HomeMy WebLinkAbout2011annualreport.pdf
December 1, 2011
The Honorable C.L. “Butch” Otter
Governor of Idaho
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 2011 Annual Report. This report is a
detailed description of the most significant cases, decisions and other activities
during 2011. The financial report on Page 8 is a summary of the commission’s
budget through the conclusion of Fiscal Year 2011, which ended June 30, 2011.
It has been a privilege and honor serving the people of Idaho this past year.
Sincerely,
Paul Kjellander
President
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This report and all the links inside can be accessed online from the Commission’s
Website at www.puc.idaho.gov. Click on “File Room,” in the upper-left-hand-
corner and then on “ IPUC 2011 Annual Report.”
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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
Joe.leckie@puc.idaho.gov
Executive Assistant/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 2011 calendar year. (The financial report on Page 8 covers
Fiscal Year July 1, 2010 through June 30, 2011.)
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.
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The Commissioners
Paul Kjellander
Commissioner Kjellander rejoined the Idaho Public Utilities Commission
in April 2011 following his service as administrator of the Office of Energy
Resources (OER). Kjellander replaced former Commission Chairman Jim
Kempton who elected not to seek re‐appointment. Kjellander, who was
elected president of the commission in April 2011, was appointed to his
current six‐year term by Idaho Governor C.L. “Butch” Otter.
Kjellander previously served on the Commission from January 1999 until
October 2007. In 2007, Governor Otter appointed Kjellander to head up the
newly created OER. During his 3.5 years at OER, Kjellander created an aggressive energy
efficiency program funded through the federal American Recovery and Reinvestment Act.
Kjellander was also elected to serve as a board member on the National Association of State
Energy Officials.
Kjellander, a Republican, was elected to three terms (1994‐1999) in the Idaho House of
Representatives, where he served as a member of the House State Affairs, Judiciary and Rules,
Ways and Means, Local Government and Transportation committees. During his last term in
office, Kjellander was elected House Majority Caucus Chairman. His legislative service includes
membership on the Legislature’s Information Technology Advisory Council and the
House/Senate Joint Committee on Technology. He also served as co‐chairman of the Legislative
Task Force on the Federal Telecommunications Act of 1996 and vice chairman of the Council of
State Governments‐West “Smart States Committee.” His interim legislative committee
assignments included the Optional Forms of County Government Committee, Capital Crimes
Committee and the Private Property Rights Committee.
Kjellander has also served as director of the Distance Learning Program at Boise State
University’s College of Applied Technology and head of broadcast technology. At the BSU Radio
Network he was station manager, director of the Special Projects Unit and director of News and
Public Affairs.
Kjellander’s undergraduate degrees from Muskingum College, Ohio, are in communications,
psychology and art. He has a master’s degree in telecommunications from Ohio University.
As a member of the National Association of Regulatory Commissioners (NARUC), Kjellander
has served on the Telecommunications, Consumer Affairs, and Electricity committees. He was
also appointed by the chairman of the Federal Communication Commission to the
Federal/State Board of Jurisdictional Separations and served as chairman. He is currently
serving as a NARUC representative to the North American Numbering Council (NANC).
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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 vice chair of the Western Electricity Coordinating
Council (WECC) Board of Directors, chairs the WECC Compliance Committee
and is a member of the Scenario Planning Steering Group for the Regional
Transmission Expansion Planning Project. She represents Idaho on the Western
Interconnection Regional Advisory Body and the State‐Provincial Steering Committee.
Smith is a past president of the National Association of Regulatory Utility Commissioners
(NARUC), serves on the NARUC Board and is a member and past chair of NARUC’s Electricity
Committee. She is also state co‐chair of the Steering Committee of the Northern Tier
Transmission Group. She chaired the Western Interstate Energy Board’s Committee for
Regional Electric Power Cooperation from October 1999 to October 2005. She is a member of
the National Council on Electricity Policy Steering 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.
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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 1991, Redford was retained by TransManche Link, 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 the Boise law firm of Elam & Burke in
2001.
Since his appointment, Commissioner Redford has become active in the National Association
of Regulatory Commissioners (NARUC) where he serves on the International Relations and
Water committees as well as the Subcommittee of Nuclear Issues‐Waste Disposal.
Commissioner Redford and his wife, Nancy, are the parents of two children.
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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 April 1, 2011
Paul Kjellander April 3, 2011 Now serving
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Financial Summary
FISCAL YEARS 2007 ‐ 2011
Description FY2007 FY2008 FY2009 FY2010 FY2011
Personnel Costs $3,467,401 $3,898,109 $4,072,505 $3,939,023 $3,996,943
Travel $146,491 $181,275 $136,859 $127,352 $145,593
Consultants $13,949 $16,041 $0.00 $3,498 $0.00
Subscriptions $28,321 $27,036 $22,883 $28,355 $27,363
Emp. Training $28,827 $33,190 $21,396 $17,079 $29,227
Postage $8,027 $7,174 $8,338 $8,019 $8,536
Telephone $28,007 $27,335 $27,910 $22,454 $20,876
Office Supplies $12,824 $17,697 $14,679 $15,307 $14,032
Office Rent $355,643 $236,497 $236,704 $252,906 $283,959
Maintenance $14,223 $15,817 $10,290 $15,694 $7,409
Insurance $2,702 $5,976 $6,380 $3,732 $1,286
Office Equip. $8,690 $5,279 $1,095 $2,973 $34,368
Computer Equip. $26,809 $15,934 $4,262 $3,185 $0.00
Commissioner Equip. $0.00 $0.00 $22,052 $0.00 $0.00
Other Equip. $0.00 $0.00 $0.00 $0.00 $0.00
Other Expenses $113,671 $122,130 $102,775 $92,913 $116,094
=========================================================================
Total
Expenditures $4,255,596 $4,609,484 $4,688,128 $4,531,990 $4,685,686
Appropriations $4,545,300 $4,944,400 $5,236,800 $5,266,100 $5,142,600
‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐
Unexpended
Balance $289,704 $334,916 $548,672 $734,110 $456,914
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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.
The IPUC has quasi‐legislative and quasi‐judicial as well as executive powers and duties.
Why can’t you 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 nearly 100 years, public utility regulation has been based
on the regulatory compact between utilities and regulators:
Regulated utilities agree to invest in the generation, transmission
and distribution necessary to adequately and reliably serve all
the customers in their assigned territories. In return for that
promise to serve, utilities are guaranteed recovery of their
prudently incurred expense along with an opportunity to earn a
reasonable rate of return.
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 be able 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 are statutorily required to 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 staff determines that the
added expense incurred by utilities was prudently incurred and
necessary to serve customers, the commission has no choice but
to allow the utility to recover that expense. The commission can
and often does deny the utilities recovery of some expense if it is
confident it has the legal justification to do so. All Commission
decisions can be appealed to the state Supreme Court.
In the end, 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.
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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.
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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 Joe Leckie, 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.)
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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 of 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 Rick Sterling, engineering section supervisor, at 334‐0351.)
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.)
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
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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 Joe Leckie, 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. 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 Joe Leckie, pipeline safety program supervisor, at 334‐0331.)
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Electrical Power in Idaho
Idaho residents consistently enjoy some of the least expensive electric service in the nation. According
to data compiled by the Energy Information Administration, Idaho ranked 51st of the 50 states and
District of Columbia in electricity rates during 2010. http://www.eia.gov/state/state‐energy‐
rankings.cfm?keyid=18&orderid=1
Idaho Power Company
2010 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
394,132 Residential Customers/$0.0808
76,563 Commercial Customers/$0.0620
118 Industrial Customers/$0.0447
Avista Utilities
2010 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
105,286 Residential Customers/$0.0854
16,573 Commercial Customers/$0.0836
476 Industrial Customers/$0.0530
2010 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
PacifiCorp/Rocky Mountain Power
56,842 Residential Customers/$0.0872
8,394 Commercial Customers/$0.0719
5,537 Industrial Customers/$0.0523
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Summary of major electric rate cases
Three rate changes result in net decrease for Idaho Power customers
Customers of Idaho Power Company will be paying slightly lower rates beginning June 1. Three
rate adjustments result in a net average decrease of 3 percent for all customer classes and
about 1.45 percent for the company’s largest class, residential customers.
The biggest reason for the overall rate decrease is the annual Power Cost Adjustment, which is
an average 4.8 percent decrease for all customers (3.6 percent for residential customers). Two
other adjustments, the annual Fixed Cost Adjustment (FCA) and a pension fund expense
recovery announced May 19 are slight increases.
Power Cost Adjustment
Case No. IPC‐E‐11‐06, Order No. 32250
The PCA tracks Idaho Power’s annual power supply expense, which varies every year depending
on water supply, fuel costs and market prices for power. The PCA is calculated, in part, by a
forecast of the coming year’s power supply costs. A second component of the calculation is a
“true‐up” of the preceding year’s revenue forecast with actual power supply costs. The true‐up
ensures that customers aren’t paying more or less than the company’s actual power supply
costs. Idaho Power’s 2010‐11 power supply expenses are $40.4 million less than the amount
currently collected in the PCA account. As a result, the commission granted the company’s
request to reduce the annual PCA surcharge an average 4.8 percent.
Every year on June 1, the Power Cost Adjustment (PCA) results in either a one‐year surcharge or
credit to customers depending on the previous year’s power supply costs. When snowpack and
streamflows are normal or better, Idaho Power can generate more power from its hydroelectric
projects. Hydro generation is less expensive for the company than generating from thermal
sources or buying power from the regional market, which Idaho Power does during low‐water
years. When that happens, customers typically get a one‐year increase or surcharge.
Also included in this year’s power supply expense account is $10 million in Energy Efficiency
Rider expense.
Fixed Cost Adjustment
IPC‐E‐11‐03, Order No. 32251
The commission approved an average 0.74 percent increase to residential and small‐business
customers in this fourth year of Idaho Power’s pilot Fixed Cost Adjustment program. Other
customer classes are not impacted.
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The FCA, implemented in 2007, allows Idaho Power to recover the fixed costs it loses when
conservation programs result in lower power sales. However, the commission capped the
increase in any single year at no more than 3 percent.
Without a mechanism like the FCA, there is a financial disincentive for Idaho Power to promote
energy efficiency and conservation because it loses revenue when conservation results in
power sales declining. Sometimes referred to as “decoupling” in the utility industry, the FCA
decouples or separates Idaho Power’s fixed costs from its energy sales, assuring the utility will
be able to recover its fixed costs as established in the most recent rate case regardless of how
much energy customers save. If the company under collects its fixed costs of serving customers,
customers get a surcharge. Conversely, if the company over collects fixed costs, customers
receive a credit, as they did in the first year of the program. The commission capped the
percentage increase that could be collected from residential and small‐business customers at
no more than 3 percent.
This year, Idaho Power under‐collected $7.9 million in fixed costs from the residential class and
$1.4 million from the small‐business class.
When the commission initially approved the program, it did so as a three‐year pilot. The
commission denied Idaho Power’s 2009 request to make the program permanent until more
questions about the program are resolved. However, the commission did agree to extend the
pilot program another two years.
Pension plan recovery
IPC‐E‐11‐04, Order No. 32248
As announced on May 19, the commission granted Idaho Power authority to increase its
contribution to its pension plan from $5.4 million annually to $17.1 million and spread the
increase over three years, resulting in a 1.39 percent increase for all customer classes.
__________________________________________________________________________________________
Case No. IPC‐E‐11‐08, Order No. 32426
December 30, 2011
Idaho Power increase is a net 3.44 percent
Base electric rates for customers of Idaho Power Company increase by 4.2 percent on Jan. 1,
2012. Part of that 4.2 percent is an increase in the monthly customer service charge from $4 to
$5. However, there is also a 0.75 percent decrease to the energy efficiency rider, resulting in a
net average increase of 3.44 percent.
The commission’s order approves a negotiated settlement between the utility, commission
staff and customer groups representing all major customer classes.
In June, Idaho Power asked for an average 10 percent increase. The original application asked
for an $81 million increase to annual revenue in light of more than $450 million the company
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invested in infrastructure since its last rate case in 2008. The
settlement allows a $34 million increase to annual revenue.
Most of the reduction in revenue requirement was achieved
by shifting $24 million in expense related to small‐power projects to the Power Cost
Adjustment mechanism made every June 1. Nearly $300,000 in expense related to turbine
inspection was deferred and amortized over four years and about $436,000 for a Light
Detection and Ranging survey was deferred and amortized over 10 years.
The revenue adjustments “reduce the magnitude of the proposed rate increases and benefit all
customer classes,” the commission said. “In particular, we note that the settlement stipulation
represents a significant reduction – almost 60 percent – in the company’s initially proposed rate
increase.” Randy Lobb of commission staff stated the settlement resulted in a “better outcome
for customers than could reasonably be anticipated through litigation.”
Idaho Power was allowed a 7.86 percent rate of return on its Idaho jurisdictional rate base of
$2.35 billion. It requested 8.17 percent.
Parties to the settlement also agreed that there would be no increase in the winter for energy
consumption within the third tier, which is above 2,000 kilowatt‐hours per month. The
commission said maintaining the third block non‐summer rate of 8.46 cents per kWh will
moderate the impact on customers who heat their homes with electricity. Rural Idaho
customers who do not live near natural gas pipelines have few options to control winter use.
The commission conducted two customer workshops before the settlement and three public
hearings and a technical hearing after the settlement was proposed. More than 100 customers
submitted written comments, all opposed to the rate increase citing the weakened economy
and adverse impacts on residential customers with low and fixed incomes.
Participants in the settlement representing primarily residential customers included
commission staff and the Community Action Partnership Association of Idaho (CAPAI). Other
participants included the Idaho Irrigation Pumpers Association, the Industrial Customers of
Idaho Power, the Department of Energy, Micron Technology, the Idaho Conservation League,
the Snake River Alliance, the Northwest Energy Coalition and Hoku Materials.
CAPAI did not sign the settlement mainly because Idaho Power has not agreed to increase its
funding for a low‐income weatherization program. CAPAI asked that the company increase its
funding for the program by 125 percent, from $1.2 million to $2.7 million. The commission
declined, stating concerns about cost‐effectiveness. “Because ratepayers fund Idaho Power’s
weatherization programs, we have a responsibility to ensure these programs are cost‐effective
and designed to maximize benefits for all customers,” the commission said. The commission
will open a case and convene public workshops to determine the best methods for establishing
the level of investment in low‐income weatherization.
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The commission deferred decisions about other issues on which the parties could not agree,
including whether the Fixed Cost Adjustment rider on customer bills should become
permanent. A final decision on the FCA will be made by March 30, 2012. The commission also
did not decide whether overhead amounts for line extensions for customers requesting new
service should be increased.
The energy efficiency rider, which is reduced from 4.75 percent of customer’s billed rate to 4
percent, funds a number of conservation programs that reduce the need for Idaho Power to
acquire additional generation or buy power from other providers. All of the programs funded
by the rider must pass three cost‐effectiveness tests that demonstrate customer rates would be
higher without the programs in place. Because $11.2 million of those programs are being
shifted into base rates, parties argued the rider should be decreased to as low as 3.4 percent.
Others, including the Idaho Conservation League, Snake River Alliance and Northwest Energy
Coalition, said the rider should remain at 4.75 percent because Idaho Power is still directed to
continue to pursue all cost‐effective energy efficiency and some “headroom” is needed to
provide for planned growth in conservation programs.
When it filed the rate case in June, Idaho Power said it made significant investment in pollution
control equipment in four units and upgraded a turbine in one unit of the Jim Bridger power
plant, a coal‐fired facility in southwest Wyoming. Idaho Power also completed construction of a
new 500‐kilovot Hemingway transmission station and the associated Hemingway to Bowmont
230‐kV transmission line at a total cost of $54 million. The company also completed
construction of the Long Valley Operations Center in Lake Ford to replace the existing McCall
Operations Center.
_____________________________________________________________________________________
Case No. IPC‐E‐10‐27, Order No. 32217
April 1, 2011
Contact: Gene Fadness (208) 334‐0339, 890‐2712
Website: www.puc.idaho.gov
Commission rejects conservation funding settlement
A settlement among a number of parties to approve an Idaho Power Company application to
shift about $20 million in expenses for conservation programs from the Energy Efficiency Rider
currently on customer bills to base rates and to the annual Power Cost Adjustment has been
rejected by state regulators.
The Idaho Public Utilities Commission said the issues raised in the settlement are more
appropriately addressed in a general rate case, which is anticipated to be filed later this year.
The commission also expressed concern that shifting some conservation program expense to
other areas may result in a cost allocation to some customer classes that is not equitable.
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Commission staff and conservation groups supported the settlement, while industrial
customers opposed it. The industrial customers said that while shifting conservation program
expenses from the 4.75 percent efficiency rider now paid by all customers to other areas may
stop further increases in the rider and perhaps reduce the rider amount, customers would end
up paying in other ways. The real impact, the industrial customers argued, would be the same
as increasing the rider to 6.6 percent.
Parties that supported the settlement included Idaho Power, commission staff, the Idaho
Conservation League, the Northwest Energy Coalition, the Snake River Alliance and the
Community Action Partnership Association of Idaho, which represents primarily residential
customers on lower and fixed incomes. A group representing irrigators did not oppose the
settlement, but still did not sign it.
Proponents of the settlement contended that moving some conservation program expenses to
base rates and some to the yearly Power Cost Adjustment puts conservation on the same level
as acquiring generation from traditional supply‐side resources such as coal and natural gas.
Including some of that expense in base rates encourages Idaho Power to continue to pursue
conservation programs by allowing it to earn a rate of return on some investment, proponents
argued.
Idaho Power operates a number of demand‐side management (DSM) programs that reduce
demand on the company’s generation needs during peak times of electrical use. The company
also has a number of energy efficiency programs that reduce energy consumption through the
use of more energy efficient lighting, appliances and industrial equipment. The cost of the
demand‐side and energy efficiency programs is recovered from customers through the Energy
Efficiency Rider on customer bills, now set at 4.75 percent.
However, the revenue raised from the Energy Efficiency Rider is not keeping up with the cost of
demand‐side and energy efficiency resources. If changes are not made, the negative balance in
the rider account will be $17 million by the end of this year and $30 million by the end of 2012.
To pay off that negative balance in one year and continue funding programs at their current
level, the rider would have to be increased from the current 4.75 percent to 7.5 percent of
customer bills. To recover the balance in two years, the rider would have to be increased to 6.6
percent. The proposed settlement would have reduced the negative balance in the rider
account to zero by early to mid‐2012 and could result later on in a reduction in the rider.
Commission staff favored the settlement, stating that increasing the rider is “attracting
unwarranted attention and criticism,” resulting in Idaho Power not getting timely recovery of
demand‐side costs needed to promote acquisition of cost‐effective conservation programs.
Parties to the settlement proposed that the expense of three major demand‐side programs,
including one for irrigators and one for residential customers with air conditioners, be shifted to
the annual Power Cost Adjustment. They proposed that expenses related to energy efficiency
programs for Idaho Power’s large commercial and industrial customers be capitalized and
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included in base rates. Doing so would allow the company to earn a rate of return on demand‐
side resources just as it does on supply‐side resources.
The commission decision to reject the settlement will not mean an increase to the rider at the
present time. Today’s order does allow Idaho Power to include $10 million of the $17 million in
the rider account be included in this year’s Power Cost Adjustment, which the company will file
on or about April 15. That $10 million has already been determined by the commission to be
prudently incurred expense. In order for conservation programs to be found prudent, they must
pass three tests showing that customers pay less for energy than they would if the programs
were not in place.
Despite its rejection of the settlement, the commission said it “recognizes and appreciates
Idaho Power’s commitment in recent years to improve its DSM programs …”
DSM programs reduced peak demand by 290 MW in 2009. That’s almost as much reduction as
the power that will be generated by the 330‐MW Langley Gulch natural gas plant being built
near New Plymouth. And energy efficiency programs saved 148,000 MWh in 2009, up from
19,000 MWh in 2004.
“Idaho Power has properly responded to the commission’s directive to pursue all cost‐effective
DSM programs, and the results have been significant and measurable,” the commission said.
______________________________________________________________________________
Case No. IPC‐E‐10‐20, Order No. 32162
January 24, 2011
Proceeds from emission allowances go to Idaho Power customers
About $490,000 of proceeds from Idaho Power Company’s sale of surplus emissions allowances
will be applied against customers’ annual Power Cost Adjustment this spring.
Consistent with prior orders, the company will share 95 percent of the proceeds from the sales
with customers and 5 percent with shareholders. The PCA is a yearly adjustment to rates – up
or down – to account for the variable costs of power supply not already included in base rates.
The inclusion of the emissions proceeds in the PCA will either reduce the size of the increase
customers may get with the June 1 adjustment or increase the size of the credit customers may
receive.
The commission denied a request by the Idaho Energy Education Project (IEEP) that 8 percent
of the proceeds be used to continue funding a two‐year pilot project for energy education and
efficiency programs in public schools. The commission agreed with findings of the commission
staff that more funding directed toward the education project not be approved until the two‐
year pilot is completed this June. Further, the commission noted, almost $375,000 of the
original $500,000 allocated for the project is still available for use.
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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.
During 2010, Idaho Power sold 20,000 surplus allowances and reported net sales proceeds of
$543,000, after deducting brokerage fees of $5,000.
“By including the SO2 funds in the PCA mechanism, it will provide an immediate benefit to all
customers,” the commission said.
______________________________________________________________________________
Case No. IPC‐E‐10‐46, Order No. 32200
March 9, 2011
PUC approves changes to Idaho Power irrigation program
Some changes proposed by Idaho Power Company to a program that pays irrigators for shutting
down pumps during periods of heavy electrical demand have been accepted by state regulators
while others were denied.
Idaho Power’s Irrigation Peak Rewards Program offers incentive payments to irrigators who
volunteer to have their service interrupted during peak‐use periods from June 15 to August 15.
Volunteer irrigators can have their service interrupted up to a maximum of 60 hours per
irrigation season. In exchange, they receive a monthly incentive payment in the form of a bill
credit during the three summer months. If not for the program, growing customer demand
during the summer months would likely require the construction of natural gas peaker plants.
Idaho Power asked the commission to make a number of changes, chief among those splitting
the incentive payments into two portions: a fixed payment (40 percent) and a variable payment
(60 percent). The company said the change was needed to better align program costs with the
actual need for capacity reduction. Idaho Power doesn’t know in advance how many times
irrigators will be interrupted, yet the credit is the same regardless of the number of
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interruptions. During 2010, Idaho Power paid irrigators $11.5 million and interrupted service
three times.
The net effect of basing some of the credit (60 percent) on actual interruption would have been
to reduce the fixed portion of the credit from $32 per kW to $12.78 per kW, plus another
amount paid no more than 60 days after the end of the irrigation season that would be based
on actual interruptions.
After taking comments from irrigators, the Idaho Irrigation Pumpers Association, the Idaho
Conservation League and commission staff, the commission agreed to a 75/25 split with 25
percent based on actual interruption instead of the company’s proposed 60 percent. The result
is reduction in the fixed portion of the credit to $25 per kW.
The company’s original proposal could cause customers to drop out, reducing the program’s
effectiveness, the commission said.
The commission denied a request by the company to limit program participation based on the
company’s need for peak load reduction. The Idaho Irrigation Pumpers Association and
commission staff also opposed that change. Commission staff said the company should not only
accept participants, but should promote the program in order to achieve peak load reduction
over the long term.
______________________________________________________________________________
Case No. IPC‐E‐10‐27, Order No. 32217
April 1, 2011
Commission rejects conservation funding settlement
A settlement among a number of parties to approve an Idaho Power Company application to
shift about $20 million in expenses for conservation programs from the Energy Efficiency Rider
currently on customer bills to base rates and to the annual Power Cost Adjustment has been
rejected.
The commission said the issues raised in the settlement are more appropriately addressed in a
general rate case, which is anticipated to be filed later this year. The commission also expressed
concern that shifting some conservation program expense to other areas may result in a cost
allocation to some customer classes that is not equitable.
Commission staff and conservation groups supported the settlement, while industrial
customers opposed it. The industrial customers said that while shifting conservation program
expenses from the 4.75 percent efficiency rider now paid by all customers to other areas may
stop further increases in the rider and perhaps reduce the rider amount, customers would end
up paying in other ways. The real impact, the industrial customers argued, would be the same
as increasing the rider to 6.6 percent.
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Parties that supported the settlement included Idaho Power, commission staff, the Idaho
Conservation League, the Northwest Energy Coalition, the Snake River Alliance and the
Community Action Partnership Association of Idaho, which represents primarily residential
customers on lower and fixed incomes. A group representing irrigators did not oppose the
settlement, but still did not sign it.
Proponents of the settlement contended that moving some conservation program expenses to
base rates and some to the yearly Power Cost Adjustment puts conservation on the same level
as acquiring generation from traditional supply‐side resources such as coal and natural gas.
Including some of that expense in base rates encourages Idaho Power to continue to pursue
conservation programs by allowing it to earn a rate of return on some investment, proponents
argued.
Idaho Power operates a number of demand‐side management (DSM) programs that reduce
demand on the company’s generation needs during peak times of electrical use. The company
also has a number of energy efficiency programs that reduce energy consumption through the
use of more energy efficient lighting, appliances and industrial equipment. The cost of the
demand‐side and energy efficiency programs is recovered from customers through the Energy
Efficiency Rider on customer bills, now set at 4.75 percent.
However, the revenue raised from the Energy Efficiency Rider is not keeping up with the cost of
demand‐side and energy efficiency resources. If changes are not made, the negative balance in
the rider account will be $17 million by the end of this year and $30 million by the end of 2012.
To pay off that negative balance in one year and continue funding programs at their current
level, the rider would have to be increased from the current 4.75 percent to 7.5 percent of
customer bills. To recover the balance in two years, the rider would have to be increased to 6.6
percent. The proposed settlement would have reduced the negative balance in the rider
account to zero by early to mid‐2012 and could result later on in a reduction in the rider.
Commission staff favored the settlement, stating that increasing the rider is “attracting
unwarranted attention and criticism,” resulting in Idaho Power not getting timely recovery of
demand‐side costs needed to promote acquisition of cost‐effective conservation programs.
Parties proposed that the expense of three major demand‐side programs, including one for
irrigators and one for residential customers with air conditioners, be shifted to the annual
Power Cost Adjustment. They proposed that expenses related to energy efficiency programs for
Idaho Power’s large commercial and industrial customers be capitalized and included in base
rates. Doing so would allow the company to earn a rate of return on demand‐side resources
just as it does on supply‐side resources.
The commission decision to reject the settlement will not mean an increase to the rider at the
present time. Today’s order does allow Idaho Power to include $10 million of the $17 million in
the rider account be included in this year’s Power Cost Adjustment, which the company will file
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on or about April 15. That $10 million has already been determined by the commission to be
prudently incurred expense. In order for conservation programs to be found prudent, they must
pass three tests showing that customers pay less for energy than they would if the programs
were not in place.
Despite its rejection of the settlement, the commission said it “recognizes and appreciates
Idaho Power’s commitment in recent years to improve its DSM programs …”
DSM programs reduced peak demand by 290 MW in 2009. That’s almost as much reduction as
the power that will be generated by the 330‐MW Langley Gulch natural gas plant being built
near New Plymouth. And energy efficiency programs saved 148,000 MWh in 2009, up from
19,000 MWh in 2004.
“Idaho Power has properly responded to the commission’s directive to pursue all cost‐effective
DSM programs, and the results have been significant and measurable,” the commission said.
____________________________________________________________________________
Case No. IPC‐E‐11‐04, Order No. 32248
May 19, 2011
Idaho Power rates to increase slightly due to pension expense
State regulators are allowing Idaho Power Company to increase rates by an average 1.39
percent to recover the company’s cash contribution to its defined benefit pension plan. The
increase will be effective June 1, the same effective date for two other rate adjustments that
will likely result in an overall decrease in rates.
Idaho Power sought commission authority to increase its contribution to its pension plan from
$5.4 million annually to $17.1 million annually over three years in order to recover a $60 million
contribution Idaho Power made to its defined benefit pension plan. The company had to make
a contribution to its plan to satisfy requirements of the federal Employee Retirement Security
Act (ERISA).
While allowing the expense recovery, the commission continued to urge the company to
consider modifying its plan to one that would require shareholders and employees to
participate in a greater share of costs. “The commission remains concerned that Idaho Power’s
defined benefits pension plan places the burden solely on customers to pay all increased costs
of the plan,” the commission said. The commission, in a separate order, directed the Idaho
Power to annually review the company’s total employee compensation and benefits package
and compare it with those offered by other utilities.
The company had the option, under ERISA, to contribute a minimum requirement of $5.8
million, but making the larger contribution now saves the company and ratepayers about $11
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million. In addition, the large contribution now will result in another $1 million savings to the
variable portion of the company’s premiums.
Idaho Power’s contributions to its pension plan have always been included in base rates.
However, since 2003 the company was not required to contribute to the plan because the
market value of the plan’s assets was more than enough to cover future obligations. Recent
market conditions and increasing pension obligations require Idaho Power to start funding the
plan again.
_____________________________________________________________________________________
Case No. IPC‐E‐11‐22, Order No. 32424
December 28, 2011
Commission extends Idaho Power revenue sharing agreement
The commission approved an Idaho Power Company application that allows the company to
continue to accelerate tax benefits to bolster earnings and share a portion of those earnings
with customers.
Idaho Power receives income tax benefits based on the level of plant investment in previous
years. The accumulated deferred investment tax credits are typically spread over the book life
of the associated plant investment and used to reduce income tax expense included in
customer rates during that period. However, as part of the 2010‐11 moratorium on base rate
increases, Idaho Power and other parties approved a settlement that allowed the utility to
shore up its earnings by accelerating up to $45 million of investment tax credits at $15 million a
year for three years if its return on equity (ROE) falls below 9.5 percent. The settlement further
stated that Idaho Power would split 50‐50 with customers the portion of earnings 10.5 percent
or greater. The customer benefit would be in the form of rate reductions or an offset to
amounts that would otherwise be included in customer rates.
Up until the 2010 agreement, Idaho Power had not been able to earn its authorized rate of
return for the previous decade in both its Idaho and Oregon jurisdictions. While the exact
amount of the 2011 year‐end ROE isn’t known yet, it is above 10.5 percent, creating the sharing
opportunity. Without the one‐time tax benefits received in 2011, the 2011 ROE was
anticipated to be below 9.5 percent.
The agreement is a modification of the 2010 settlement that extends the ability of Idaho Power
to amortize the credit through Dec. 31, 2014 and make an adjustment to the sharing portion for
2011. That adjustment provides an additional benefit to customers for earnings above 10.5
percent. Seventy‐five percent of the company’s share of earnings above 10.5 percent will be
used to offset company pension expenses that would otherwise be included in customer rates.
That same provision would be included in the 2012‐2014 extension of the agreement. During
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2012‐2014, if ROE is between 10 and 10.5 percent, the customers’ 50‐50 share will be a
reduction applied at the same time as the annual Power Cost Adjustment (PCA) every June 1.
“The existing accounting order approved by the commission has benefitted customers, the
company and shareholders,” the commission said. “Rating agencies and shareholders generally
view the earnings stability provided by the past agreement as positive.”
The agreement will provide customers an estimated $15 million benefit they would not receive
and it reduces amounts that would otherwise be included in customer rates, the commission
said.
In addition to commission staff and the company, parties participating in the settlement
discussions were the Industrial Customers of Idaho Power and Micron Technology, Inc.
__________________________________________________________________________________________________________________
Case No. PAC‐E‐10‐07, Order No. 32196
March 1, 2011
Commission issues final order in Rocky Mountain Power rate case
The commission released its final order in a Rocky Mountain Power (RMP) rate case that began
in May 2010. In late December, the commission issued an interim order that established new
rates for all customer classes that became effective Jan. 1, 2011, but still had issues to resolve
regarding the utility’s largest customer, the Monsanto Company plant in Soda Springs.
The 68‐page order addresses the
Monsanto issues and provides the
findings to support the late December
decision to grant the company an
overall 6.78 percent increase in its annual revenue requirement, or $13.75 million. When the
company filed its application last May, it asked for a 13.7 percent increase, or $27.7 million.
After technical hearings, the company lowered its request to 12.3 percent or $24.9 million.
The 6.78 percent average increase is offset by a decision to reduce customers’ Energy Efficiency
Charge from 4.72 percent to 3.4 percent, resulting in a net average increase for residential
customers of about 5.5 percent. The net amount of actual increase varies by class of customer
and by usage. For example, with the new two‐tiered rate design approved by the commission in
this case, a residential customer using RMP’s average consumption of 839 kilowatt‐hours per
month will realize a 1.5 percent decrease. The two‐tiered rate structure increases rates as
consumption increases, with residents paying more after the first 700 kWhs of use in the
summer and after the first 1,000 kWh in the winter. The rates for the first tier are actually lower
than the company’s previous rates.
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From May to October, standard residential customers will pay 9.58 cents per kWh for their first
700 kWhs. The former May‐October rate was 10.4 cents. For use exceeding 700 kWhs during
summer, the new rate is 12.9 cents.
During the winter season (November through April) residential customers will pay 7.33 cents
per kWh for the first 1,000 kWhs. The former winter rate was 8 cents. For use above 1,000
kWhs, the rate is 9.9 cents.
Part of the average 6.8 percent annual increase in rates is a customer service charge that varies
according to customer class and is added to cover metering and billing expense. For most
residential customers that charge is $5. The company requested $12.
Many of the customer comments opposed RMP’s proposal to increase the standard residential
rate by 8 percent, while residential customers who are on the company’s Time of Day program
would pay 15.6 percent more. The commission determined to assign an equal percentage
increase for both residential customers of 6.78 percent.
The largest reductions the commission made in RMP’s request (addressed in detail later in this
press release) include 1) allocating $11.4 million in expense for the company’s irrigation load
control program to the utility’s entire six‐state system and not just to Idaho customers; 2)
reducing RMP’s requested allowable rate of return from 8.36 percent to 7.98 percent and its
requested Return on Equity from 10.6 percent to 9.9 percent; 3) allowing only 73 percent of the
company’s investment in the Populus to Terminal (Downey to Salt Lake City) transmission line
and putting the remaining 27 percent in plant held for future use; and 4) disallowing in rates all
wage increases awarded by the company to employees during 2009 and 2010 as well money for
the company’s Supplemental Executive Retirement Plan. Removing wage increases does not
necessarily mean employee increases will be withdrawn, but that the cost would not be paid by
customers.
“In making these adjustments we address concerns raised by parties and customers and
acknowledge the economic conditions and service requirements in the company’s southeastern
Idaho service territory,” the commission said. The commission conducted two workshops, four
public hearings, two technical hearings and a telephonic hearing. Nearly 100 people testified
and the commission also received more than 200 written comments.
Regarding RMP’s request for an increased rate of return and return on equity, the commission
order states:
“We find that RMP (Rocky Mountain Power) in this case downplayed the poor economic
conditions that exist in its Idaho service territory where many are on fixed incomes, unemployed
and underemployed. This commission cannot discount as simply anecdotal the testimony and
comments of RMP customers. While we cannot say ‘no’ to a requested increase in rates because
customers are uniform in their opposition, together their testimony serves as the real‐life context
and backdrop of our decision. Their testimonies and comments remind us that we are not
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engaged in simply an academic exercise dealing in regulatory principles, generalities and
industry averages. Our decision has real consequences.”
However, the commission said it also has statutory obligations to balance the interests of both
customers and company to ensure a financially healthy utility that can provide reliable service
and plan for future needs:
“We recognize that for some customers any increase may result in economic hardship. That
being said, we have a dual obligation in rate cases. To customers our task is to establish rates
that are fair and reasonable. To the company we have a statutory obligation to set rates at a
level sufficient to allow RMP to recover its reasonable expenses of operation and receive a
reasonable return on prudent capital investments in utility plant and facilities. Carrying out this
duty is necessary for the company to be financially sound and capable of providing its customers
with safe and reliable electric service.”
When the commission denies cost recovery to a utility, it must be able to legally demonstrate
why the utility’s costs were not prudently incurred or in the best interest of customers. All
commission decisions can be appealed to the state Supreme Court.
Rocky Mountain Power is a division of PacifiCorp, which operates in six states and is in the
midst of a multi‐year program of investing in renewable energy, transmission facilities and
environmental controls to serve the growing demands of its customers in Idaho and across its
system. The company claimed that its system‐wide expenses during 2009 include over $4 billion
of new plant investment and $87 million in increased power costs. Those expenses are then
allocated among the six states based on each state’s electrical load, which for Idaho is about 6
percent of PacifiCorp’s total system load. Expenses that cannot be demonstrated to benefit
Idaho customers are not included in the rates Idaho customers pay.
The case was extended for an additional technical hearing to consider changes to Monsanto
Company’s agreement with Rocky Mountain Power that allows the utility, under specified
circumstances, to curtail its power delivery to Monsanto to meet other customer needs.
Monsanto has a total load of 182 megawatts, but up to 173 MW can fall under the interruptible
portion of the agreement. The interruptibility provisions of the agreement are significant
because electric rates are a substantial portion of production costs at the elemental
phosphorous plant and also because Monsanto’s economic vitality has a large impact on the
economy of Soda Springs and the surrounding area.
The electric service agreement between Monsanto and RMP allows the utility to curtail electric
delivery to Monsanto under any of these three circumstances: 1) to allow the utility to meet
mandated reserve requirements, 2) for economic reasons – as when market prices for
electricity allow RMP to save money for itself and its customers – and 3) to interrupt for system
integrity to avoid outages. The agreement limits the number of megawatts that can be curtailed
and the number of hours that curtailment can happen for each of the three circumstances.
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RMP proposed significant reductions in the amount it said it would pay Monsanto for the
interruptions. Monsanto disputed the value the company placed on the interruption services. In
today’s order, the commission established values for each of the three interruptibility products
that are higher than those proposed by RMP but less than those proposed by Monsanto. The
actual numerical values are proprietary. The commission also encouraged the parties to craft an
agreement that establishes the value of the products for five years rather than three years. The
commission said the longer agreement would promote greater price certainty for Monsanto as
well as allow RMP to plan more effectively into the future.
The commission’s order also directs RMP to increase its annual funding for low‐income
weatherization in Idaho from $150,000 to $300,000 and to increase the dollar amount of RMP
funds available for each weatherization project from 75 percent to 85 percent of total eligible
costs. The commission noted there is a five‐year backlog of homes that need and are eligible for
weatherization in southeastern Idaho.
Below is a more detailed summary of the commission’s finding on some of the major issues in
this case:
Irrigation load control program costs
The Idaho Irrigation Load Control program pays credits to irrigation customers who agree to have their service
curtailed during times of peak demand. In 2007, the program provided 78 megawatts to the company, but by 2009
that had grown 250 percent to provide 276 megawatts of demand reduction for the company. The nearly $20
million in savings benefits PacifiCorp customers in all six states and, therefore, the $11.4 million cost of the
program should be allocated system‐wide and not just to Idaho customers, the commission ruled. Doing that
removes $3.25 million in Idaho annual revenue requirement for RMP and also allows a reduction to the Energy
Services Rider paid by customers from 4.72 percent to 3.4 percent.
“We find that it is unreasonable to expect Idaho customers to continue to bear the costs associated with the
current jurisdictional treatment of the Irrigation Load Control Program expenses,” the commission said.
Rate of return, return on equity
The rate of return is the amount the company is allowed the opportunity to earn on its capital investment. The
company requested 8.357 percent and was granted 7.98 percent. The return on equity is the rate of return equity
investors expect given the risks of an individual security and consistent with returns that are available from similar
investments. The company requested 10.6 percent and was granted 9.9 percent. Setting the allowable rate of
return and return on equity is not a guarantee the company will reach those levels, but caps the returns at the
commission’s authorized level.
The commission uses three primary standards in determining rate of return. The authorized return should be 1)
sufficient to maintain financial integrity, 2) attract capital under reasonable terms and 3) be commensurate with
returns investors could earn by investing in other enterprise of comparable risk. The rate of return must be enough
to attract capital investment in new transmission, distribution and generation but not so high as to be
unreasonable for customers.
The commission cited current economic conditions in southeastern Idaho as a primary factor in reducing the
company’s requested return on equity to 9.9 percent.
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Populus to Terminal Transmission Line
The line, which runs from Downey to Salt Lake City, is the first of eight proposed new high‐voltage transmission
segments that will make up PacifiCorp’s Energy Gateway transmission expansion project. The line benefits Idaho
customers in that it is intended to add 1,400 MW of transmission capacity to an already heavily constrained area
and allows the company access to less costly generation sources.
However, the commission ruled that because the company can use only about 1,040 MW of the total capacity,
Idaho’s portion of the full cost should not be included in rates until the entire 1,400 MW is available to customers.
Therefore, the commission placed 27 percent of the transmission investment into Plant Held for Future Use.
“Idaho, we find, will pay its fair share to meet the company’s system load and transmission requirements but we
will not allow full ratebasing of investment in Populus to Terminal prematurely and we will not require Idaho
customers to assume and pay for unused capacity.”
Wages and pensions
Wage increases awarded employees in 2009 and 2010 cannot be included in rates, reducing revenue requirement
by almost $1 million. The commission’s order states:
“The Commission finds that in tough economic times the local economy in the Company’s service area is a
greater indicator as to the appropriateness of a wage increase than market data and industry averages.
We find no demonstration by the Company that the union and non‐union wage increases were required
for the Company to be a competitive employer able to retain or attract employees. We find no offer of
proof that without the union and non‐union wage increase the service provided by the Company would be
degraded and safety compromised. We find that as a certificated provider of service RMP has elected to
be a member of the communities it serves.”
The commission also disallowed recovery of costs related to RMP’s Supplemental Executive Retirement Plan. “The
company has not demonstrated that these costs are related to providing services to southeast Idaho,” the
commission said. “The responsibility for generous severance benefits for executives, we find, is the responsibility
of the company and its shareholders, not Idaho customers.”
Intervenors in the case who provided testimony and rebuttal and cross‐examined witnesses during technical
hearings included Monsanto Company, the Idaho Irrigation Pumpers Association, the Idaho Conservation League,
PacifiCorp Idaho Industrial Customers, the Community Action Partnership Association of Idaho and commission
staff.
_____________________________________________________________________________________
Case No. PAC‐E‐11‐07, Order No. 32216
March 31, 2011
Yearly adjustment results in 5.8 percent increase in RMP surcharge
A one‐year surcharge on the bills of Rocky Mountain Power customers will be set at an average
5.8 percent. The average increase to standard residential customers is 5.2 percent.
Rocky Mountain Power originally sought an average 7.4 percent surcharge to pay off a deferral
account that had accumulated to $12.8 million. The commission approved a recovery of $10.4
million, electing to postpone recovery of about $2.4 million until next year.
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The surcharge, which is effective April 1 and expires next March 31, allows Rocky Mountain
Power to pay off deferred power supply costs that vary from year to year and are not included
in base rates. These include expenses that change from day to day such as those for coal,
natural gas and electricity from the wholesale market. None of the money collected in the
surcharge can be used to increase company earnings, but goes directly toward paying off
deferred and unanticipated power supply expense. During years that market prices for power
supply are less than what is included in base rates, customers would receive a one‐year credit.
To encourage the company to be prudent in its power supply purchase decisions, the
commission requires that shareholders pay 10 percent of the power supply expenses not
already included in rates.
The surcharge is called an Energy Cost Adjustment Mechanism, or ECAM. The surcharge or
credit will be made April 1 of every year. The commission instituted the mechanism in 2009 as a
way to more closely match customer rates with the actual cost of providing service. Doing so
reduces the frequency and size of general rate case filings. It also helps to keep financing costs,
which are ultimately paid by customers, at lower levels.
That $2.4 million the commission elected to postpone to next year is about one‐half of a load‐
growth adjustment rate that makes up part of the ECAM. Because the commission recently
modified the portion of the ECAM that accounts for increases or declines in load growth, it
anticipates a lower load growth adjustment next year which should contribute to a less of an
increase in the overall ECAM next year. Further, the commission said, spreading some of the
ECAM deferral over two years helps to mitigate the impact of a rate increase customers
received just three months ago.
______________________________________________________________________________
Case No. PAC‐E‐10‐07, Order No. 32224
April 19, 2011
Commission denies most of Rocky Mountain Power petition
The commission denied nearly all Rocky Mountain Power’s petition that it reconsider the
decision it made Feb. 28 to grant it an average 6.8 percent rate increase. The commission did
grant a small portion of Rocky Mountain’s petition which increases average base rates by just
under three‐tenths of 1 percent, from 6.8 percent to 7.07 percent. The approximate 0.3
percent adjustment will be applied to rates April 25. When Rocky Mountain Power originally
filed its request last May, it sought a 13.7 percent increase, but later adjusted its request to
12.3 percent.
The commission denied Rocky Mountain Power reconsideration on its earlier decisions to:
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• Place 27 percent of the cost for the new Populus to Terminal transmission line in
eastern Idaho in an account called Plant Held for Future Use;
• Not allow carrying charges on that 27 percent;
• Not allow wage increases incurred during 2009;
• Establish a rate of return of 9.9 percent rather than the 10.6 percent sought by the
company.
The commission granted reconsideration in the following areas:
• Allow $95,597 of the total $993,515 disallowed in wage and salary increases. The
$95,597 allowed is a portion of 2008 annualized labor expense;
• Allow $1.082 million to be included of the total $34.2 million denied for wind integration
expense due to a calculation error.
Other minor adjustments, including those above, resulted in a new annual revenue
requirement of $14.35 million. The revenue requirement previously approved by the
commission was $13.75 million. The company originally requested $27.7 million.
The commission also clarified its intent regarding the value of the credits awarded Monsanto
Company for agreeing to have its electrical service interrupted during peak load times. The
commission said the value of the credits can be changed when the company’s overall demand
and energy charges change as the result of a rate case and that the credit applies only to 162
MW of Monsanto’s billing demand and not on the entire load.
The commission decided to address later the question of whether an order that directs Rocky
Mountain Power to commit $50,000 for low‐income conservation education is a one‐time
commitment or an annual expense. The commission said the issue can be taken up in the
company’s next general rate case which is expected to be filed in late May.
Regarding its overall decision in this case, the commission said it “strongly disagrees” with
Rocky Mountain’s assertion that the commission based its decision on public perception and
allowed the ratemaking proceeding to become a political referendum. The commission said its
decision was based on evidence in the record presented at hearings.
Rocky Mountain Power claims the new Populus transmission line that begins near Downey and
extends into the Salt Lake City area benefits customers even if it not yet entirely utilized
because it increases system reliability and transfer capability. It also allows the company to use
the line to import lower‐cost market energy and to sell excess energy off system, Rocky
Mountain claims. Rocky Mountain asked that if the entire cost of the line isn’t included in
customer rates that it be allowed a carrying charge on the portion placed in Plant Held for
Future Use.
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The commission denied both requests, noting that state statute (Idaho Code § 61‐502A)
prohibits the commission from granting utilities a rate of return on Property Held for Future
Use that is not used and useful in providing service to customers. “This statute is clear and
unambiguous,” the commission said.
“Contrary to the company’s argument, the commission has not denied recovery of a full portion
of the investment made in the transmission line,” the commission said. “Recovery has simply
been deferred until such time as the transmission line is fully utilized and available to the
benefit of Idaho ratepayers.” The commission did, however, clarify that no depreciation of the
investment will occur on the portion of transmission expense held for future use.
Regarding pay increases, Rocky Mountain Power argued that the state of Idaho awarded its
employees a 3 percent increase in 2009, citing that as evidence that the company’s base wage
increases were reasonable. Commission staff asserted that only 3 percent of all state
employees received increases during 2009 and that Gov. Butch Otter ordered state agencies to
reduce payroll costs by 5 percent during that year. “The commission finds that Rocky Mountain
Power has failed to present any evidence which would compel us to revisit the issue of wage
increases. Instead, the company has made spurious and false assertions regarding alleged wage
increases received by state of Idaho employees during 2009,” the commission said.
The company argued that just as expense to integrate wind into its transmission expense ($6.50
per megawatt‐hour) is allowed for PURPA projects, it should also be allowed for company‐
owned wind plants. The commission said Rocky Mountain failed to adequately prove its actual
wind integration expense. The $6.50 per MWh allowed for non‐company owned wind projects
does not mean the expense is the same for company‐owned projects, the commission said.
Rocky Mountain also asserted that the 9.9 percent return on equity (ROE) allowed by the
commission is erroneous because it invents a new standard of “poor economic conditions.”
The commission disagreed, stating the ROE is based on “expert testimony and exhibits available
in the case record.” The U.S. and state constitutions grant the commission a “broad range of
reasonableness” in establishing rates of return, the commission said, noting that the 9.9
percent ROE was within the range proposed by staff and Monsanto.
______________________________________________________________________________
Case No. PAC‐E‐11‐06, Order No. 32235
May 3, 2011
Parties settle on changes to irrigation load control program
The commission accepted a settlement proposed by Rocky Mountain Power, eastern Idaho
irrigators and commission staff that will result in less drastic changes to the company’s
irrigation load control program than those originally proposed by the company.
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Rocky Mountain Power’s Dispatchable Irrigation Load Control program, in place since 2007,
allows the utility, during periods of peak demand, to turn off the pumps of irrigators who
volunteer to participate. In exchange, irrigators received a credit of $30 per kilowatt. Pumps can
be turned off for periods of time during June through August from 11 a.m. to 7 p.m. as long as
the utility provides prior‐day notification and as long as total curtailment for any participant
does not exceed 52 hours.
On Jan. 20, Rocky Power filed an application to change the program because of voltage
problems created by rapidly expanding participation in the program. When the program began
in 2007, participating load totaled 65 megawatts, but that increased to 278 MW in 2010. The
company claimed that much curtailment was creating voltage control problems with circuits at
four substations experiencing unacceptable increases. To respond, Rocky Mountain wanted to
reject prospective program participants and reduce the credit irrigators receive from $30 per
kW to $25.30. The company also proposed to modify the penalty irrigators receive for opting
out of scheduled curtailments.
Irrigation customers as well as commission staff objected to some of the proposed changes. A
negotiated settlement by commission staff, the Idaho Irrigation Pumpers Association and the
company will allow the utility to limit program participation to 232 MW for the next two years,
or an 18 percent reduction. Further, the $30 per kW credit to each irrigator will be reduced by
$1.45 for this season only to account for 11 MW of unobtainable curtailment due to the voltage
issues at four substations. In the meantime, the company agreed to invest a minimum of $1.3
million in capital improvements to install equipment needed to address the issues at the four
substations before the start of the 2012 irrigation season.
During the two‐year period of this settlement, new participants or additional load reduction
from existing participants will not be accepted. Volunteer irrigators can decline to participate in
some of the curtailments, but the credit they are paid by the company is reduced for each
curtailment incident for which the irrigator decides to opt out.
The Idaho Conservation League also participated in the settlement discussions. It did not sign
the settlement but does not oppose it.
_____________________________________________________________________________
Case Nos. AVU‐E‐11‐01, Order No. 32371
September 30, 2011
Rate case settlement results in decrease to customers
The commission granted Avista Utilities a base rate electric increase of about 1.1 percent and a
base rate gas increase of 1.6 percent. However, due to decreases in other rate components,
billed rates for customers actually decreased effective Oct. 1.
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The overall rate decrease to electric customers is an average 2.4 percent for all customer
classes (2.1 percent to residential class) and an average 0.8
percent to gas customers (0.5 percent to residential class).
While permanent base electric rates increase, the annual
Power Cost Adjustment – which varies every year depending
on water and market conditions – is a decrease of about 6 percent. Ratepayers also benefit
from an increase in a credit given residential and small‐farm customers from the Bonneville
Power Administration.
On the gas side, customers are getting an increase to both base rates and the annual Purchased
Gas Cost Adjustment, but they are getting a more substantial decrease due to the reduction in
an efficiency rider used to fund to conservation programs.
An electric residential customer using the company’s average of 956 kilowatt‐hours a month
will see a $1.79 per month decrease for a revised monthly bill of $82.02. The overall electric
rate decreases from the current 7.9 cents per kWh for the first 600 kWhs of use to 7.68 cents
per kWh. For use above 600 kWh, the billed rate decreases from the current 8.8 cents 8.6 cents
per kWh.
A residential natural gas customer using an average of 62 therms would see a 20‐cent per
month decrease for a revised monthly bill of $60.96. The billed rate decreases from the current
91.5 cents per therm to 90.7 cents per therm.
Part of the base electric and gas rate increase include an increase in the monthly customer
service charge from $5 to $5.25 per month for electric customers and from $4 to $4.25 per
month for natural gas customers.
In the base rate electric case, Avista is granted a $2.8 million increase in annual revenue. When
Avista filed the case in July it asked for a $9 million increase in annual revenue. Avista sought a
$1.9 million increase in gas revenue and is granted $1.1 million.
The commission approved a negotiated settlement between the utility, commission staff and
other parties representing industrial customers, the Idaho Conservation League and the
Community Action Partnership Association of Idaho, the latter representing primarily
customers on low‐ and fixed‐incomes.
A key part of the settlement is that Avista agrees to not collect another base electric or gas rate
increase before April 1, 2013. (This does not include yearly tracker adjustments such as the
Power Cost Adjustment or Purchased Gas Cost Adjustment and energy efficiency rider
adjustments.)
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The commission said it appreciated the “diligent work” by all the parties to resolve the issues in
the case. “We note that the stipulation and settlement represents a significant reduction in the
requested revenue increase,” the commission said. The company was granted only 31 percent
of its original electric rate increase request and 58 percent of its original gas increase request.
Further, the commission said, the provision in the settlement to not implement new base rates
before April 1, 2013 “provides an extended period of rate stability that otherwise might not
occur.”
The agreement also provides an additional $10,000 in funding for outreach to low‐income
customers on conservation measures, bringing the total annual funding for that program to
$50,000. This is in addition to the $700,000 already made available for low‐income
weatherization projects.
The parties to the settlement are also directed to participate in workshops to address updating
the cost of service to each customer class, rate design and low‐income programs.
ELECTRIC ADJUSTMENTS include two increases and two decreases, for a net overall rate decrease of 2.4 percent.
Base rate increase of $2.8 million, or an average 1.1 percent. (Case No. AVU‐E‐11‐01)
Deferred state income tax increase of $8.7 million. This was previously approved as part of the
settlement of the 2010 rate case. Deferred state income tax benefits are no longer available to reduce
rates. (Case No. AVU‐E‐10‐01, Order No. 32070)
Power Cost Adjustment (PCA) decrease of $15.5 million or about 6 percent. The PCA is a yearly
adjustment to rates based on the always changing costs of power supply. When water is plentiful and
market prices for power lower than anticipated, customers typically get a credit. During low‐water years
or during years of high market and fuel costs, customers typically get a surcharge. Avista’s PCA, which is
adjusted every Oct. 1, this year is a $15.5 million decrease. (Case No. AVU‐E‐11‐03, Order No. 32375)
A decrease in customer bills as the result of a $2.2 million increase in the Bonneville Power
Administration (BPA) exchange credit given residential and small‐farm customers. The BPA is a not‐for‐
profit federal agency that markets power from 31 federal hydroelectric dams and a nuclear plant in the
Northwest. The 1980 Northwest Power Act required that residential and small‐farm customers in the
Northwest share in the benefits of the federal hydroelectric projects located in the region. Avista applies
the benefits it receives, which usually fluctuate annually, to customers as a credit on their monthly
electric bill.
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The battle over wind
Dating as far back as 2005, Idaho’s utilities,
the Commission and renewable energy
developers have been trying to determine
the most equitable method to price
renewable energy, particularly wind. Wind
development, particularly under federal
PURPA provisions, has been rapid in Idaho
Power’s service territory in particular.
Up until the filing of this report, the issue of a true avoided‐cost and an appropriate surrogate
avoided resource were still being debated. Technical hearings are scheduled for August 7‐9,
2012, in the GNR‐E‐11‐03 docket to address these issues. Here is a timeline of the issues as they
have evolved.
June 2005 – Idaho Power Company files application to be granted a six‐ to nine‐month
suspension from its obligation under the federal Public Utility Regulatory Policies Act (PURPA)
to buy energy generated by qualifying wind‐powered projects. Later, Idaho’s two other major
regulated utilities, Avista Utilities and PacifiCorp (then Utah Power) joined the case, seeking to
be included in the moratorium. The utilities sought the moratorium to address the growing
number of intermittent wind proposals, which, they claimed, could impact the reliability of the
transmission grid. An Idaho Power analysis concluded that in order to safely integrate 1,000
MW of intermittent wind generation, it would be necessary to concurrently add 640 MW of
combustion turbines to provide capacity when wind resources were not operating. Between
November 2004 and its June 2005 filing, Idaho Power has signed contracts from wind
developers totaling 61.5 MW and has applications pending before the commission for another
21.5 MW. The company has also received contracts from developers intending to pursue
another 193 MW of wind projects. Before 2004, Idaho Power had less than 1 MW of PURPA
wind‐powered generation under contract.
August 2005 – Rather than granting the suspension, the commission (Order No. 29839)*
reduced the size of non‐firmed wind projects that can qualify for the commission’s published
rate from 10 megawatts to 100 kilowatts while the commission examined the case further.
The commission said it needed more time to study the impact of the wind projects on reliability
for customers and to examine whether the higher price paid for PURPA wind projects is
beneficial for customers who end up paying the cost of higher‐priced energy. (The money
Idaho Power pays wind developers is included as part of Idaho Power’s overall power supply
cost that is eventually passed on to customers in the company’s power cost adjustment process
every spring.)
February 2007 ‐‐ Idaho Power proposes that the 100‐kilowatt limit on wind projects that can
qualify for published rates be moved back up to 10,000 kilowatts or 10 megawatts. Idaho Power
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completed a wind integration study and asked the commission for a return to the 10 MW size
cap if wind developers: 1) agree to share in the cost of state‐of‐the‐art wind forecasting
services; 2) include a guarantee in future wind contracts that demonstrates projects are
mechanically capable to generate at full output during 85 percent of the hours during a month
and 3) agree to accept a discount of $10.72 per MW for wind integration. Idaho Power would
also agree to remove the "90/110 performance band" that stipulated when output was less
than 90 percent of projections or more than 110 percent of projections, Idaho Power could pay
developers a lesser market‐based rate rather than the PURPA rate.
July 2007 – Avista Utilities and PacifiCorp also file cases proposing return to 10 MW limit with
conditions as proposed by Idaho Power.
Press release:
http://www.puc2.idaho.gov/intranet/cases/elec/IPC/IPCE0703/staff/20070223PRESS%20RELEA
SE.HTM
August 2007 ‐‐ Commission staff conducted two workshops to explore whether the utilities and
wind developers could agree to a generic wind integration adjustment, but the parties were
unable to settle. With the parties unable to agree, the matter was put before the commission
for a decision.
http://www.puc2.idaho.gov/intranet/cases/elec/IPC/IPCE0703/staff/20070822PRESS%20RELEA
SE.HTM
February 2008 – After nearly three years, three cases involving how much it costs to add wind
to utilities’ transmission grids is resolved. Three orders establish the amount of discounts
utilities can assess against wind developers to account for the cost of integrating wind into their
systems. The orders also removed the 100 kW cap on the size of small‐power projects that can
qualify for the published rate, bringing it back to 10 MW. Also removed was the 90‐110
performance band that allowed utilities to pay wind developers a market rate rather than the
typically higher state rate when wind output from projects did not fall within forecasted ranges.
The order established a tiered‐discount for Idaho Power and Avista that increased as more wind
is added, but caps the discount so that it can go no higher than $6.50 per MWh. For the first
300 megawatts of wind on a utility’s system, the discount is 7 percent. That increases to 8
percent when a utility has contracts for 301 to 500 MW of wind and to 9 percent for 501 MW or
more. The commission approved a flat discount rate of $5.10 for PacifiCorp, which operates as
Rocky Mountain Power in southeastern Idaho.
http://www.puc2.idaho.gov/intranet/cases/elec/IPC/IPCE0703/staff/20080221PRESS%20RELEA
SE.HTM
November 2010 – Idaho Power, Avista and PacifiCorp (now Rocky Mountain Power in eastern
Idaho) file a joint petition asking the commission to investigate a number of issues related to
small‐power projects that qualify for published rates. The utilities asked that the eligibility cap
on the size of projects that qualify for the posted rate be reduced from 10 average megawatts
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to 100 kilowatts in 14 days. The utilities contend a rapidly expanding number of wind projects
are having a profound price impact on customers and on transmission systems. The utilities
claim that the small‐power projects PURPA was originally intended to encourage are now
developed by sophisticated large‐scale wind farms that aggregate several projects to fall under
the 10 MW limit within a mile apart from each other to qualify for the avoided‐cost rate. When
combined, these projects can total up to 100 or 150 MW interconnecting at one delivery point.
Idaho Power claimed it had 208 MW of wind generation and another 264 MW of approved
wind contracts scheduled to be online by the end of 2010. Idaho Power said it could have 1,100
MW of wind generation on its system in the near term, which exceeds the amount of power
used in Idaho Power’s total system on the lightest energy‐use days.
The commission denied the request to lower the size limits of projects than can qualify for the
posted rate. However, the commission did say that any decision it makes in regard to lowering
the limit would become effective Dec. 14, 2010.
http://www.puc2.idaho.gov/intranet/cases/elec/GNR/GNRE1004/staff/20101206PRESS%20REL
EASE.HTM
February 2011: Commission issues order reducing the eligibility cap for wind and solar projects
to qualify for published rates from 10 MW to 100 kW. The 10 MW limit remained for non‐wind
and non‐solar renewable projects. The commission said the smaller size limit for wind and solar
projects is temporary until a number of issues that led to a petition filed by the state’s largest
three electric utilities can be resolved. Wind and solar projects that signed agreements with
utilities dated before Dec. 14 are still under the former 10 MW eligibility cap.
http://www.puc2.idaho.gov/intranet/cases/elec/GNR/GNRE1004/staff/20110207PRESS%20REL
EASE.HTM
February and March 2011: With the commission’s case still pending, the Idaho Legislature gets
involved when residents in eastern Idaho, angry over wind development, from Idahoans for
Responsible Wind Energy and lead the charge to declare a two‐moratorium on wind
development. There is also significant opposition to the extension of a sales tax rebate on
equipment used in producing renewable generation. The tax was scheduled to sunset by June
30 without legislative action to extend it. The moratorium on wind development was killed in
committee on an 11‐8 vote.
http://www.businessweek.com/ap/financialnews/D9M4F3000.htm
The debate over whether to extend the sales tax rebate continued to the final day of the
session. A compromise bill to extend the tax credit for just another four months failed on an 18‐
17 State Senate vote, the final vote of the legislative session.
http://www.idahoreporter.com/2011/idaho‐senate‐rejects‐wind‐energy‐tax‐rebate‐extension/
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Wind development was one of the major issues of the session, if not the major issue. Wrote
John Miller of Associated Press: “What to do about wind power in Idaho has become one of the
most expensive issues in the Legislature this year, judging from more than a dozen lobbyists
employed by the utilities, wind energy developers and foes of the industry ...”
June 2011: The commission issues an order leaving the eligibility cap under which wind and
solar projects can qualify for commission published rates at 100 kilowatts. As a result,
developers of 12 Idaho Power Company wind projects and five Rocky Mountain Power projects
whose contracts were executed after the Dec. 14 deadline will not be eligible for published
rates. However, the wind projects could still be developed under a rate negotiated between the
project developers and the utilities. Ten Idaho Power wind projects that were submitted just
before the deadline have already been approved by the commission.
Commission staff and other parties attempted to establish criteria that would allow the
commission more discretion in determining whether a QF was truly a small project as
anticipated by PURPA or a larger project that had disaggregated. The commission declined to
adopt the criteria, maintaining that the potential would still remain for the criteria to be
circumvented.
The commission said it will initiate another proceeding to investigate the methodology used to
calculate the avoided‐cost rate. “We believe it is more appropriate to first establish the just and
reasonable avoided‐cost rates before we implement procedures for obtaining the rate,” the
commission said. “While we recognize the impact that this decision will have on small wind and
solar projects, it would be erroneous, and illegal pursuant to PURPA, for this commission to
allow large projects to obtain a rate that is not an accurate reflection of the utility’s avoided
cost for the purchase of QF generation,” the commission said.
The Northwest and Intermountain Power Producers Coalition argued that the 10 average MW
cap has worked “remarkably well” for Idaho. “We fundamentally think that it is unfortunate
that the three utilities initiated this docket at all,” NIPPC said. “We believe that this docket has
been an unnecessary exercise and that is because the system is not broken and, hence, it does
not need to be fixed.”
http://www.puc2.idaho.gov/intranet/cases/elec/PAC/PACE1101/staff/20110608PRESS%20RELE
ASE.HTM
July 2011: The Commission declines petitions from wind developers to reconsider their June
order. Five Rocky Mountain Power projects and two Idaho Power projects appeal to the State
Supreme Court.
http://www.puc2.idaho.gov/intranet/cases/elec/PAC/PACE1101/staff/20110727PRESS%20RELE
ASE.HTM
IPUC Annual Report 2011
42 | P a g e
August 2011: The Cedar Creek projects file a petition to the Federal Energy Regulatory
Commission, asking it to “institute an enforcement action” against the commission for violation
of PURPA. Cedar Creek alleged that QFs are entitled to receive avoided cost rates on the date a
legally enforceable obligation is incurred, not solely the date on which a contract is signed by
both parties and fully executed. Cedar Creek alleged that legally enforceable obligation
occurred well before the commission’s Dec. 14, 2010, deadline.
http://www.puc2.idaho.gov/intranet/cases/elec/FER/FERE1102/general/20110810NOTICE%20
OF%20PETITION%20FOR%20ENFORCEMENT.PDF
October 2011: FERC issues an order declining to institute an enforcement action but said the
PUC’s June order was “inconsistent with our regulations implementing PURPA.” It said Cedar
Creek may pursue its arguments in the appropriate court. The commission responds the same
month by announcing it will schedule four settlement discussions with Cedar Creek developers.
November 2011: The Commission issues an order announcing the scheduling for a new docket,
GNR‐E‐11‐03, to review the terms of PURPA power purchase agreements including, but not
limited to, the surrogate avoided resource and Integrated Resource Planning methodologies for
calculating avoided cost rates. After the 18 parties to the case pre‐file direct testimony by Jan.
31, 2012, a settlement conference will be held Feb. 28. Rebuttal testimony will be filed by the
end of June with hopes that the case will conclude by the end of July.
December 2011: Sales agreements between PacifiCorp and three of five wind projects rejected
earlier by the commission are approved, but the projects may be moved from their original
Bingham County location to a new site ‐‐ Ridgeline Energy’s Meadow Creek wind farm in
Bonneville County.
Because of already available transmission at the Meadow Creek site, the power purchase
agreements from three of the projects may be assigned to Ridgeline Energy. If the Cedar Creek
projects are assigned to Ridgeline, the scheduled operation date moves up to Dec. 31, 2012,
which qualifies the projects to receive Department of Treasury grants and other tax incentives
before they expire.
Even though two of the five projects won’t be built, the output from the three remaining
projects will be the same as was agreed to with all five original projects: an annual nameplate
capacity not to exceed 133.4 megawatts with annual output not to exceed 50 average
megawatts per month.
Ridgeline’s Meadow Creek site is smaller but has more wind capacity than the Cedar Creek
location. However, Ridgeline’s site has only 80 megawatts of transmission capacity and will
need to acquire another 40 MW of capacity to accommodate the former Cedar Creek projects.
IPUC Annual Report 2011
43 | P a g e
If no additional transmission becomes available, then part of the projects may revert to the
Cedar Creek site. (If Congress extends tax credits, all of the projects could remain at the original
site.)
http://www.puc2.idaho.gov/intranet/cases/elec/PAC/PACE1101/staff/20111221PRESS%20RELE
ASE.HTM
December 2011: Commission staff met informally with the developer of two Idaho Power wind
projects, Grouse Creek Wind Parks, to see if that case could be settled. The Grouse Creek
projects were the only two of the 12 Idaho Power projects that appealed to the state Supreme
Court. Oral argument in that case is set for March 7, 2012.
January 2012: Wind opponents declare their intent to introduce several pieces of legislation to
limit further development of wind. Idahoans for Responsible Wind Energy forms into a new
group called the Energy Integrity Project.
http://www.energyintegrityproject.org/Home_Page.html
Smallpower renewable projects added during 2011
Sahko Hydro Project near Filer, 0.5 MW, Idaho Power, IPC‐E‐10‐37
http://www.puc.idaho.gov/internet/press/011311_IPCoFilerhydro.htm
Hidden Hollow Energy 2 at Ada County Landfill, 3.2 MW, Idaho Power, IPC‐E‐10‐44
http://www.puc.idaho.gov/internet/press/021811_IPCoAdalandfill.htm
Hazelton A Hydroelectric near Jerome, 8.1 MW, Idaho Power, IPC‐E‐10‐45
http://www.puc.idaho.gov/internet/press/021811_IPCoHazeltonhydro.htm
Exergy‐Rogerson wind projects (Deep Creek, Cottonwood, Rogerson Flat, Salmon Creek) near
Rogerson, each up to 10 MW, Idaho Power, IPC‐E‐10‐47, ‐48, ‐49 and ‐50.
http://www.puc.idaho.gov/internet/press/021811_IPCoRogersonwindprojects.htm
Cargill, Inc. biogas‐fueled digester at dairy farm near Roberts, 1.7 MW, PacifiCorp (Rocky
Mountain Power), PAC‐E‐11‐08
http://www.puc.idaho.gov/internet/press/060911_RMPCargill.htm
Clark Canyon Hydro, near Dillon, Mont., 4.7 MW, Idaho Power, IPC‐E‐11‐09
http://www.puc.idaho.gov/internet/press/072611_IPCoClarkCanyon.htm
Interconnect Solar, near Murphy, 20 MW, Idaho Power, IPC‐E‐11‐10
http://www.puc.idaho.gov/internet/press/102411_IPCoInterconnectSolar.htm
IPUC Annual Report 2011
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Idaho Natural Gas Utilities
Intermountain Gas Company
Residential Commercial Industrial Transportation Total
2011 Customers 282,309 30,139 10 107 312,565
% of Total 90% 10% 0% 0.04% 100%
2010 Customers 275,522 29,673 9 105 305,309
Therms (millions) 222 111 3 241 577
% of Total 38% 19% 1% 42% 100%
2010 Therms 212.5 106.5 25.6 221.8 566.5
Revenue (millions) $185.4 $86.5 $1.8 $8.3 $282
% of Total 66% 31% 1% 3% 100%
2010 Revenue $326.8
Avista Utilities
Residential Commercial Industrial Transportation Total
Customers 66,294 8,435 95 8 74,832
% of Total 89% 11% 0% 0% 100%
2010 Customers 65,050 8,303 100 8 73,461
Therms (millions) 48 28 2 45 123
% of Total 39% 23% 2% 37% 100%
2010 Therms 48 27.7 1.9 48.8 126.3
Revenue (millions) $48 $23 $2 $0.4 $73
% of Total 65% 31% 3% 1% 100%
2010 Revenue $83.54
Questar Gas
Residential Commercial Industrial Transportation Total
Customers 1799 231 0 0 2030
% of Total 89% 11% 0% 0% 100%
2010 Customers 1730 227 1 0 1958
Therms (millions) 1.4 0.85 0 0 2.26
% of Total 62% 38% 0% 0% 100%
2010 Therms 1.26 0.76 0.10 0 2.12
Revenue (millions) $1.13 $0.59 $0.00 $0.00 $1.72
% of Total 63.11% 34.50% 2.39% 0.00% 100.00%
2010 Revenue $1.65
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Case No. INT‐G‐11‐01, Order No. 32372
September 30, 2011
Intermountain Gas rates decline 5.3 percent
Natural gas rates for customers of Intermountain Gas Company are declining an average 5.3
percent effective Oct. 1.
Low demand growth due to lingering economic conditions and increases in natural gas supply
are the primary reasons the company’s weighted average cost of gas (WACOG) continues to
decline.
The portion of customer bills that is based on the WACOG (gas supply and transportation cost)
decreases from 49.2 cents per therm to 45.3 cents, resulting in about an average $2.17 per
month reduction for residential customers.
There are two major components to natural gas rates, a base rate and the PGA. Base rates
cover fixed costs that rarely change. The PGA includes variable costs and is designed to more
closely align actual rates with the variable portion of gas rates. The variable rates included in
the PGA include: 1) the cost of purchased gas from suppliers, which is largely dependent on
wholesale market prices; 2) the cost to transport natural gas and 3) the cost to store it.
Company officials say supplies of natural gas nationwide continue to remain strong with natural
gas production at an all‐time high.
The annual adjustment does not impact company earnings, whether the PGA is an increase or
decrease. The amount collected in the PGA variable portion of rates can be used only to meet
gas supply, transportation, storage and other related expenses and cannot go to increase
company earnings.
_____________________________________________________________________________
Case No. AVU-G-11-01, Order No. 32371
September 30, 2011
Rate case settlement results in decrease to customers
The Idaho Public Utilities Commission is granting Avista Utilities a base rate electric increase of
about 1.1 percent and a base rate gas increase of 1.6 percent. However, due to decreases in
other rate components, billed rates for customers actually decrease effective Oct. 1.
IPUC Annual Report 2011
46 | P a g e
The overall rate decrease to electric customers is an average 2.4 percent for all customer
classes (2.1 percent to residential class) and an average 0.8 percent to gas customers (0.5
percent to residential class).
A residential natural gas customer using an average of 62 therms would see a 20‐cent per
month decrease for a revised monthly bill of $60.96. The billed rate decreases from the current
91.5 cents per therm to 90.7 cents per therm.
Part of the base electric and gas rate increase include an increase in the monthly customer
service charge from $5 to $5.25 per month for electric customers and from $4 to $4.25 per
month for natural gas customers.
A key part of the settlement is that Avista agrees to not collect another base electric or gas rate
increase before April 1, 2013. (This does not include yearly tracker adjustments such as the
Power Cost Adjustment or Purchased Gas Cost Adjustment and energy efficiency rider
adjustments.)
NATURAL GAS ADJUSTMENTS include three increases and one decrease for net overall rate
decrease of 1 percent.
Base rate increase of $1.1 million, or 1.6 percent. (Case No. AVU‐G‐11‐01).
Deferred state income tax increase of $470,423. This was previously approved as part
of the settlement of the 2010 rate case. Deferred state income tax benefits are no
longer available to reduce rates. (Case No. AVU‐G‐10‐01, Order No. 32070)
Purchased Gas Adjustment (PGA) increase of $776,190 or an average 1 percent. The
PGA operates much like the electric PCA, matching anticipated gas supply and
transportation costs with actual cost. (Case No. AVU‐G‐11‐04, Order No. 32370)
Energy efficiency rider decrease of $2.4 million or an average 3.5 percent. The rider is
used to fund conservation programs that reduce the company’s need to buy gas supply
at greater cost than the cost of the conservation programs. For residential customers,
the decrease in the rider is from about 5.7 cents per therm to 2.7 cents per therm.
Avista estimates that during 2010, natural gas efficiency programs resulted in natural
gas savings of about 1.9 million therms. (Case No. AVU‐G‐11‐03, Order No. 32366)
______________________________________________________________________________
Case No. INT‐G‐11‐03, Order No. 32450
February 2, 2012
Intermountain seeks second decrease this year
On Dec. 22, Intermountain Gas Company sought commission approval to decrease the variable
portion of it rates by an average 4.5 percent effective Feb. 1, 2012.
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47 | P a g e
The “prolific availability” of U.S. shale gas production, record storage of natural gas supply and
the lack of hurricane activity and cold weather are all contributing factors cited by
Intermountain Gas Company in its fifth consecutive request for a reduction in natural gas rates.
Intermountain Gas serves about 312,000 customers in 74 communities across southern Idaho.
If approved by the commission, the portion of rates that covers natural gas supply and
transportation would decline from 45.35 cents per therm to 41.8 cents. That represents about
half the total summer residential rate of 86 cents per therm and winter residential rate of 75
cents.
Intermountain Gas also cited completion of the Ruby gas pipeline (from southeast Wyoming to
south‐central Oregon) as another factor contributing to lower gas supply prices. The Ruby
pipeline has displaced other traditional natural gas supplies and softened prices at the Alberta
Energy Company hub (AECO) that makes up a significant portion of Intermountain’s gas supply
portfolio.
This is Intermountain Gas Company’s fifth consecutive request for a reduction in natural gas
rates.
IPUC Annual Report 2011
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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 25 $0.00 $ 25 $ 27 per month 7/4/2008
$44.50 (commercial)
2. Aspen Creek 25 $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
$400 if line,
meter in place $ 20bh/$40 ah $27.43 up to 7,500 gal 1/1/2010
$2500 if not $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 $17.50 up to 4,000 gal 8/12/2011
$1.51 each 1,000 gal over
6. Capitol Water Corp. 2,875 None approved $15
Starts at $12.65/mo in winter
and $28.70/mo summer for
non-metered. Metered rates
start at $8.50/mo 5/1/2009
Annual
Power Cost
Adjustment at
0.81% of bill
7. Country Club Hills Utility 132 $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 3,400
$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
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 3,593
Minimum $500
depending on
meter size
$20/bh and $40/ah
$16.10 (depending on meter
size) up to 03/16/10
12,000 gal and $0.611
Each 1,000 gal over
IPUC Annual Report 2011
49 | 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 23 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 nm 11/05/2008
$1100 unauthzed
15. Kootenai Heights Water 11 None approved $50 $38.50 up to 10,000 gal 6/21/2007
$3.10 each 1000 gal over
16. Mayfield Springs 100 $725 $35bh/$70ah 1” meter $22 up to 10,000 gal
$0.30 each 1,000 gal over 10/10/2008
2” meter $50 up to 20,000 gal
$0.30 each 1,000 gal over
17. Morning View 96 None approved $ 25 bh/-ah ¼ acre-$ 27.41/mo. 9/01/2007 $5 for
½ acre-$ 35.94/mo. Reserve
1 acre-$ 44.48/mo Account
18. Murray Water Works 33 $800 $25 March-Oct $ 26/mo 7/15/2003 Rate case
$50 Oct-Feb pending
19. Pack Saddle Estates 35 $430
$ 25 if 45 days or less;
$130 for more than 45
days $34.24/mo 6/3/1996
20. Picabo 28 $500 $ 15 involuntary $41/mo summer 7/1/2004
Irrigation
(April-Sept)
$ 25 voluntary $22/mo winter $19/mo
21. Ponderosa 29 $2,500 $ 35 bh/ah Resident: $ 48/mo 7/1/2003
Seasonal: $ 25/mo
22. Resort 389 None approved $ 20 bh/$60ah $ 44.80/mo per 1 ERU 3/15/2005
4X that after 30 days
23. Rickel 27 $6,000 $25 bh/ah $ 30 up to 15,000 gal 5/011997
$1.10 each 1,000 gal over
24.Rocky Mountain
Utility Company
25. Spirit Lake
38
305
$150
$2,500
$20 bh
Or $40 ah
$ 16 bh/$32 ah
$39/50/mo
$12.50 up to 9,000 gal
01/01/09
10/30/09
$0.10 each 100 gal over
25. Stoneridge 193 $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 $118/per quarter 2/2/2009
1” res/larger 30 days or less/
Based on size $40 after hours
28. Troy Hoffman 144 $458/1” $20/bh $11.80/first 5,000 gal 1/1/2011
$40/ah $1.10 each 1,000 gal
29. United Water Idaho 78,892 See Tariff $20/ bh Starting at $20.10 bi-monthly 2/1/2012
$30/ ah Winter -- $1.44 per 100 cf
Summer - $1.44 per 100 cf
Up to 300 cf and $1.798
For each 100 cf over
IPUC Annual Report 2011
50 | P a g e
Case No. TRH-W-10-01, Order No. 32152
January 3, 2011
Rates increase for Troy Hoffman Water customers
The monthly minimum rate for the approximate 150 customers of Troy Hoffman Water Corporation
increased from $5.50 to $11.50 per month effective Jan. 1, 2011.
Rates have not increased for 14 years for the company, which serves customers in Coeur d’Alene. When
the company filed its case last June, it asked for an increase in the monthly charge from $5.50 to $13.31,
plus another $1.45 for every 1,000 gallons used in excess of 3,000 gallons. The commission ultimately
approved the $11.50 monthly minimum but applied it to the first 5,000 gallons. Customers will pay
$1.10 for every 1,000 gallons used in excess of 5,000 gallons per month.
The commission received 25 written comments from customers and four testified at a telephonic
hearing. Customers opposed the size of the increase, especially given the poor economic conditions.
“We recognize that for some customers any increase may result in economic hardship,” the commission
said. “While we have an obligation to customers to establish rates that are fair and reasonable, this
commission at the same time has a statutory obligation to Troy Hoffman to set rates at a level sufficient
to allow the company to recover its reasonable expenses of operation and to receive a reasonable
return on prudent capital investments in utility plant and facilities. Carrying out this duty is necessary for
the company to be financially sound and capable of providing its customers with safe and reliable water
service.”
The commission approved an annual revenue requirement of $41,834, an increase of $17,682. Major
repairs totaling $40,795 were made to the well pump and motor, electrical service and well house
during 2009. Commission staff reviewed the repairs to determine if they were necessary and reasonably
priced.
Within one year, the company must test the accuracy of its newly installed production flow meter and
randomly test at least 10 percent of its customer service meters. The company must also review and
update all its customer notices, bills and other documents to ensure they are consistent with
commission rules and regulations and change its business hours from 7 a.m. to 4 p.m. to 8 a.m. to 5 p.m.
_____________________________________________________________________________
Case No. BRN‐W‐11‐01, Order No. 32324
August 15, 2011
Rates increase for Boise’s Brian Water customers
The Idaho Public Utilities Commission has approved a rate increase for the 46 households served by
Boise‐based Brian Water Corporation.
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51 | P a g e
The increase raises the basic monthly charge from the current $12.50 to $17.50 for the first 4,000
gallons used per month. The commission also approved an additional commodity charge of $1.51 for
every 1,000 gallons used above 4,000 gallons.
Brian Water serves customers in the Warm Springs area of eastern Boise.
The commission re‐stated its 2007 directive to the company to read meters monthly rather than bi‐
monthly. The company has failed to do so, the commission noted, and must do so now to avoid facing
civil penalties. “In failing to institute monthly billing, Brian Water not only exacerbates its cash flow
problems, but also subjects the company to potential penalties,” the commission said.
Further cash flow problems are attributed to the company’s failure to more timely collect bills. The
commission directed Brian Water to use commission rules to enforce bill collection and implement a 1
percent per month late fee on any unpaid balance.
The Brian Water system was built in the early 1960s and has two production wells, one a primary well
and one a back‐up well. Because of the age of the system, water loss is high. Further, the Idaho
Department of Environmental Quality has stated that the system’s nitrate levels exceed the federal
maximum contamination level. The company is considering a new, deeper well. The commission said
that when the company builds a new well it should include the costs of a flow meter which would allow
the company to reduce loss and better manage its water resource.
The commission said it also included enough additional revenue ($4,590 of additional annual revenue
for a total yearly revenue requirement of $17,532) to allow the company to begin replacing its aging
meters. The money allowed in the new rates should permit the company to replace five meters each
year.
______________________________________________________________________________
Case No. UWI‐W‐11‐02, Order No. 32443
January 24, 2012
Commission adopts settlement of United Water rate case
The approved a settlement to the United Water Idaho rate case that will increase rates for Boise area
water customers by an average 8 percent effective Feb. 1 followed by a 2.5 percent increase on Feb. 1,
2013. For an average residential customer, the monthly increase will be about $2.28 per month in 2012
and another 72 cents per month in 2013.1
United Water, which serves about 84,000 customers in the Boise metro area, filed last August for a near
20 percent one‐time increase of about $5.82 per month, or about $7.6 million in additional yearly
revenue. The settlement allows a $3 million revenue increase in 2012 and $950,000 in 2013 or about 52
1 For the average customer who uses a 5/8” to ¾”‐inch meter, the fixed customer charge would increase from
$18.10 every two months to $20.10 in 2012 and $20.80 in 2013. The commodity charge, which varies according to
consumption, would increase from $1.35 per hundred cubic feet (ccf) in the winter months to $1.44 per ccf in 2012
and $1.464 in 2013. During the months of May through September, all use above 3 ccf would be billed at $1.80
per ccf in 2012 (up from $1.69) and to $1.83 in 2013.
IPUC Annual Report 2011
52 | P a g e
percent of United Water’s original request. Further, the agreement precludes any other rate increases
until 2014 at the earliest.
Parties proposing the settlement to the commission included commission staff, United Water and the
Community Action Partnership Association of Idaho (CAPAI), which represents low‐income customers.
The commission acknowledged the more than 250 comments filed by concerned customers, none
favorable to the request. Most of the comments expressed concern about United Water seeking more
revenue because declining water use resulted in less revenue. About 38 percent of United Water’s $7.6
million request in new revenue was attributed to declining water sales. The settlement approved by the
commission removed nearly all the revenue increase requested attributable to reduced water use. The
agreement calls for future meetings between staff and United Water to discuss revenue and earnings
instability associated with reduced water use.
Parties to the settlement also did not agree on an appropriate return on equity (ROE). United Water
requested an overall rate of return of 8.43 percent (it is currently earning 5.64 percent) and an ROE of
10.5 percent. Commission staff’s recommended ROE was significantly below anything approved by the
commission for an Idaho utility in the last 20 years. A specified level of return is not included in the
stipulation, one reason why a lower overall revenue requirement could be achieved.
Commission staff thoroughly reviewed United Water’s expenses and investments. The staff adjustments
approved by the commission totaled a nearly $4 million reduction in the company’s
revenue request. “The stipulation we approve is for a significantly reduced amount and spreads
recovery of that reduced amount over two years,” the commission said.
However, further reductions were difficult to find because much of the company’s request was driven
by additional investment for pipelines, filtration and pumping, which are required to provide adequate
service. United Water claims it has invested more than $20 million in its system since its last rate case.
Improvements include a new supply treatment facility, a 600,000‐gallon water storage tank, 1.7 miles of
new 24‐inch water main and replaced water mains, service lines and meters. The company is also
investing $5.5 million in a new customer information system. “There is no dispute that the company has
made capital improvements that are properly recovered in rates, and that its costs have increased since
its last rate increase, while its revenues have declined,” the commission said.
Customers also objected to an increase in the fixed customer charge from $9.05 per month to $10.05.
United Water’s customer charge is notably higher than customer charges for other electric and gas
utilities operating in Idaho.
Cost‐of‐service studies for water companies typically show a higher degree of fixed costs to deliver
water than is necessary to deliver electricity or natural gas. Much of United Water’s cost is in the
infrastructure it operates and maintains, and those costs exist independent of the amount of water
used. Revenue not collected in the customer charge must be recovered in the charge for water used
(commodity charge), which, for many customers, would dramatically increase billing, particularly in the
summer.
Both commission staff and CAPAI supported the increase to the customer charge over shifting those
costs to the commodity charge. CAPAI said it generally prefers to place the bulk of any rate increase on
the actual water used to enhance a customer’s ability to control his or her bill.
IPUC Annual Report 2011
53 | P a g e
United Water agreed to increase the cap on the amount of annual benefits it will make available to
assist low‐income customers from $50 to $65. Further, the company agreed to remove the upper limit
of matching funds it will contribute to the “UW Cares.” The company currently will match up to $20,000
of customer contributions to UW Cares. Under the proposed stipulation, the company has agreed to
match whatever customers contribute, even beyond $20,000. That means funds will be available to
meet the needs of all United Water customers who apply for the UW Cares program.
______________________________________________________________________________
Case No. UWI‐W‐W‐11‐01, Order No. 32201
March 11, 2011
Commission approves agreement between water utilities
The commission approved a United Water Idaho petition to renew and expand an interconnection
agreement with the City of Eagle that allows both utilities to supply water to each other during
emergency situations.
The agreement allows United Water and the City of Eagle to modify their existing interconnection to
enable a two‐way flow between the two systems during those times when excess water supply may be
needed for fire suppression, a significant pipe break, unexpected pump shutdown or scheduled
maintenance of large facilities.
The maximum instantaneous supply that United Water will supply to the City of Eagle is 1,500 gallons
per minute and the maximum daily supply is 1.44 million gallons per day. The City of Eagle will be able to
provide 825 gallons per minute and up to 1.1 million gallons per day.
The cost to modify the system to allow the two‐way flow is $19,995. United Water will pay $14,496 and
the City of Eagle, $5,499.
The agreement provides that both companies will use their best efforts to ensure that water furnished is
potable and in compliance with all federal and state laws and regulations in effect at the time water
supply is delivered to either party.
“The agreement helps maintain United Water’s supply to customers in the event of emergencies, and
allows United Water to reasonably provide water to the city, without degrading its own supply or water
quality,” the order states.
_____________________________________________________________________________________
Case No. ISL‐W‐11‐01, Order No. 32268
June 22, 2011
Island Park Water ordered to cease incorrect billing
The commission is ordering Island Park Water Company to cease all billing practices that are in conflict
with the tariff approved by the commission in November 2008.
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54 | P a g e
Some of the water company’s 334 customers recently complained to the commission that they were
being charged $280 per lot rather than commission‐approved $280 per customer (or connection).
Commission staff investigated to substantiate the customers’ complaints.
In response, the commission’s order directs the company to do the following:
Cease all billing practices that conflict with the tariff.
Refrain from terminating service to customers who did not pay bills that conflict with the tariff.
Send corrected invoices to all customers who were billed incorrectly and simultaneously provide
copies to the commission.
Repay customers for any amounts collected based on a rate exceeding the rate allowed by the
tariff.
Send a copy of a current customer list to the commission.
Provide commission staff with a specific date and time that the commission’s auditors may visit
the company.
_____________________________________________________________________________
Case No. UWI‐W‐11‐03, Order No. 32391
November 7, 2011
Unclaimed deposits will be used to benefit water customers
The commission granted United Water Idaho’s request to transfer about $95,600 in unclaimed customer
deposits into a program that assists low‐income and disadvantaged customers of the Boise area water
utility.
The unclaimed deposits are from developers of water main extensions to subdivisions that were never
completed. United Water said it made every effort to contact the developers who made deposits of
$80,817.48 in 2007 and $14,771.71 in 2008.
State law allows unclaimed customer deposits of more than year after service is terminated to be
directed into low‐income assistance programs if the commission certifies to the state treasurer that a
utility participates in a financial assistance program.
United Water will include the unclaimed deposits in its UW Cares program, administered by the El‐Ada
Community Action Partnership. Since 2005, UW Cares has provided more than $77,000 in grants to
1,600 qualified customers. About $74,000 of that has comes from shareholders and another $3,000
from voluntary customer contributions.
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Idaho Telecommunications
Case No. ALL‐T‐10‐01, Order No. 32209
April 4, 2011
Wireless company qualifies for highcost support in rural Idaho
State regulators have granted a request by Allied Wireless Communications Corporation, doing business
in Idaho as Alltel Wireless, to be declared eligible to receive federal funds to expand its wireless network
to serve several rural areas of Idaho.
The commission ruled that Alltel qualifies as an “eligible telecommunications carrier” (ETC). The
designation means the wireless carrier is now eligible to receive support 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 customers who pay a
portion of their bill each month to support the Universal Service Fund.
Competitive wireless companies now receive the same federal support as wireline companies if state
commissions find that ETC designation promotes competition and is in the public interest. Edge Wireless
became the first cellular phone company in Idaho to qualify for ETC designation in 2007.
Alltel will provide service to 20 rural wire centers now served by five incumbent telephone companies.
(A wire center is a geographic area served by a central office switch, which provides dial tone and dialing
functions.) The wire centers are in areas now served by Cambridge Telephone Company (Cambridge,
Council, Cuprum, Lowman and Indian Valley), CenturyTel of Idaho (Leadore, North Fork and Salmon),
Custer Telephone Cooperative (Challis, Clayton, Elk Bend and May) Famers Mutual Telephone Co.
(Fruitland and Nu Acres) and Midvale Telephone Exchange (Lakeview, Midvale, Warm Lake, Warren and
Yellow Pine).
Alltel cited five public interest benefits in its application including: 1) higher speed service, 2) potential
solution to health and safety risks by not having to travel long distances to find a telephone (its
customers will have access to E 911 dispatch); 3) negligible impact on the overall Universal Service Fund;
4) the benefit of increased competition and economic development in rural areas and 5) no possibility
for “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. Alltel maintains it
will serve the entire wire center in all its areas, not just the lower‐cost areas.
The commission said ETC designation is in the public interest because Alltel had demonstrated it is
capable of providing the services described in its application, has a viable network plan to provide
service throughout the areas, has a local use plan that is similar to the companies already serving the
area and is able to remain functional during emergencies.
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Case Nos. GNR‐T‐11‐02 and GNR‐T‐11‐03
May 5, 2011
Surcharge for telephone fund to increase slightly
A surcharge that helps to ensure low‐income Idahoans, including many senior citizens, have access to
local dial‐tone service for medical and other emergencies, will increase by 1 cent per month for each
business, residential and wireless phone line effective June 1.
The commission agreed to increase the surcharge for the Idaho Telecommunications Service Assistance
Program (ITSAP) from 6 cents per access line per month to 7 cents.
Those who qualify for ITSAP receive a monthly discount of $13.50 from their telephone bills. Program
eligibility is determined by the state Department of Health and Welfare, although the Idaho Public
Utilities Commission establishes the amount of surcharge necessary to fund the program. Revenues
from the surcharge provide about 30 percent of the total discount low‐income Idahoans receive while
federal funds provide the rest. A state match is required to qualify for the federal funds.
During 2010, an average of 27,539 Idahoans per month qualified for ITSAP assistance. The surcharge to
fund the program has been as high as 12 cents per line per month, but the number of wireline access
lines continues to decline, with an 8 percent drop during 2010. The number of wireless access lines
remained about the same during 2010, with just a 0.6 percent decline. While the number of ITSAP
recipients is expected to remain constant, the decrease in the number of lines funding the program
necessitated the 1‐cent increase in the surcharge.
In a related case, the commission decided to leave at current levels the funding for the Idaho
Telecommunications Relay Service (TRS), which assists hearing and speech impaired
telecommunications users.
The TRS allows hearing and speech impaired citizens to use telephones via a relay center that converts
oral conversation to text‐type and vice versa. The service is funded by an assessment on residential and
business lines of 2 cents per month and a charge of two‐tenths of 1 cent per minute on intrastate long
distance calls.
Use of the service is declining due to advancing technology in Internet‐based services and cell phone
texting. During 2010, the relay center handled 70,995 minutes of traffic, a 24 percent decrease from
2009. The number of access lines to fund TRS was 531,190 in 2010, a decrease of about 57,850 lines
from the previous year.
_____________________________________________________________________________________
Case No. GNR‐T‐11‐01, Order No. 32277
July 5, 2011
PUC creates registration process for wholesale telecoms
The commission has created a process that allows telephone companies who provide services other
than traditional local exchange to register as wholesale providers of telecommunications services in
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Idaho. Companies that do provide local exchange services must be issued a Certificate of Public
Convenience and Necessity (CPCN) from the commission.
The wholesale providers said the registration process will make it easier for them to enter into
interconnection agreements with existing companies that have telecommunications infrastructure in
place.
The need for the registration process surfaced in 2010 when Time Warner Cable Information Services
applied to the commission to receive a CPCN. The commission denied the certificate because Time
Warner did not plan to offer local exchange service, but sought only to offer Voice over Internet
Protocol (VoIP) services to commercial customers in Idaho using facilities owned by its cable affiliate.
The commission said the CPCN was not necessary because Time Warner is a wholesale provider that
offers services to other telecommunications companies, not to the public or end‐users. The commission
said Time Warner was free to offer its wholesale service without commission involvement.
However, Time Warner officials asserted that existing providers in Idaho wouldn’t interconnect with
them without a certificate. Further, Time Warner alleged that without a certificate it won’t be assigned
telephone numbers and connections with E‐911 emergency service.
The Time Warner case led to a commission investigation that determined there are a number of
competitive local exchange companies that, while operating with a certificate, are still not providing
local service to end‐users. A number of the companies objected to a commission letter suggesting the
commission may rescind their certificates.
In response, the commission opened a docket to investigate whether a process short of issuing a CPCN
could be created for competitive providers who do not offer local exchange services. As a result, the
commission created the registration process, which allows companies to use Sections 1 and 5‐8 of its
existing Rule 114 to register. Those sections require the companies to provide certain identifying
information and a commitment to adhere to number pooling and reporting requirements to assist the
commission in preserving telephone numbers and delaying further the creation of more than one area
code in the state.
_____________________________________________________________________________________
Case No. TFW‐T‐09‐01, Order No. 32301
August 1, 2011
Commission denies ETC designation to prepaid wireless service
State regulators have denied an application from TracFone Wireless, Inc., a prepaid wireless service
provider, to be declared an Eligible Telecommunications Carrier in Idaho. The designation would have
qualified TracFone to receive money from federal and state low‐income assistance programs.
The commission’s denial is due primarily to TracFone’s refusal to contribute to a combined federal and
state program called Lifeline, funded by a 6‐cent surcharge on each residential, business and wireless
phone line in the state. Because TracFone offers pre‐paid wireless service, it does not bill its customers
and, therefore, claimed it has no means to collect the surcharge. TracFone also said it would not
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contribute to Idaho’s Emergency‐911 fund. Not doing so is a violation of the Idaho Emergency
Communications Act.
TracFone already offers pre‐paid wireless service in Idaho, but sought ETC designation so it could
provide service to low‐income customers under the name SafeLink Wireless. Qualifying customers
would receive a free handset and up to 67 minutes of free time. For use beyond 67 minutes, customers
would purchase a pre‐paid card at 20 cents per minute. SafeLink offers service to low‐income, low‐
volume users and transient users who either choose not to enter into long‐term service commitments or
are unable to meet the credit requirements necessary to obtain service from other carriers.
The commission noted the company’s testimony that it has the ability to track the usage rate of its
customers and calculate the amount that would be due in low‐income and E‐911 surcharges. “The plain
and unambiguous language of these laws requires all telecommunications carriers – including pre‐paid
wireless carriers – to remit fees established under those statutes,” the commission stated. “TracFone
will not be allowed to escape the duty to remit the surcharges simply because it chooses not to bill its
customers on a monthly basis.”
TracFone argued that the issues regarding payment of fees to Lifeline or to the Emergency 911 fund can
be addressed in separate proceedings and that ruling in favor the ETC designation now would make its
service immediately available to many low‐income households in Idaho.
_____________________________________________________________________________________
Case No. TFW‐T‐09‐01, Order No. 32358
September 21, 2011
Commission declines to reconsider telecommunications order
The commission affirmed its earlier denial of an application by TracFone Wireless, Inc., a prepaid
wireless service provider, to be declared an Eligible Telecommunications Carrier in Idaho. ETC status
would have qualified TracFone to receive money from federal and state low‐income assistance
programs.
The denial is due primarily to TracFone’s refusal to contribute to a combined federal and state program
called “Lifeline.” Funded by a 6‐cent surcharge on each residential, business and wireless phone line in
the state, Lifeline provides discounts that allow qualifying low‐income households to retain basic
telephone service. TracFone claims it cannot assess its customers the surcharge because it offers pre‐
paid wireless service rather than billing its customers, which would provide a mechanism for collecting
the surcharge. TracFone also said it would not contribute to Idaho’s Emergency‐911 fund. Not doing so
is a violation of the Idaho Emergency Communications Act, the commission ruled.
After the commission’s July 29 denial, TracFone petitioned for reconsideration. This week the
commission declined to reconsider. TracFone now has the option to appeal to the state Supreme Court.
TracFone already offers pre‐paid wireless service in Idaho, but sought ETC designation so it could
provide service to low‐income customers under the name SafeLink Wireless. Qualifying customers
would receive a free handset and up to 67 minutes of free time. For use beyond 67 minutes, customers
would purchase a pre‐paid card at 20 cents per minute. SafeLink offers service to low‐income, low‐
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volume users and transient users who either choose not to enter into long‐term service commitments or
are unable to meet the credit requirements necessary to obtain service from other carriers.
The commission said the fact that TracFone does not bill its customers does not justify violating Idaho
statutes that require all telecommunications providers to contribute to E‐911 and Lifeline. “TracFone
has elected to pursue a business model that makes the collection of the fees more challenging than a
more typical telecommunications provider ....” the commission said. “We find that TracFone’s selection
of a business model does not render the relevant statutes inapplicable.”
In its earlier order, the commission noted TracFone’s testimony that it has the ability to track the usage
rate of its customers and calculate the amount that would be due in low‐income and E‐911 surcharges.
TracFone further argued that denial of its application would be a “disservice” to low‐income households
in Idaho. “TracFone’s purported aim of increasing the Lifeline participation rate for Idaho households,
however laudable, must be weighed against the company’s persistent refusal to contribute to programs
that directly benefit many of those same households,” the commission said.
_____________________________________________________________________________________
Case No. TMW‐T‐10‐01, Order No. 32319
August 10, 2011
TMobile eligible for federal, state funds
T‐Mobile West Corp. qualifies as an “eligible telecommunications carrier” (ETC) in Idaho, according to an
order issued by the commission.
ETC status means T‐Mobile can receive support from the federal Universal Service Fund, 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 customers who pay a portion of their bill each month to support
the Universal Service Fund. For residential wireline and wireless customers in Idaho the charge is 12
cents per month and for business customers, 19 cents.
In recent years, competitive wireless companies have been allowed to receive the same federal support
as wireline companies if state commissions find that ETC designation promotes competition and is in the
public interest.
T‐Mobile currently provides wireless service in various locations around the state. With ETC status, T‐
Mobile asserts it will provide all the universal services supported by the USF including access to directory
and emergency services and will make discounted services available to qualifying low‐income customers
through the Idaho Telephone Service Assistance Plan called “Lifeline.” Idaho residential, business and
wireless customers pay 6 cents per month for the state’s contribution to the Lifeline program.
“Granting ETC status will benefit consumers by offering new services and increased competition,” the
commission said. “In addition, we find granting T‐Mobile ETC status will provide rural customers with
greater access to wireless services,” as well as being beneficial to low‐ and fixed‐income customers who
qualify for Lifeline service discounts
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A number of companies already providing service in Idaho, including Allied Wireless, CTC Wireless,
Syringa Wireless and Rural Wireless, objected to the T‐Mobile application on two grounds: 1) AT&T’s
application before the Federal Communications Commission to acquire T‐Mobile threatens the USF in
Idaho and 2) that T‐Mobile failed to demonstrate that it will adequately service both non‐rural and rural
areas.
The opposing companies, calling themselves the Telecom Group, contended that the FCC may approve
the AT&T merger only under a condition that T‐Mobile surrender its USF support as the FCC did with
two 2008 mergers. That, the Telecom Group said, would reduce the total high‐cost USF support
available to Idaho. However, the commission noted that the FCC did not impose similar conditions in
merger cases as recent as 2009. Further, in the 2008 merger cases, the companies voluntarily agreed to
phase out high‐cost support. “We find that it is unreasonable to delay or reject T‐Mobile’s ETC
application based on what the FCC may or may not decide in the AT&T and T‐Mobile transaction,” the
commission said.
The Telecom Group argued that T‐Mobile did not provide enough information regarding its plan to
adequately serve more costly rural areas in the territory it seeks to serve. The commission said T‐
Mobile’s application met the commission requirements and that a two‐year network plan is submitted
every year. “We find this annual requirement will hold T‐Mobile accountable for making a reasonable
effort to implement its two‐year network plan and its ETC status may be revoked if it does not,” the
commission said.
T‐Mobile said that the opposition to the ETC application is a “naked attempt” to avoid or delay
enhanced competition in the rural areas of Idaho.
The areas T‐Mobile will serve include those areas already served by these rural telecom companies:
Albion, CenturyTel, Columbine, Direct Communications, Farmers Mutual, Filer Mutual, Fremont
Telecom, Mud Lake Telephone Cooperative, Potlatch, Project Mutual and Silver Star.
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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, dba as CenturyLink, 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.
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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
2011
Inspections 171
Rail cars inspected 1569
Violations 9
Rail cars with defects 215
Crossing accidents investigated 2
Crossing complaints 2
Locomotives Inspected 11
Defects within locomotives inspected 0
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Consumer Assistance
The Consumer Assistance staff responded to 1,886 complaints, comments or inquiries in
calendar year 2010, of which 90 percent were from residential customers.
Breakdown of complaints by type of utility
Contacts regarding telecommunications companies: 32 percent
Contacts regarding energy (electric, gas) companies: 52 percent
Contacts regarding water companies: 10 percent
Non-utility related contacts: 6 percent
(Qwest Communications had 41 percent of telecommunication complaints; Idaho Power had 51 percent and
Intermountain Gas 21 percent of energy utility complaints and United Water had 32 percent of water complaints.)
Summary of service quality issues:
Disputed billings 23 percent
Credit and collection issues 33 percent
Miscellaneous 14 percent
Utility rates and policies 15 percent
Telecommunications issues 6 percent
Line extensions and service upgrades 1 percent
Service quality and repair 5 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 74 percent of consumer complaints required investigation by
the staff. About 39 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.
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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
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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
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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
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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
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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
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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
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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
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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
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City Electric Gas Tele
Woodland AVISTA None Qwest
Worley AVISTA/Kootenai None Verizon
Yellow Pine Idaho Power None Midvale
________________________________________________________________________
Questions regarding this report? Please call Gene Fadness at 334‐0339 or e‐mail to
gene.fadness@puc.idaho.gov.