HomeMy WebLinkAbout2011annualreport_draft.pdfIPUC Annual Report 2010
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The Honorable C.L. “Butch” Otter
Office of the Governor
Statehouse
Boise, ID 83720‐0034
Dear Governor Otter:
It is my distinct pleasure to submit to you, in accordance with Idaho Code
§61‐214, the Idaho Public Utilities Commission 2010 Annual Report.
It has been an extremely busy year at the Commission. Rate increase filings
from utilities are now almost an annual event. In addition to base rate
increases, there are also adjustments – usually increases – to other line items
on the customer bill. These include energy efficiency riders, annual
adjustments to account for the varying costs of power supply not already included in bases rates
and changes to the Bonneville Power Administration credit. Customers are increasingly
frustrated with not only the dollar amount but the frequency of the rate adjustment filings. The
Commission is continually challenged to find ways to make those increases as manageable as
possible and to reduce the frequency of filings.
Thanks to a large Power Cost Adjustment (PCA) reduction, Idaho Power Company customers
actually saw overall rates decline by an average 5.2 percent. Permanent base rates did increase,
by 1.4 percent but a PCA reduction of 6.6 percent netted a 5.2 percent decrease. Customers of
Avista Utilities in northern Idaho received a 9.25 percent electric increase and 2.6 percent gas
increase, but those increases are spread over three years. Avista requested a one‐time 14
percent increase. Avista’s Power Cost Adjustment was also an increase of 2.6 percent on the
electric side and 4.5 percent on the gas side. Further, Avista customers ended up paying another
2 percent due to a reduction in the Bonneville Power Administration credit. Rocky Mountain
Power customers received an average 6.8 percent increase after the utility originally sought a
13.7 percent increase. The increase for residential and small‐business customers is actually 5.5
percent, due to a 1.3 percent reduction in that utility’s energy efficiency rider.
There is good news to report in the areas of energy efficiency and development of renewable
power.
Customer participation in energy efficiency and demand side management programs have
resulted in significant reductions to energy use as well as electrical demand on utility
generation. Such savings preclude or delay the need for utilities to build new generation or
acquire it from more expensive sources. The success of these programs also present challenges
for the commission. The programs cost money and utilities are seeking increases in energy
efficiency riders to fund the programs. The commission is continuing to refine its methods in
testing the cost‐effectiveness of these programs to ensure that, even with a rider, customers
pay less in the long run because these programs are in place.
We are seeing a significant increase in power purchase agreements between our utilities and
developers using anaerobic digestion and other biomass sources as well as solar and wind. But,
as with energy efficiency, the success in renewable development poses challenges as well.
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Utilities are claiming wind is coming online too quickly. They are seeking a reduction in the
eligibility cap – now set at 10 megawatts – under which projects can qualify for commission
posted rates under the provisions of the Public Utilities Regulatory Policies Act, or PURPA. That
case will be ongoing through early 2012.
Our dedicated staff is working on several additional projects you will find outlined in the pages
of this report. This is my last year on the Commission. It has been a privilege and an honor to
serve you and the citizens of Idaho.
Sincerely,
Jim Kempton
President
Idaho Public Utilities Commission
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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
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 2009 calendar
year. (The financial report on Page 8 covers Fiscal Year July 1, 2009 through June 30, 2010.)
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
Jim D. Kempton
Commissioner Kempton began his service on the commission on Oct. 22,
2007. Kempton was appointed by Gov. C.L. “Butch” Otter to fill the unexpired
term of Commissioner Paul Kjellander who was appointed to head the newly
created Office of Energy Resources. On April 6, 2009, Commissioner
Kempton was elected president of the commission.
Before he was appointed to the commission, Kempton was one of two
Idaho representatives on the Northwest Power and Conservation Council,
appointed to that post by former Idaho Gov. Dirk Kempthorne. While on the
council, he also acted as a natural resource cabinet member for Gov. Otter.
Kempton, of Albion, was a member of the Idaho House of Representatives from 1991‐2000,
where he served on the House Revenue and Taxation Committee and chaired the
Transportation and Defense Committee. Earlier, he served for two years on the Environmental
Affairs Committee. Kempton earned his bachelor's and master's degrees in physics from the
University of Idaho. He was a fighter pilot in the United States Air Force and an associate
professor of physics at the United States Air Force Academy. He also worked in the Pentagon as
Department of Defense liaison between the Secretary of Commerce and Secretary of Defense
on international co‐production programs. His Pentagon assignments included Air Force research
and development responsibilities in the F‐16 fighter program and coordinating Iranian Program
Review briefings to the Secretary of the Air Force. He returned to Idaho in 1981 and was
engaged in ranching until 1990, when he was elected to the Idaho Legislature. He is a former
member of the "Idaho EPSCoR" Board, a National Science Foundation experimental program to
stimulate competitive research.
He and his wife, Susan, are the parents of two grown daughters.
Marsha H. Smith
Commissioner Smith is serving her fourth term on the commission. Her
current term expires in January 2015. Smith, a Democrat, served as
commission president from November 1991 to April 1995.
Commissioner Smith is 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
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University of Washington.
Before her appointment to the commission, Commissioner Smith served as deputy attorney
general in the business regulation/consumer affairs division of the Office of the Idaho Attorney
General and as deputy attorney general for the Idaho Public Utilities Commission. She was the
commission's director of Policy and External Affairs and chair of the NARUC Staff Subcommittee
on Telecommunications.
A fourth‐generation Idahoan, Commissioner Smith has two sons.
Mack A. Redford
Commisisoner Redford was appointed to the commission in February
2007 by Gov. Butch Otter. During 2008 through April 2009, he served as
president of the commission. His term expires in January 2013. At the
time of his appointment, Commissioner Redford practiced law for the
Boise‐based firm of Elam & Burke PA, specializing in commercial
transactions, construction and engineering law, mediation, real estate and
general business.
Redford grew up in the Weiser and Caldwell areas, graduating from
Caldwell High School. He received both his bachelor’s and law degree
from the University of Idaho and in 1967 became a deputy in the Idaho attorney general’s office.
In 1977, he became a deputy attorney general for the Trust Territory of the Pacific Islands,
headquartered in Saipan, Northern Mariana Islands. The territory included a chain of 2,000
islands stretching from Hawaii to the Philippines.
In 1981, Redford became general counsel for Morrison Knudsen Engineers and Morrison
Knudsen International, a position that took him to Saudi Arabia where MK was building the King
Khalid Military City. In 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 Now serving
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Financial Summary
FISCAL YEARS 2005 ‐ 2009
Description FY2006 FY2007 FY2008 FY2009 FY2010
Personnel Costs $3,637,402 $3,467,401 $3,898,109 $4,072,505 $3,939,023
Travel $144,840 $146,491 $181,275 $136,859 $127,352
Consultants $40,518 $13,949 $16,041 $0.00 $3,498
Subscriptions $21,722 $28,321 $27,036 $22,883 $28,355
Emp. Training $34,424 $28,827 $33,190 $21,396 $17,079
Postage $8,408 $8,027 $7,174 $8,338 $8,019
Telephone $31,497 $28,007 $27,335 $27,910 $22,454
Office Supplies $14,709 $12,824 $17,697 $14,679 $15,307
Office Rent $115,468 $355,643 $236,497 $236,704 $252,906
Maintenance $8,652 $14,223 $15,817 $10,290 $15,694
Insurance $1,487 $2,702 $5,976 $6,380 $3,732
Office Equip. $0.00 $8,690 $5,279 $1,095 $2,973
Computer Equip. $22,874 $26,809 $15,934 $4,262 $3,185
Commissioner Equip. $3,973 $0.00 $0.00 $22,052 $0.00
Other Equip. $20,082 $0.00 $0.00 $0.00 $0.00
Other Expenses $108,604 $113,671 $122,130 $102,775 $92,913
=========================================================================
Total
Expenditures $4,214,660 $4,255,596 $4,609,484 $4,688,128 $4,531,990
Appropriations $4,754,600 $4,545,300 $4,944,400 $5,236,800 $5,266,100
‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐
Unexpended
Balance $539,940 $289,704 $334,916 $548,672 $734,110
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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.
Tell them no!
One of the most frequent questions we get after a utility files
a rate increase application is, “Why can’t you just tell them no?”
For much of the last 90 years, public utility regulation has
been based on the “regulatory compact” between utilities and
regulators: In return for an exclusive franchise (territory) granted
by regulators, utilities agree to serve all those
requesting service; and in return for agreeing to invest capital in
plant and facilities, utilities are given a reasonable opportunity to
earn a fair return on that capital.
In setting rates, the commission must consider the needs of
both the utility and its customers. The commission serves the
public interest, not the popular will. It is not in customers’ best
interest, nor is it in the interest of the State of Idaho, to have
utilities that do not have the generation, transmission and
distribution infrastructure to provide safe, adequate and reliable
electrical, natural gas and water service. This is a critical, even
life‐saving, service for Idaho’s citizens and essential to the state’s
economic development and prosperity.
Unlike unregulated businesses, utilities cannot cut back on
service as costs increase. As demand for electricity, natural gas
and water grows, utilities must meet that demand. In Idaho
recently, and across the nation, a continued increase in demand
as well as a number of other factors have contributed to rate
increases on a scale we have not witnessed before. It is not
unusual now for Idaho’s three major investor‐owned electric
utilities to file annual rate increase requests.
In light of these continued requests for rate increases, the
Commission walks a fine line in balancing the needs of utilities to
serve customers and customers’ ability to pay. When a rate case
is filed, our staff of auditors, engineers and attorneys will take up
to six months to examine the request. If we find the added
expense incurred by utilities was prudently incurred and needed
to serve customers, we have no choice but to allow the utility to
recover that expense. However we can, and often do, deny the
utilities’ recovery of expenses if we are confident we have the
legal justification to do so. All Commission decisions can be
appealed to the state Supreme Court.
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.
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
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participants in each case ‐ including utilities, public, agricultural, industrial, business and
consumer groups.
Administration
The Administrative Division is responsible for coordinating overall IPUC activities. The
division includes the three commissioners, two policy strategists, a commission secretary, an
executive administrator, an executive assistant and support personnel.
The two policy strategists are executive level positions reporting directly to the
commissioners with policy and technical consultation and research support regarding major
regulatory issues in the areas of electricity, telecommunications, water and natural gas.
Strategists are also charged with developing comprehensive policy strategy, providing assistance
and advice on major litigation before the commission, public agencies and organizations.
(Contact Lou Ann Westerfield, 334‐0323 and Wayne Hart, 334‐0354, policy analysts.)
The commission secretary, a post established by Idaho law, keeps a precise public
record of all commission proceedings. The secretary issues notices, orders and other documents
to the proper parties and is the official custodian of documents issued by and filed with the
commission. Most of these documents are public records. (Contact Jean Jewell, commission
secretary, at 334‐0338.)
The executive administrator has primary responsibility for the commission’s fiscal and
administrative operations, preparing the commission budget and supervising fiscal,
administration, public information, personnel, information systems, rail section operations and
pipeline safety. The executive administrator also serves as a liaison between the commission
and other state agencies and the Legislature. (Contact Ron Law, executive administrator, at
334‐0331.)
The executive assistant is responsible for public communication between the
Commission, the general public and interfacing governmental offices. The responsibility includes
news releases, responses to public inquiries, coordinating and facilitating commission
workshops and public hearings and the preparation and coordination of any IPUC report
directed or recommended by the Idaho Legislature or Governor. (Contact Gene Fadness,
executive assistant, at 334‐0339.)
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
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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 Dave Schunke, engineering section supervisor, at 334‐0355.)
The Telecommunications Section includes three analysts who handle issues involving
telecommunications. (Contact Joe Cusick, section supervisor, at 334‐0333.)
The Consumer Assistance Section includes six division investigators who resolve
conflicts between utilities and their customers. Customers faced with service disconnections
often seek help in negotiating payment arrangements. Consumer Assistance may mediate
disputes over billing, deposits, line extensions and other service problems.
Consumer Assistance monitors Idaho utilities to verify they are complying with
commission orders and regulations. Investigators participate in general rate and policy cases
when rate design and customer service issues are brought before the commission. (Contact
Beverly Barker, administrator for the Consumer Assistance section, at 334‐0302.)
Rail Section
The Rail Section oversees the safe operations of railroads that move passengers and
freight in and through Idaho and enforces state and federal regulations safeguarding the
transportation of hazardous materials by rail in Idaho. The commission’s rail safety specialist
inspects railroad crossings and rail clearances for safety and maintenance deficiencies. The Rail
Section investigates all railroad‐crossing accidents and makes recommendations for safety
improvements to crossings.
As part of its regulatory authority, the commission evaluates the discontinuance and
abandonment of railroad service in Idaho by conducting an independent evaluation of each case
to determine whether the abandonment of a particular railroad line would adversely affect
Idaho shippers and whether the line has any profit potential. Should the commission determine
abandonment would be harmful to Idaho interests, it then represents the state before the
federal Surface Transportation Board, which has authority to grant or deny line abandonments.
(Contact Ron Law, rail section supervisor, at 334‐0331.)
Pipeline Safety Program
The pipeline safety section oversees the safe operation of the intrastate natural gas
pipelines and facilities in Idaho. The commission’s pipeline safety personnel verify compliance of
state and federal regulations by on‐site inspections of intrastate gas distribution systems. Part of
the inspection process includes a review of record‐keeping practices and compliance with
design, construction, operation, maintenance and drug/alcohol abuse regulations.
Key objectives of the program are to monitor accidents and violations, to identify their
contributing factors and to implement practices to avoid accidents. All reportable accidents will
be investigated and appropriate reports filed with the U.S. Department of Transportation in a
timely manner. (Contact Ron Law, pipeline safety program supervisor, at 334‐0331.)
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Electrical Power in Idaho
Idaho residents consistently enjoy some of the least expensive electric service in the nation,
according to surveys conducted by the National Association of Regulatory Utility Commissioners
(NARUC), the Edison Electric Institute and the Energy Information Administration of the U.S.
Department of Energy.
Idaho Power Company
2009 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
391,759 Residential Customers/$0.0778
76,494 Commercial Customers/$0.0620
120 Industrial Customers/$0.0452
Avista Utilities
2009 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
104,609 Residential Customers/$0.0828
16,484 Commercial Customers/$0.0802
486 Industrial Customers/$0.0518
2009 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
PacifiCorp/Rocky Mountain Power
56,430 Residential Customers/$0.0827
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8,082 Commercial Customer/$0.0700
5,545 Industrial Customer/$0.0536
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Summary of major electric rate cases
Case Nos. IPCE1006,07 and 08 and 12.
May 28, 2010
Idaho Power rates decline slightly with four adjustments
Rates for Idaho Power Company customers will decrease an average 5.2 percent as the result of
four rate adjustments approved today by state regulators.
The commission approved the annual Power Cost Adjustment, an average 6.5 percent decrease,
and three smaller increases. The percentage of decrease will vary because the adjustments
don’t apply to all customer classes and vary in size according to customer class. For residential
customers, the PCA decrease is 3.2 percent and the overall rate decrease, after the increases in
the three other cases, is 1.4 percent. The adjustments are effective June 1.
Below is a summary of the four rate adjustments.
Power Cost Adjustment (6.5 percent decrease) – Every year on June 1, customers receive
either a one‐year surcharge or credit, depending on streamflows and market conditions from
the previous year, a forecast of the next year’s conditions and a true‐up of the previous year’s
forecast.
This year’s power supply costs not included in base rates are anticipated to be $42.2 million, far
less than 2009’s $188.9 million, resulting in a PCA reduction of $146.7 million. As the result of a
stipulated agreement reached with Idaho Power in January, $88.7 million of that PCA reduction
will be included in permanent base rates, thus avoiding an Idaho Power rate case this year. The
January agreement stipulates that Idaho Power base rates will not increase again until January
2012 at the earliest. The remaining $58 million of the PCA reduction goes directly to customers.
The impact on the PCA surcharge is a reduction from 1.4 cents per kWh to 0.31 cents per kWh.
The power cost surcharge covers expenses, not already included in base rates, which Idaho
Power incurs to provide energy to its customers. During low water years, Idaho Power must rely
on more expensive sources of power than that generated from its 17 hydroelectric plants.
Power supply expenses vary due to the always fluctuating prices for natural gas or changing
market prices for wholesale power, thus the need for a yearly adjustment to rates. None of the
money collected from the PCA surcharge can go to increase company earnings, but can be used
only to pay off power supply and related expenses.
Automated meter installation (0.41 percent increase) – Idaho Power may include $2.36 million
in base rates for the second year of a three‐year installation of automated meters throughout its
territory. The company is replacing its existing meters with advanced metering infrastructure
(AMI) that will eventually allow customers to monitor electric prices and adjust their use to take
advantage of lower price‐periods. Idaho Power submitted a cost estimate of $71 million for the
project and will absorb any costs above that. At the end of the second year, expenditures are at
$47.3 million.
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In early 2009, the commission directed Idaho Power to "move forward with all deliberate speed"
with installation. The meters were installed last year in the Boise area and are being installed
this year in Canyon and Payette counties and surrounding regions. During 2011, meters will be
installed in the Magic Valley, Pocatello and Salmon areas.
The advanced meters can be read from a remote location, negating the need for an Idaho Power
representative to access customer properties. They can provide the company and individual
customers with hourly meter readings and inform customers of current electric prices, allowing
them to manage their use and reduce their bills.
“As we did in 2009 … we continue to find that both present and future public convenience will
be served through the enhanced outage management and billing accuracy, as well as reduced
operating and maintenance expenses,” the commission said. Implementation of AMI “will
inevitably benefit customers and lower the pressure for increased rates,” the commission said.
Fixed Cost Adjustment (1.85 percent increase) – The commission is allowing the company to
recover about $6.3 million in under collected fixed costs from residential and commercial
customers.
The FCA was implemented in 2007 as a pilot program. The FCA allows Idaho Power to recover
the fixed costs (but not to exceed 3 percent) it loses when conservation programs result in lower
power sales. Without a mechanism like the FCA, there is a financial disincentive for utilities to
promote energy efficiency and conservation programs because they lose money when those
programs are successful. The FCA allows Idaho Power to recover its fixed costs as established in
the most recent rate case. If the company under collects its fixed costs, 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.
This year, Idaho Power reports it under collected $5.17 million in fixed costs from the residential
class and $1.16 million from the small‐business class. This was due largely to a 7.6 percent
increase in energy savings during 2009 and a 28 percent reduction on the company’s energy
demand during peak‐use periods.
The Idaho Conservation League submitted comments supporting the FCA, but said the
commission should require Idaho Power to “better articulate the benefits customers receive
from the FCA mechanism.”
The expansion of conservation programs since implementation of the FCA help keep rates lower
than they would otherwise be. Reducing demand on a utility’s generating system, particularly
during times of peak‐use, is less expensive per kilowatt‐hour than building new power plants to
meet demand. By enrolling in conservation programs, customers can benefit by using electricity
more efficiently, reducing consumption and bills. Even customers who don’t directly participate
benefit because the cost of the electricity saved system‐wide through these programs is about
half the cost of electricity generated by a new power plant.
The FCA will continue as a pilot program for two more years to allow for more data to
accumulate and to correct problems.
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Pension Funding (0.77 percent increase) – The commission is allowing Idaho Power to increase
rates by 0.77 percent to allow it to collect $5.4 million over 12 months to replenish its pension
plan. The company’s contributions to its pension plan have always been included in base rates.
However, since 2003, Idaho Power was not required to contribute to the pension 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 begin funding the
plan again. The commission said this year’s amount due may be recovered over 12 months, but
cautioned Idaho Power that recovery of this year’s expense does not ensure the same level of
benefit in future years.
The commission suggested Idaho Power consider alternative pension plans. “It is unreasonable
for Idaho Power’s customers to be solely responsible for large contributions to the company’s
defined pension plan. Many employers in recent years have replaced their defined benefit plans
with pension programs that place greater responsibility and investment risks on employees.
Idaho Power must similarly consider changes to its retirement plan and address shareholder and
employee liabilities in the assignment of pension plan investment risk. The commission will not
approve additional pension plan contributions from customers without evidence that Idaho
Power has carefully reviewed alternatives to reduce the burden placed on customers.”
The commission’s orders in all four cases are final. Interested parties may petition the
commission for reconsideration by no later than June 18. Petitions for reconsideration must set
forth specifically why the petitioner contends that the order is unreasonable, unlawful or
erroneous. Petitions should include a statement of the nature and quantity of evidence the
petitioner will offer if reconsideration is granted.
Case Nos. AVU‐E‐10‐01, AVU‐G‐10‐01
September 21, 2010
Commission adopts settlement of Avista rate case
The commission adopted a settlement to the Avista Utilities electric and gas rate cases that
increases electric rates an average 9.25 percent over three years and gas rates an average 2.6
percent over two years. The first year electric increase is 3.59 percent and the first year gas
increase is 1.9 percent, both effective Oct. 1.
The commission said the settlement “represents a reasonable compromise to the positions and
we find it in the public interest.”
“In particular, we note the Stipulation and Settlement represents a significant reduction in the
request revenue increase. More specifically, the first year increase in electric rates contained in
the Stipulation and Settlement is 3.59 percent rather than the 14 percent originally proposed by
Avista,” the commission said.
The commission said it recognized “that initial disputes among the parties were numerous and
significant. This case has generated many customer comments opposed to the rate increases
originally requested by the company.”
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Avista originally requested a $32.1 million increase in annual electric revenue and a $2.6 million
increase in annual gas revenue. The settlement approved by the commission gives the company
$21.2 million spread over three years in electric revenue and $1.85 million spread over two
years in gas revenue. Helping to offset the increase was a $17.5 million deferred state income
tax benefit.
The three‐year phased rate increase effective dates are as follows:
‐‐ Oct. 1, 2010 ‐‐ 3.6 percent electric and 1.9 percent gas.
‐‐ Oct. 1, 2011 – 3.9 percent electric and 0.72 percent gas.
‐‐ Oct. 1, 2012 – 1.74 percent electric and 0 percent gas.
Parties to the case which supported the settlement included Avista, commission staff, Idaho
Forest Group, Clearwater Paper Association, the Idaho Conservation League, the Snake River
Alliance and the Community Action Partnership Association of Idaho, the latter which represents
customers on low‐ and fixed‐incomes. The Idaho Community Action Network did not participate
in settlement discussions, but submitted comments opposing any rate increase. North Idaho
Energy Logs also intervened in the case but did not file comments.
The rate case settlement is the first of two rate adjustments proposed this year. The second is
the company’s annual Power Cost Adjustment, (PCA) which would increase rates for one year an
average 2.6 percent. The commission is expected to rule on that request in the next few days.
For a residential customer who uses the average residential consumption of 1,000 kWhs per
month, the rate effective Oct. 1 would increase a bill by about $3.50 per month from $80.90 to
$84.40. If the one‐year PCA is approved, an average residential bill would increase by another
$1.88 per month. The customer service charge for electric customers increases from $4.60 to $5
per month. The gas customer service charge of $4 per month does not increase. Avista originally
requested an increase to $6.75 per month for both customer service charges.
The adopted settlement ends a case that began last March.
The commission is well aware of the impact of rate increases in today’s economy, particularly on
customers with low and fixed incomes. “We do agree with those comments that Avista needs to
‘tighten its belt’ to reduce costs and improve its efficiencies,” the commission said. Avista and
other parties in the case need to be “diligent in finding efficiencies or instances where the
company’s costs may be unreasonable,” the commission said. The phased‐in rate increase and
tax credit help mitigate the impact of the increase given the current state of the economy.
“Understandably, most of the customers submitting comments oppose Avista’s initial double‐
digit rate increase,” the commission said. While the commission does all it can to find expense
reductions and other methods to mitigate the impact of rate increases, state law does not allow
the commission to outright reject rate increases. State statutes require that all regulated utility
rate requests be considered by the commission to determine whether the expenses the utility
seeks to recover through customer rates are needed to serve customers and if they are
prudently incurred. The commission may deny expense recovery if the utility fails to provide
evidence that adequately supports the new expenses as needed to serve customers and
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prudently incurred. All commission decisions can be appealed to the state Supreme Court by the
utility, intervenors or customers.
The settlement increases funding for low‐income weatherization from $465,000 to $700,000 per
year. The fund will permit more low‐income customers and senior citizens to weatherize their
homes resulting in lower energy bills. The settlement also provides $40,000 to Community
Action Partnership agencies for low‐income outreach and education programs about energy
conservation. Avista will conduct five energy conservation workshops for senior citizens in five
Idaho communities no later than Dec. 31, 2011.
When Avista filed the rate case in March, it said the increases are necessary because of
escalating power supply costs, increased costs to meet new federal requirements that ensure
reliability, and the need to replace aging infrastructure.
Power supply contracts that provide Avista customers with about 100 average megawatts,
about 10 percent of the company’s entire retail load, expire at the end of this year. The power
provided by these contracts is about 3 cents per kilowatt‐hour, which is well below the cost to
replace that power. Also included in this case were about $21 million in costs related to a
power purchase agreement with the owners of the Lancaster natural gas generating station
near Rathdrum. About 80 percent of Avista’s increase is attributable to the Lancaster
agreement, termination of the low‐cost power contracts and increased customer load.
Case No. AVU‐E‐10‐03
October 1, 2010
Avista PCA is 2.6 percent increase
Avista’s electric customers will pay an average 2.6 percent more for the company’s yearly Power
Cost Adjustment, which tracks the always changing costs of electric power supply. For an
electric customer who uses an average of 1,000 kWh per month, the increase is about $1.88 per
month.
Below‐normal hydro generation and costs associated with the Lancaster generating plant
resulted in more power supply expense than is already included in base rates resulting in
Avista’s one‐year 2.6 percent Power Cost Adjustment (PCA) surcharge.
The two major components of Avista customers’ electric bills are the base rate, which covers
primarily fixed costs that don’t change from year to year, and the PCA rate. The PCA increases or
decreases rates depending on conditions outside the company’s control that can dramatically
alter power supply expense. Those conditions include variations in hydroelectric generation
caused by lack of stream flows, unanticipated changes in fuel costs and changes in wholesale
market prices for energy.
During those years when power supply expenses are less than what is already covered in base
rates, customers receive a credit. During years when power supply expenses are greater than
included in base rates, customers get a surcharge. Both the surcharge and credit last for 12
months and then a new adjustment will be calculated to adapt to changing conditions and
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updated projections. The updated PCA is effective Oct. 1 of each year. Unlike a general rate
case, a PCA increase does not increase company earnings. The PCA surcharge is collected from
ratepayers, kept in a deferred account, and then passed directly to wholesale power and fuel
suppliers.
The PCA surcharge effective Oct. 1 increases from 0.34 cents per kWh to 0.53 cents per kWh.
Case No. AVU‐E‐10‐04, Order No. 32100
October 28, 2010
Change in BPA credit results in increase to Avista customers
The adjustment is the result of a settlement between the Bonneville Power Administration and
Avista regarding the size of a credit the BPA gives to residential and small‐farm customers of
investor‐owned utilities in four Northwest states. The commission has no role in determining
the size of the credit.
Effective Nov. 1, the credit is reduced from 0.289 cents per kWh to 0.147 cents per kWh. For a
residential customer whose electrical consumption is the company’s average, the result of the
reduced credit is about a $1.42 per month increase.
A 2007 federal court decision reallocated much of the credit to customers of publicly owned
utilities, after the court determined that customers of investor‐owned utilities, like Avista, have
been overpaid during the most recent years the credit had been in place. The settlement
reduces the credit to comply with that ruling and also to settle some outstanding accounts
Avista had with BPA.
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.
Case No. PAC‐E‐10‐07, Interlocutory Order No. 32151
December 27, 2010
Rocky Mountain residential customers get net 5.5 percent increase
Residential customers of Rocky Mountain Power will pay a net increase of about 5.5 percent in
electric rates effective January 1. For all customer classes combined, the average base rate
increase approved by the commission is 6.78 percent.
Rocky Mountain Power, serving 70,000 customers in eastern Idaho, filed last May with the
commission for an average 13.7 percent rate increase. In October, Rocky Mountain Power
lowered its request to 12.3 percent, seeking an additional $24.9 million in annual revenue. The
additional annual revenue requirement approved by the commission is $13.75 million.
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The commission adjusted the amount allowed in rates by reducing pension expanse and
eliminating wage increases which, the commission said, addresses some of the concerns of
customers and takes into account the economy in southeast Idaho. The commission also
reduced the company’s proposed investment it sought to include in rates for the Populus to
Terminal transmission line from eastern Idaho into northern Utah.
The commission conducted two public workshops, a three‐day technical hearing and five public
hearings during the six‐month investigation of the case and received hundreds of written
customer comments. The commission was pleased by the large turnout at the public workshops
and hearings where customers expressed concern about rate increases given the current state
of the economy and also about paying for wind and transmission projects they thought would
benefit other states and not Idaho. “Customers may rest assured that this commission will never
approve expenses for generation and transmission projects that do not benefit customers in
Idaho,’’ said Commissioner Marsha Smith, who chaired the hearings.
For residential customers, the average base rate increase is 6.8 percent. However, the
commission reduced customers’ Energy Efficiency Charge from 4.72 to 3.4 percent, resulting in a
net average increase for residential customers of about 5.5 percent.
Residential customers will actually pay less than the current rate for their first 700 kilowatt‐
hours of use in the summer months and their first 1,000 kWhs of use in the winter months. The
commission approved a two‐tiered rate structure that increases rates as consumption increases.
From May to October, standard residential customers will pay 9.58 cents per kWh for their first
700 kWh. The current May‐October rate is 10.4 cents. For use exceeding 700 kWhs during
summer, the new rate is 12.9 cents. From November through April, residential customers will
pay 7.33 cents per kWh for the first 1,000 kWhs. The current winter rate is 8 cents. For use
above 1,000 kWh, the rate is 9.9 cents.
The commission rejected a Rocky Mountain Power request to increase rates of residential
customers in the optional Time of Day program by 15.6 percent, while increasing standard
residential customer rates by 8 percent. Instead, the commission approved the same percentage
increase for all residential customers.
For the other major customer classes, the average increase with the company’s proposal in
parenthesis is as follows:
• General service (commercial) – 4.5 percent (9.7)
• General service (large power) – 7.4 percent ((13.3)
• Irrigation – 2.9 percent (7.6)
• Monsanto – 9.6 percent (18.2)
• Agrium – 9.4 percent (14.7)
The commission approved an upper limit of Return on Equity at 9.9 percent, less than the
company’s current ROE of 10.25 percent and its requested ROE of 10.6 percent. The utility is not
guaranteed an ROE, but an opportunity to earn a return of up to 9.9 percent on the investments
it makes to serve customers. Under its previous ROE of 10.25 percent, the company earned an
average 6 percent over the last 10 years.
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Addressing the continued needs of the low‐income sector in Rocky Mountain’s Idaho territory,
the commission increased the company’s annual funding level for low‐income weatherization
from $150,000 to $300,000.
A final order in this case will not be issued until late February. Issues related to the contract
between Rocky Mountain Power and its largest customer, Monsanto, will be further examined
over the next two months, with a technical hearing scheduled for Feb. 1. The final order will
determine what Monsanto should be paid for allowing Rocky Mountain to interrupt service
during certain times of the year.
Case No. PAC‐E‐10‐01, Order No. 31033
April 2, 2010
First ECAM will raise Rocky Mountain rates about 1.3 percent
The commission has accepted the first Energy Cost Adjustment Mechanism (ECAM) for
PacifiCorp, which does business as Rocky Mountain Power in eastern Idaho.
The mechanism allows the utility to recover power supply expense not already included in base
rates. Rates for residential users will increase by about 1.29 percent, effective April 1, or about
90 cents per month. Irrigation rates increase by 1.55 percent and commercial rates 1.34
percent.
The annual adjustment will better match customer rates with the actual cost of providing power
and should reduce the frequency of filings by the company for general rate increases.
The ECAM will be adjusted up or down every April 1. If net power costs are higher than those set
in the most recent general rate case, the company collects the difference through a one‐year
surcharge listed as a separate item on customer bills. If net power costs are lower, customers
receive a one‐year credit. In this filing, Rocky Mountain claimed that net power costs for the
latter half of 2009 were $2.2 million higher than what was collected in base rates. The
commission accepted $2 million of those expenses.
Power costs include expenses for coal, natural gas and electricity that Rocky Mountain buys on
the wholesale market. Revenue the company makes from sales of electricity or natural gas on
the market is credited to customers. During those years when there is a surcharge, all the
revenue collected from the surcharge must go toward paying power supply costs. ECAM
revenue cannot be used to increase company earnings. Power supply costs are placed in a
deferred account audited by the commission.
A greater portion of PacifiCorp’s generation now comes from natural gas. The utility also gets
about 30 percent of its generation from hydropower. Changing water conditions and volatility in
the natural gas markets can cause fluctuations that sometimes result in power supply expense
that is greater than that already included in base rates and sometimes in power supply expense
that is less than that included in base rates.
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The yearly ECAM should also decrease borrowing costs for the company. Rocky Mountain Power
is in a period of increased generation and transmission investment to meet customer demand.
Assurances to financial markets of timely recovery of expenses allows for financing at lower
interest rates, benefitting both the company and its customers.
To encourage the company to be prudent in its power supply purchase decisions, the ECAM
requires that shareholders pay 10 percent of the power supply expenses not already included in
rates.
Case No. PACE1003, Order No. 32023
July 6, 2010
PUC approves part of efficiency services rate request
State regulators have allowed Rocky Mountain Power to increase its “Customer Efficiency
Services Rate,” from 3.72 percent of customer bills to 4.72 percent effective July 1.
The company originally sought an increase to 5.85 percent of customer bills, but the commission
said there are some issues that need further examination before Rocky Mountain will be able to
recover all its expenses related to funding programs that reduce demand on the utility
generation system (often referred to as “demand‐side management” or DSM programs). The
efficiency services rate also funds programs that promote efficient use of electricity.
The issues that need further examination will be addressed during the course of Rocky
Mountain’s base rate case pending before the commission. In that case, likely to continue
through this year, Rocky Mountain is requesting an average 13.7 percent increase to base rates.
The Customer Efficiency Services Rate is a separate item from the base rate on customer bills.
The revenue collected from this rate must be directed only to investment in DSM and energy‐
efficiency programs and, unlike the base rate, cannot be used to increase company earnings.
The commission said it “strongly supports” and commends Rocky Mountain Power “for its
commitment to providing its customers with DSM and energy efficiency options.” When
customers are able to reduce demand on Rocky Mountain Power’s generation through the
irrigation load control or the Home Energy Efficiency Program, the need for the utility to build
new generation or buy more costly power from other sources is delayed or eliminated, resulting
in lower energy costs for both the company and its customers. “All customers benefit from
deferring the costs of (the company) having to acquire new supply‐side resources,” the
commission said.
Rocky Mountain invests about $5.2 million in seven conservation programs, but the programs
generated $17.1 million in customer benefits during 2009. Due in part to increased customer
participation in the southeast Idaho utility’s conservation programs, Rocky Mountain sought to
increase its yearly investment in the programs from $5.2 million to about $8.3 million. The
increase approved by the commission results in a yearly investment of about $6.7 million.
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The Idaho Conservation League and the Idaho Irrigation Pumpers Association said the expenses
related to the irrigation load control program should be moved to base rates because of the size
of the program. Even though the energy efficiency rate funds seven programs, about half the
cost of the programs is related to the irrigation program.
The Idaho Conservation League said the irrigation program “most closely resembles a supply‐
side resource” operating much like a generation plant with a quantifiable amount of energy that
can be dispatched as irrigators simultaneously reduce their consumption. Participation in the
irrigation load control program provided Rocky Mountain with 285 megawatts of generation
during 2009. One megawatt is one million watts, enough electricity to power about 650 average
homes.
Moving the cost of the irrigation load control program to base rates would free up more
revenue from the efficiency services rate to be directed to residential programs, the Idaho
Conservation League said.
Residential efforts include the Home Energy Efficiency program, which offers financial incentives
to customers to invest in energy‐efficient washing machines; refrigerators; water heaters;
dishwashers; lighting; cooling equipment and services; ceiling, wall and attic insulation; and
windows. The lighting savings program resulted in a four‐fold increase in lighting savings from
2008 to 2009. There is also a low‐income weatherization program and a refrigerator recycling
program, the latter resulting in 725 units recycled during 2009.
The Idaho Irrigation Pumpers Association said the costs of the irrigation load control program
should be shared by other customers in Rocky Mountain’s region rather than solely Idaho
customers because there is a system‐wide benefit to reduced demand on generation. The
irrigators said there should be no increase to the efficiency services rate. That could be
accomplished, they argued, by removing expenses related to the irrigation control program and
fund the remaining programs at the previously existing 4.72 percent level.
Rocky Mountain countered by saying the ability to recover its expenses for DSM and energy‐
efficiency programs removes a disincentive to invest in the programs because the resulting
energy reduction could render the company unable to recover its prudent expenses and earn a
rate or return.
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Other major electric cases
Case No. IPCE0930, Order No. 30978
January 14, 2010
Commission adopts rate moratorium agreement
The commission is accepting a settlement between Idaho Power Company and a number of
customer groups that places a moratorium on general rate case increases until January 2012
while, at the same time, giving the utility a better opportunity to earn its allowed rate of return.
Idaho Power was in the early stages of filing a rate case last fall that could have resulted in a
base rate increase of between 10 and 20 percent effective this June. Instead, the utility and
parties to the settlement negotiations reached an agreement that allows Idaho Power to use
some of the anticipated reduction customers will get in the Power Cost Adjustment (PCA)
surcharge this spring and to accelerate investment tax credits it receives to bolster its earnings.
The agreement is signed by representatives of irrigation customers, industrial and major
commercial customers and representatives of low‐income residential customers. “It is notable
that all of Idaho Power’s major customers and customer groups participated in the discussions
leading to the stipulation, and all determined it presented a better alternative to the likely
results of a rate case,” the commission said.
One of the participants, the Snake River Alliance, said “the revenue sharing, PCA sharing, and
rate case moratorium components of the settlement in this case serve the company and its
customers as well as possible in our current economic times.”
The Community Action Partnership Association of Idaho (CAPAI), which represents low‐income
residential customers, said that “given the company’s recent substantial investments in
infrastructure … and given that the company had incurred relatively high costs during the test
year, CAPAI believes a general rate case would likely have resulted in an end‐result more costly
to Idaho Power ratepayers….”
An anticipated significant reduction in the annual Power Cost Adjustment made this a good year
for the agreement. Every year on June 1, Idaho Power customers get either a PCA surcharge or a
credit on their bills, largely depending on the previous year’s water levels and market
conditions. It is anticipated that this year’s PCA will be a significant decrease to customers,
though how much of a decrease won’t be known until after April 15. This agreement allows the
first $40 million of the anticipated PCA reduction to be shared equally between the customers
and the company. The PCA reduction between $40 million and $60 million will go directly to
customers as a rate reduction. The next block of up to $75 million will cover the company’s
permanent power supply expense account. Should the PCA reduction exceed the $60 million
and the amount applied to power supply expense, the next $10 million will be shared between
customers and company and any amount beyond that will go directly to reduce customers rates.
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The agreement also allows Idaho Power to accelerate its use of tax credits it receives on its
capital investments to shore up its earnings. The agreement allows the company to accelerate
up to $45 million of investment tax credits at $15 million a year for three years if its rate of
return falls below 9.5 percent. Idaho Power proposes to share earnings with customers through
rate reductions if the company’s ROE is higher than 10.5 percent. Idaho Power has not been
able to earn its authorized rate of return in either its Idaho or Oregon jurisdictions for the last
decade.
Improved earnings are important to maintain Idaho Power’s ability to finance ongoing plant
investments needed to serve customers, the commission said. “The company’s increased
financial stability benefits customers by enabling the company to delay rate cases and
potentially lower interest costs. It is beneficial to customers and to Idaho Power if the company
can enhance its ability to stabilize earnings in the near term, strengthening the company’s
position in the financial markets and enabling it to reduce the cost of borrowing funds for
operations or plant investment.”
The moratorium applies only to changes in base rates. It does not include possible increases or
decreases to the annual PCA or the annual Fixed Cost Adjustment. It also does not include
possible increases to energy efficiency riders or increases related to recovery of costs for
advanced metering infrastructure, pension expense or funding for low‐income weatherization.
Case No. IPCE1003, Order No. 30999
February 19, 2010
PUC plans workshop on competitive bidding guidelines
Staff from the commission will be conducting a public workshop regarding the possible creation
of commission‐established bidding guidelines for Idaho Power Company.
Independent power producers, as well as group representing industrial and irrigation customers,
last November filed a petition with the commission asking that it consider establishing
competitive bidding guidelines for the procurement of major generation projects by Idaho’s
three major electric utilities. However, Rocky Mountain Power, which operates in eastern Idaho,
and Avista Utilities in northern Idaho are already subject to guidelines established by other
states in which they operate. Because those utilities currently use those guidelines for projects
that serve Idaho, the original application was modified to include only Boise‐based Idaho Power
Company.
The groups petitioning the commission contend that Idaho Power is free to issue bid requests
that are “designed and administered completely without commission or other stakeholder
input.”
The petitioners pointed specifically to the $400 million, 330‐megawatt Langley Gulch natural gas
plant the commission approved last fall. The Idaho Power‐owned plant is under construction
near New Plymouth.
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In that case, Idaho Power initiated a bid process that was reviewed by a third party. Idaho Power
received five valid proposals that represented 13 alternative sources, including a proposal by the
company to build the plant itself. Idaho Power selected its own self‐build plan, claiming it will
have a revenue requirement impact of about $95 million less than the next competing proposal.
Some parties in the case argued the bid process was flawed, because, among other reasons, the
bid evaluator was hired by the company and there was not an independent scoring by the bid
evaluator. The parties also maintained that Idaho Power should have more seriously considered
a “build‐and‐transfer project.” which would allow a third party to build the plant and then turn it
over to Idaho Power to operate.
In approving the project, the commission acknowledged the bid process could have been more
transparent and that the “total universe of potential bidders was perhaps not realized.”
However, the commission said, “Based on the evidence presented, we cannot conclude that a
lower price and better project would have resulted” if the bid process had been better designed.
The commission said it was apparent that the competitors were “sophisticated bidders and that
the short list of projects were all competitive.”
As a result of the questions raised in the Langley Gulch case, the commission said it would open
a case to investigate bidding guidelines. “The actual and perceived flaws in the RFP (Request for
Proposals) process, we find, while not fatal to the company’s resource selection, clearly
demonstrate a need for a separate proceeding to consider RFP competitive bidding rules and
guideline,” the commission said.
Case No. PACE0907, Order No. 31021
March 23, 2010
PacifiCorp can assess slightly higher rate to wind producers
The commission is allowing PacifiCorp, which does business as Rocky Mountain Power in eastern
Idaho, to charge a higher wind integration rate to developers of small wind projects, but not as
large as requested.
Currently, PacifiCorp charges developers an integration rate of $5.10 per megawatt‐hour. Citing
increased costs to integrate wind into its overall generation portfolio, PacifiCorp requested a
rate of $9.96 per MWh. The commission granted $6.50 per MWh, which is the same as the
maximum amount allowed other utilities buying from small wind projects in Idaho, including
Avista Utilities and Idaho Power Company.
The wind integration rate is intended to capture from developers of small‐wind projects the cost
the utility incurs to integrate wind into its transmission grid. Included in those costs are
adjustments utilities make in their choice of generation options in order to accommodate wind.
Also, because wind generation is unpredictable, utilities must have back‐up generation in place
for those times when wind is not producing the output anticipated.
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The wind integration rate is discounted from the overall rate utilities must pay wind developers
who qualify under the provisions of the federal Public Utility Regulatory Policies Act of 1978
(PURPA). Under PURPA, qualifying generators of small‐power projects that generate up to 10
megawatts are paid a rate published by the commission. Wind integration costs are subtracted
from the published rate.
PacifiCorp claims an updated study shows that it costs the utility in the range of $9.96 to $11.85
per MWh to integrate wind into its system. However, the Portland‐based Renewable Northwest
Project, which promotes the development of renewable energy, recommended the increase be
denied because of flaws in the PacifiCorp study.
The commission noted there is no consensus on the methodology used to calculate wind
integration costs. This case is not the appropriate forum to select a methodology, the
commission said.
In setting the rate at $6.50, the commission acknowledged that PacifiCorp has added wind
resources since the original $5.10 rate was set and that “integration costs have likely increased.”
“We encourage PacifiCorp to continue to refine its wind integration cost analysis,” the
commission said. “We expect it to consider in its analysis and studies, the results of regional
efforts and studies.” PacifiCorp recently initiated a new integration study it expects to complete
in late summer.
Case No. IPC‐E‐09‐28, Order No. 31063
April 30, 2010
Decoupling mechanism will continue as “pilot” program
The commission is denying a petition by Idaho Power Company to make the pilot Fixed Cost
Adjustment (FCA) program permanent. The results of the program are “mixed” and there are
still too many unanswered questions, the commission said. However, the commission allowed
the program to continue for another two years as a pilot program.
“We are pleased with the company’s increased efficiency efforts,” the commission said.
“However, the issues and potential concerns with the FCA, as identified by the parties in this
case, support a conclusion that making the FCA permanent at this point is premature.”
Regulated utilities have a built‐in disincentive to invest in energy efficiency and conservation
programs because they lose revenue when consumption declines. To remove that disincentive,
the Fixed Cost Adjustment was implemented by the commission three years ago for Idaho
Power on a pilot basis. The adjustment is designed to ensure the company recovers its fixed
costs of serving customers regardless of the amount of energy conservation. Often referred to
as “decoupling,” the FCA decouples the link between energy efficiency and energy sales.
If the actual fixed costs recovered from customers by Idaho Power are less than the fixed costs
authorized in the most recent rate case, residential and small‐commercial customers get a
surcharge. If the company collects more in fixed costs than authorized by the commission,
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customers get a credit. After the program’s first year, customers received a credit (0.8 percent).
In the second year, there was a surcharge (.82 percent) and a surcharge (1.85 percent) is
proposed this year.
With implementation of the FCA, the commission expected Idaho Power to significantly increase
the size and availability of energy efficiency programs, which the commission said the company
has done.
There have been reductions in energy consumption, but commission staff and other groups who
intervened in the case argued that other variables such as economic conditions, high
unemployment, weather and adoption of building codes can all result in energy reduction
regardless of Idaho Power’s investment in energy conservation programs.
“Any approved decoupling mechanism should not reward the utility unduly for reductions in
consumption resulting from conditions the utility did not sponsor or create,” said the
Community Action Partnership Association of Idaho (CAPAI), which, along with commission staff
and the Idaho Conservation League, opposed making the program permanent. CAPAI also
expressed concern about impact on rates for customers on fixed and low incomes. While
commission staff and these groups did oppose making the program permanent, they did not
oppose allowing the program to continue on a pilot basis. AARP Idaho, however, said the FCA
should be discontinued entirely.
The commission agreed with comments from commission staff and the Idaho Conservation
League that disagreements remain about the accuracy of the amount of fixed cost identified for
recovery because a cost of service study that established that fixed cost is not recent and was
never approved by the commission. Some groups also argued that the FCA can send a conflicting
price signal to ratepayers when reduced energy consumption results in a rate increase as Idaho
Power proposed in two of the three years.
The Snake River Alliance and the Natural Resources Defense Council endorsed Idaho Power’s
petition to make the FCA permanent. The Snake River Alliance said the FCA has been an
“effective mechanism” to promote energy efficiency and that the nominal adjustments in rates
are “more than compensated by customers’ reduced energy use.”
The Natural Resources Defense Council noted the company’s “impressive growth in energy
efficiency and demand‐response programs.” In 2007, Idaho Power upped its investment in
conservation programs from $11.5 million to $15.66 million, resulting in an energy savings of
91,145 megawatt‐hours, a 29 percent increase from energy saved in 2006. In 2008, conservation
investment jumped from $15.66 million to $21.2 million and megawatt‐hours saved totaled
104,156, a 54 percent increase over 2007.
Idaho Power maintained the FCA is “performing as the parties and the commission intended
when it was implemented.” The company recognizes there are still questions to be answered,
but noted the FCA can continue to be adjusted even after it is made permanent. Not doing so
adds an element of uncertainty to the commission’s long‐running commitment to the FCA, the
company said.
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The commission acknowledged Idaho Power’s increased investment in efficiency programs, but
said that is not justification for making the program permanent until the company can show a
“demonstrable nexus” between the FCA and company investment in conservation programs.
“Evidence suggests that the FCA may have done little to spur Idaho Power’s increased
investment, as least for residential customers,” the commission said, noting that energy savings
were greater in customer classes that don’t have the FCA.
The commission ordered the program continue on a pilot basis for another two years, beginning
June 1, 2010, during which time further data can be developed and the issues raised by
commission staff and the parties addressed.
Case No. IPCE1004, Order No. 31080
May 17, 2010
IPC participation in NEEA approved; but funding to be reviewed
Idaho Power Company’s application for authority to fund its continued participation in the
Northwest Energy Efficiency Alliance has been approved. However, the commission made clear
it will require the company to demonstrate a “sufficient benefit to customers,” before it will
include NEEA funding in customer rates.
NEEA is a non‐profit organization working to accelerate market adoption of energy‐efficient
products, technologies and practices within homes, businesses and industries. It is funded by
Northwest utilities, the Bonneville Power Administration and the Energy Trust of Oregon.
NEEA is asking that Idaho Power pay 8.62 percent of its overall 2010‐14 budget. That totals
$16.5 million, which is $3.3 million per year over five years. Idaho Power’s share of NEEA
funding is included in the 4.75 percent energy efficiency rider paid by customers.
While the commission approved Idaho Power’s continued participation, the company will yet
need to show that customers benefitted sufficiently when the company files an annual report of
its conservation related program. “The commission expects rider funds to be used judiciously to
ensure customers receive tangible benefits from their payments to support energy efficiency
programs,” the commission said.
Idaho Power said NEEA helps fund these activities that benefit customers:
• a commercial new construction initiative that includes an integrated design lab in Boise;
• an energy management program that works with large commercial customers to
improve building operations and maintenance to save about 10 to 20 percent of electric
energy use;
• the development of energy building codes;
• the evaluation of Idaho Power’s energy efficiency programs to increase their cost
efficiency; and
• promotion of increased market adoption of energy efficiency programs in rural markets.
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The Idaho Conservation League and the Snake River Alliance supported Idaho Power’s continued
participation, although ICL expressed concern that participation could reduce funds available for
other efficiency programs that may have more immediate results. The Snake River Alliance said
it believes Idaho Power’s participation “resulted in energy efficiency gains that would not have
occurred absent NEEA’s role in Idaho.”
The Industrial Customers of Idaho Power opposed the application, maintaining an increase in
NEEA funding would result in a decrease of money available for other conservation programs.
The industrial customers said Idaho Power should spend rider funds on programs that provide
“easily measureable reductions in demand on Idaho Power’s system, not on increased funding
of NEEA’s broadly focused, regional market transformation programs.”
Case No. IPCE0824, Order No. 32002
June 16, 2010
Commission accepts Idaho Power green tag plan
The commission is accepting a business plan filed by Idaho Power Company spelling out how the
utility intends to treat the renewable energy credits (RECs) it earns from its renewable energy
sources. Customer groups have differed over whether the RECs, or “green tags,” should be sold
to benefit customers or “retired” to meet possible future renewable energy standards.
A Renewable Energy Credit is issued to each utility for every megawatt‐hour of electricity
generated by an eligible renewable energy resource. The RECs represent a currency that can be
traded on an active market to entities wishing to support renewable energy.
RECs are becoming more valuable as a growing number of states require their regulated utilities
to buy or generate a certain amount of power from renewable sources. Idaho Power’s 101‐
megawatt Elkhorn Wind project in Oregon and its 13MW Raft River geothermal project in south‐
central Idaho generated more than 320,000 MWh of RECs for Idaho Power in 2007 and 2008.
Last year, after reconsideration, the commission directed Idaho Power to sell its 2007 and 2008
RECs and use the approximate $1.7 million in proceeds to benefit ratepayers. Idaho Power
originally requested that it be allowed to retire, rather than sell, the RECs in anticipation of
federal or state renewable mandates. By retiring the RECs, Idaho Power said it could represent
to renewable energy certification programs and to customers that it is meeting customer
expectations for increased use of renewable energy.
Standards established by Green‐E Energy, the nation’s leading independent certification and
verification program for renewable energy, say that green tags sold by utilities from a renewable
project cannot be counted twice – by the utility doing the selling and the purchaser. Thus, when
Idaho Power sells its green tags, the company maintains it can no longer represent to customers
that customers are receiving the benefits of renewable energy projects that carry green tags.
According to Idaho Power, the Green‐E standards prohibit the utility from using visuals of its
wind or geothermal projects in charts, graphs or line art as part of the green resources delivered
to customers if the green tags that accompany those projects are sold.
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Idaho, unlike many other states, does not require its regulated utilities to generate a certain
amount of its power from renewable sources. However, retaining the green tags would allow
Idaho Power to satisfy any future state or federal laws imposing renewable portfolio standards,
the company claimed in its original filing.
After the commission granted Idaho Power’s request to retire the tags, the Industrial Customers
of Idaho Power petitioned for reconsideration, arguing the value associated with the RECs
belongs to the ratepayers and should be sold to benefit them. On the other side of the issue, the
Idaho Conservation League and the Renewable Northwest Project argued that the commission
allow the utility to retire the RECs.
After reconsideration, the commission directed the company to sell the RECs. But the order
allowing them to be sold also required the company to submit a business plan on how it intends
to treat REC sales in the future.
In April, Idaho Power submitted that plan which proposes that, in the short term, the RECs be
sold and the customers’ share of the proceeds be returned to customers in the annual Power
Cost Adjustment process. In the longer term, Idaho Power plans to continue acquiring and
holding contractual rights to own the RECs to meet any possible future renewable energy
standards.
Idaho Power states there is a “reasonable likelihood” that a federal renewable standard will be
passed by Congress that will require the company to obtain and retire RECs for compliance.
“However, because of current economic conditions and recent increases in costs and customer
rates, the basic philosophy of Idaho Power’s REC Management Plan is to sell its RECs in the near‐
term,” the company stated.
The Idaho Conservation League and the Renewable Northwest Project also opposed the
company’s plan for handling future RECs. They said the plan fails to consider the value of REC
retirement and that it should explain how Idaho Power intends to sell its RECs and still comply
with REC market guidelines.
Idaho Power customer Annie Black said the environmental benefits that should be accorded the
company and its customers are stripped away when the REC is sold, contrary to the state’s
energy policy requiring a diversified energy portfolio. Black requested a hearing to review the
implications of Idaho Power’s proposed plan or, if a hearing is denied, that the commission not
accept the plan.
The commission, denying requests for further hearings or that the plan not be accepted, noted
that accepting the plan as filed does not mean the commission endorses its specifics.
“As noted by the commenters in this case, the REC system is a complicated market that is still
developing and varies from state to state,” the commission said. “We expect Idaho Power to
remain fully engaged in REC market developments and to comply with proper procedures
regarding representations of renewable energy. We further direct the company to submit a
modified REC management plan when a change in state or federal energy policy warrants such
actions.”
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Case No. AVUE1002
June 4, 2010
Avista wants to expand net metering program
The commission has approved a request from Avista Utilities to let larger‐sized, customer‐
owned generation projects qualify for the company’s net metering program.
Currently, customers owning projects up to a capacity of 25 kilowatts are eligible to receive
credits for the generation they produce on solar, wind, biomass or hydropower projects. Avista
has received commission approval to increase the size of projects that can qualify for the net
metering rate to 100 kilowatts.
Customers who generate their own electricity can have their generation credited from their
monthly billings. Those who produce more than they consume, can have their excess kilowatt‐
hours applied to future billing periods to reduce their bills. At the end of the calendar year, any
unused kilowatt‐hour credits are granted to the company without compensation to the
customer‐generator.
Avista allows customers to enroll as net metering customers on a first‐come, first‐served basis
until the cumulative generating capacity of all customers equals 1.52 megawatts or about 0.1
percent of Avista’s retail peak demand.
Avista serves about 120,000 electric customers in northern Idaho.
Case No. IPCE0933, Order No. 32042
August 6, 2010
Commission accepts Idaho Power planning document
Idaho Power Company has fulfilled a requirement to file with state regulators every two years a
plan that sets forth how the company intends to serve the electric requirements of its
customers over the next 20 years. The plan, called an Integrated Resource Plan (IRP), says the
company plans to add about 3,000 megawatts of capacity over the next 20 years to meet
anticipated load growth.
The plan also spells out how the company plans to reduce summer peak load by 323 megawatts
by 2012, due largely to demand reduction programs aimed at commercial, industrial and
irrigation customers. Energy efficiency programs are forecast to reduce load by 127 average
megawatts by 2029, a 53 percent increase over measures included in Idaho Power’s 2006 IRP.
Acceptance of the plan by the commission does not necessarily mean the commission endorses
all the projects outlined in the plan. Circumstances change, which require updating the
document every two years.
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Idaho Power’s southern Idaho and eastern Oregon territory serves about 486,000 customers,
but those numbers are expected to increase to 680,000 at the end of the 20‐year plan in 2029.
Idaho Power anticipates that summertime peak‐load hours will increase by 53 megawatts over
the next 20 years and average load by 13 megawatts.
To accommodate the load growth over the next 10 years, Idaho Power continues to rely on
expanding its demand reduction programs. It also plans to add 540 megawatts of new
generation, including the 300‐MW Langley Gulch natural gas plant now under construction near
New Plymouth. The company plans to add 150 megawatts of wind generation and 40 MW of
geothermal generation. Completion of a proposed major 500‐kv transmission line from the
Boardman Substation near Boardman, Ore., to the Hemingway Substation near Melba will make
available another 425 MW of capacity to Idaho Power’s customers. An upgrade of the Shoshone
Falls hydroelectric facility will make another 20 MW available by 2015.
Looking beyond 10 years, the company plans another 1400 MW of generation from natural gas
plants and 500 MW from wind. The additional wind assumes completion of the Gateway West
Transmission Project, a joint transmission project proposed by Idaho Power and Rocky Mountain
Power that would pass through southern Wyoming and southern Idaho.
In 2008, 78 percent of Idaho Power’s electricity came from existing, low‐cost hydroelectric and
coal resources. These resources are the primary reason Idaho Power has historically had some
of the lowest retail electric rates in the nation. As Idaho Power adds new resources in the future
due to load growth and reduced generation from coal, the company asserts that power supply
expenses and rates are going to increase.
In fact, the Boardman coal plant in Oregon, from which Idaho Power gets about 64 megawatts,
is expected to cease operating within 10 years. Groups filing comments in the case, including the
Snake River Alliance and the Idaho Conservation League, said the company needs to be more
specific about how it intends to meet demand with the elimination or drastic curtailment of coal
generation. The commission agreed, asking Idaho Power to include more details in its next plan.
The Renewable Northwest Project, along with the Snake River Alliance, expressed concern that
Idaho Power may yet include coal in its long‐range planning if the cost of any future federal
carbon regulation is less than $30 per ton. The groups also oppose too much reliance on new
natural gas peaker plants given the price volatility of natural gas.
The parties to the case commended Idaho Power for its plans to increase wind and geothermal
development and its added reliance on conservation programs to reduce demand on the
company’s existing generation. The Snake River Alliance said the recent increase in the customer
rider to fund conservation programs ‐‐ to 4.75 percent – may not be enough to capture all the
potential energy conservation. The commission agreed the conservation programs are
necessary, but the issue of what is a fair and reasonable charge for customers to fund those
programs is “never black or white. For a regulator, there are considerations of equity and timing
and affordability. It is a pocketbook issue for many of the state’s unemployed and economically‐
challenged.”
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All the groups encouraged Idaho Power to pursue solar‐powered generation. The commission
said the recently announced Boise City solar project may provide Idaho Power an opportunity to
assess the merits of solar resources.
Case No. IPCE1023
October 22, 2010
Utility given more flexibility to negotiate with large customers
The commission has approved a request by Idaho Power Company to allow it to negotiate
contracts with new large industrial customers rather than having the new customers pay the
standard tariff rate.
Idaho Power claims it has received inquiries from as many as 75 potentially new large industrial
and irrigation customers. Due to generation and transmission constraints, Idaho Power said it
would not be able to serve the new customers if it cannot negotiate provisions that allow the
utility to adapt its transmission system to accommodate new load.
All Idaho Power industrial customers with a load between 1 and 25 megawatts are served under
a tariff – Schedule 19 – that that has the same rates and delivery requirements. Four industries
that have a load of 25 megawatts or more are classified as “special contract” customers. That
classification gives Idaho Power the price and delivery flexibility to accommodate the
requirements of these large customers without negatively impacting other customers. The four
special contract customers are Micron, the Idaho National Laboratory, JR Simplot Company and
Hoku Materials.
In this case, Idaho Power sought commission approval to lower the load requirement for
customers to qualify as special contract customers from the current 25 megawatts to 20
megawatts. The commission has granted that request and it becomes effective Jan. 1, 2011.
The commission said it recognizes that the ability of Idaho Power’s generation and transmission
system to serve new large load customers is constrained. “We find that the company’s proposal
will enable it to better manage the impacts of potential new large loads on its system,” the
commission said.
For example, a special contract would permit Idaho Power and the industrial customer to reach
an agreement to curtail power or exercise other options to the customer if Idaho Power is
unable to provide service. Further, a special contract could lessen the rate impact on other
customers by including a rate structure for contract customers that has a marginal cost
component for an initial period. The contract could also require the large customer to make
upfront contributions for new or upgraded distribution or transmission needed to serve the new
customer.
Because of constraints on its power supply and transmission, Idaho Power would not have been
able to serve Hoku Materials, Inc., a new polysilicon production facility in Pocatello, without a
special contract. Hoku requested 82 megawatts of year‐round capacity. The two entities last
year agreed on a four‐year seasonally‐shaped contract that requires Hoku to reduce its demand
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during the peak summer months through 2012, the year Idaho Power expects to have enough
power supply and transmission to serve Hoku at full capacity. During those peak months, Hoku
will reduce its demand by performing annual maintenance on its systems.
The agreement also allowed Idaho Power to charge Hoku a special rate rather than the standard
rate for the entire load, which would have likely placed upward pressure on all of Idaho Power’s
customer rates. Hoku is paying the costs for Idaho Power to build the transmission and
substation upgraded needed to enable delivery of energy to Hoku’s facilities.
PURPA‐related cases
In 1978, Congress passed the Public Utility Regulatory Policies Act (PURPA) to promote
the development of renewable energy technologies as alternatives to fossil fuels. PURPA
requires electric utilities to buy power generated by qualifying small‐power producers at
a rate that is set and posted by state commissions. The rate is called the avoided‐cost
rate because it is to be based on the cost the utility avoids by not having to generate the
power itself or buy it from other sources. In Idaho, the avoided‐cost rate is based on the
estimated cost a utility would incur in building a combined‐cycle natural gas power
plant. Currently, only qualifying projects 10 MW or smaller qualify for the posted rate.
The commission must ensure the avoided‐cost rate is reasonable for utility customers
because 100 percent of the price utilities pay to qualifying producers is included in
customer rates.
Case No. GNR‐E‐10‐04, Order No. 32131
December 6, 2010
Commission to examine renewable power issues
Idaho’s three major investor‐owned utilities are petitioning the commission to investigate a
number of issues related to small‐power projects that qualify for a rate published by the
commission. The utilities are also asking that the eligibility cap on the size of projects that
qualify for the posted rate be reduced from 10 average megawatts to 100 kilowatts while the
investigation is under way.
The commission set Dec. 17 as the deadline for parties who want to intervene in the case, is
taking public comments through Dec. 22 and is hearing oral arguments on Jan. 27. Several
parties, representing primarily wind developers, have already filed petitions to intervene.
The three utilities – Idaho Power Company, Avista Utilities and PacifiCorp – all contend that a
rapidly expanding number of wind projects is having a profound impact on customers and on
utility transmission systems. The utilities further contend that large‐scale wind farms are
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breaking up their projects into smaller 10‐MW increments to qualify for the published avoided‐
cost rate, which may be more attractive than rates for projects larger than 10 MW.
In its petition, the three utilities are claiming that the small‐power projects PURPA was originally
intended to encourage are now developed by sophisticated large‐scale wind farms that
aggregate several projects 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, the utilities claim. For example, Idaho Power claims it now has 208 MW of wind
generation and another 264 MW of approved wind contracts scheduled to be online by the end
of this year. The utility claims 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 rapid expansion of these projects is causing a strain on utility
transmission systems, the utilities claim.
The commission denied a request of the utilities to lower the size limits of projects than can
qualify for the post rate within 14 days of its Nov. 5 application. However, the commission did
say that any decision it makes next year in regard to lowering the limit will become effective
Dec. 14, 2010.
Parties intervening in the case claim the utilities’ petition is not backed up by evidence and will
have an adverse impact on PURPA development in Idaho. “Once in place, such a drop in the
eligibility cap is likely to remain in place for many months, likely years,” said the Northwest and
Intermountain Power Producers Coalition. “The implications on the renewable energy industry
will be widespread and have impacts on the entire economy of Idaho.”
The J.R. Simplot Company said it “fears the investment climate in Idaho will be, and may have
already been, tainted from the perspective of sophisticated investors who undoubtedly have
many other more favorable jurisdictions in which they may invest their renewable energy
dollars.” The J.R. Simplot Company and the Milk Producers of Idaho, among others, asked that a
lowered eligibility cap apply only to wind projects and not other renewable projects, such as
anaerobic digester, small‐hydro and solar projects.
The commissions is seeking comment on three matters: 1) the advisability of reducing the
published avoided cost eligibility cap; 2) if the eligibility cap is reduced, the appropriateness of
exempting non‐wind projects from the reduced eligibility cap and 3) the consequences of
dividing larger wind projects into 10 average megawatt projects in order to qualify for the
published rate.
Case No. GNR‐E‐10‐01, Order No. 31025
March 18, 2010
Rates paid smallpower producers decline
The rates that regulated utilities pay small‐power producers have decreased significantly due to
declining natural gas prices, according to a new price forecast by the Northwest Power and
Conservation Council.
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Under the provisions of the federal Public Utility Regulatory Policies Act (PURPA), regulated
electric utilities are required to buy power from qualifying small‐power producers or co‐
generators, such as wind or anaerobic digester projects. The rate to be paid the developers of
projects 10 megawatts or smaller is determined by the commission and is called the “avoided
cost rate” because it is to be equal to the cost the electric utility avoids if it would have had to
generate the power itself or purchase it from another source.
One of the key factors the commission uses in determining the published avoided‐cost rate is a
long‐term natural gas forecast by the Northwest Power and Conservation Council. A change in
the forecast automatically triggers a recalculation of the published avoided cost rates.
Under new rates effective immediately, a qualifying PURPA project developer who signs a 20‐
year levelized contract this year would be paid $79.19. Under the previous rate, a developer
would have been paid $90.90 per MWh.
According to NPCC data, the price for natural gas at the Sumas trading hub in Washington state
including delivery averaged $7.68 per/MMBtu, but had dropped to $3.91 in 2009 and is
projected to be about $4.56 this year.
Case No. IPCE1002, Order No. 31034
April 5, 2010
Commission accepts agreement with anaerobic digester
The commission approved a contract between Idaho Power Company and Cargill, Inc., the
developer of an anaerobic digester near Hansen. The agreement is for 2.25 megawatts of
output from Cargill’s Bettencourt Dry Creek Biofactory.
The anaerobic digester has been producing electricity on a non‐firm basis since August of 2008.
This 10‐year agreement is for firm delivery.
Commission staff noted this agreement contains significantly higher delay penalties than past
PURPA contracts. The delay security is $45 per kW or about $101,250, compared to about $25
per kW in previous contracts.
Idaho Power maintains the higher penalty is needed because several PURPA projects have failed
to meet their scheduled operation date.
Although this project is already operating, commission staff believes Idaho Power included the
$45 per kW penalty partly because the company is seeking an endorsement of the higher
security requirement with the intent of including it in future contracts. The commission said
delay provisions should not be too much so as to be punitive, but should be high enough to be
an incentive for project owners to complete their projects on time. Further, the commission
said, the delay provisions mitigate any additional costs to the company and its customers when
the utility is forced to buy substitute power on the market due to a project not coming on line.
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Case No. IPCE1005
April 27, 2010
PUC approves Idaho Power agreement with smallhydro developer
The commission approved a 20‐year power purchase agreement between Idaho Power Co. and
the developer of a small hydro‐generation facility near Parma.
Riverside Investments LLC, based in Adrian, Ore., is the owner of the 450‐kilowatt Arena Drop
hydro project. The project is scheduled to be in operation by July 15.
Case No. IPCE0934, Order No. 31087
May 20, 2010
Contract with geothermal project is approved
The commission approved an Idaho Power Company sales agreement with the developer of
geothermal generation project 12 miles northwest of Vail, Oregon. The project is within Idaho
Power’s service territory.
The Neal Hot Springs Unit No. 1 is expected to produce about 22 megawatts of power by late
2012. The project is owned by USG Oregon LLC, a subsidiary of U.S. Geothermal based in Boise.
The agreement provides that Idaho Power will receive the rights to the renewable energy
credits now available or created during the 25‐year term of the agreement.
Beginning in 2012, the flat energy price, under the agreement, is $96 per megawatt hour. The
price escalates annually by 6 percent in the initial years and by 1.33 percent during the latter
years of the agreement. The approximate 25‐year levelized price is $117.65 per MWh.
Idaho Power asserts that while the price of energy under this agreement is higher than most
sales agreements, there are benefits that bring value to Idaho customers. Those include Idaho
Power’s right to the renewable energy credits, the utility’s ability to curtail energy output from
the project when needed, Idaho Power’s first right to ownership of possible future site
development and the right to extend the terms of the contract.
Because the projected output is more than 10 average megawatts, the project is too large to
qualify for posted PURPA rates. Instead, the proposed rates were negotiated between the
company and the project developer.
Initially, Idaho Power sought bids for a geothermal source, but received only three. Two of those
bids were later withdrawn and the third was too speculative, the company said. The company
then decided to actively pursue negotiations with developers of five potential geothermal sites,
including the Neal Hot Springs site.
The commission noted that a bid process is the preferred method for getting competitive
proposals for energy purchases. But when the bid process is not successful, Idaho Power is not
precluded from directly negotiating contract terms with a single provider. However, Idaho
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Power “always bears the burden” in demonstrating that a purchase agreement’s terms “are fair,
just and reasonable,” the commission said.
All payments Idaho Power makes for the purchase of energy from the site will be included in the
company’s annual Power Cost Adjustment process until the next rate case at which time costs
are included in base rates.
Case No. IPCE1016, 17, 18
July 6, 2010
Idaho Power agreements with anaerobic digester projects OK’d
The commission approved Idaho Power Company requests to enter into power sales
agreements with the developer of three Magic Valley anaerobic digester power projects.
The 15‐year contracts are all with a Middleton‐based developer. Two of the projects are in Twin
Falls County. They are the 4‐megawatt Rock Creek Dairy project near Filer and the 2‐megawatt
Swager Farms Dairy project near Buhl. The 2‐megawatt Double B Dairy project is near Murtaugh
in Cassia County.
All three of the projects contain purchase rates that on the May 24 date of their contract signing
had been replaced by lower rates approved by the commission on March 16. However, the
commission determined that the projects were entitled to be grandfathered and paid the higher
rate in place before March 16. An internal review process by Idaho Power delayed contract
signing until May 24 even though all the contract issues had been resolved before March 16.
For all three of the proposed projects, the rate in the first year is $75.65 per megawatt‐hour.
The rate gradually increases over the 15 years of the contracts to $128.31 per MWh. That rate is
adjusted for heavy‐ and light‐load seasons as well as heavy‐ and light‐load hours. The proposed
Rock Creek Dairy project intends to deliver 1,296 megawatt‐hours per month, while the Swager
Farms and Double B project are anticipating an output of 648 MWh per month.
Anaerobic digestion is a biological process that produces a gas principally composed of methane
and carbon dioxide otherwise known as biogas. These gases, produced from organic wastes such
as livestock manure and food processing waste, are converted into electric energy.
Case No. IPCE1019
September 17, 2010, Order No. 32068
Commission approves first solar PURPA project
The commission approved a sales agreement between Idaho Power Co. and Grand View Solar
PV One, the utility’s first PURPA agreement with a solar power project.
The project, 16 miles west of Mountain Home, is a qualifying facility under the provisions of
PURPA, the federal Public Utility Regulatory Policies Act of 1978.
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Idaho caps the size of projects that can qualify for the published avoided‐cost rate at 10 MW.
Even though the Grand View Solar project capacity is 20 megawatts, the project is not expected
to exceed 10 average megawatts on a monthly basis given the fact that solar power cannot be
generated around‐the‐clock. Should the project exceed 10 average megawatts, Idaho Power will
accept the energy but will not be required to pay for it.
The sales agreement is for 20 years with a scheduled online date of Jan. 1, 2011. The agreement
is “non‐levelized,” meaning the price for the electricity generated gradually increases through
the life of the contract. The rate is $77.77 per megawatt‐hour in 2011 escalating to $128.31 per
MWh in 2031. That rate is adjusted for heavy‐ and light‐load seasons as well as heavy‐ and light‐
load hours. The planned monthly output for the project varies from 1,326 megawatt‐hours in
January to 4,816 megawatt‐hours in July.
Idaho Power has a number of net metering agreements with customers who own small primarily
residential solar projects, but this project is the first solar sales agreement with a larger
provider.
The manager of the Grand View Solar PV One project is Robert Paul of Deseret Hot Springs, Calif.
Case No. PAC‐E‐10‐05, Order No. 32084
October 13, 2010
Agreement between PacifiCorp, east Idaho wind projects approved
The commission approved a sales agreement between PacifiCorp and the developer of two wind
projects near American Falls. PacifiCorp does business in eastern Idaho as Rocky Mountain
Power.
The two projects, called Power County Wind Park North and Power County Wind Park South,
will deliver up to 10 average megawatts per month. The scheduled online date is Dec. 31, 2011.
The developer is Boise‐based Windland, Inc.
Case No. IPCE1022, Order No. 32104
November 3, 2010
Idaho Power agreement with biomass project approved
The commission approved an energy sales agreement between Idaho Power Company and the
developers of a biomass power project at an Emmett sawmill.
The project, called Yellowstone Power, is a biomass‐fueled combined heat and power project to
be co‐located with the recently commissioned Emerald Forest Sawmill, which employs up to 47
workers in Gem County. Power is generated using steam created from the controlled burning of
the woody biomass fuel.
Idaho Power and Yellowstone Power agreed on a 15‐year contract under which the project
would generate an average 10 megawatts per month. Projects that generate 10 megawatts or
less qualify for a rate posted by the commission under the provisions of the federal Public Utility
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Regulatory Policies Act, or PURPA. At issue in this case was whether the project was far enough
along in development that it could be “grandfathered” under an older PURPA rate that expired
on March 15 and was replaced by a rate that is about 15 percent lower. Because the costs of
PURPA projects are included in customer rates, the commission must ensure that customers are
not paying an unreasonable rate for the power.
Because there was no written evidence of an agreement before the rates were lowered in
March, commission staff could not recommend approval of the agreement under the older,
higher rates. However, in approving the agreement, the commission, which operates separately
from commission staff, said, “There is no reason to question the representations of Idaho Power
and Yellowstone as to when contract negotiations of the parties occurred.” Both Idaho Power
and Yellowstone maintained an agreement was essentially in place before the rates that Idaho
Power must pay Yellowstone were lowered.
A key factor the commission uses in calculating the avoided‐cost rate is a long‐term natural gas
forecast issued by the Northwest Power and Conservation Council. A change in the forecast
automatically triggers a recalculation of the published avoided cost rates. In March, the NPPC
issued an updated forecast that resulted in a lower rate that the company must pay developers
because of declining natural gas prices.
However, projects that were under development at the time the rates were lowered can be
grandfathered under the older rate if: 1) the developer has executed a power sales agreement
before the new rate became effective and 2) the developer has filed a meritorious complaint
alleging the project was sufficiently mature and far enough along in the contracting process that
a contract would have been signed had not the utility delayed the process.
Idaho Power argued the agreement should be approved because it was engaged with the
developer in discussions throughout 2009. Yellowstone Power argued that the facts that the
purchase of property for the project was complete and that it had been issued a permit to
construct by the Idaho Department of Environmental Quality are evidence of the project’s
maturity.
While the commission approved the agreement based “on the totality of circumstances,”
commissioners said they were “troubled by the apparent lack of any written documentation”
that a power purchase agreement was materially complete. The commission said it expects
Idaho Power and other regulated utilities to document oral communications and to “assist the
commission in its gatekeeper role of assuring that utility customers are not being asked to pay
more than the company’s avoided cost,” in power purchase agreements.
The commission noted the cogeneration project will provide “steady, predictable generation for
Idaho Power around the clock.” The biomass project is a “valuable addition to help diversify
Idaho Power’s resource portfolio,” and will inject jobs and revenue into an Idaho county hit hard
economically over the last 10 years, the commission said.
The project developer is Dick Vinson of Thompson Falls, Montana.
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Case No. IPCE1024
November 26, 2010
Idaho Power’s first large PURPA project approved
The commission has approved an Idaho Power Company sales agreement with a 44‐turbine
wind project near American Falls in eastern Idaho.
The 80‐megawatt Rockland Wind Project is a PURPA project with a scheduled operation date of
Dec. 31, 2011. PURPA is the federal Public Utility Regulatory Policies Act passed by Congress
during the energy crisis of the late 1970s. The act requires electric utilities to offer to buy power
produced by small power producers or cogenerators who obtain Qualifying Facility (QF) status.
The proposed agreement has many unique characteristics because of its size. All Idaho Power
PURPA wind projects to date are 10 megawatts or smaller, which is as large as a project can be
for developers to be paid an “avoided cost” rate that is determined and published by the
commission. The avoided cost rate is to be equal to the cost the electric utility avoids if it would
have had to generate the power itself or purchase it from another source. However, projects
larger than 10 MW can still qualify as PURPA projects if the developer and the utility are able to
negotiate a cost that closely matches the utility’s avoided cost. Because customers ultimately
pay for the power generated by PURPA projects, it is not in the public interest for the
commission to approve sales agreements that result in customers paying more for electricity
that could have been generated or purchased elsewhere at lower cost.
The negotiated levelized energy price in the 25‐year agreement is $71.29 per megawatt‐hour,
lower than the published avoided cost rate of $75.88 for projects 10 MW or smaller. Blue
Ribbon Energy LLC, which develops PURPA projects smaller than 10 MW, did not oppose the
agreement, but noted that Rockland was able to accept a lower payment because of tax credits
and benefits it received. Blue Ribbon Energy said Idaho Power or any other utility should not be
allowed to treat this agreement “as establishing a precedent for rates.”
The commission praised Idaho Power and Rockland for negotiating an agreement “that we find
sets forth a creative solution to resource issues that have heretofore often resulted only in
impasse and the filing of complaints.”
Some of those issues resolved include not only price, but items such as delay and security
provisions, mechanical guarantees and the treatment of renewable energy credits or “green
tags,” created by the project.
The agreement contains financial damage and security provisions for the benefit of customers in
the event of the project’s default or failure to meet its completion date as well as mechanical
availability guarantees. The developer would retain the renewable energy credits (green tags)
for the first 10 years which will help offset the development cost. Idaho Power would retain the
renewable energy credits for the final 15 years when the utility may have to comply with federal
or state renewable portfolio standards.
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Case No. IPCE0925, Order No. 32136
December 13, 2010
Transmission agreement between IPC, wind developer OK’d
State regulators have approved a $2.17 million agreement between Idaho Power Company and
Idaho Winds LLC that would allow a wind project near Glenns Ferry to interconnect with Idaho
Power’s transmission system without requiring a larger, more costly upgrade to the system.
The 21‐megawatt Sawtooth Wind project six miles northwest of Glenns Ferry is scheduled to be
in operation by Dec. 31, 2012, but will require substantial upgrades to Idaho Power’s
transmission system. Construction of the upgrades is expected to be completed by Juny 22,
2011.
The agreement is that 25 percent of upgrade costs will be paid by Idaho Power and included in
customer base rates and 25 percent will be paid by Idaho Winds. The remaining 50 percent will
be advanced by Idaho Winds, but subject to refund by Idaho Power over 10 years if the project
meets its output requirements. That 50 percent of the upgrade cost will be included in customer
rates over time as refunds are made.
The agreement also includes “redispatch,” provisions included in agreements with other wind
projects in the same area. Those provisions allow Idaho Power to direct Sawtooth Wind to
forcibly reduce its generation output in the event of outages on specified transmission lines.
Those provisions prevent Idaho Power from having to make even more costly upgrades to its
transmission system.
Both Idaho Power and commission staff agreed that the chances of such outages during peak‐
use times on Idaho Power’s system are unlikely because wind projects are not expected to be
generating at or near capacity during extremely hot times of the year when transmission
congestion usually occurs. Idaho Power believes the need for redispatch provisions will be
relieved after 2015 if the proposed Gateway West transmission project is built.
Case No. IPCE1026, Order No. 32138
December 20, 2010
Utility agreement with anaerobic digester approved
State regulators have approved a sales agreement between Idaho Power Company and AgPower
Jerome LLC, a 4.5 megawatt anaerobic digester project to be built near Jerome.
The project, which includes three 1.6 MW turbines, is a Qualified Facility under the provisions of
the federal Public Utility Regulatory Policies Act (PURPA).
Project developers, based in Colorado, asked that the project be grandfathered under an older,
higher posted rate because the sales agreement was substantially complete before the avoided‐
cost rate was lowered by the commission on March 16. The agreement was not signed in time
because the parties disagreed over liquidated damages and security provisions. When AgPower
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agreed to drop its opposition to those provisions, Idaho Power did not object to the project
being grandfathered under the former avoided cost rate.
Under the agreement, AgPower will be paid about $80.05 per megawatt‐hour in the first year of
operation, with a project online date of Jan, 1. 2012. By the 20th year of the agreement, project
developers would be paid about $128.31 per MWh. That amount varies during heavy‐ and light‐
load seasons of the year and heavy‐ and light‐load hours of the day.
Case No IPCE1038, 39, 40, 41, 42, 43
December 28, 2010
Commission approves agreements with six wind projects
The commission accepted sales agreements between Idaho Power Company and a San Francisco
developer for six wind projects near Mountain Home. The developer is the same for all six
projects with Maurice Miller and Glenn Ikemoto listed as project managers.
All six wind farms – Cold Springs, Desert Meadow, Hammett Hill, Mainline, Ryegrass and Two
Ponds – qualify for the commission’s posted Avoided Cost Rate under the provisions of PURPA.
Each of the projects has a capacity of 23 megawatts, but because wind is intermittent, the
agreements call for delivery of 10 average megawatts per project per month to Idaho Power.
Should the projects exceed 10 average megawatts, Idaho Power may accept the energy but will
not pay for it.
While the commission adopted the sales agreements, it expressed concern about the
transmission capacity available on Idaho Power’s system at the single point of interconnection, a
230‐kilovolt line in Elmore County, which is also near two other projects – Bennett Creek and
Hot Springs – owned by the same developer. A system impact study was performed that
indicated the existing transmission system can accommodate output from the projects without
transmission network upgrades. However, when that study was completed it was for projects
with a nameplate capacity of 20 MW. Since the study was completed, the project evolved with
the developer’s turbine choice resulting in projects with a nameplate capacity of 23 MW.
Consequently, the commission is ordering the developer to request additional transmission
capacity and be responsible for all costs associated with the request.
All the agreements include a mechanical availability guarantee, a reduction in the price paid to
the developer to allow for integrating the wind into Idaho Power’s transmission system and a
wind forecasting cost assessed the developer. The parties also agreed to damages and security
provisions in the event the projects do not meet their operation date of Dec. 31, 2012.
The rate for these projects is a non‐levelized rate that increases through the 20‐year contract. In
2013, the rate for normal load hours during normal seasons of the year is $61.93 per megawatt‐
hour (6.19 cents per kWh), escalating to $121.76 per MWh in 2032. That rate varies to account
for heavy and light load hours of the day and heavy and light load seasons of the year.
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Idaho Natural Gas Utilities
All three natural gas distribution companies with operations in Idaho, Intermountain Gas, Avista
Utilities, and Questar Gas, continued to experience reduced commodity costs. However these
reductions were less than those experienced in 2009, when Intermountain Gas, Avista Utilities,
and Questar Gas all decreased their Purchase Gas Cost Adjustment (PGA) portion of their rates
by on average 30 percent. In 2010, Intermountain Gas, Avista Utilities, and Questar Gas
decreased the Purchase Gas Cost Adjustment (PGA) portion of their rates by 0.8%, 6.7% and
1.9%, respectively. (See more detailed information below.)
The primary reason for the continuing decline in natural gas prices is due to the weakness in the
regional and national economy, which has reduced the weather‐adjusted demand for natural
gas during a period when natural gas supplies have been plentiful. A national report issued by
the Energy Information Administration (EIA) in August of this year, provides insight into the
anticipated conditions of the natural gas industry through 2011:
Natural Gas Consumption: Expected natural gas consumption is forecast to increase by 3.8
percent from the 2009 levels of 64.9 billion cubic feet per day (Bcf/d) in 2010 and remain flat in
2011. Growth in the use of natural gas in both the power and industrial sectors accounts for the
bulk of the increase in consumption in 2010 over 2009. The majority of this increase in electric
power industry consumption is attributed to increased demand for air‐conditioning as the 2010
summer was 36 percent warmer than last year as measured by population‐weighted cooling
degree days. In addition, electric utilities with a mix of coal and natural gas plants have
increased their utilization of their natural gas plants relative to prior years as coal prices have
steadily increased between 2008 and 2010. Natural gas consumption in the industrial sector is
projected to increase by 7 percent through 2010 and expected to increase by only 1 percent
through 2011. Residential and commercial consumption through 2011 is projected to remain at
levels comparable to those of 2009.
Natural Gas Production: Production during 2010 should end the year 1.1 percent above 2009
levels with continued low gas prices suppressing drilling activity by 1.4 percent in 2011. Several
issues that have contributed to increased production and associated high inventory levels focus
on increased shale gas drilling activity and increased natural gas production associated with the
drilling for oil, which has doubled over the past year. However, the recently imposed offshore
drilling moratorium in the Gulf of Mexico should reduce future drilling activity for the remaining
months of 2010 and through 2011.
Natural Gas Pricing: The natural gas spot price averaged $0.463 per therm in July 2010 which
$0.0017 per therm less than June 2010. EIA forecasts natural prices for the remainder of 2010 to
average $0.4466 per therm. A small decline in production and slightly increased consumption is
expected to lead to an average price of $0.498 per therm in 2011. The EIA estimates that
continued high storage levels combined with enhanced domestic production capabilities and
slow consumption growth are expected to keep prices from rising. Locally, the Northwest Gas
Associations’ 2011 Gas Outlook predicts demand for natural gas across the region (Idaho,
Oregon, Washington and British Columbia) growing by an average 1 percent through 2019.
Climate change policies enacted by state and provincial legislatures across the region are
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expected to drive some of that growth. The network of gas pipelines and storage facilities
linking the region’s consumers to natural gas supplies is currently sufficient to serve regional
needs. System expansions are market driven and have historically occurred appropriately with
regard to type, size and timing. A number of projects are currently under development that will
enhance reliability and ensure the region has access to the supplies it needs to serve growing
demand.
Individual Utility Statistics
Intermountain Gas Company
Residential Commercial Industrial Transportation Total
Customers 275,522 29,673 9 105 305,309
% of Total 90.24% 9.72% 0.00% 0.04% 100.00%
Therms (millions) 212.53 106.54 25.59 221.84 566.50
% of Total 37.52% 18.81% 4.51% 39.16% 100.00%
Revenue (millions) $214.32 $102.16 $2.00 $8.38 $326.86
% of Total 65.57% 31.25% 0.61% 2.56% 100.00%
Avista Utilities
Residential Commercial Industrial Transportation Total
Customers 65,050 8,303 100 8 73,461
% of Total 88.55% 11.30% 0.14% 0.01% 100.00%
Therms (millions) 48.00 27.69 1.89 48.78 126.33
% of Total 38.00% 21.92% 1.47% 38.61% 100.00%
Revenue (millions) $53.62 $27.61 $1.80 $0.49 $83.54
% of Total 64.19% 33.05% 2.16% 0.60% 100.00%
Questar Gas
Residential Commercial Industrial Transportation Total
Customers 1730 227 1 0 1958
% of Total 88.36% 11.59% 0.05% 0.00% 100.00%
Therms (millions) 1.26 0.76 0.10 0.00 2.12
% of Total 59.52% 35.96% 4.52% 0.00% 100.00%
Revenue (millions) $1.04 $0.57 $0.04 $0.00 $1.65
% of Total 63.11% 34.50% 2.39% 0.00% 100.00%
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2010 Gas Cases
Case No. INTG0903, Order No. 31089
June 1, 2010
Commission OKs ‘snowmelt tariff’ for Intermountain Gas
Intermountain Gas Company has been granted authority to temporarily interrupt service to new
snowmelt customers during periods when natural gas is in short supply. Residential and
commercial customers who have snowmelt equipment would receive a discounted rate in
exchange for their service being interrupted.
Natural‐gas fired snow‐melting equipment, installed under driveways and on rooftops, uses an
inordinate amount of natural gas compared to more conventional uses. During days when
natural gas is at peak use, snow‐melt use competes with other customers for the finite amount
of available natural gas than can flow through Intermountain’s distribution system, potentially
degrading service to other customers. System expansion to serve the increased load for
snowmelt customers could substantially increase costs and, thus, rates for all customers.
Last November, Intermountain Gas made an application to the Idaho Public Utilities Commission
for authority to establish the new interruptible rate for new snowmelt customers. Existing
customers who have snowmelt equipment can volunteer to be interrupted.
After taking customer comments and also conducting a workshop, the commission is granting
Intermountain Gas’ request. “By making snowmelt service interruptible, future system
expansions to serve this load can be avoided and snowmelt service can occur when system
capacity is available,” the commission said. The commission also said the company should
“actively promote and market its interruptible tariffs as a conservation measure in order to
maximize participation among existing snowmelt customers.”
There should be a minimum of two hours’ notice before interrupting a snowmelt customer’s
service, the commission said. In addition, the company must keep affected customers apprised
of when service is expected to be restored.
An on‐off switch will be located at an outdoor perimeter site that is easily accessible to
Intermountain Gas personnel, which will negate the need to enter a customer’s home. In the
future, remote technology should be available that would negate the need for the on‐off switch
at each site.
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Case No. INTG1001, Order No. 32004
July 7, 2010
Commission won’t regulate resale of compressed natural gas
Responding to a request by Intermountain Gas Company, the commission issued a declaratory
order stating it does not have jurisdiction over the resale of natural gas by non‐utility third
parties.
Third‐party entities have asked Intermountain Gas to sell them natural gas so that the third
parties can resale it for use as compressed natural gas (CNG) in vehicle fleets.
Intermountain Gas sought assurance from the commission that it would not consider the utility
in violation of state law or tariff provisions if it were to sell to third parties for resale to vehicle
fleets. Intermountain anticipates other potential resale transactions may be proposed by other
entities due to the price, availability and environmental benefits of using natural gas as a
transportation fuel. Some Western states, including Washington, Utah and Wyoming, permit
public CNG fueling stations.
In response, the commission determined that the Energy Policy Act of 1992 preempts the
commission’s authority over the resale of natural gas for transportation purposes.
Consequently, the commission said it “will not exert rate‐setting jurisdiction over the resale of
natural gas for use as a fuel in motor vehicles.”
The Treasure Valley Clean Cities Coalition submitted comments supporting Intermountain Gas in
its view that the commission not regulate the resale of compressed natural gas for
transportation purposes. TVCCC supports greater use of CNG as a motor fuel that will reduce
dependency on foreign oil, improve air quality and promote local economic development.
Intermountain Gas also raised liability concerns regarding resellers. The company asked that the
declaratory order include a statement that the commission will continue to regulate the safety
of natural gas facilities operated by Intermountain, but only to the point where Intermountain’s
facility or pipeline connects to a buying customer’s metering device. In this way, Intermountain
Gas may not be held liable for what happens when its product is resold by third‐party entities.
The commission said it will continue to enforce its safety rules and regulations up to the point
that Intermountain’s facilities connect to a customer’s metering device. Beyond that point, the
International Fire Code establishes the safety requirements for facilities dispensing CNG as a
motor fuel. The State Fire Marshal, local fire departments and fire districts are primarily
responsible for enforcing the International Fire Code.
Intermountain proposes to sell natural gas to resellers using its existing tariff rates.
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Case Nos. AVUE1001, AVUG1001
September 21, 2010
Avista gas rates increase 2.6 percent over 3 years under settlement
The commission adopted a settlement to the Avista Utilities electric and gas rate cases that
increases electric rates an average 9.25 percent over three years and gas rates an average 2.6
percent over two years. The first year electric increase is 3.59 percent and the first year gas
increase is 1.9 percent, both effective Oct. 1.
The commission said the settlement “represents a reasonable compromise to the positions and
we find it in the public interest.”
“In particular, we note the Stipulation and Settlement represents a significant reduction in the
request revenue increase. More specifically, the first year increase in electric rates contained in
the Stipulation and Settlement is 3.59 percent rather than the 14 percent originally proposed by
Avista,” the commission said.
The commission said it recognized “that initial disputes among the parties were numerous and
significant. This case has generated many customer comments opposed to the rate increases
originally requested by the company.”
Avista originally requested a $32.1 million increase in annual electric revenue and a $2.6 million
increase in annual gas revenue. The settlement approved by the commission gives the company
$21.2 million spread over three years in electric revenue and $1.85 million spread over two
years in gas revenue. Helping to offset the increase was a $17.5 million deferred state income
tax benefit.
The three‐year phased rate increase effective dates are as follows:
‐‐ Oct. 1, 2010 ‐‐ 3.6 percent electric and 1.9 percent gas.
‐‐ Oct. 1, 2011 – 3.9 percent electric and 0.72 percent gas.
‐‐ Oct. 1, 2012 – 1.74 percent electric and 0 percent gas.
Case AVU‐G‐10‐02
October 1, 2010
Avista PCA, gas efficiency charges increase
The commission approved two increases, one to electric rates and another to natural gas rates
for customers of Avista Utilities.
Gas customers will pay an average 2.6 percent more for an increase to the gas energy efficiency
rider. For a residential gas customer who uses the utility’s average of 66 therms per month, the
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increase is about $1.52 per month. Avista did not propose an increase to its existing tariff for
energy efficiency programs for its electric customers.
Neither of the rate adjustments increase or decrease company earnings. All the money collected
in the PCA and in the efficiency rider must go directly to those programs.
Natural gas efficiency rider, Case No. AVU‐G‐10‐02
Customer response to more than 30 Avista conservation programs to reduce natural gas
consumption has been greater than anticipated, with customers in Idaho and Washington saving
2 million therms as a result of the programs, well above the targeted 1.6 million therms.
When utilities propose increases in efficiency riders, the commission investigates the
conservation programs funded by the rider for their cost‐effectiveness and approves them only
if it has evidence demonstrating that lack of such programs would result in even higher rates for
customers.
In its comments, commission staff stated an increase in natural gas rates will not be viewed
favorably by many customers, especially given the current economic climate. However, after a
review of the programs, staff determined, and the commission agreed, that the total of all
customers’ bills will be lower with the programs and the rider in place than without them. For
example, the reduction of more than 2 million therms by customers during 2009 prevented
Avista from having to buy or store those 2 million therms at greater cost to customers.
Other than voluntary reduction, utility‐operated energy efficiency remains the lowest‐cost
resource for all customers. Even those who do not directly participate in the programs benefit
from them because of the lower consumption systemwide. The company’s most recent cost‐
benefit analysis (2008) indicates the net benefit to customers from the programs was more than
$8.9 million.
Avista’s conservation programs consist primarily of providing financial incentive or rebates for
cost‐effective efficiency measures installed by customers with a simple payback of greater than
one year. This includes more than 300 measures packaged into 30‐plus programs. Some of the
measures include programs for appliances, compressed air and HVAC systems and motors.
There are also industrial applications, maintenance strategies and sustainable building
measures.
Portions of rider revenue go toward low‐income weatherization, direct aid ($465,000) to Idaho
electric and natural gas low‐income customers and $25,000 to Idaho Community Action
Partnership agencies for low‐income outreach and conservation education.
The per‐therm cost of the rider to residential customers increases from $0.034 cents per therm
to $0.057 cents.
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Case No. INTG1003, Order No. 32077
October 6, 2010
Intermountain Gas PGA is a decrease for most customers
Rates for most Intermountain Gas Company customers declined slightly October 1 as a result of
Intermountain Gas’ annual Purchased Gas Cost Adjustment (PGA) mechanism.
The commission approved a $2.2 million decrease in Intermountain Gas’ annual revenue due to
a declining demand for natural gas, ample storage and lower than normal wholesale gas prices.
This is the fourth time in five years that Intermountain’s annual PGA has resulted in a decrease
for most 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.
With this year’s PGA, rates decline by about 1.6 percent – about 90 cents a month – for the 77
percent of Intermountain Gas customers who use natural gas for water and space hearing.
Customers who use natural gas for space heating only received a 0.2 percent increase, about 9
cents a month for an average customer.
The growth in the customer class that uses natural gas for space heating only was not enough to
offset the projected variable costs for this PGA year. Natural gas and electric utilities typically
determine the rate each customer class pays based on the cost required to serve that class.
Basing rates as closely as possible to cost of service eliminates one class of customers
subsidizing another class of customers.
With the Oct. 1 adjustment, the PGA portion of gas rates drops from 49.6 cents per therm to
49.2 cents per therm. That 49.2 cents represents slightly more than half of the total customer
rate. For customers who use natural gas for both space and water rating, the new total rate is
76.2 cents per therm in the winter (December‐March) and 79.6 cents in the summer (April‐
November.) For customers who use natural for space heating only the total winter rate is 83.2
cents per therm and the total summer rate is 94.5 cents.
The yearly PGA 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.
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Case No. AVUG1003, Order No. 32102
October 28, 2010
Reductions in PGA credit mean increase for Avista customers
The commission has approved a reduction in the size of the annual Purchased Gas Cost
Adjustment (PGA) credit that will increase gas rates by an average 4.5 percent, or about $2.53 a
month for a customer who uses the company average of 63 therms per month.
Avista’s weighted average cost of gas is decreasing from about 49.1 cents per therm to 45.8
cents because of a continued decline in wholesale gas prices. However, the credit customers got
last year – 22 percent – is substantially larger that the reduced WACOG this year, resulting in a
net increase for customers. Avista’s annual Purchase Gas Cost Adjustment (PGA) goes up or
down each year depending on the year’s wholesale gas and transportation prices.
Case No. INTG1004, Order No. 32139
December 22, 2010
PUC accepts Intermountain Gas planning document
State regulators have accepted a five‐year planning document submitted by Intermountain Gas
Company that forecasts an annual increase of 1.75 percent in the company’s peak‐day gas loads
through 2015.
Intermountain Gas, like other regulated utilities, is required to file the plan, called an Integrated
Resource Plan (IRP), with the commission. The plan anticipates conditions over the next five
years and includes resource selections and the process for making resource decisions. The public
is to be offered opportunities to provide input into the planning process.
The commission accepted the plan, but said Intermountain Gas should make a greater effort at
involving the public. The utility should provide “appropriate notice to city and county leaders as
part of the process, especially in the Idaho Falls and Rexburg areas,” which are experiencing high
growth, the commission said. The commission is concerned that a new portable Liquid Natural
Gas facility near Rexburg is not sufficient to encourage and support new business ventures in
that area.
Rexburg is on the Idaho Falls Lateral that extends from north from Pocatello to St. Anthony and
represents 15 percent of the company’s customer base. To meet customer demand during peak
periods, the company said it can switch its industrial customers to fuel oil. During 2009, 41.2
percent of the throughput on Intermountain’s system was attributable to industrial sales and
transportation. Peak‐day delivery deficits can also be managed, the company said, by bringing in
gas from the new Rexburg Liquefied Natural Gas facility.
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54 | P a g e
The Sun Valley Lateral, which serves about 4 percent of Intermountain’s Idaho customers, will
require a future upgrade to the existing pipeline system to meet growth in that area, the IRP
states.
The Idaho Conservation League filed comments, stating that Intermountain needs to encourage
more conservation and efficiency programs to avoid building new infrastructure and to mitigate
price volatility in natural gas markets.
In its order, the commission said Intermountain should consider conservation programs that
“have the potential to be cost‐effective in promoting and enticing energy savings.”
Acceptance of the plan by the commission does not mean that the projects in the plan are
approved, only that the company has met its obligation to file the document.
Intermountain Gas serves about 305,000 residential, commercial and industrial customers
throughout southern Idaho.
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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 $12.50 up to 4,000 gal 4/1/2008
$1.35 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
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Each 1,000 gal over
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” $10/bh $5.50/first 3,000 gal/ 8/01/1996
$0.60 each 1,000 gal
29. United Water Idaho 78,892 See Tariff $20/ bh Starting at $17.81 bi-monthly 7/28/2006
$30/ ah Winter -- $1.21 per 100 cf
Summer - $1.3311 per 100 cf
Up to 300 cf and $1.664
For each 100 cf over
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57 | P a g e
Case No. BCSW0902, Order No. 30970
January 7, 2010
New rates approved for Bar Circle ‘S’ customers
Rates for customers of the Bar Circle “S” Ranch Water Company are increasing from $15 per
month to $27.43 for the first 7,500 gallons of use. The increase was effective Jan. 1.
For use beyond 7,500 gallons, the rate will be $1.74 for each 1,000 gallons. The former rate was
95 cents for each thousand gallons consumed beyond 7,500 gallons.
Bar Circle “S” serves about 160 residential and commercial customers about 15 miles northwest
of Coeur d’Alene. It sought an increase to $32.92 per month and $2.08 for every 1,000 gallons
used above 7,500 gallons. The company sought an annual revenue requirement of $80,335. The
commission approved an annual revenue requirement of $55,734.
This is the first general rate increase for Bar Circle “S” since 1990. Since then the company has
made several major improvements and expansions. Those include installation of a standby
generator for the booster and fire pumps, several replacements of the 60‐horsepower pumping
unit in Well No. 2, improvements to the mainline in 2002, improvements to the Garwood
reservoir in 2001 and well‐site improvements. The company recently installed a 6‐inch recording
flow meter on the discharge side of the company’s booster pumps as required by the Idaho
Department of Environmental Quality.
Commission staff conducted workshops and the commission conducted a public hearing in the
case. Customers also submitted written comments.
Many comments contended that a rate increase the size requested by the company in these
economic times is unreasonable. Some customers said the company should not have waited 18
years before requesting a rate increase. The fact the company waited many years to request an
increase “does not change the evidence presented in this case,” the commission said.
State statutes require that regulated utilities be allowed to recover the prudently incurred
expenses necessary to serve customers and earn a reasonable rate of return. When the
commission denies recovery of expense to a utility it must be able to justify its reasons for
disallowance based on the evidence presented in the case. All commission decisions can be
appealed to the state Supreme Court.
Some customers expressed concern they might be subsidizing the addition of the Double T
Estates development into the Bar Circle “S” system. “We assure customers that any costs that
the company may have accrued that benefited Double T were removed from the calculation of
the (Bar Circle “S”) revenue requirement,” the commission said. In compliance with an earlier
commission order, the developer of Double T agreed to pay Bar Circle “S” for the cost of the
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58 | P a g e
construction of the water main extension and related system improvements to provide service
to Double T.
Case No. UWIW0901, Order No. 31016
March 5, 2010
Commission adopts rate settlement with United Water
United Water Idaho customers will pay 9.9 percent more for water effective immediately with
the adoption of a settlement in the utility’s six‐month rate case.
The utility originally filed for a 15.2 percent increase and, during the course of the case, upped
that request to 16.6 percent. The settlement, negotiated by the company, commission staff and
an organization representing low‐income customers, allows for a 9.9 percent increase this year
and 1.7 percent on Feb. 1, 2011. The settlement includes an agreement that rates won’t
increase again until January 2012 at the earliest.
The agreement grants the request of many customers to allow United Water to switch to
monthly billing from bi‐monthly billing and provides the opportunity for customers of 12 months
or longer to participate in a level‐pay plan.
For an average residential customer, the increase will be about $2.83 per month, according to
the company. Part of the 9.9 percent increase is an 80‐cent per month increase in the customer
service charge.
United Water rates last increased in August 2006. Since then, the company invested more than
$13 million in capital improvements. “The company’s application and evidence proves, and
(commission) staff’s comprehensive audit confirms, that the company’s revenue request was
driven primarily by necessary replacement of aging infrastructure and increased power costs,”
the commission said.
The commission said it is well aware of current economic conditions and the hardship that any
increase places on customers. “A request for a rate increase filed by a utility in strained
economic times, when many customers may be struggling to pay existing bills, presents a
challenging responsibility for the commission,” the order states. By law, the company is entitled
to recover its reasonable expenses and receive a reasonable return on investments. To further
mitigate the size of the increase, the commission allowed United Water to defer some expenses,
including power costs, rate case expense and storage tank painting costs over a number of
years.
Commission staff said it was convinced that the agreed‐upon increase to come out of the
settlement was a better outcome for customers than had the case not been settled. The
Community Action Partnership Association of Idaho (CAPAI), representing low‐income
customers, said the settlement was reasonable. “Though we are in the midst of extremely
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difficult economic times, the settlement reached was likely the best that could be achieved from
all customers’ points of view.”
The commission agreed to CAPAI’s request that United Water, CAPAI and commission staff
convene workshops to review possible changes to United Water’s program for low‐income
customers and discuss efforts to improve participation in the company’s water conservation
program.
Case No. FLSW0901, Order No. 31022
March 11, 2010
Increase for Falls Water customers is 6 percent
Rates for customers of Falls Water Company near Idaho Falls will increase by about 6 percent
effective April 1. With the increase, an average residential bill will be about $24.16 per month.
The commission approved the increase after a six‐month investigation. Falls Water, which
serves about 3,600 customers north of Ammon and northeast of Idaho Falls, originally sought an
average 14.4 percent increase.
Falls Water sought to increase its annual revenue requirement by about $143,500. The
commission approved $92,728, for a total annual revenue requirement of $1,094,570.
To meet that revenue requirement, the company proposed to increase the minimum charge for
metered customers from $14 to $18 per month, but decrease its commodity charge from 66.7
cents per 1,000 gallons used above 12,000 gallons to 60 cents. The commission approved an
increase in the minimum charge to $16.10 per month for the vast majority of customers with ¾‐
inch or 5/8‐inch meters and a commodity charge of 61 cents for every 1,000 gallons above
12,000 gallons.
The minimum charge increases gradually for customers with larger meters. Falls Water
proposed to charge the same rate for all meter sizes, but the commission said that customers
who impose a higher demand on the system should pay more. Only 4 percent of customers have
larger meters.
The company’s last rate increase was in January, 2008. Since then, Falls Water has installed a
new well, meters and transmitters and replaced a hydrant. It also moved into larger office and
warehouse space.
“We recognize that for some customers, an increase will result in an economic hardship,” the
commission said. “Recognizing the current economic climate of this region and the country, we
also note that the commission has an obligation to Falls Water and its customers to set rates at
a level sufficient to allow the company to recover its reasonable expenses and receive a
reasonable return on its investments. This is necessary so the company can remain financially
sound and capable of providing adequate, clean water to its customers.”
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While the commission accepted the company’s rationale regarding its need for a larger office
and warehouse, it cautioned Falls Water about its affiliate relationship with the owners of the
office space, Rockwell Development, Inc. Commission staff investigated rental rates for office
and warehouse space in the Idaho Falls area and found the lease agreement with Rockwell to be
reasonable, but did not include proposed “escalators” that would have annually increased rental
expenses in customer rates.
The commission also declined to include in rates the entire $160,000 in land acquisition costs for
the combined siting of the new well and a future water storage reservoir. The commission
accepted $80,000, which was the land acquisition cost for the new well, but said the remainder
could not be included until the storage reservoir is in use and beneficial to customers. The
company purchased the land from Rockwell Development.
“The commission is genuinely concerned by the number of affiliate transactions that Falls Water
engages in without apparent regard to providing evidence of arm’s length bargaining,” the
commission said.
The commission also noted the company is not in full compliance with the commission’s
customer relations rules. It directed Falls Water to update within 60 days its main line extension
rules, monthly billing statements, initial and final notices of termination and annual rules
summary.
Case No. MURW1001
December 20, 2010
Commission declines to reconsider Murray Water decision
The commission denied a petition to reconsider its decision in a Murray, Idaho, water company
rate case.
Nearly all of the 36 customers of Murray Water Works Systems asked that the commission
postpone and/or reverse its Nov. 2 order increasing rates until Murray Water complies with “all
federal, state and county laws, regulations, orders and licenses pertaining to public utilities.”
The commission denied the petition, stating that its previous order addresses customer
concerns. “We find it prudent to allow Murray a reasonable opportunity to comply with our
directives,” the commission said. “In the interim, commission staff will continually monitor
Murray’s quality of service and verify whether Murray complies with the commission’s
mandates. As always, customers are permitted to participate in the verification process and
submit specific concerns and complaints …” the commission stated.
Customers want Murray Water owner Arlen Lish to comply with Idaho Department of
Environmental Quality regulations, particularly one that states water companies must hire a
certified waster system operator. The commission’s November order directed Murray Water to
hire a system operator at a cost of $400 per month. “If Mr. Lish is unwilling or otherwise unable
to become a certified system operator, then the commission orders the company to seek out
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61 | P a g e
and employ another individual to comply with IDEQ’s certification requirement …” the
commission stated.
Customer complaints regarding Murray Water’s substandard business and recordkeeping
practices “are well‐founded” and were addressed in the November order, the commission said.
In that order, the commission directed Murray Water to issue billing statements and
termination notifications that comply with commission rules. Full‐time customers must be billed
on a monthly basis while part‐time customers can be billed annually, the commission said. The
company had not been sending notice to customers until the accounts are more than 60 days
past due.
In its November order, the commission approved an increase in the monthly fee for full‐time
customers from $26 to $51.50. Rates for part‐time customers (eight months or less) increase
from $26 to $34.50, while monthly rates for business customers increase from $26 to $70.
The commission denied requests from Murray Water that individual meters be installed to
detect leaks and that it be allowed to install a back‐up power system and fire hydrants. The
commissions said all those items would add significant expense requiring an even greater
increase.
This was the company’s first rate case since 2003.
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Idaho Telecommunications
With the passage and signing of House Bill 224 in 2005, local exchange companies
operating in Idaho were provided the option of removing their services from rate
regulation. Idaho’s two largest telecommunications companies, Qwest
Communications, both North and South, and Verizon Northwest, lost no time in taking
advantage of this option, announcing their election to seek price deregulation shortly
after the new legislation became law. In 2007, Citizens Telecommunications, doing
business as Frontier Communications of Idaho, also opted into price deregulation.
While the services of all regulated telecommunications companies remain under
commission jurisdiction for customer service and quality issues, the rate deregulated
companies no longer need to seek commission approval to adjust rates. (Qwest South
had elected price deregulation for all of its services except basic local exchange service
in 1988.) In August of 2008, the three‐year transition period with caps expired for
Qwest and Verizon.
These companies provide service to more than 90 percent of the telephone lines in
Idaho, so the overwhelming majority of Idahoan’s telephone service is no longer subject
to rate regulation.
In 2009, CenturyTel merged with Embarq and is doing business as CenturyLink. Awaiting
final approval on a federal level is the bid of Frontier Communications to acquire
Verizon wireline assets, creating the nation’s largest pure rural telecommunications
service provider. Verizon operates in northern Idaho from about Orofino north. Frontier
currently has Idaho customers in the Elk City, McCall and Cascade regions.
Case No. GNRT1004, Order No. 32058
September 2, 2010
Surcharge for universal service to increase
A surcharge that helps telephone companies provide service to high‐cost rural areas will
increase slightly on Oct. 1.
The Idaho Telecommunications Act of 1988 created the Universal Service Fund (USF) to maintain
universal availability of local telephone service at reasonable rates in areas where greater
distances and fewer customers makes providing service more costly than providing the same
service in urban areas. Idaho Code 62‐610A, states that, “all consumers in this state, without
regard to their location, should have comparable accessibility to basic telecommunications
services at just and reasonable rates.” With assistance from the Universal Service Fund, rural
telephone companies are able to keep their rates at no more than 25 percent above rates in
more urban areas.
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All telephone companies pay to the fund through a surcharge on customer bills. The
commission’s order increases the amount telephone customers pay from 10 cents per
residential line per month to 12 cents and from 17 cents per business line to 19 cents.
Customers of long distance companies also pay the surcharge. The surcharge for in‐state toll
calls will increase from $.003 (three‐tenths of a cent) per minute to $.0035 per minute.
The surcharge collected $1.73 million for USF through June 30, but payments from USF to the
eight rural companies that qualify totaled $1.82 million. Although disbursements are down from
$1.94 million last year, disbursements still exceed the amount collected by the surcharge,
necessitating the increase.
With the increasing use of cellular phones, the number of residential and business landlines
continues to decrease. As of May 1, telephone companies reported an inventory of 328,592
residential lines, a nearly 11 percent decrease from the previous year. Business lines also
decreased by 2 percent to 219,752. Long‐distance billed minutes declined by 6 percent.
The eight telephone companies that qualify for USF disbursements include: Albion Telephone
Company, Cambridge Telephone Company, Direct Comm of Rockland, Inland Telephone
Company of Roslyn, Wash. (serving Idaho customers in Lenore and Leon), Fremont Telecom, Inc.
of St. Anthony; Midvale Telephone Exchange, Rural Telephone Co. of Glenns Ferry and Silver
Star Telephone Co. of Freedom Wyo. (serving Idaho customers in the eastern portions of
Bonneville and Caribou counties).
Case No. TIMT0801, Order No. 32059
August 31, 2010
Commission denies Time Warner reconsideration
The commission said it will not reconsider a February order that said Time Warner does not
need a certificate to provide wholesale telecommunications services in Idaho.
Time Warner wants to provide VoIP services (Voice Over Internet Protocol) to commercial
customers who then may sell to residential and/or small‐business customers. Time Warner
asked the commission to grant it a Certificate of Public Convenience and Necessity (CPCN).
Incumbent local exchange telecommunications providers – such as Qwest and Frontier
Communications (formerly Verizon) – and competitors that provide telecommunications
services using the facilities of incumbent providers, must obtain a CPCN to provide residential
exchange service to end‐users in Idaho.
The commission said it has no authority or jurisdiction to grant the certificate because Time
Warner does not intend to provide services at a retail level, or directly to residential or small‐
business end‐users. Instead, it will provide services on a purely wholesale basis. “Time Warner
will essentially be a carrier’s carrier,” the commission said.
Time Warner alleges that without a certificate, it won’t be able to interconnect with local
exchange services and it will have difficulty obtaining telephone numbers for its customers from
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65 | P a g e
a national agency that allocates numbers. Time Warner plans to interconnect with Qwest in
southern Idaho and Frontier Communications in northern Idaho. By not issuing it a certificate,
Time Warner alleges the state is creating a barrier to competition, a violation of both federal
and state law.
But the commission said denial of the CPCN does not mean the company cannot operate in the
state.
“If any Idaho local exchange company refuses to enter into an interconnection agreement with
Time Warner, Time Warner’s remedy is to file a complaint with the commission,” the
commission said. Federal law requires telecommunication carriers to interconnect with
competitors. The incumbent companies have a duty to negotiate in good faith and interconnect
with any requesting telecommunications carrier, the commission said.
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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, 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
2010
Inspections 194
Rail cars inspected 2035
Violations 1
Rail cars with defects 318
Crossing accidents investigated 2
Crossing complaints 2
Locomotives Inspected 15
Defects within locomotives inspected 0
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Operation Lifesaver
Idaho Operation Lifesaver is a non‐profit state organization dedicated to increasing
public awareness of the potential dangers that exist at highway/rail grade crossings and around
trains in general.
Volunteers from various sponsoring groups and other interested individuals staff the
organization. Volunteer staff members talk to about 130,000 people each year at presentations
and safety booths. Because of the IPUC’s railroad safety oversight, it has taken a leading role in
sponsoring and supporting Operation Lifesaver. IPUC staff members participate by making
presentations to groups, manning safety booths and serving on the board and various
committees.
It is the intent of the program to achieve its goal by using:
Education – Educate the public about trains by providing safety presentations and by
operating informational booths.
Engineering – Work with government entities, businesses and railroads to improve
highway/rail intersections.
Enforcement – Work with law enforcement agencies and railroads to enforce traffic
laws pertaining to highway/rail intersections.
Railroads in Idaho
Palouse River Railroad Burlington Northern Railroad
709 N. 10th St, Walla Walla, WA, 90362 176 E. Fifth St., St. Paul, MN, 55101
509.522.1464 208.263.2016
Idaho track miles: 0 Idaho track miles: 123
Great Northwest Railroad Eastern Idaho Railroad
PO Box 116, Lewiston, ID, 83501 618 Shoshone St. West, Twin Falls, ID, 83301
208.743.2559 208.733.4686
Idaho track miles: 8 Idaho track miles: 269
Idaho Northern & Pacific Montana Rail Link
PO Box 715, Emmett, ID, 83617 PO Box 8779, Missoula, MT, 59807
208.365.6353 406.523.1500
Idaho track miles: 99 Idaho track miles: 45
St. Maries River Railroad Union Pacific Railroad
318 N. 10th St., St. Maries, ID, 83861 1416 Dodge St., Omaha, NE, 68179
208.245.4531 208.343.1771
Idaho track miles: 99.4 Idaho track miles: 849
BG&CM Railroad, Inc. Boise Valley Railroad, Inc.
PO Box 1759, Orofino, ID, 83544 100 PFE Drive, Nampa, ID, 83687
208.476.7938 208.442.0144
Idaho track miles: 109 Idaho track miles: 36
IPUC Annual Report 2010
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Case No. UPRR1001, Order No. 32135
December 20, 2010
Commission won’t oppose Nampa rail abandonment
The commission will not intervene in a petition by Union Pacific Railroad to the federal Surface
Transportation Board for authority to abandon a near mile stretch of railway in downtown
Nampa.
The section proposed for abandonment begins near the intersection of 16th Avenue South and
Front Street in Nampa and extends nearly a mile to the south near East Florida Avenue.
The authority to grant or deny rail abandonment rests with the federal Surface Transportation
Board and is governed by federal law. However, the IPUC is required to conduct a public hearing
before the abandonment is considered at the federal level. The commission did so last October
at the Nampa City Hall.
At that hearing, city leaders and those affiliated with the Nampa Bicycle and Pedestrian Citizens
Advisory Group said they wanted to use the line as a pedestrian and bicycle pathway that is
critical to linking residential neighborhoods to downtown.
But shippers who formerly used the line, testified against the proposed abandonment. TVM
Recycling and Seminis Vegetable Seeds are located along the line, but have had to transload
their products to Caldwell and Kuna because UP failed to maintain the line. Staff from the
commission testified that UP paved over a crossing and started taking some rails out.
The commission’s role is to determine if the abandonment 1) adversely affects the area being
served, 2) impairs the access of Idaho shippers to vital goods and markets, and 3) whether the
rail line has the potential for profitability. If the commission determines the proposed
abandonment is not in the public interest, it files comments and represents the state before the
Surface Transportation Board.
The commission, however, will not pursue the matter before the federal agency, stating that the
cost of repairing the line and making it suitable for rail service is no longer viable. “Union
Pacific’s failure to maintain the line and ensure rail service to the shippers demonstrates its lack
of commitment to its smaller customers,” the commission said. “UP could have acted in a more
collaborative manner with the shippers and possibly averted the need to abandon the line.”
Under the exemption procedure pursued by Union Pacific, the Surface Transportation Board will
publish a notice in the Federal Register within 20 days after the petition for exemption is filed.
Thirty days after the notice is published, the railroad is permitted to abandon the rail line unless
the STB stays the abandonment.
IPUC Annual Report 2010
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Consumer Assistance
The Consumer Assistance staff responded to 2,897 complaints, comments or
inquiries in calendar year 2009, of which 88 percent were from residential customers.
The number of contacts increased by 10 percent from 2008.
Breakdown of complaints by type of utility
Contacts regarding telecommunications companies: 35 percent
Contacts regarding energy (electric, gas) companies: 48 percent
Contacts regarding water companies: 9 percent
Non-utility related contacts: 8 percent
(Qwest Communications had 40 percent of telecommunication complaints; Idaho Power had 50 percent
and Intermountain Gas 21 percent of energy utility complaints and United Water had 36 percent of water
complaints.)
Summary of service quality issues:
Disputed billings 22 percent
Credit and collection issues 31 percent
Miscellaneous 17 percent
Utility rates and policies 18 percent
Telecommunications issues 7 percent
Line extensions and service upgrades 2 percent
Service quality and repair 4 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 35 percent of investigations resulted in reversal or
modification of the utilities’ original action.
Toll‐Free Complaint Line
The commission has a toll‐free telephone line for receiving utility complaints and
inquiries from consumers outside the Boise area. The toll‐free line (1‐800‐432‐0369) is
reserved for inquiries and complaints concerning utilities. Consumers may also file a
complaint electronically via the commission’s Website at www.puc.idaho.gov.
IPUC Annual Report 2010
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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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City Electric Gas Tele
Mud Lake Rocky Mountain None Mud Lake Co-op
Mullan AVISTA AVISTA Verizon
Murphy Idaho Power None Qwest
Murray AVISTA None Verizon
Murtaugh Idaho Power Intermountain Qwest
Myrtle Clearwater Power None Inland
Naf Raft River Coop None ATC
Nampa Idaho Power Intermountain Qwest
Naples Northern Lights None Verizon
Neeley Idaho Power None Qwest
Newdale RMP/Fall River Coop None Fairpoint
New Meadows Idaho Power None Citizens
New Plymouth Idaho Power Intermountain Qwest
Nezperce Clearwater Power/AVISTA None Qwest
Norland Idaho Power None Project Mutual
Nordman Northern Lights None Verizon
North Fork Idaho Power None CenturyTel
Notus Idaho Power None Qwest
Nounan Rocky Mountain None Qwest
Oakley Idaho Power None Project Mutual
Obsidian Salmon River Coop None Midvale
Ola Idaho Power None Citizens
Oldtown AVISTA None Verizon
Onaway AVISTA/Clearwater Power None Verizon
Orchard Idaho Power None Qwest
Oreana Idaho Power None CenturyTel Gem
Orofino Clearwater Power/AVISTA None Verizon
Orogrande AVISTA None Citizens
Osburn AVISTA AVISTA Verizon
Ovid Rocky Mountain None Qwest
Oxford Rocky Mountain None Qwest
Paris Rocky Mountain None Direct
Parker Rocky Mountain Intermountain Fairpoint
Parma Idaho Power Intermountain Citizens
Patterson Salmon River Coop None CenturyTel
Paul Idaho Power/Rural Intermountain ProjMut
Pauline Idaho Power None Direct
Payette Idaho Power Intermountain Qwest
Pearl Idaho Power None Qwest
Peck Clearwater Power None Verizon
Picabo Idaho Power None Qwest
Pierce AVISTA None Verizon
Pine Idaho Power None Rural
Pinehurst AVISTA AVISTA Verizon
Pingree Idaho Power None Qwest
Pioneerville Idaho Power None Qwest
Placerville Idaho Power None Qwest
Plummer Plummer Electric None Verizon
Pocatello Idaho Power Intermountain Qwest
Pollock Idaho Power None Citizens
Ponderay AVISTA AVISTA Verizon
Porthill AVISTA/Northern Lights None Verizo
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City Electric Gas Tele
Portneuf Idaho Power None Qwest
Post Falls Kootenai Elec/AVISTA AVISTA Verizon
Potlatch Clearwater Power/AVISTA None Verizon
Prairie Idaho Power None Rural
Preston Rocky Mountain Questar Qwest
Priest River AVISTA None Verizon
Princeton Clearwater Power/AVISTA None Verizon
Raft River Raft River Coop Intermountain ATC
Rathdrum Kootenai Elec/AVISTA AVISTA Verizon
Reubens Clearwater Power/AVISTA None Qwest
Rexburg RMP/Fall River Coop Intermountain Qwest
Reynolds Creek Idaho Power None Qwest
Richfield Idaho Power None CenturyTel Gem
Riddle Idaho Power None CenturyTel Gem
Rigby Rocky Mountain Intermountain Qwest
Riggins Idaho Power None Citizens
Ririe Rocky Mountain Intermountain Qwest
Riverside Idaho Power Intermountain Qwest
Roberts Rocky Mountain None Qwest
Robin Rocky Mountain None Qwest
Rock Creek Idaho Power None Verizon
Rockford Idaho Power None Qwest
Rockland Idaho Power None Direct
Rogerson Idaho Power None Filer Mutual
Rose Lake AVISTA/Kootenai None Verizon
Roswell Idaho Power None Citizens
Roy Idaho Power None Direct
Rupert Idaho Power Intermountain ProjectMut
Sagle AVISTA None Verizon
St. Anthony RMP/Fall River Coop Intermountain Fairpoint
St. Charles Rocky Mountain None Direct
St. Joe AVISTA None Verizon
St. Maries Clearwater Power/AVISTA None Verizon
Salmon Idaho Power None CenturyTel
Samaria Rocky Mountain None ATC
Samuels Northern Lights None Verizon
Sanders Clearwater Power None Verizon
Sandpoint AVISTA AVISTA Verizon
Santa Clearwater Power None Verizon
Shelley Rocky Mountain Intermountain Qwest
Shoshone Idaho Power Intermountain Qwest
Shoup None None Rural
Silverton AVISTA AVISTA Verizon
Smelterville AVISTA AVISTA Verizon
Smiths Ferry Idaho Power None Citizens
Soda Springs Soda Springs Muni Intermountain Qwest
Southwick Clearwater Power None Potlatch
Spalding AVISTA/Clearwater Power None Qwest
Spencer Rocky Mountain None Mud Lake Co-op
Spirit Lake AVISTA/Kootenai None Verizon
Springston AVISTA/Kootenai None Verizon
IPUC Annual Report 2010
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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
IPUC Annual Report 2010
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City Electric Gas Tele
Woodland AVISTA None Qwest
Worley AVISTA/Kootenai None Verizon
Yellow Pine Idaho Power None Midvale
________________________________________________________________________
IPUC Annual Report 2010
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Questions regarding this report? Please call Gene Fadness at 334‐0339 or e‐mail to
gene.fadness@puc.idaho.gov.