hours during those summer days when demand on Idaho Power’s generation system is at its peak. Participants would receive compensation in exchange for reduced loads. The commission said Idaho Power has selected a “capable entity with significant experience in negotiating and securing the necessary load reduction agreements.” The commission is satisfied that the agreement contains adequate protection for the company and ratepayers should EnerNOC fail to deliver on its demand reduction requirements. IPUC Annual Report 2009 39 | P a g e PURPA projects Commission updates rates to be paid developers of small-power projects Case No. GNR-E-08-02, Order No. 30738 Case No. GNR-E-09-01, Order No. 30744 March 17, 2009 Developers of qualifying renewable small-power projects will be paid considerably more for their generation as a result of updated published rates. The Commission updated both the fuel and non-fuel components of a mechanism used to calculate the rates that Idaho’s three major regulated utilities must pay to small-power or cogeneration project developers whose projects qualify under the federal Public Utility Regulatory Policies Act, or PURPA. PURPA, passed by Congress during the energy crisis of the late 1970s, requires electric utilities to offer to buy power produced by qualifying small-power producers or cogenerators. The rate that utilities must pay project developers, called an “avoided-cost rate,” is determined by state commissions. The avoided-cost rate is to be equal to the cost the utility avoids if it would have had to generate the power itself or purchase it from another source. In Idaho, projects cannot be larger than 10 megawatts to qualify for the published avoided-cost rate. The commission recently issued two orders; one that updates the non-fuel components of the avoided-cost rate, such as capital costs and operations and maintenance and another that updates the always varying fuel components of the rate. The fuel component is adjusted shortly after the Northwest Power and Conservation Council releases a new natural gas price forecast, which it did in late December. The result of both orders is an avoided-cost rate that is considerably higher than the former rate paid by utilities to small-power producers. For example, the developer of a wind farm or geothermal facility with a capacity of less than 10 MW would be paid $88.67 per megawatt-hour (or about 8.87 cents per kWh) for a 20-year levelized (same rate all 20 years) contract with Avista Utilities. That compares to the former avoided-cost rate of $70.12 per MWh. The three major investor-owned utilities in Idaho – Idaho Power, PacifiCorp and Avista Utilities – participated in the case as did Black Canyon LLC, which is developing a wind generation facility in Bonneville County. PacifiCorp, which does business in eastern Idaho as Rocky Mountain Power, filed a motion to delay implementing the new avoided-cost rate and, in the absence of a delay, asked the commission to decrease the size of projects that can qualify for the published rate from 10 MW to no larger than 1 MW. PacifiCorp contended the Northwest Power and Conservation Council natural gas price forecast was too high given the recessionary economic environment. The commission said PacifiCorp did not present enough evidence that the rate is not reasonable. Further, the commission said, any utility can petition the commission at any time if it believes the mechanism used to calculate the rate is unreasonable. IPUC Annual Report 2009 40 | P a g e Anaerobic digester to sell output to Idaho Power Case No. IPC-E-09-22, Order No. 30874 August 14, 2009 The Commission approved a sales agreement allowing Idaho Power Co. to buy the output from the Bettencourt B6 dairy anaerobic digester located near Jerome. The agreement, between Idaho Power and Cargill Environmental Finance, is for 2.13 megawatts. The purchase price will be equal to 85 percent of a Dow Jones market price that is the weighted average of the daily on-peak and off-peak price for non-firm energy. The project is scheduled to in operation by September 1. After the project has operated for a reasonable amount of time, Idaho Power expects that Cargill and the company will enter into a long-term firm energy sales agreement. Idaho Power will buy energy from three Hagerman area wind farms Case Nos. IPC-E-09-18, Order No. 30924; IPC-E-09-19, Order No. 30925; IPC-E-09-20, Order No. 30926 October 15, 2009 The Commission approved three energy sales agreements between Idaho Power Company and a Boise- based wind developer who will build three wind farms in the Hagerman area. The sales agreements are with Exergy Development Group of Idaho, which plans to build all three projects under the provisions of PURPA, the Public Utility Regulatory Policies Act of 1978. PURPA requires electric utilities to offer to buy power produced by qualifying small-power producers or co-generators. The rate to be paid project developers, called an “avoided cost rate,” is to be equal to the cost the electric utility avoids if it would have had to generate the power itself or purchase it from another source. The three projects – Camp Reed (22.5 MW), Payne’s Ferry (21 MW) and Yahoo Creek (21 MW) – are scheduled to begin operating Sept. 30, 2010. Under the agreements, each of the plants will deliver up to 10 average megawatts on a monthly basis, which is the upper limit of the size of projects that can qualify for PURPA posted rates. The projects are among the first PURPA wind agreements signed since the resolution of a major case involving all of Idaho’s regulated electric utilities and wind developers. Because of the intermittency of wind generation and its impact on the utility transmission grid, the posted rate paid to wind developers is reduced to reflect the utility’s cost of integrating the generation into its system. Wind developers must also provide mechanical guarantees and share in the expense of wind forecasting. In exchange, the utilities agreed to drop a provision that penalized wind developers if their actual generation output was less than 90 percent or more than 110 percent of their projected output. These wind agreements are also unusual in that the contracts are for levelized rates rather than non- levelized rates. Levelization means that the developer is paid an energy price at the front-end of the 20-year agreement that is in excess of the actual energy value. The overpayment is recouped in later years when the payments are projected to be less than the value of the power. Levelized rates can be an incentive to cogeneration and small-power development because it helps project developers recoup up-front expenses more quickly. But few developers choose this option because of the accompanying security requirements IPUC Annual Report 2009 41 | P a g e put in place to discourage contract default. In the event of a default, some project owners may not be unable to refund the utility the overpayment that comes in the early years of a levelized contract. The developer of these three wind projects has agreed to meet various security requirements in addition to a maintenance reserve account of at least $2 million. Under the 20-year contracts, Idaho Power will pay the posted rate of $84.40 per megawatt-hour during months of normal demand, which include January, February, June, September and October. During the months of heavy demand (July, August, November and December), Idaho Power will pay $102.58 per megawatt-hour. During months of less-than-normal demand (March through May), Idaho Power will pay $61.47 per megawatt-hour. Those rates include the wind integration charge and are adjusted slightly during heavy-load hours and light-load hours of the day. Commission approves Idaho Power agreement with wind project Case No. IPC-E-09-25, Order No. 30964 December 18, 2009 The Commission approved a sales agreement with Idaho Winds LLC for a wind project six miles northwest of Glenns Ferry in Elmore County. Meridian-based Idaho Winds LLC will construct and operate the 21-megawatt Sawtooth Wind Project. Though its optimum capacity is 21 MW, under normal conditions it will not exceed 10 average megawatts on a monthly basis. The wind project is scheduled to be in operation by Dec. 31, 2012. The project will operate as a Qualifying Facility under the provisions of PURPA, the Public Utility Regulatory Policies Act of 1978. PURPA requires electric utilities to offer to buy power produced by qualifying small-power producers or co-generators. The rate to be paid project developers, called an “avoided cost rate,” is to be equal to the cost the electric utility avoids if it would have had to generate the power itself or purchase it from another source. Under the 20-year contract, Idaho Power will pay the posted rate of $75.45 per megawatt-hour during months of normal demand in the first full-year of the contract, anticipated to be 2013. Under the agreement, the price gradually increases through the 20-year life of the contract. For example, the 2030 price during normal demand months is $118.97 per MWh. The rates vary during light-load and heavy-load months and hours. In the same order, the commission accepted a letter agreement between Idaho Power and the Alkali Wind Project that was originally to be built on the same site. Due to a transmission study delay and escalating costs during that delay, the Alkali project was terminated. IPUC Annual Report 2009 42 | P a g e IPUC Annual Report 2009 43 | P a g e Idaho Natural Gas Utilities Throughout 2009, there were significant decreases in all the utilities commodity costs. Intermountain Gas, Avista Utilities, and Questar Gas all decreased the Purchase Gas Cost Adjustment (PGA) portion of their rates by 26.5 percent, 33 percent and 32.7 percent, respectively. (See more detailed information below.) The primary cause for the decrease in commodity costs was the downturn in the regional and national economy. Nationally, the Energy Information Administration (EIA) estimated that natural gas consumption fell by 1.5 percent in 2009 despite a significant increase in natural gas‐fired electric power generation. In addition to the impact of weather‐adjusted drops in demand, other concurrent factors mentioned by Idaho gas utilities in explaining the drop in prices included: 1) the cooler summer reduced the need for natural gas fired electric generation; 2) the discovery of an abundance of North American shale reserves; 3) the spread of global recession led to higher than normal supplies of Liquid Natural Gas (LNG); 4) the volume of natural gas in storage exceeded historical averages and continued to increase through the injection season; and 5) the surge in drilling rigs brought on by last summer’s high prices. More recently spot natural gas prices at trading locations across the country have leveled out following last year’s declines associated with concerns over economic conditions. According to the EIA, consumption is forecast to remain relatively unchanged in 2010 and is anticipated to increase by 0.4 percent in 2011. Locally, the Northwest Gas Associations’ 2010 Gas Outlook predicts demand for natural gas across the region (Idaho, Oregon, Washington and British Columbia) growing by an average 1 percent through 2019. Climate change policies enacted by state and provincial legislatures across the region are expected to drive some of that growth. The EIA estimates that continued high storage levels combined with enhanced domestic production capabilities and slow consumption growth are expected to keep prices from rising. IPUC Annual Report 2009 44 | P a g e Individual Utility Statistics (As of the most recent FERC filing) Intermountain Gas Company Residential Commercial Industrial Transportation Total Customers 270,790 28,983 9 107 299,889 % of Total 90.30% 9.66% 0.00% 0.04% 100.00% Therms (millions) 217.17 83.19 29.63 229.07 559.06 % of Total 38.85% 14.88% 5.30% 40.97% 100.00% Revenue (millions) $223.84 $105.36 $2.15 $10.40 $341.75 % of Total 65.50% 30.83% 0.63% 3.04% 100.00% Avista Utilities Residential Commercial Industrial Transportation Total Customers 64,014 8,145 99 7 72,265 % of Total 88.58% 11.27% 0.14% 0.01% 100.00% Therms (millions) 49.09 27.34 2.27 45.93 124.63 % of Total 39.39% 21.94% 1.82% 36.85% 100.00% Revenue (millions) $59.55 $30.20 $2.30 $0.46 $92.51 % of Total 64.37% 32.65% 2.49% 0.49% 100.00% Questar Gas Residential Commercial Industrial Transportation Total Customers 1,697 225 1 0 1,923 % of Total 88.25% 11.70% 0.05% 0.00% 100.00% Therms (millions) 1.25 0.73 0.03 0.00 2.01 % of Total 62.34% 36.27% 1.39% 0.00% 100.00% Revenue (millions) $1.10 $0.56 $0.02 $0.00 $1.67 % of Total 65.56% 33.54% 0.90% 0.00% 100.00% IPUC Annual Report 2009 45 | P a g e Declining wholesale market rates results in Avista lowering gas rates Case No. AVU-G-09-02, Order No. 30714 January 6, 2009 Declining wholesale natural gas prices mean that Idaho natural gas customers of Avista Utilities will pay lower rates. Rates for an average residential customer will decline about 4.7 percent as a result of the Commission order. Avista, which serves about 72,000 natural gas customers in north-central and north Idaho, has opted to begin returning a larger portion of a growing balance in an account funded by customers to pay for the company’s wholesale gas purchases. Because wholesale prices are lower than anticipated, customers are paying more than market rates. Typically, the Purchased Gas Cost Adjustment (PGA) deferral account is adjusted only once a year on Oct. 1. At that time, customers get either a surcharge when market prices are higher than anticipated or a credit when market prices are lower than anticipated. This year, because of the continued decline in prices, Avista applied to the commission to refund about $4 million of a $5.6 million PGA deferred account to customers now rather than waiting until Oct. 1. “In order to allow customers to receive the greatest benefit from a decrease in rates during the winter heating season, the commission finds it in the public interest to immediately implement Avista’s rate decrease without further procedural delay,” the commission said. Avista elected not to refund the entire $5.6 million because it may increase the possibility of a rate increase when the company files its annual PGA this fall. PGA filings do not increase or decrease company earnings. The amount accrued in the PGA account is adjusted every year to reflect the varying price of natural gas. When wholesale prices are higher than anticipated, a surcharge is collected from customers and all that money must be used to pay Avista’s natural gas and transportation expenses. When Avista over- collects, the amount is refunded to customers through a credit. For an average Avista residential customer who uses 65 therms per month, the decrease will be about $3.89 per month, or 4.7 percent, according to Avista’s calculations. Avista natural gas rates decline again Case No. AVU-G-09-03, Interlocutory Order No. 30826 June 1, 2009 For the second time in less than six months, the rates paid by natural gas customers of Avista Utilities are going down. The Commission approved Avista’s application to decrease rates to Idaho customers by about 6.7 percent due to the continued decline in the wholesale cost of natural gas. For an average residential customer who uses 65 therms per month, the decrease is about $5.26 per month. Customers received a 4.7 percent decrease on Jan. 6 and company officials say they expect another decrease to come in October after the company files its annual Purchase Gas Cost Adjustment (PGA). Because the commission wanted customers to immediately realize the benefit of lower wholesale prices, it approved the reduction with an “Interlocutory Order,” which means the commission will still take time to more thoroughly review the application as well as take comments from the public or interested parties through June 19. If the commission does receive comments or protests, it has the discretion to set the matter for hearing. If there are no comments or protests, the Commission may consider the matter on its merits and issue the final order without a formal hearing. IPUC Annual Report 2009 46 | P a g e Intermountain Gas customers will start paying less Oct. 1 Case No. INT-G-09-02, Order No. 30913 September 29, 2009 The Commission approved a request by Intermountain Gas Company to reduce the variable portion of its gas rates by about 22.2 percent for residential customers and 21.6 percent for commercial customers. Residential rates for customers who use natural gas for both space and water heating, will decline from $1.05 to 80.9 cents per therm from April to November and from $1.02 to 77.5 cents from December through March. For a customer who uses natural gas for both space and water heating, the average monthly reduction is about $16.23 per month. For residential customers who use natural gas for space heating only, the reduction will be about $11.27 a month. For commercial customers, the average monthly reduction is $69.21. This is the third reduction in four years of Intermountain’s annual Purchased Gas Cost Adjustment, or PGA. Every year on Oct. 1, the PGA portion of Intermountain Gas rates are adjusted either up or down depending largely on the price of natural gas on the wholesale gas market. Increases or decreases in the PGA do not affect the company’s earnings. “A current imbalance exists between supply and demand for natural gas, which has driven down gas prices,” the commission said. “In addition, Intermountain Gas utilizes dynamic hedging and effectively manages its natural gas storage.” In addition to customers benefitting from lower wholesale market prices, Intermountain stores significant amounts of natural gas procured during the summer season for use during the winter when market prices are normally higher. Also, in an effort to further stabilize prices paid by customers during the winter, Intermountain has entered into various hedging agreements to lock in the price for significant portions of its underground storage. Currently, residential customers who use natural gas for both space and water heating pay $1.05 per therm ($1.02 during winter months). About 67.5 cents of that is based on the always variable weighted average cost of gas (WACOG). The rest of the rate is based on fixed costs such as capital investment and operations and maintenance. The fixed portion of the rate changes only after a rate case, while the variable WACOG is adjusted at least once annually through the PGA process. With the Oct. 1 decrease, the WACOG decreases from 67.5 cents per therm to 49.6 cents per therm. Intermountain’s total PGA includes a combination of both increases and decreases to the cost of its gas supply and transportation including: 1)an increase in costs billed to Intermountain due to higher prices charged by Northwest Pipeline, which was offset by a small decline in the amount of gas transported on the pipeline; 2) an increase in costs from Intermountain’s Canadian pipeline suppliers, 3) a decrease in the company’s projected storage contract costs and 4) a reduction in firm transportation and storage costs due to Intermountain’s management of its storage and firm capacity rights on pipeline systems. Intermountain Gas serves about 305,000 customers across southern Idaho. IPUC Annual Report 2009 47 | P a g e Avista gas rates drop by 22 percent Case No. AVU-G-09-05, Order No. 30937 November 3, 2009 Residential and small-business customers of Avista Utilities started paying about 22 percent less in natural gas rates Nov. 1. Avista serves about 70,000 natural gas customers in northern Idaho. “A reduction in demand for natural gas coupled with an abundance of natural gas supplies have driven down natural gas prices,” the Commission said in an order approving Avista’s third request this year to decrease its Purchased Gas Cost Adjustment (PGA) surcharge. “In addition, Avista follows a flexible, diversified natural gas purchasing plan and effectively manages its underground natural gas storage facility,” the commission said. “These actions allow Avista to provide stable and low prices to its customers.” The reduction is larger than that requested by Avista. Avista wanted to refund customers the balance in its PGA deferral account over two years to mitigate a possible future increase in the adjustment next year. But the commission said customers should get all the benefit this year. Residential customers who use the average 66 therms per month will get a monthly reduction of about $16.44 or 21.93 percent. The company requested a reduction of about $12.74 per month or 17.8 percent. Large commercial customers will get about a 25.9 percent decrease. An adjustment to the PGA, to reflect the always changing prices of natural gas, is made at least once yearly. However, the commission directed Avista “to promptly file an application to amend” the PGA should gas prices continue to deviate significantly either up or down from current prices. The PGA results in either a surcharge or a credit depending on the always fluctuating prices of wholesale gas and related transportation costs. While the decrease reduces Avista’s annual revenue by $18.8 million, it does not impact company earnings; nor does an increase in the surcharge. PUC approves gas hook-up fee for some new Sun Valley customers Case No. INT-G-09-01, Order No. 30908 September 29, 2009 State regulators are allowing Intermountain Gas Company to assess a new hook-up fee for new seasonal natural gas customers building large homes in the Sun Valley and Ketchum areas. The hook-up fee becomes effective Oct. 1. The hook-up fee, approved by the Commission, will pay for a $640,000 upgrade of the northern end of the Sun Valley Lateral, which is now operating at capacity. The upgrade increases the allowable operating pressure on that segment of the pipeline. The seasonal occupancy of the homes being built in the area does not allow the company to generate enough year-round revenue to make the upgrade project cost-effective without a hookup fee. The fee will be assessed only to new customers in the impact area who benefit from the upgrade. If the actual costs of the project result in a lower hookup fee calculation than that initially charged to customers, Intermountain Gas will refund customers the difference. The defined impact area includes those customers north of Gimlet Road, excluding the Gimlet Subdivision. Ninety-seven percent of the demand is contained within the last 15 miles (northern end) of the 68-mile lateral, according to the company. IPUC Annual Report 2009 48 | P a g e Intermountain Gas wants ability to interrupt snow-melt customers Case No. INT-G-09-03, Order No. 30957 December 11, 2009 Intermountain Gas Company is asking the Commission for authority to temporarily interrupt service to customers who use natural gas-fired snow-melting equipment during times when use of natural gas supply is peaking. Natural-gas fired snow-melting equipment, installed under driveways and on rooftops, uses an inordinate amount of natural gas compared to more conventional uses. During days when natural gas is at peak use, the snow-melt equipment has the potential to impact service to other customers, said Intermountain Gas in its application to the commission. The company claims that because snowmelt customers use large amounts of natural gas for only a few days or weeks during the winter, it creates an inefficient use of the company’s distribution system and does not allow for cost recovery of the added capacity. Intermountain Gas is proposing that new residential and small-commercial customers installing snow-melt equipment or existing customers remodeling to install the equipment receive the interruptible service. For customers who already have snow-melt equipment, Intermountain is negotiating voluntary agreements that allow for interruption after advance notice by the company. Under the proposal, all new snow-melt applications would require individual meters installed at customer expense. These meters would be distinct from the meters provided for other natural gas service. At its discretion, Intermountain Gas would manually or remotely turn off all snow-melt meters in affected regions of its system when the ability of the system to make all natural gas deliveries is at stake. The company believes the interruptions will not be lengthy, but will depend on weather and snowfall conditions. The case was still pending at the time this report was published. IPUC Annual Report 2009 49 | P a g e Idaho Water Utilities The commission regulates 29 privately held water systems, or only about 1 percent of the approximate 2,100 water systems in the state. The regulated systems vary in size from companies with about 78,000 customers to companies with as few as 22 customers. These companies provide industrial, commercial and residential customers throughout the state with drinking water as well as water for irrigation, recreation and manufacturing. Most of the unregulated systems are operated by homeowner associations, water districts, co‐ops and cities. The rates listed here represent only the residential customer class and may not reflect the actual rates paid by a specific customer. (bh) = business hours (ah) = after hours (nm) = non‐metered (g) = gallons (cf) = cubic feet Utility Name Number of New Hook-up Reconnect Residential Monthly Last Rate Sur- Customers Fee Fee Rates Revision charge 1. Algoma 27 $0.00 $ 25 $ 17.59/mo. nm 7/4/2008 $44.50 (commercial) 2. Aspen Creek 35 $1,000 $15bh/$25ah $25 up to 15,000 gal 9/25/2002 After 30 days --$75 $1 each 1,000 gals over 3. Bar Circle "S" 160 $250 $ 20bh/$40 ah $27.43 up to 7,500 gal 1/1/2010 $500 meter inst. $1.74 each 1,000 gal over 4. Bitterroot 117 $750 $ 25 bh/ah $21 up to 15,000 gal 2/1/2006 $1.24 BF $1.73 each 1,000 gal over $2.67 Valve 5. Brian 46 None approved $ 12.50 bh/ah $10.50 up to 4,000 gal 5/1/1999 $1.08 each 1,000 gal over 6. Capitol Water 2,878 None approved $20bh Varying monthly rates for metered and non-metered service depending on size, starting at $12.10 (nm) and $7.50 (m). 1/1/2009 Surcharges vary with service size and type 7. Country Club Hills Utility 147 $500 $14 bh $17 up to 30,000 gal 6/1/2005 $28 ah $0.60 each 1,000 gal over 8. Diamond Bar Estates 51 $310 /existing $ 15 bh $ 29.00→5,500 gal 12/1/2007 $2,500 to install $ 30 ah .80 each 1,000 gal over 9. Eagle Water Company 3,415 $845 includes $100 study surcharge and $500 loan surcharge. $15 bh/ $30 ah Monthly flat rate starting at $11.75 (nm); $ 7.84 up to 600 cf. metered and $0.45 for each add 100 cf 2/23/2009 Surcharge for master- metered MH park 10. Evergreen 36 $600 None approved $ 15 up to 7,500 gal 01/06/95 $0.35 each 1,000 gal over 11. Falls Water 3,569 Minimum $500 depending on meter size $20/bh and $40/ah $20.17 (nm); $14 up to 01/14/08 12,000 gal and $0.667 Rate case pending Each 1,000 gal over IPUC Annual Report 2009 50 | P a g e Utility Name Number of New Hook-up Reconnect Residential Monthly Last Rate Sur- Customers Fee Fee Rates Revision charge 12. Grouse Point 24 None approved $20bh/ $40ah $22 up to 8,000 gal 1/4/2004 $0.50 each 1,000 gal over 13. Happy Valley 24 $500 $ 20bh/ah $27.00 up to 20,000 gal 8/3/2001 $0.70 each 1,000 gal over 14. Island Park 334 $200 authorized $20bh/$20ah $280/year 11/05/2008 $1100 unauthzed 15. Kootenai Heights Water 54 None approved $50 $38.50 up to 10,000 gal 6/21/2007 $3.10 each 1000 gal over 16. Mayfield Springs 54 $725 $35bh/$70ah 1” meter $22 up to 10,000 gal $0.30 each 1,000 gal over 09/01/2008 2” meter $50 up to 20,000 gal $0.30 each 1,000 gal over 17. Morning View 97 None approved $ 25 bh/-ah ¼ acre-$ 27.41/mo. 9/24/2007 $5 for ½ acre-$ 35.94/mo. Reserve 1 acre-$ 44.48/mo Account 18. Murray 25 $800 None approved $ 26/mo 7/15/2003 19. Pack Saddle Estates 35 $430 $ 25.00 bh/ah $25 if under 45 days 6/3/1996 $130 beyond 45 days 20. Picabo 28 $500 $ 15 involuntary $22/mo residential 7/1/2004 Irrigation (April-Sept) $ 25 voluntary $37/mo commercial $19/mo 21. Ponderosa 29 $2,500 $ 35 bh/ah Resident: $ 48/mo 7/1/2003 Seasonal: $ 25/mo 22. Resort 396 None approved $ 20 bh/$60ah $ 44.80/mo per 1 ERU 3/15/2005 4X that after 30 days 23. Rickel 33 $6,000 $25 bh/ah $ 30 up to 15,000 gal 5/011997 $1.10 each 1,000 gal over 24. Spirit Lake 309 $2,500 $ 16 bh/ah $12.50 up to 9,000 gal 6/10/2007 $0.12 each 100 gal over 25. Stoneridge 334 $1,200 $18.50bh/$33.50ah $24/mo based on size 7/02/2007 Happy 30-days plus varies $0.79/1,000 gal Valley res Per size of service Pay $16.83/mo Does not 26. Sunbeam 22(?) None approved None approved $12 up to 12,000 gal 5/31/1983 file annual $1.20 each 1,000 gal over report 27. Teton Springs 272 $600 for $20 if disconnected 1” line $240/quarter 2/2/2009 1” res/larger 30 days or less/ Based on size $40 after hours 28. Troy Hoffman 144 $458/1” $10/bh $5.50/first 3,000 gal 8/01/1996 $0.60 each 1,000 gal 29. United Water Idaho 83,235 See Tariff $20/ bh Winter: 7/28/2006 separate $30/ ah $16.21 monthly plus Res flat rate, $1.21/100 cf. Sprinkler, Summer: and $16.21 monthly plus Fire hydrant $1.21 /100cf up to 3cf schedules $1.51 for each 100 cf over IPUC Annual Report 2009 51 | P a g e Water rates approved for Teton Springs; case addresses unique issues Case No. TTS-W-08-01, Order No. 30718 January 29, 2009 The Commission approved rates for about 272 customers of the Teton Springs Water and Sewer Company. This case was unique because of Teton Springs’ request to establish a fund for emergency repairs and also to assess an “availability charge” on undeveloped lots in the resort. The water company serves single-family home, multi-residential units and commercial customers within the Teton Springs Golf and Casting Club planned resort development near Victor. The development has 581 single-family lots, 14 commercial lots and two multi-family dwellings that will contain 143 residential units at build-out. Currently, the company serves 194 residential customers, 73 multi-family unit customers and five commercial customers. The commission approved an annual revenue requirement for the utility of $146,309. Teton Springs requested $259,256. The commission approved a rate base of $57,763, while the company proposed $75,350. The rate base is the dollar value of a utility’s physical facilities and operating capital used to serve its customers. From this total capital investment (less depreciation) the utility is authorized to earn a rate of return. The commission approved a 12 percent rate of return. The commission approved total annual expenses of $137,483, against the company’s proposal of $285,166. As part of its annual expense, Teton Springs proposed that $89,140 be recovered from customers for a fund to allow the company to quickly make emergency repairs to the system. The $89,140 is the annual depreciation of the total water system investment of $3.1 million. But the commission said collecting that money from customers would be asking them to pay a second time for plant-in-service already contributed by customers and recovered by the developer in the sale of the resort lots. However, the commission said the company raised an issue common to many of Idaho’s small water companies: When small water systems are developed using lot sales to recover infrastructure costs (contributed capital), they have no plant-in-service investment that can be included in rate base from which the company can earn a rate of return. When emergency repairs are required, small water utilities typically must borrow the money and then apply to the commission for a temporary surcharge. “We find this situation presents challenges to a small water utility’s economic viability and often compromises its capability to satisfy its statutory duty to maintain adequate service,” the commission said. Consequently, the commission is allowing the company to establish an emergency reserve fund of nearly $7,000 per year to be used only for emergencies and major unplanned capital expenditures that add up to greater than 10 percent of the company’s annual revenue requirement. The company must provide an auditable paper trail of the expenses and provide the commission with written notice when it uses the fund. The amount of the fund is 5 percent of the company’s revenue requirement, not including operations and maintenance expense. It may accumulate over the years, but cannot exceed the company’s authorized annual revenue requirement. Teton Springs also sought an “availability charge” on customers owning undeveloped lots. Teton Springs is only at one-third of expected build-out. In declining the request, the commission cited a 1982 order it issued after the Hayden Pines water utility sought to assess a charge on all billable lots with water available to them. While hook-up fees can be charged, the commission said, customers cannot be billed for water service they are not receiving. Such a charge would amount to a tax and a public utility does not have the constitutional right to levy a tax. “The economic consequences of developing a water service infrastructure for a resort community initially must remain with the developer,” the commission said. “This risk cannot be passed on to the universe of potential future customers or owners of undeveloped lots.” IPUC Annual Report 2009 52 | P a g e To address revenue loss because of the resort community’s seasonal disconnects, the commission granted Teton Springs authority to charge a reconnection fee to customers who re-connect after more than a 30-day absence. The rates approved by the commission are as follows: -- Single-family residential, $240 per quarter. The company requested $150 per quarter and a $75 per quarter “availability charge” for undeveloped lots. --Multi-family residential, $80 per quarter. The company requested $150 per quarter. --Commercial, $240 per quarter for properties served by a one-inch service line. The amount increases as the size of the service line increases. The company requested $450 and an availability charge of $225 on undeveloped commercial lots. The commission also directed the company to submit a plan to meter all customers. The flat rates will likely be eliminated once meters are installed and customers billed based primarily on consumption. Commission approves Eagle Water charge, but will review expenses Case No. EAG-W-09-01, Order No. 30734 February 27, 2009 The Commission is allowing Eagle Water Company to assess its customers a 48 percent surcharge on consumption of more than 600 cubic feet per month. The surcharge is to pay down a near $1 million loan needed to meet expenses for a number of capital improvement projects that have been completed or are near completion. However, the Commission is also beginning a process to review the company’s improvements to determine their prudency. The surcharge, which became effective Feb. 23, is subject to refund if the commission finds the expenses were not prudent or necessary to serve customers. The surcharge replaces a 42.5 percent surcharge that expired last October. At that time, Eagle Water petitioned the commission to continue that surcharge, but the commission denied the request noting that the proposed extension of the former surcharge was for new expenses that had yet to be reviewed. The former surcharge paid for an engineering study that preceded the capital improvement projects included in the new surcharge. The commission gave the company authority to borrow up to $995,000 from the Idaho Banking Company at 6.75 percent over seven years and to access the remaining balance of about $120,000 in the former surcharge fund. Monies collected from the surcharge will go to pay down the loan. Eagle Water Co. serves about 3,000 residential customers and 415 business customers in Eagle and the surrounding area. It is not the same as the City of Eagle Water, a municipal water system. The new surcharge increases customers’ commodity charge from 45 cents for every 100 cubic-feet of water used beyond 600 cubic-feet (about 4,500 gallons) to 67 cents. The $7.84 per month for the first 600 cubic- feet of use remains the same. Capital projects completed include the rebuilding of one well and the construction of a seventh well. Improvements still in progress include construction of a new eighth well and a new motor and generator for the new booster station. According to Eagle Water, the capital improvement projects will total $1.53 million plus another $98,100 for legal and engineering expenses. IPUC Annual Report 2009 53 | P a g e The improvements will provide the company with enough back-up water so that it will no longer need to pay the City of Eagle’s municipal water system $10,000 per month for providing back-up support during emergencies. The state Department of Environmental Quality placed Eagle Water Co. under a moratorium that prohibited the company from adding new customers until the system’s capacity was increased. The moratorium was lifted when Eagle Water entered into an agreement with the City of Eagle to provide back- up water in times of emergency. PUC to conduct workshop regarding Eagle Water surcharge Case No. EAG-W-09-01, Order No. 30878 August 14, 2009 The Commission approved an application by Eagle Water Co. to continue a 48 percent surcharge on consumption of more than 600 cubic feet per month to pay for capital improvements and expenses. Eagle Water Co. serves about 3,415 customers in Eagle and the surrounding area. It is not the same as the City of Eagle Water, a municipal water system. The surcharge will fund about $600,000 in improvements and expenses and is anticipated to expire in about 4 to 4 ½ years. The company asked for $1.5 million in improvements. The largest amount approved for the surcharge fund was $215,000 related to the construction of a new well. Another $360,000 in costs related to the new Well No., 7 will be put in permanent base rates. Another $110,000 was an expense owed the City of Eagle’s municipal water system to provide a tie-in to that system so that the company would have enough back-up supply in case of emergencies. The state Department of Environmental Quality (DEQ) placed Eagle Water Co. under a moratorium that prohibited the company from adding new customers until the system’s capacity was increased. The moratorium was lifted when Eagle Water entered into an agreement with the City of Eagle to provide back-up water in times of emergency. The company is developing a new well – Well No. 8 – that will eliminate the interconnection requirement with the City of Eagle. The well is built and tested, but is temporarily capped because the pump house has not been built. Eagle Water Co. wanted to include $211,500 in land acquisition and drilling costs for the new well in the surcharge fund, but the commission denied that request because the well is not yet benefitting customers. When the well is placed in service, the company may then seek to recover costs, the commission said. The company wanted to recoup those funds earlier because of cash-flow problems, but the commission said it had previously approved a bank loan for Eagle Water that was intended to provide the company with access to revenue. Other items approved for the surcharge included $107,400 for a booster station at Well No. 2; $60,700 for rebuilding Well No. 4; $43,765 for a pressure reducing valve required by DEQ; $45,000 in legal fees; and $22,800 for capital costs related to the tie-in to Eagle City’s water system. The commission urged Eagle Water to reduce its reliance on surcharges and, at its next application, submit a case for redesigned base rates. IPUC Annual Report 2009 54 | P a g e Kootenai County water company expands territory Case No. BCS-W-08-01, Order No. 30731 February 27, 2009 The Commission approved an expansion of the territory served by a Kootenai County water company to include a new subdivision of 47 five-acre residential lots. Bar Circle “S” Water Company, which serves about 156 households seven miles north of Coeur d’Alene, sought authority to add the proposed 237-acre subdivision to be built in two phases. The company claims the added territory, which is about 1,300 feet from the existing Bar Circle “S” territory, won’t adversely affect existing customers and won’t require construction of additional sources of water supply. Construction costs for the added mains, valves, fire hydrants, service line taps, meter boxes, meter bases and line extensions needed to interconnect to the existing water system will be paid by the subdivision developer. The only cost to be borne by the company will be the cost of the meters at the time service is requested. Commission staff expressed concern about the company’s ability to serve the second phase of the development and whether the state Department of Environmental Quality would require a back-up well or additional water source. The company said it has acquired a permit for a 10- to 12-inch well to replace a 6- inch well that is not now serviceable and that the back-up well will be in operation by the time the second phase of the development is built. Rates increase 4.3 percent for Capitol Water customers CAP-W-08-02, Order No. 30713 April 8, 2009 Rates for the approximate 2,700 Boise customers of Capitol Water Co. will increase by 4.3 percent. The company asked the Commission for a 7.8 percent increase. Capitol Water has about 2,560 residential customers and 150 commercial customers in an area bounded roughly by Northview Street north to Ustick Road and from North Maple Grove east to Curtis Road. Capitol Water asked for the increase to cover $102,000 in expenses to relocate distribution pipes, fire hydrants and customer service connections to accommodate the Ustick Road widening. In addition, the company sought $11,235 to pay for the October 2008 failure of a pump that is now back in service and asked the commission to let it put a mechanism in place that would allow Capitol Water it to increase its rates whenever increases in electric rates for Idaho Power are approved. The commission allowed recovery of expenses for the Ustick widening project and for the pump failure repairs but denied the company’s request to increase rates when electric rates increase. The commission said the company’s electric rates did not increase as dramatically as claimed, actually dropping from 2005 to 2007 and slightly increasing in 2008. Capitol Water last had a rate case in 2006. On Jan. 1 of this year, a customer surcharge of $3.55 per month was removed from customer bills. In place since 2002, the surcharge paid for $500,000 in improvements, including one well replacement and an upgrade to the company’s distribution system. IPUC Annual Report 2009 55 | P a g e PUC OKs changes to Spirit Lake East charges; denies monthly billing Case No. SPL-W-09-01, Order No. 30938 November 4, 2009 The Commission granted a petition by Spirit Lake East Water Company to revise its tariff by adding fees for late payments, returned checks and reconnecting service. However, the commission denied the company’s request to begin billing its customers on a monthly, rather than quarterly, basis. Spirit Lake East Water Company services about 330 customers in the Spirit Lake area. The tariff revisions approved include a late-payment charge of 1 percent per month of the unpaid balance; a $20 returned check fee; a reconnection fee of $32 for reconnection within 30 days of disconnection and $52 for customers disconnected more than 30 days. A reconnection made hours other than normal business hours will be $65. The commission said the charges are similar to the amounts charged by other utilities. A change to monthly billing should be made only after all the costs of the conversion are known and measured against the benefits and after the public has had sufficient time to comment, the commission said. “It may be, as the company asserts, that a change to monthly billing will produce a more consistent revenue stream, send clearer signals to the company’s customers about their water usage, provide better data about water usage or loss, and allow for earlier discovery of leaks on a customer’s side of the meter. These benefits do not come without costs,” the commission said. There will be expenses to change the existing billing system and its software program. In addition, the costs for reading meters and recording all readings would increase. Those costs were not quantified in the company’s application. “The proposal to change to monthly billing is not approved, but will be reserved for a rate case when the additional costs and benefits can be adequately evaluated,” the commission said. Commission begins process of reviewing United Water request Case No. UWI-W-09-01, Order No. 30901 September 17, 2009 The Commission is beginning an up to six-month process to review United Water Idaho’s application for a rate increase. The Boise-based company, which serves 83,900 customers in Ada County, applied earlier this month for the increase, its first rate adjustment application in three years. If the increase were approved in its entirety, an average residential customer would pay about $4.37 more per month, or about 15.2 percent. United Water claims the increase is warranted because it has made numerous major capital investments since its 2006 rate case, including $2 million in treatment facilities, more than $12 million replacing aging infrastructure, $1.4 million in booster station improvements and more than $700,000 in auxiliary power generators at various sites. To recover its investment, the company claims it will need to increase its annual revenue by $5.6 million. State statutes require that regulated utilities be allowed to recover their prudently incurred costs of doing business plus a reasonable rate of return. The company’s application states that the proposed changes in rates would produce a rate of return of 8.49 percent. The rate of return approved by the commission must not be unreasonably high for customers, but high enough to attract investors for major capital projects and upgrades. When the commission denies cost recovery to a utility it must be able to legally demonstrate why the denied costs were not prudently incurred or needed to serve customers. Utilities, as well as other parties in the case, can appeal commission decisions to the state Supreme Court. IPUC Annual Report 2009 56 | P a g e Idaho Telecommunications With the passage and signing of House Bill 224 in 2005, local exchange companies operating in Idaho were provided the option of removing their services from rate regulation. Idaho’s two largest telecommunications companies, Qwest Communications, both North and South, and Verizon Northwest, lost no time in taking advantage of this option, announcing their election to seek price deregulation shortly after the new legislation became law. In 2007, Citizens Telecommunications, doing business as Frontier Communications of Idaho, also opted into price deregulation. While the services of all regulated telecommunications companies remain under commission jurisdiction for customer service and quality issues, the rate deregulated companies no longer need to seek commission approval to adjust rates. (Qwest South had elected price deregulation for all of its services except basic local exchange service in 1988.) Rate increases are limited, with caps that increase annually, and are eliminated after three years, unless the commission extends them for two additional years. In August of 2008, the three‐year transition period with caps expired for Qwest and Verizon. On June 1, 2007, Qwest increased its basic local exchange rate by 20 percent. In July 2007, Verizon increased its local service rates by 10 percent. In August 2007, Citizens notified the Commission that it would increase its monthly residential rates by 10 percent. These companies provide service to more than 90 percent of the telephone lines in Idaho, so the overwhelming majority of Idahoan’s telephone service is no longer subject to rate regulation. In 2009, CenturyTel merged with Embarq and is doing business as CenturyLink. Awaiting final approval on a federal level is the bid of Frontier Communications to acquire Verizon wireline assets, creating the nation’s largest pure rural telecommunications service provider. Verizon operates in northern Idaho from about Orofino north. Frontier currently has Idaho customers in the Elk City, McCall and Cascade regions. IPUC Annual Report 2009 57 | P a g e Wireless company qualifies for high-cost support in rural Idaho Case No. CTL-T-09-01, Order No. 30867 August 6, 2009 The Commission granted a request by Cambridge-based CTC Telecom, Inc., to be declared eligible to receive federal funds to expand its wireless network to serve Adams, Boise, Gem and northern Washington counties. The Commission ruled that CTC Telecom, which will operate as Snake River PCS, qualifies as an “eligible telecommunications carrier” (ETC). The designation means the wireless carrier can receive about $171,300 each year from the federal Universal Service Fund (USF). The USF was created by Congress to ensure that telephone consumers in rural areas – where it costs more to build a telephone network – can have access to the same telecommunications services as consumers in urban areas at roughly the same cost. All telephone companies providing interstate service contribute to the USF. The companies pass that cost on to their consumers who currently pay about 12.9 percent of their bill each month to support the Universal Service Fund. That charge is adjusted yearly. The commission granted ETC status for CTC Telecom in the communities of New Meadows, Council, Indian Valley, Cambridge, Garden Valley, Horseshoe Bend, Idaho City and Lowman. ETC status for CTC Telecom is in the public interest, the commission said, because the carrier can provide a competitive choice for telephone consumers. CTC Telecom certified to the commission that it has or will soon have the ability to provide local calling, access to emergency services, operator services, directory assistance and long-distance calling. The commission denied CTC’s request to serve in the Midvale Telephone Exchange because CTC did not demonstrate to the commission that it would serve the entire exchange. Carriers seeking ETC status must provide service throughout their requested service area, not just in places where there is a higher concentration of customers. Carriers are denied ETC status if they engage in “cream skimming,” or serving only those customers within an exchange’s lower cost areas and not building the network out to also take in customers in more remote, high-cost areas. CTC denied it was targeting low-cost areas in the Midvale exchange. However, CTC’s decision to disaggregate the Midvale service area requires the commission to adhere to its previous rulings granting ETC status only in those areas where an entire service area is included in the carrier’s expansion plans. By granting ETC status, Snake River PCS customers who meet state Health and Welfare Department guidelines will also become eligible to participate in the Idaho Telecommunications Service Assistance Program. Sometimes referred to as “Lifeline,” the program helps to ensure low-income Idahoans, including senior citizens, have access to local dial-tone service for medical and other emergencies. Lifeline is funded by federal funds in addition to a monthly charge of 6 cents per line for each Idaho residential, business and wireless customer. The revenue from that charge and the federal funds allow Lifeline to discount the monthly bills of qualifying participants by $13.50 per month. IPUC Annual Report 2009 58 | P a g e Idaho participates in nationwide Lifeline Awareness Week Low-income households can benefit from telephone assistance program Local telephone service provides more than social connection. When it’s necessary to call “911” or a family member in times of emergency, local telephone service can be a lifeline. The Idaho Public Utilities Commission joined state commissions across the nation and consumer groups to increase awareness of “Lifeline,” a joint federal and state program to provide local telephone service to low-income households. The Idaho commission, along with the Federal Communications Commission and the National Association of Regulatory Utility Commissioners, declared Sept. 14-20 “Lifeline Awareness Week.” Lifeline helps to ensure that low-income Idahoans, including many senior citizens, have access to local dial-tone service for medical and other emergencies. The federal Universal Service Fund provides a discount of $10 per month while the state-level program – the Idaho Telephone Service Assistance Program (ITSAP) – adds another $3.50 per month per qualifying household. That $13.50 per month discount amounts to a significant reduction to residential phone bills. About 28,000 Idaho households participated in the program during 2008. This is out of a total of 618,000 local access wirelines and 984,500 local access wireless lines. According to figures recently released by the FCC, about 97.3 percent of Idaho households had telephone service, a penetration rate that ranks eighth in the nation. For telephone subscribers with an annual income of less than $10,000, Idaho has a penetration rate of 95.2 percent, or fourth in the nation. Part of the reason for Lifeline Awareness Week in Idaho is to celebrate our success in getting telephone service to the vast majority of households, including low-income households,” said Jim Kempton, president of the Idaho Public Utilities Commission. “However, we know there are Idahoans who do not have telephone service, but would if they were aware Lifeline is available,” he said. The state portion of the Lifeline program is funded by a 6-cent per line, per month charge on residential, business and wireless phone lines. The state Department of Health and Welfare determines who qualifies for the program, while the Public Utilities Commission determines the statewide uniform monthly charge. Lifeline assistance is now available for customers of wireless telephone carriers that have been declared eligible telecommunications carriers by the commission. Those with questions regarding Lifeline can call the Commission at 334-0300 or 1-800-432-0369 or access the Commission Web site at: http://www.puc.idaho.gov/CONSUMER/ITSAP.PDF You can also contact your local telephone company or your local Community Action Partnership (CAP) agency. A list of CAP agencies and contact information is available on the Commission Web site at: http://www.puc.idaho.gov/CONSUMER/counties.htm IPUC Annual Report 2009 59 | P a g e Telecommunication Utilities Under PUC Jurisdiction Albion Telephone Corp (ATC) , P.O. Box 98, Albion, Idaho 83311‐0098 208/673‐5335 Cambridge Telephone Co. P.O.Box 88, Cambridge, Idaho 83610‐0086 208/257‐3314 CenturyTel of Idaho, Inc., P.O.Box 1007, Salmon, Idaho 83467 208/756‐3300 CenturyTel of the Gem State, P.O.Box 9901, 805 Broadway, Vancouver, WA 98668 360/905‐5800 Also: 111 A Street, Cheney, Washington 99114 509/235‐3170 *Frontier, A Citizens Telecommunications Company of Idaho P.O. Box 708970, Sandy, Utah 84070‐8970 801/274‐3127 Local: 201 Lenora Street, McCall, Idaho 83638 208/634‐6150 Inland Telephone Co., 103 South Second Street, Box 171, Roslyn, WA 98941 509/649‐2211 Fremont Telecom, Inc., 110 E. Main Street, St. Anthony, Idaho 83445 208/624‐7300 Midvale Telephone Exchange, Box 7, Midvale, Idaho 83645‐0007 208/355‐2211 *Verizon Northwest, Inc., 20575 N.W. Von Neumann Dr., Hillsboro, OR 97006 503/629‐ 2285 Local: 208/765‐4351 (Coeur d’Alene); 800/483‐4100 (Moscow); 208/263‐0557, Ext. 204 (Sandpoint) Oregon‐Idaho Utilities, Inc., 3645 Grand Ave., Ste. 205A, Oakland, CA 94610 510/338‐ 4621 Local: 1023 N. Horton St., Nampa, Idaho 83653 208/461‐7802 Pine Telephone System, Inc., Box 706, Halfway, OR 97834 541/742‐2201 Potlatch Telephone Company, dba/ TDS Telecom, Box 138, 702 E. Main St. Kendrick, Idaho 83537 208/835‐2211 Direct Communications Rockland, Inc., Box 269, 150 S. Main St. Rockland, ID 83271 208/548‐2345 Rural Telephone Company, 829 W. Madison Avenue, Glenns Ferry, Idaho 83623‐2372 208/366‐2614 Silver Star Telephone Company, Box 226, Freedom, WY 83120 307/883‐2411 Columbine Telephone Co. Inc., dba Teton Telecom Box 900, Driggs, Idaho 83422 208/354‐3300 *Qwest Communications, North and South Idaho, Box 7888 (83723) or 999 Main Street, Boise, Idaho 83702 800/339‐3929 *These companies, which represent more than 90 percent of Idaho customers, are no longer rate regulated. IPUC Annual Report 2009 60 | P a g e Regulating Idaho’s railroads More than 900 miles of railroad track in Idaho have been abandoned since 1976. Federal law governs rail line abandonments. The federal Surface Transportation Board decides the final outcome of abandonment applications. Under Idaho law, however, after a railroad files its federal notice of intent to abandon, the IPUC must determine whether the proposed abandonment would adversely affect the public interest. The commission then reports its findings to the STB. In reaching a conclusion, the commission considers whether abandonment would adversely affect the service area, impair market access or access of Idaho communities to vital goods and services, and whether the line has a potential for profitability. The Idaho Public Utilities Commission also conducts inspections of Idaho’s railroads to determine compliance with state and federal laws, rules and regulations concerning the transportation of hazardous materials, locomotive cab safety and sanitation rules, and railroad/highway grade crossings. Hazardous material inspections are conducted in rail yards and at shipping facilities. In 1994, Idaho was invited to participate in the Federal Railroad Administration’s State Participation Program. IPUC has a State Program Manager and two FRA certified hazardous material inspectors. The IPUC inspects railroad‐highway grade crossings where incidents occur, investigates citizen complaints of unsafe or rough crossings and conducts railroad‐ crossing surveys. Railroad Activity Summary 2009 Inspections 227 Rail cars inspected 2158 Violations 9 Rail cars with defects 284 Crossing accidents investigated 8 Crossing complaints 2 Locomotives Inspected 15 Defects within locomotives inspected 0 IPUC Annual Report 2009 61 | P a g e Operation Lifesaver Idaho Operation Lifesaver is a non‐profit state organization dedicated to increasing public awareness of the potential dangers that exist at highway/rail grade crossings and around trains in general. Volunteers from various sponsoring groups and other interested individuals staff the organization. Volunteer staff members talk to about 130,000 people each year at presentations and safety booths. Because of the IPUC’s railroad safety oversight, it has taken a leading role in sponsoring and supporting Operation Lifesaver. IPUC staff members participate by making presentations to groups, manning safety booths and serving on the board and various committees. It is the intent of the program to achieve its goal by using: Education – Educate the public about trains by providing safety presentations and by operating informational booths. Engineering – Work with government entities, businesses and railroads to improve highway/rail intersections. Enforcement – Work with law enforcement agencies and railroads to enforce traffic laws pertaining to highway/rail intersections. Railroads in Idaho Palouse River Railroad Burlington Northern Railroad 709 N. 10th St, Walla Walla, WA, 90362 176 E. Fifth St., St. Paul, MN, 55101 509.522.1464 208.263.2016 Idaho track miles: 0 Idaho track miles: 123 Great Northwest Railroad Eastern Idaho Railroad PO Box 116, Lewiston, ID, 83501 618 Shoshone St. West, Twin Falls, ID, 83301 208.743.2559 208.733.4686 Idaho track miles: 8 Idaho track miles: 269 Idaho Northern & Pacific Montana Rail Link PO Box 715, Emmett, ID, 83617 PO Box 8779, Missoula, MT, 59807 208.365.6353 406.523.1500 Idaho track miles: 99 Idaho track miles: 45 St. Maries River Railroad Union Pacific Railroad 318 N. 10th St., St. Maries, ID, 83861 1416 Dodge St., Omaha, NE, 68179 208.245.4531 208.343.1771 Idaho track miles: 99.4 Idaho track miles: 849 BG&CM Railroad, Inc. Boise Valley Railroad, Inc. PO Box 1759, Orofino, ID, 83544 100 PFE Drive, Nampa, ID, 83687 208.476.7938 208.442.0144 Idaho track miles: 109 Idaho track miles: 36 IPUC Annual Report 2009 62 | P a g e Consumer Assistance The Consumer Assistance staff responded to 2,644 complaints, comments or inquiries in calendar year 2008, of which 87 percent were from residential customers. The number of complaints has decreased slightly from 2007, when complaints totaled 2,672. Breakdown of complaints by type of utility Contacts regarding telecommunications companies: 43 percent Contacts regarding energy (electric, gas) companies: 43 percent Contacts regarding water companies: 7 percent Non-utility related contacts: 7 percent (Qwest Communications had 35 percent of telecommunication complaints; Idaho Power had 40 percent and Intermountain Gas 32 percent of energy utility complaints and United Water had 27 percent of water complaints.) Summary of service quality issues: Disputed billings 23 percent Credit and collection issues 28 percent Miscellaneous 17 percent Utility rates and policies 14 percent Telecommunications issues 8 percent Line extensions and service upgrades 4 percent Service quality and repair 6 percent While dispute resolution remains an important task, it is hoped that by working with consumer groups, social service agencies, and utilities, persistent causes of consumer difficulties can be identified and addressed. Consumer complaints present an opportunity for utilities and the commission to learn the effect of utility practices and policies on people. For example, the unintentional and perhaps unfair impact of a rule or regulation might be discovered in the course of investigating a complaint. In such cases an informal, negotiated remedy may not be possible, and formal action by the commission would be required. The Consumer Assistance Staff’s participation in formal rate and policy cases before the commission is the primary method used to address these issues. While the Consumer Assistance Staff is able to respond to some consumer inquiries without extensive research, about 77 percent of consumer complaints required investigation by the staff. About 42 percent of investigations resulted in reversal or modification of the utilities’ original action. Toll‐Free Complaint Line The commission has a toll‐free telephone line for receiving utility complaints and inquiries from consumers outside the Boise area. The toll‐free line (1‐800‐432‐0369) is reserved for inquiries and complaints concerning utilities. Consumers may also file a complaint electronically via the commission’s Website at www.puc.idaho.gov. IPUC Annual Report 2009 63 | P a g e Utilities By City City Electric Gas Tele Aberdeen Idaho Power Intermountain Citizens Acequia Rural Electric None Project Mutual Ahsahka Clearwater Power None Verizon Albion Albion Light None ATC Almo Raft River Coop None ATC Alridge Rocky Mountain None Qwest American Falls Idaho Power Intermountain Qwest Ammon Rocky Mountain Intermountain Qwest Arbon Idaho Power None Direct Arco Rocky Mountain None ATC Arimo Rocky Mountain None Qwest Ashton RMP/Fall River Coop None Fairpoint Athol Kootenai Electric/AVISTA AVISTA Verizon Atlanta Atlanta Power None Rural Atomic City Idaho Power None Qwest Avery AVISTA None Verizon Avon Clearwater Power/AVISTA None Verizon Baker Idaho Power None CenturyTel Bancroft Rocky Mountain Intermountain Qwest Banida Rocky Mountain None Qwest Banks Idaho Power None Citizens Basalt Rocky Mountain Intermountain Qwest Basin Idaho Power None Project Mutual Bayview AVISTA/Kootenai None Verizon Bellevue Idaho Power Intermountain Qwest Bennington Rocky Mountain none Qwest Berger Idaho Power None Qwest Bern Rocky Mountain None Qwest Blackfoot Idaho Power Intermountain Qwest Blanchard AVISTA None Verizon Bliss Idaho Power None Qwest Bloomington Rocky Mountain None Direct Boise Idaho Power Intermountain Qwest Bone Rocky Mountain None Qwest Bonners Ferry Bonners Ferry Light AVISTA Verizon Bovill AVISTA/Clearwater Power AVISTA Verizon Bowmont Idaho Power None Qwest Bridge Raft River Coop None ATC Bruneau Idaho Power Intermountain CenTel Buhl Idaho Power Intermountain Qwest Burke AVISTA None Verizon Burmah Idaho Power None Project Mutual Burley Burley Municipal Intermountain Qwest Butte City Lost River Coop None ATC Cabinet Northern Lights None Verizon Calder AVISTA None Verizon IPUC Annual Report 2009 64 | P a g e City Electric Gas Tele Caldwell Idaho Power Intermountain Qwest Cambridge Idaho Power None Cambridge Cape Horn Salmon River Coop None None Carey Idaho Power None Citizens Careywood Northern Lights None Verizon Carmen Idaho Power None CenturyTel Cascade Idaho Power None Citizens Castleford Idaho Power None Qwest Cataldo AVISTA/Kootenai AVISTA Verizon Cavendish Clearwater Power None Verizon Centerville Idaho Power None Qwest Challis Salmon River Coop None Custer Coop Chatcolet Plummer Electric None Verizon Chester RMP/Fall River Coop None Fremont Chubbuck Idaho Power Intermountain Qwest Clark Fork AVISTA None Verizon Clarkia Clearwater Power None Verizon Clayton Salmon River Coop None Custer Coop Clearwater Idaho Co. Light None Qwest Clifton Rocky Mountain None Qwest Clover Idaho Power None Qwest Cobalt Idaho Power None None Cocolalla Northern Lights None Verizon Coeur d’Alene AVISTA/Kootenai AVISTA Verizon Colburn Northern Lights None Verizon Conda Rocky Mountain Intermountain Qwest Coolin Northern Lights None Verizon Copeland Northern Lights None Verizon Corral Idaho Power None Citizens Cottonwood AVISTA None Qwest Council Idaho Power None Cambridge Craigmont Clearwater Power/AVISTA None Qwest Crouch Idaho Power None Citizens Culdesac Clearwater Power/AVISTA None Qwest Cuprum Idaho Power None Cambridge Dalton Gardens AVISTA/Kootenai AVISTA Verizon Darlington Lost River Coop None ATC Dayton Rocky Mountain None Qwest Deary Clearwater Power/AVISTA AVISTA Verizon Declo Declo Municipal Intermountain Qwest De Smet Kootenai Electric None Verizon Dietrich Idaho Power None Qwest Dingle Rocky Mountain None Qwest Dixie Idaho Co. Light None Citizens Donnelly Idaho Power None Citizens Dover AVISTA AVISTA Verizon IPUC Annual Report 2009 65 | P a g e City Electric Gas Tele Downey Rocky Mountain None Qwest Driggs Fall River Coop None Silver Star Drummond Fall River Coop None Fairpoint Dubois Rocky Mountain None Mud Lake Co-op Eagle Idaho Power Intermountain Qwest East Hope AVISTA None Verizon Eastport Northern Lights None Verizon Eden Idaho Power None Qwest Eddyville AVISTA/Kootenai None Verizon Edgemere Northern Lights None Verizon Elba Raft River Coop None ATC Elk City AVISTA None Citizens Elk River AVISTA None Verizon Ellis Salmon River Coop None Midvale Elmira Northern Lights None Verizon Emida Clearwater Power None Verizon Emmett Idaho Power Intermountain Qwest Enaville AVISTA None Verizon Fairfield Idaho Power None Citizens Fairview Rocky Mountain None Qwest Felt Fall River Coop None Silver Fenn AVISTA None Qwest Ferdinand AVISTA None Qwest Fernan Lake AVISTA/Kootenai AVISTA Verizon Fernwood Clearwater Power None Verizon Featherville Idaho Power None Rural Filer Idaho Power Intermountain Filer Firth Rocky Mountain Intermountain Qwest Fish Haven Rocky Mountain None Direct Fort Hall Idaho Power Intermountain Qwest Franklin Rocky Mountain Questar Qwest Fruitland Idaho Power Intermountain Farmers Fruitvale Idaho Power None Qwest Gannett Idaho Power None Qwest Gardena Idaho Power None Citizens Garden City Idaho Power Intermountain Qwest Garden Valley Idaho Power None Citizens Gem AVISTA Utilities None Verizon Genesee Clearwater Power/AVISTA AVISTA Verizon Geneva Rocky Mountain None Qwest Georgetown Rocky Mountain Intermountain Qwest Gibbonsville Idaho Power None Century Tel Gifford Clearwater Power/AVISTA None Inland Gilmore Idaho Power None Century Tel Glenns Ferry Idaho Power Intermountain Qwest Golden AVISTA None Citizens Good Grief Northern Lights None Verizon Gooding Idaho Power Intermountain Qwest Grace Rocky Mountain Intermountain Qwest Grand View Idaho Power None CenturyTel Gem Grangemont Clearwater Power None Verizon IPUC Annual Report 2009 66 | P a g e City Electric Gas Tele Grangeville AVISTA None Qwest Granite Northern Lights None Verizon Grasmere Idaho Power None CenturyTel Gem Greencreek AVISTA None Qwest Greenleaf Idaho Power Intermountain Qwest Greer AVISTA None Verizon Hagerman Idaho Power None Qwest Hailey Idaho Power Intermountain Qwest Hamer Rocky Mountain None Mud Lake Co Hammett Idaho Power Intermountain Qwest Hansen Idaho Power Intermountain Qwest Harpster Idaho Co. Light None Qwest Harrison Kootenia Elec/AVISTA None Verizon Harvard Clearwater Power/AVISTA None Verizon Hauser AVISTA/Kootenai AVISTA Verizon Hayden AVISTA/Kootenai AVISTA Verizon Hayden Lake Kootenai Elec/AVISTA AVISTA Verizon Hazelton Idaho Power None Qwest Headquarters AVISTA None Verizon Heise Rocky Mountain None Qwest Helmer Clearwater Power/AVISTA None Verizon Henry Lower Valley Power None Silver Star Heyburn Heyburn Electric Intermountain Qwest Hill City Idaho Power None Citizens Holbrook Rocky Mountain None ATC Hollister Idaho Power Intermountain Filer Mu Homedale Idaho Power Intermountain Citizens Hope AVISTA None Verizon Horseshoe Bend Idaho Power None Citizens Howe Rocky Mountain None ATC Huetter AVISTA/Kootenai AVISTA Verizon Humphrey Rocky Mountain None Qwest Huston Idaho Power None Qwest Idaho City Idaho Power None Qwest Idaho Falls Idaho Falls Electric Intermountain Qwest Indian Valley Idaho Power None Cambridge CambridgeInkom Idaho Power Intermountain Qwest Iona Rocky Mountain Intermountain Qwest Irwin Lower Valley Power None Silver Star Island Park Fall River Rural None Fairpoint Jerome Idaho Power Intermountain Qwest Juliaetta Clearwater Power/AVISTA None Potlatch Juniper Raft River Coop None ATC Kamiah AVISTA/Clearwater Power None Qwest Kellogg AVISTA AVISTA Verizon Kendrick Clearwater Power/AVISTA None Potlatch Ketchum Idaho Power Intermountain Qwest Kilgore Rocky Mountain None Mud Lake Kimama Idaho Power None Project Mutual Kimberly Idaho Power Intermountain Qwest King Hill Idaho Power None Qwest Kingston AVISTA AVISTA Verizon Kooskia AVISTA None Qwest IPUC Annual Report 2009 67 | P a g e City Electric Gas Tele Kootenai AVISTA AVISTA Verizon Kuna Idaho Power Intermountain Qwest Laclede AVISTA/Northern Lights None Verizon Lake Fork Idaho Power None Citizens Lakeview Kootenai Electric Co-op None Midvale Lamb Creek Northern Lights None Verizon Lane AVISTA/Kootenai None Verizon Lapwai Clearwater Power/AVISTA None Qwest Lava Hot Springs Rocky Mountain Intermountain Qwest Leadore Idaho Power None CenturyTel Lemhi Idaho Power None CenturyTel Lenore Clearwater Power None Inland Leon Clearwater Power/AVISTA None Inland Leslie Lost River Coop None ATC Letha Idaho Power None Qwest Lewiston AVISTA/Clearwater Power AVISTA Qwest Lewisville Rocky Mountain Intermountain Qwest Lincoln Rocky Mountain None Qwest Lorenzo Rocky Mountain None Qwest Lost River Lost River Coop None ATC Lowman Idaho Power None Cambridge Lucile Idaho Power None Citizens Lund Rocky Mountain None Qwest Mackay Lost River Coop None ATC Malad City Rocky Mountain None ATC Malta Raft River Coop Intermountain ATC Marion Idaho Power None Project Mutual Marsing Idaho Power None Citizens Marysville Rocky Mountain None Fairpoint May Salmon River Coop None Custer Coop McCall Idaho Power None Citizens McCammon Rocky Mountain Intermountain Qwest Meadows Idaho Power None Citizens Meadow Creek Northern Lights/ None Verizon Bonners Ferry Light Medimont Kootenai Electric/AVISTA None Verizon Melba Idaho Power None Qwest Menan Rocky Mountain Intermountain Qwest Meridian Idaho Power Intermountain Qwest Mesa Idaho Power None Cambridge Middleton Idaho Power Intermountain Qwest Midvale Idaho Power None Midvale Minidoka Minidoka Electric None Project Mutual Mink Creek Rocky Mountain None Qwest Monteview Rocky Mountain None Mud Lake Co-op Montour Idaho Power None Citizens Montpelier Rocky Mountain Intermountain Qwest Moore Lost River Coop None ATC Moreland Idaho Power Intermountain Qwest Moscow AVISTA/Clearwater Power AVISTA Verizon Mountain Home Idaho Power Intermountain Qwest Moyie Springs Northern Lights/ AVISTA Verizon IPUC Annual Report 2009 68 | P a g e City Electric Gas Tele Mud Lake Rocky Mountain None Mud Lake Co-op Mullan AVISTA AVISTA Verizon Murphy Idaho Power None Qwest Murray AVISTA None Verizon Murtaugh Idaho Power Intermountain Qwest Myrtle Clearwater Power None Inland Naf Raft River Coop None ATC Nampa Idaho Power Intermountain Qwest Naples Northern Lights None Verizon Neeley Idaho Power None Qwest Newdale RMP/Fall River Coop None Fairpoint New Meadows Idaho Power None Citizens New Plymouth Idaho Power Intermountain Qwest Nezperce Clearwater Power/AVISTA None Qwest Norland Idaho Power None Project Mutual Nordman Northern Lights None Verizon North Fork Idaho Power None CenturyTel Notus Idaho Power None Qwest Nounan Rocky Mountain None Qwest Oakley Idaho Power None Project Mutual Obsidian Salmon River Coop None Midvale Ola Idaho Power None Citizens Oldtown AVISTA None Verizon Onaway AVISTA/Clearwater Power None Verizon Orchard Idaho Power None Qwest Oreana Idaho Power None CenturyTel Gem Orofino Clearwater Power/AVISTA None Verizon Orogrande AVISTA None Citizens Osburn AVISTA AVISTA Verizon Ovid Rocky Mountain None Qwest Oxford Rocky Mountain None Qwest Paris Rocky Mountain None Direct Parker Rocky Mountain Intermountain Fairpoint Parma Idaho Power Intermountain Citizens Patterson Salmon River Coop None CenturyTel Paul Idaho Power/Rural Intermountain ProjMut Pauline Idaho Power None Direct Payette Idaho Power Intermountain Qwest Pearl Idaho Power None Qwest Peck Clearwater Power None Verizon Picabo Idaho Power None Qwest Pierce AVISTA None Verizon Pine Idaho Power None Rural Pinehurst AVISTA AVISTA Verizon Pingree Idaho Power None Qwest Pioneerville Idaho Power None Qwest Placerville Idaho Power None Qwest Plummer Plummer Electric None Verizon Pocatello Idaho Power Intermountain Qwest Pollock Idaho Power None Citizens Ponderay AVISTA AVISTA Verizon Porthill AVISTA/Northern Lights None Verizo IPUC Annual Report 2009 69 | P a g e City Electric Gas Tele Portneuf Idaho Power None Qwest Post Falls Kootenai Elec/AVISTA AVISTA Verizon Potlatch Clearwater Power/AVISTA None Verizon Prairie Idaho Power None Rural Preston Rocky Mountain Questar Qwest Priest River AVISTA None Verizon Princeton Clearwater Power/AVISTA None Verizon Raft River Raft River Coop Intermountain ATC Rathdrum Kootenai Elec/AVISTA AVISTA Verizon Reubens Clearwater Power/AVISTA None Qwest Rexburg RMP/Fall River Coop Intermountain Qwest Reynolds Creek Idaho Power None Qwest Richfield Idaho Power None CenturyTel Gem Riddle Idaho Power None CenturyTel Gem Rigby Rocky Mountain Intermountain Qwest Riggins Idaho Power None Citizens Ririe Rocky Mountain Intermountain Qwest Riverside Idaho Power Intermountain Qwest Roberts Rocky Mountain None Qwest Robin Rocky Mountain None Qwest Rock Creek Idaho Power None Verizon Rockford Idaho Power None Qwest Rockland Idaho Power None Direct Rogerson Idaho Power None Filer Mutual Rose Lake AVISTA/Kootenai None Verizon Roswell Idaho Power None Citizens Roy Idaho Power None Direct Rupert Idaho Power Intermountain ProjectMut Sagle AVISTA None Verizon St. Anthony RMP/Fall River Coop Intermountain Fairpoint St. Charles Rocky Mountain None Direct St. Joe AVISTA None Verizon St. Maries Clearwater Power/AVISTA None Verizon Salmon Idaho Power None CenturyTel Samaria Rocky Mountain None ATC Samuels Northern Lights None Verizon Sanders Clearwater Power None Verizon Sandpoint AVISTA AVISTA Verizon Santa Clearwater Power None Verizon Shelley Rocky Mountain Intermountain Qwest Shoshone Idaho Power Intermountain Qwest Shoup None None Rural Silverton AVISTA AVISTA Verizon Smelterville AVISTA AVISTA Verizon Smiths Ferry Idaho Power None Citizens Soda Springs Soda Springs Muni Intermountain Qwest Southwick Clearwater Power None Potlatch Spalding AVISTA/Clearwater Power None Qwest Spencer Rocky Mountain None Mud Lake Co-op Spirit Lake AVISTA/Kootenai None Verizon Springston AVISTA/Kootenai None Verizon IPUC Annual Report 2009 70 | P a g e City Electric Gas Tele Springfield Idaho Power None Citizens Stanley Salmon River Coop None Midvale Star Idaho Power None Qwest Starkey Idaho Power None Qwest State Line AVISTA/Kootenai AVISTA Verizon Sterling Idaho Power None Citizens Stibnite Idaho Power None (Radio Phone) Stites AVISTA None Qwest Stone Rocky Mountain None ATC Sublett Raft River Coop None ATC Sugar City RMP/Fall River Coop Intermountain Qwest Sunbeam Salmon River Coop None Custer Co-op Sun Valley Idaho Power Intermountain Qwest Swanlake Rocky Mountain None Qwest Swan Valley Lower Valley Power None Silver Star Sweet Idaho Power None Citizens Tamarack Idaho Power None Citizens Tendoy Idaho Power None CenturyTel Tensed Clearwater Power None Verizon Terreton Rocky Mountain None Mud Lake Co-op Teton RMP/Fall River Coop None Fairpoint Tetonia Fall River Coop None Silver Star Thatcher Rocky Mountain None Qwest Thornton RMP/Fall River Coop Intermountain Qwest Three Creek Idaho Power None Rural Triangle Idaho Power None Rural Triumph Idaho Power None None Troy Clearwater Power/AVISTA AVISTA Potlatch Tuttle Idaho Power None Qwest Twin Falls Idaho Power Intermountain Qwest Tyhee Idaho Power None Qwest Ucon Rocky Mountain Intermountain Qwest Victor Fall River Coop None Silver Star Viola Clearwater Power/AVISTA None Verizon Virginia Rocky Mountain None Qwest Waha Clearwater Power/AVISTA None Qwest Wallace AVISTA AVISTA Verizon Wapello Idaho Power None Qwest Wardner AVISTA AVISTA Verizon Warm Lake Idaho Power None Midvale Warm River Fall River Coop. None Fairpoint Warren Idaho Power None Midvale Wayan Lower Valley Power None Silver Star Weippe Clearwater Power/AVISTA None Verizon Weiser Weiser Water & Light Dept. Intermountain Qwest Wendell Idaho Power Intermountain Qwest Westmond Northern Lights None Verizon Weston Rocky Mountain None Qwest White Bird Idaho Co. Light None Citizens Whitney Rocky Mountain None Qwest Wilder Idaho Power Intermountain Citizens Winchester AVISTA/Clearwater Power None Qwest IPUC Annual Report 2009 71 | P a g e City Electric Gas Tele Woodland AVISTA None Qwest Worley AVISTA/Kootenai None Verizon Yellow Pine Idaho Power None Midvale