Annual report final 120117.pdf

IDAHO
PUBLIC
UTILITIES
COMMISSION
2017 Annual Report
Idaho Public Utilities Commission
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TABLE OF CONTENTS
COMMISSIONERS ....................................................................................................................... 5
FINANCIAL SUMMARY FUND 0229 ........................................................................................... 8
Fiscal Years 2013 – 2017 .............................................................................................................................. 8
COMMISSION STRUCTURE AND OPERATIONS ......................................................................... 9
Administration ................................................................................................................................................. 11
Legal ................................................................................................................................................................ 12
Utilities Division............................................................................................................................................... 12
Railroad .......................................................................................................................................................... 13
Pipeline Safety ............................................................................................................................................... 13
WHY CAN’T YOU JUST TELL THEM NO? .................................................................................. 14
2017 MAJOR EVENTS .............................................................................................................. 15
ELECTRIC .................................................................................................................................. 21
NATURAL GAS ......................................................................................................................... 32
WATER. .................................................................................................................................... 40
TELECOMMUNICATIONS. ........................................................................................................ 43
CONSUMER ASSISTANCE ........................................................................................................ 46
REGULATING IDAHO’S RAILROADS ........................................................................................ 47
REGULATING IDAHO’S PIPELINES ........................................................................................... 48
Idaho Public Utilities Commission
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Idaho Public Utilities Commission
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Idaho Public Utilities Commission
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Idaho Public Utilities Commission

Contact us: 208-334-0300
Website: www.puc.idaho.gov
Commission Secretary 208-334-0338
Executive Assistant 208-334-0330
Public Information 208-334-0339
Utilities Division 208-354-0367
Legal Division 208-334-0324
Rail Section and Pipeline Safety 208-334-0330
Consumer Assistance Section 208-334-0369
Outside Boise, Toll-Free Consumer Assistance 1-800-432-0369

Idaho Telephone Relay Service (statewide)
Voice: 1-800-377-3529
Text Telephone: [phone]
TRS Information: 1-800-368-6185

This report can be accessed online from the Commission’s Website at www.puc.idaho.gov. Click on “File Room,” in the upper-left-hand-corner and then on “IPUC 2017
Annual Report.”
Front cover photograph courtesy of Avista Utilities.
Idaho Public Utilities Commission
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Idaho Public Utilities Commission
December 1, 2017

The Honorable C.L. “Butch” Otter
Governor of Idaho
Statehouse
Boise, ID 83720-0034

Dear Governor Otter:
It is my distinct pleasure to submit to you, in accordance with Idaho Code §61-214, the Idaho
Public Utilities Commission 2017 Annual Report. This report provides a detailed description
of the most significant cases, decisions and other activities throughout 2017. The financial
report on Page 8 offers a summary of the commission’s budget through the conclusion of
Fiscal Year 2017, which ended June 30, 2017.
It has been a privilege and honor serving the people of Idaho this past year.

Sincerely,

Paul Kjellander
President, Idaho Public Utilities Commission

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Idaho Public Utilities Commission
Idaho Public Utilities Commission
Page 8
Paul Kjellander serves as president of the Idaho Public Utilities Commis-
sion, having been appointed to his current six-year term in 2017 by Gov.
C.L. “Butch” Otter. His term expires in 2023.
It is Commissioner Kjellander’s second term in his second stint on the Com-
mission, having previously served from January 1999 until October 2007.
Gov. C.L. “Butch” Otter reappointed Kjellander in April 2011, following
his service as administrator of the newly created state Office of Energy
Resources (OER).
A member of the National Association of Regulatory Commissioners’
board of directors, Kjellander is chairman of the association’s Committee
on Telecommunications and serves as NARUC representative to the North
American Numbering Council. He previously served on NARUC’s Committee on Consumer Affairs
and its Electricity Committee.
Kjellander is an at-large member of the National Council on Electricity Policy, which is funded by
the US Department of Energy and managed by NARUC.
Kjellander is also a member of the Federal Communications Commission’s 706 Joint Board, and has
served as chairman of the FCC’s Federal-State Joint Board on Jurisdictional Separations.
During his time at OER, which is now known as the Office of Energy and Mineral Resources, Kjel-
lander created an aggressive energy efficiency program funded through the federal American
Recovery and Reinvestment Act of 2009. He also served on the board of the National Association
of State Energy Officials.
Before joining the Commission in 1999, Kjellander was elected to three terms in the Idaho House of
Representatives, where he served from 1994 to 1999. As a legislator, Kjellander served on a num-
ber of committees, including the House State Affairs, Judiciary and Rules, Ways and Means, Local
Government and Transportation. During his final term in office, Kjellander was elected chairman of
the House Majority Caucus.
Kjellander has also served as director of Boise State University’s College of Applied Technology
Distance Learning, program head of broadcast technology, station manager of BSU Radio Net-
work, director of the Special Projects Unit for BSU Radio and BSU Radio’s director of News and
Public Affairs.
He earned undergraduate degrees in communications, psychology and art from Muskingum Col-
lege in Ohio. He also has a master’s degree in telecommunications from Ohio University.
COMMISSIONERS
PAUL KJELLANDER
Idaho Public Utilities Commission
Page 9
Kristine Raper was appointed to the commission on Feb. 19, 2015 by Gov.
C.L. “Butch” Otter. Her term expires in January 2021.
Commissioner Raper serves on the Electricity Committee of the National Asso-
ciation of Regulatory Utility Commissioners (NARUC) and is the incoming pres-
ident of the Western Conference of Public Service Commissioners.
Raper is a member of the Body of State Regulators for the California ISO’s
Energy Imbalance Market. She is also a member of the State-Provincial
Steering Committee.
Raper recently testified before Congress regarding Public Utility Regulatory
Policies Act (PURPA), defending Idaho’s decisions regarding the federal law.
Commissioner Raper has also testified on PURPA issues before the Idaho Supreme Court, District Court
and the Federal Energy Regulatory Commission, which enforces PURPA.
Raper previously served on the Member Advisory Committee of the Western Electric Coordinating
Council (WECC).
Prior to her appointment to the Idaho Public Utilities Commission, Raper served for seven years as a
deputy attorney general assigned to the Commission. During her time as an attorney for the Commis-
sion, Raper was involved in electric, gas, water and telecommunications cases, with an emphasis on
PURPA-related matters.
Before her service as a deputy attorney general, Commissioner Raper served for eight years as a
law clerk to R.D. Maynard of the Idaho Industrial Commission. There, Raper developed expertise in
state worker’s compensation law and unemployment matters appealed through the Idaho Department
of Labor.
Raper was born in Delaware and moved to Utah with her family in the early 1980s. She moved to
Boise in 1990 to attend Boise State University and earned a bachelor of science in criminal justice in
1995. She received her juris doctor from the University of Idaho in 2001.
The commissioner and her husband, Mark, share three children.
KRISTINE RAPER
COMMISSIONERS
Idaho Public Utilities Commission
Page 10
Eric Anderson was appointed to the Commission in December 2015. His term
expires in January 2019.
Commissioner Anderson serves on the National Association of Regulatory
Utility Commissioners’ Committee on Water as well as its Committee on In-
ternational Relations.
Before his appointment by Gov. C.L. “Butch” Otter, Anderson served five
terms in the Idaho Legislature, from 2004-2014. Anderson was chairman of
the House Ways and Means Committee in his final term in the state Legisla-
ture.
As a member of the state House of Representatives, Anderson served on a number of committees, in-
cluding Environment, Energy and Technology; Commerce and Human Resources; Resources and Con-
servation; Business; and State Affairs. He also chaired a legislative Interim Subcommittee on Renewa-
ble Energy.
Anderson received a bachelor of art degree in political science and government from Eastern Wash-
ington University in 1979.
A general contractor and real estate broker, Anderson served as director and vice president of
Sandpoint-based Northern Lights Inc., an electric cooperative in Sandpoint, prior to his appointment to
the Commission.
He has also served as a director of the Idaho Consumer-Owned Utilities Association, the National Ru-
ral Electric Cooperative Association and the Idaho Energy Resources Authority. He is a past member
and advisor to the Pacific States Marine Fisheries Council and the Pacific Northwest Economic Region’s
Executive Council.
ERIC ANDERSON
COMMISSIONERS
Idaho Public Utilities Commission
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Description FY 2013 FY 2014 FY 2015 FY 2016

FY 2017

Personnel Costs $3,491,500 $3,528,900 $3,563,500 $3,835,900 $4,070,200
Communication Costs $31,300 $31,000 $23,500 $28,700 $23,400
Employee Development Costs $55,600 $53,200 $99,200 $98,700 $81,400
Professional Services $9,700 $12,300 $8,500 $8,600 $11,900
Legal Fees $551,600 $519,700 $538,400 $579,400 $482,100
Employee Travel Costs $123,600 $141,100 $152,500 $159,200 $173,900
Fuel & Lubricants $4,700 $2,700 $5,600 $2,900 $4,900

Insurance $3,100 $4,400 $4,300 $2,000 $3,500
Rentals & Leases $276,100 $584,600 $308,600 $223,800 $147,000
Misc. Expenditures $117,000 $104,700 $84,400 $104,300 $114,900
Computer Equipment $29,200 $66,400 $73,600 $52,200 $44,700
Office Equipment $13,000 $11,900 $16,500 $8,100 $4,200
Motorized/Non-Motorized
Equip $0 $0 $32,500 $0 $0
Specific Use Equipment $0 $0 $0 $1,700 $4,500

Total Expenditures $4,706,400 $5,060,900 $4,911,100 $5,095,100 $5,166,600

Fund 0229-20 Appropriation $4,916,800 $5,061,700 $5,595,600 $5,766,500 $5,902,700

Unexpended Balance $210,400 $800 $684,500 $671,400 $736,100
FINANCIAL SUMMARY FUND 0229*
Fiscal Years 2013-2017
* This summary represents assessment-funded expenses only. It does not include federal or other funds.
Idaho Public Utilities Commission
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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 utili-
ties.
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, cor-
ruption or incompetence.
The three-member commission was established by the 12th Ses-
sion 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. Stat-
utory authorities for the commission are established in Idaho
Code titles 61 and 62.
The IPUC has quasi-legislative and quasi-judicial as well as ex-
ecutive powers and duties.
In its quasi-legislative capacity, the commission sets rates and
makes rules governing utility operations. In its quasi-judicial
mode, the commission hears and decides complaints, issues writ-
ten orders that are similar to court orders and may have its deci-
sions appealed to the Idaho Supreme Court. In its executive ca-
pacity, 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 ad-
ministrative tasks. Chairmanship of individual cases is rotated among the commissioners.
Idaho Public Utilities Commission
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The commission conducts its business in two types of meetings – hearings and decision meetings. Decision
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 proceed-
ings 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” pre-
sent testimony and evidence, subject to
cross-examination by attorneys from the
other parties, staff and the commissioners.
At public hearings, members of the public
may testify before the commission.
Many public hearings are conducted in cities and towns that are part of the service territory of the utility
seeking a rate increase. In less contested rate cases, the commission will sometimes conduct hearings tele-
phonically 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 to those testify-
ing.
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 com-
mission staff. Minutes of the meetings are taken. Decisions reached at these meetings may be either final or
preliminary, but subsequently become final when the commission issues a written order signed by a majority
of the commission. Under the Idaho Open Meetings Law, commissioners may also privately deliberate
matters that have been fully submitted.
IPUC hearing room
IPUC headquarters at 472 W. Washington St.
in downtown Boise
COMMISSION STRUCTURE AND OPERATIONS
Idaho Public Utilities Commission
Page 14
COMMISSION STAFF
OUR MISSION

 Determine fair, just and reasonable rates and utility prac-
tices for electric gas and water consumers.
 Ensure that delivery of utility services is safe, reliable and
efficient.
 Ensure safe operation of pipelines and rail carriers within
the state.
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 Commis-
sion staff is organized into 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, pre-
senting its own testimony, evidence and expert witnesses. The Commission considers staff recommendations along with
those of other participants in each case - including utilities, public, agricultural, industrial, business, environmental
and consumer groups.
Administration
The Administrative Division is responsible for coordinating overall IPUC activities. It includes the three
commissioners, a policy analyst, a commission secretary, an executive administrator, an executive assis-
tant, public information officer and support personnel.
The policy analyst is an executive level position that reports 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 strate-
gy, providing assistance and advice on major litigation before the commis-
sion, public agencies and organizations.
Contact Stephen Goodson, Policy Analyst, [phone].
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 Diane Hanian, Commission Secretary, [phone].
The executive administrator has primary responsibility for the commission’s fiscal and administrative op-
erations, preparing the commission budget and supervising fiscal, administration, public information,
Idaho Public Utilities Commission
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personnel, information systems, rail section operations and pipeline safety. The executive administrator
is the primary contact for matters concerning Information Technology, Fiscal and Human Resources. He
also serves as a liaison between the commission and other state agencies and the Legislature.
Contact Joe Leckie, Executive Administrator, [phone].
Legal
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 fed-
eral courts and before other state or federal regulatory agencies.
Contact Karl Klein, Legal Division Director, [phone].
Utilities Division
The Utilities Division, responsible for technical and policy analysis of utility matters before the commis-
sion, is divided into five sections.
Contact Randy Lobb, Utilities Division Administrator, [phone].
The Accounting Section of six auditors and one supervisor audits utility books and records to verify re-
ported revenue, expenses and compliance with commission orders. Staff auditors present the results of
their findings in audit reports as well as in formal testimony and exhibits. When a utility requests a
rate increase, cost-of-capital studies are performed to determine a recommended rate of return. Reve-
nues, expenses and investments are analyzed to determine the amount needed for the utility to earn
the recommended return on its investment. Contact Terri Carlock, Utilities Division Deputy Administra-
tor and Accounting Section Supervisor, [phone].
The Engineering Section of three engineers, two analysts and one supervisor reviews the physical oper-
ations of utilities. The staff of engineers and analysts develops computer models of utility operations
and compares alternative costs to repair, replace and acquire facilities to serve utility customers. The
group calculates and analyzes the price of acquiring cogeneration and renewable generation facilities
and identifies the cost of serving various types of customers. They evaluate the adequacy of utility ser-
vices and frequently help resolve customer complaints.
Contact Mike Louis, Engineering Section Supervisor, [phone].
The Technical Analysis section of four utility analysts and one supervisor reviews utility Integrated Re-
source Plans, capital investments and forecasts of energy, water and natural gas use. They examine the
prudency and cost-effectiveness of all Demand Side Management (DSM) programs , which include en-
ergy efficiency and demand response. They also identify potential for new DSM programs, track the
impact on utility revenues and focus on residential self-generation.
Contact Stacey Donohue, Technical Analysis Section Supervisor, [phone].
COMMISSION STAFF
Idaho Public Utilities Commission
Page 16
The Telecommunications section includes two analysts who oversee tariff and price list filings, area code
oversight, Universal Service, Lifeline and Telephone Relay Service. They assist and advise the commis-
sion on technical matters that include advanced services, 911 and other matters as requested.
Contact Carolee Hall, Telecommunications Analyst, [phone].
The Consumer Assistance section includes five division investigators and one supervisor who resolve con-
flicts 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, Consumer Assistance Administrator, [phone].

Railroad Section
Our rail inspector oversees the safe operations of railroads that move freight throughout Idaho and en-
forces state and federal regulations safeguarding the transportation of hazardous materials by rail in
the state. The Commission’s rail safety specialist inspects railroad crossings and rail clearances for safe-
ty and maintenance deficiencies. The Rail section helps investigate 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 au-
thority to grant or deny line abandonments.
Contact Joe Leckie, Rail Section Manager, [phone].
Pipeline Safety
The three-member Pipeline Safety section oversees the safe operation of the intrastate oil and natural
gas pipelines in Idaho.
Pipeline safety personnel verify compliance with state and federal regulations by on-site inspections of
intrastate pipeline 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 fac-
tors and to implement practices to avoid accidents. All reportable accidents will be investigated and
appropriate reports filed with the U.S. Department of Transportation in a timely manner.
Contact Joe Leckie, Pipeline Safety Program Manager, [phone].
COMMISSION STAFF
Idaho Public Utilities Commission
Page 17
One of the most frequently asked questions the PUC receives after a utility
files an application for a rate increase is, “Why can’t you just tell them no?”
Actually, we can, but not without evidence.
For more than 100 years, public utility regulation has been based on this reg-
ulatory compact between utilities and regulators: Regulated utilities agree to
invest in the generation, transmission and distribution necessary to adequately
and reliably serve all the customers in their assigned territories. In return for that promise to serve, utili-
ties are guaranteed recovery of their prudently incurred expense along with an opportunity to earn a
reasonable rate of return. The rate of return allowed must be high enough to attract investors for the
utility’s capital-intensive generation, transmission and distribution projects, but not so high as to be un-
reasonable for customers.
In setting rates, the Commission must consider the needs of both the utility and its customers. The Com-
mission 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 distribu-
tion infrastructure to be able to provide safe, adequate and reliable electrical, natural gas and water
service. This is a critical, even life-saving, service for Idaho’s citizens and essential to the state’s econom-
ic development and prosperity.
Unlike unregulated businesses, utilities cannot cut back on service as costs increase. As demand for elec-
tricity, natural gas and water grows, utilities are statutorily required to meet that demand.
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, analysts and attorneys will take up to six
months to examine the request. During that period, other parties, often representing customer groups,
will “intervene” in the case for the purpose of conducting discovery, presenting evidence and cross-
examining the company and other parties to the case. The Commission staff, which operates inde-
pendently of the Commission, will also file its own comments that result from its investigation of the com-
pany’s request. The three-member Commission will also conduct technical and public hearings.
Once testimony is presented from the company, commission staff and intervening parties, and testimony
is taken from hearings and written comments, that information is included in the official record for the
case. It is only from the evidence contained in this official record that the Commission can render a deci-
sion.
If the utility has met its burden of proof in demonstrating that the additional expense it incurred was 1)
necessary to serve customers and 2) prudently incurred, the Commission must allow the utility to recover
that expense. The Commission can — and often does — deny recovery of some or all the expense utili-
ties seek to recover from customers if the Commission is confident it has the legal justification to do so.
Utilities and parties to a rate case have the right to petition the Commission for reconsideration. If re-
consideration is not granted, the Commission’s decision can be appealed to the state Supreme Court.
WHY CAN’T YOU JUST TELL THEM NO?
Idaho Public Utilities Commission
Page 18
2017 MAJOR EVENTS
Idaho gets second area code
Idaho’s transition to a new area code and mandatory 10-digit dialing came to a close in September.
The process of introducing the state’s second area code began in fall 2015, when the Commission ap-
proved a plan calling for mandatory 10-digit dialing in August 2017 and for providers to begin as-
signing the 986 area code to new customers in September 2017.
The need for Idaho’s second area code was prompted by warn-
ings that the state was on track to exhaust its supply of available
telephone numbers by mid-2018.
The Commission had staved off the need for a new area code in
2001 by implementing various numbers conservation plans that
successfully delayed the need by 15 years.
The demand for telephone numbers has increased significantly
since then, however, due primarily to the proliferation of cell phones, the Internet, Voice over Internet
Protocol and other emerging technologies.
The Commission decided in November 2015 that the state should assign the new area code statewide
to all new phone numbers effective Sept. 5, 2017. Referred to as a “geographic overlay,” this ap-
proach was one of two options for implementation of the new area code and was the unanimous recom-
mendation of the state’s telecommunications providers.
The other option, a “geographic split,” would have assigned the new area code to all numbers in half
of the state, requiring all customers in the area assigned the new area code to change their telephone
numbers. That would have caused significant disruptions to businesses in the area with the new area
code, the Commission determined.
While the “geographic overlay” option meant that everyone could keep their existing phone number, it
also meant that Idahoans would have to dial 10 digits (area code plus prefix plus four digit number)
for all calls within the state.
To ensure residents were prepared for this change, the Commission established a 16-month transition
period highlighted by the introduction of voluntary 10-digit dialing in November 2016.
Ten-digit dialing became mandatory for all calls on Aug. 5, 2017, and providers began assigning the
986 area code on Sept. 5, 2017.
Commissioner Raper testifies before Congress regarding PURPA
Commissioner Kristine Raper spoke at a hearing before the House Energy and Commerce Committee’s
Subcommittee on Energy in September about the need to reform the Public Utility Regulatory Policies
Act of 1978 (PURPA).
PURPA was intended in part to promote the development of renewable energy by requiring utilities to
buy power from qualifying renewable facilities. While PURPA supporters say the law has helped spur
Idaho Public Utilities Commission
Page 19
the development of wind and solar energy, critics contend developers of renewable energy are manip-
ulating the law, resulting in higher electric rates.
Complaints in recent years prompted the House Energy and Com-
merce Subcommittee to review the law.
A series of hearings called “Powering America: Reevaluating PUR-
PA’s Objectives and Its Effects on Today’s Consumers,” were part
of that review process.
In her testimony, Raper urged lawmakers to take steps to fix PUR-
PA’s flaws.
State regulators should have more authority to determine what
constitutes a qualifying facility under the law, Raper testified. Today that responsibility is exclusively
under the jurisdiction of the Federal Energy Regulatory Commission.
Avista Utilities proposes merger with HydroOne
In September, Avista requested regulatory approval of its proposed merger with HydroOne Limited,
which provides electric service to more than 1.3 million customers in Ontario.
The Commission is one of several regulatory entities that must approve the $5.3 billion deal. Others
include regulatory agencies in Washington state, Oregon, Montana and Alaska, and the Federal Ener-
gy Regulatory Commission.
The merger also must comply with the Hart-Scott-Rodino Antitrust Improvements Act of 1976, and it
must be authorized by the Committee on Foreign Investment in the United States, an inter-agency gov-
ernmental board charged with reviewing the national security implications of foreign investments in US
companies.
If the merger is approved, Avista would become a wholly-owned subsidiary of HydroOne but would
keep its name and continue to operate out of its current headquarters in Spokane as a “standalone util-
ity” with its existing employees and management team.
Combined, the two companies would be one of the largest regulated utilities in North America, with
more than $25.4 billion in assets.
In its application requesting Commission approval, Avista said its customers would see immediate bene-
fits of receiving service from a larger utility, including a proposed rate credit of $31.5 million that
would be distributed over a 10-year period.
Long-term benefits of the merger include increased purchasing power and reduced costs associated
with efficiencies that emerge as best practices and business processes are developed and technology
shared, according to the company.
Based in Toronto, HydroOne is the largest electric utility in Ontario. It lacks generation resources but
maintains a network of nearly 19,000 miles of transmission lines and 77,000 miles of distribution lines.
2017 MAJOR EVENTS
Idaho Public Utilities Commission
Page 20
Avista’s generation resources include eight hydropower facilities, five natural gas plants and a biomass
facility. The company has ownership interest in two coal-fired plants and maintains more than 20,800
miles of transmission and distribution lines. It provides electric service to approximately 130,000 Idaho-
ans and natural gas service to more than 80,000 in northern Idaho.
The Commission will analyze the proposed merger in order to determine whether it is in the interest of
Idaho residents. Idaho Code 61-328 states that an electric utility may transfer property only if the
Commission finds that:
 Rates will not increase because of the transaction.
 The buyer has the intent and financial ability to operate and maintain the property in the public
service.
 The transaction is consistent with the public interest.
The Ontario government owns 49.9 percent of HydroOne’s shares
but “it does not hold or exercise any managerial oversight over
Hydro One,” according to the application.
If the merger is approved, Avista would no longer be a publicly-
traded company and would instead have one owner, HydroOne.
The companies have requested Commission approval of the mer-
ger by mid-August 2018.
Intermountain Gas’ first rate case in more than 30 years is resolved
In April, the Commission approved a rate increase for Intermountain Gas customers, the company’s first
general rate case since 1985.
The Commission’s 46-page order called for a 1.58-percent increase effective May 1.
The company’s proposal had called for rates to increase by an average of 4.06 percent but was re-
vised to an average 3.7-percent increase after a three-day technical hearing.
The Commission’s decision also called for the elimination of seasonal rates for residential customers,
adoption of a demand charge for two customer classes – large volume and transportation, and ac-
ceptance of Intermountain’s proposal to create demand side management programs to help customers
reduce natural gas consumption in order to decrease the amount of gas the company would have to
buy from wholesale suppliers.
Intermountain petitioned the Commission to reconsider its decision on May 18, citing four concerns.
Two of Intermountain’s concerns pertained to weather data used to project energy usage, and there-
fore revenue. In its order, the Commission found that Intermountain Gas’ methodology for using weather
data to forecast energy usage among its customers was not reproducible.
That made it impossible to determine whether the company’s model accurately projected the amount of
energy it would need to purchase, and the amount of revenue required to recover those expenses
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Idaho Public Utilities Commission
Page 21
through customer rates, the Commission said. As a result, the Commission used a weather normalization
model developed specifically for this case and decreased the associated revenue requirement by ap-
proximately $2 million.
Intermountain’s reconsideration petition said the Commission’s analysis overstated revenue.
The utility also expressed concern with the Commission’s decisions to disallow $1.38 million in expenses
paid to Intermountain’s affiliate, MDU Resources, and $704,000 in nonexecutive incentive compensa-
tion.
In granting Intermountain’s reconsideration petition, the Commission directed the interested parties to
explore settlement opportunities. The parties, which included the company, commission staff and the
Northwest Industrial Gas Users, forged a settlement agreement in September that called for a compro-
mise on the four concerns that Intermountain had cited.
The settlement approved by the Commission allowed the compa-
ny to recover an additional $1.2 million in expenses related to
affiliated expenses and incentive compensation, representing a
50/50 split of the dollar amounts related to these two issues,
and to recover an additional $6,065 in annual base rate reve-
nues related to weather modeling. The settlement also establish-
es a procedure for determining the weather normalization meth-
odology employed in future rate cases.
The settlement agreement resulted in a 1.36-percent rate in-
crease across all customer classes. That equates to an additional 37 cents on the monthly bill of the av-
erage residential customer.
IPUC rules on Idaho Power preparations for entry into Energy Imbalance Market
In February, the Commission approved Idaho Power’s request to authorize a deferral account to track
the costs incurred associated with joining the California ISO’s Energy Imbalance Market (EIM).
The Commission believed it was premature to find that the utility’s participation would benefit customers
in the long term, however.
The EIM that Idaho Power plans to join in April 2018 balances the supply and demand for energy via
automated dispatch services at five-minute intervals from generation resources across the region.
Idaho Power’s current configuration features hourly dispatch services from its own generation and re-
serve resources.
Idaho Power contends that moving from an hourly market to a five-minute imbalance market will allow
it to balance supply and demand more efficiently and cost-effectively.
The potential annual savings could be between $4 million and $5 million, Idaho Power said; the upfront
costs of joining the EIM were estimated at approximately $11 million.
The Commission adopted Idaho Power’s proposal to spread the initial costs over a 10-year period but
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Idaho Public Utilities Commission
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said the costs cannot be recovered from ratepayers until they are known rather than estimated. Those
costs also must be found to be prudently incurred before they are included in rates.
In its order, the Commission also asked the company to provide more evidence of customer benefits.
Idaho Power had proposed providing a quarterly benefits report provided by the EIM administrator,
the California Independent System Operator. The Commission asked for such a report but further di-
rected the company to provide a report one year after joining the EIM that outlines the costs and bene-
fits of participation.
Commission approves settlement related to early closure of coal plant
In June , the Commission approved a settlement related to the early retirement of a coal-fired plant in
Nevada.
The settlement allows the company to accelerate the recovery of its
investment in the North Valmy Power Plant through base rates, lead-
ing to a rate increase of 1.17 percent.
That equates to an additional $1.20 on the monthly bill of the typical
residential customer using 1,000 kilowatt-hours (kWh) per month.
The company had originally proposed raising rates by 3.1 percent to
recover its investment in Valmy. That would have led to a $3.08 in-
crease to the monthly bill of the typical residential customer using
1,000 kWh per month.
The settlement agreement calls for shuttering Valmy’s Unit 1 in 2019, and Unit 2 in 2025.
Unit 1 went into service in 1981 and Unit 2 came online in 1985. Each had a 50-year life expectancy,
and their depreciation was embedded in Idaho Power’s base rates with the expectation that the units
would operate until 2031 and 2035, respectively.
The rate increase is expected to generate nearly $13.3 million in annual revenue until 2028, when
Valmy is fully depreciated – down from $28.5 million in Idaho Power’s original proposal.
Idaho Power maintains that closing the plant early will ultimately save customers money. The company
said a significant decrease in market prices for electricity had made it uneconomic to operate the 522-
megawatt plant except during extremely cold or hot weather, when the demand for energy surges.
Idaho Power said costs associated with the plant’s operation have increased significantly since 2011.
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ELECTRICAL POWER IN IDAHO
Avista Utilities
2016 average number of customers/average revenue per kilowatt-hour
330,699 residential customers/$0.09605
41,785 commercial customers/$0.09613
1,342 industrial customers/$0.06085
Idaho Power Company
2016 average number of customers/average revenue per kilowatt-hour
440,362 residential customers/$0.1029
88,561 commercial customers/$0.0772
121 industrial customers/$0.0563
Rocky Mountain Power
2016 average number of customers/average revenue per kilowatt-hour
62,615 residential customers/$0.1064
9,339 commercial customers/$0.0910
628 industrial customers/$0.0658
Idaho Public Utilities Commission
Page 24
Settlement reached in Avista rate case
Avista’s electric rates increased by an average of 2.6 percent on Jan.
1, 2017 after the utility reached a settlement with Commission staff
and other parties.
The company had originally requested a 6.3-percent increase. The most significant adjustment to the
company’s proposal was to move $4.5 million in net expenses for the Palouse Wind project from base
rates to the annual Power Cost Adjustment process.
The move reduced the economic burden imposed on Idaho ratepayers by 10 percent. The settlement
also set the residential basic charge at $5.75 per month, down from $6.25 the company had request-
ed.
In June 2017, Avista asked for approval of a two-year plan calling for rate increases in 2018 and
2019.
The company said the request was driven by ongoing investments in its plants and technology in addi-
tion to increased costs of providing power to its customers.
A tentative settlement agreement was reached in late September. If approved by the Commission, the
settlement would increase electric rates by an average of 5.6 percent in 2018 and 2.3 percent in
2019, while increasing the basic monthly service charge by 25 cents, to $6. The company’s original pro-
posal called for an average increase of 7.9 percent in 2018 and 4.2 percent in 2019, along with the
25-cent increase to the service charge.
Commission deems prudent Avista’s energy efficiency expenses
In June, the Commission determined that nearly $10 million Avista spent on energy efficiency programs
in 2014 and 2015 was prudently incurred and therefore could be recovered through an energy effi-
ciency rider paid by the 125,000 northern Idahoans who receive electric service from Avista.
The programs, which include educational outreach and incentives for weatherization measures, saved
31,081 megawatt-hours (MWh) over the two-year period, just meeting the company’s goal of 30,996
MWh.
Commission approves changes to several surcharges
The Commission approved modifications to four annual billing mechanisms in September that affect cus-
tomers who receive electric service from Avista.
The changes took effect Oct. 1, and the overall impact to residential customers was a 2-percent in-
crease, or $1.73 on the monthly bill of the average residential customer using 910 kWh per month.
Here’s a look at those billing mechanisms:
Fixed Cost Adjustment
This mechanism is modified annually in order to allow a utility to recover any fixed costs that are lost
when energy sales decline. It is intended to remove a utility’s disincentive to promote energy efficiency
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and conservation by ensuring that the utility will recover its fixed costs even if energy sales decline. In
requesting Commission approval to increase the FCA by 3 percent, the maximum allowed, Avista said
revenue fell short of expenses by approximately $6.5 million in 2016 due to an abnormally warm win-
ter as well as savings from its energy efficiency programs.
As a result of the change, a residential customer using an average of 910 kWh in a month would see
an increase of $2.56 on the monthly bill.
Power Cost Adjustment
This mechanism allows Avista to modify its rates annually when its costs of generating and purchasing
electricity to serve is customers do not equal the revenue recovered through rates.
Since power supply costs were lower than expected in 2016, the PCA
approved in September is expected to refund customers approximate-
ly $7.3 million.
That equates to a decrease of $2.03 on the monthly bill of the aver-
age residential customer using 910 kilowatt-hours per month.
Residential and Small Farm Energy Credit
The result of an agreement between the utility and the Bonneville Power Administration, this credit
passed through to customers the benefits of the federal Columbia River hydropower system.
The change approved in September lowered the bill of the average residential and small farm custom-
er by 0.2 percent. That equates to a savings of 16 cents on the monthly bill of the average residential
customer using 910 kWh.
Energy efficiency rider
In September 2017, the Commission approved an increase to the Energy Efficiency Rider for Avista’s
electric customers.
The change took effect Oct .1, leading to an increase of $1.37 on the monthly bill for a residential cus-
tomer using 910 kWh.
Adjusted with Commission approval, this surcharge allows a utility to recover the costs incurred provid-
ing energy efficiency services to its customers, and to match future revenue with expenses budgeted for
energy efficiency programs.
In 2016, Avista’s energy efficiency programs were underfunded by nearly $10 million. The primary
reason for the deficit was a non-residential lighting program that exceeded its budget by $9 million.
The increase approved by the Commission is expected to boost revenue by approximately $3.9 million
annually.
The surcharge is now assessed at 0.395 cents per kilowatt-hour used for residential service, up from
0.245 cents per kWh, while the surcharge will increase to 0.427 cents per kWh for general service cus-
tomers, up from 0.271 cents per kWh.
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Programs funded by the rider will be scrutinized for prudency in a future proceeding. Expenses in-
curred through the programs must be cost-effective in order for the costs to be recovered through cus-
tomer funds. Expenses not found to be prudent must be paid by shareholders rather than customers.
Avista files long-range planning document with IPUC
Avista expects conservation measures to offset more than half of its expected load growth over the
next 20 years, according to a planning document filed with the Commission in August.
Though the need for new generation is expected, Avista’s Integrated Resource Plan (IRP) also indicates
its current generation resources will remain cost effective and reliable through 2036.
Regulated utilities are required to file an updated IRP with the Idaho Public Utilities Commission every
other year. The IRP serves as a status report on a utility’s ongoing plans to serve customers at the low-
est cost and least risk over the next two decades.
Avista’s 2017 IRP differs from its 2015 plan in several ways, including the anticipation of a slowdown
in the annual growth rate, from 0.6 percent projected in the 2015 IRP to 0.47 percent; less reliance on
natural gas-fired peaker plants; and a delay in the need for additional generation from 2020 until
2026.
The delay is due not only to lower than expected load growth but
also recently signed contracts for hydropower, energy efficiency
measures and the introduction of demand response programs that
temporarily reduce the demand for energy.
While the preferred strategy outlined in Avista’s 2015 IRP called
for 557 megawatts (MW) of new natural gas generation, with the
first facility projected to be in service by the end of 2020, the
2017 IRP calls for three new natural gas-fired plants with a com-
bined capacity of 353 MW.
Those consist of a 204 MW natural gas-fired peaker plant to begin operation in 2026, a 102 MW
peaker plant by the end of 2030 and a 47 MW peaker plant in 2034.
Peaker plants derive their name from the fact that they are utilized only during periods of peak de-
mand for energy among customers. According to Avista, these peaker plants are more cost-effective
because they provide a low-cost, flexible source for generation that allows the utility to efficiently in-
corporate intermittent power generation, such as wind and solar.
The company also plans to construct a 15 MW solar facility for its commercial and industrial customers,
and is building two energy storage facilities that would provide a total of 2.5 MWh of storage.
Most of Avista’s generation is through hydropower. The company owns and operates eight hydropower
plants capable of generating 1,080 MW. The IRP calls for improvements to those plants that would
boost capacity throughout the planning period.
Avista also recently signed long-term contracts with public utility districts to purchase hydropower gen-
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erated on the Columbia River. These contracts are capable of adding 165.3 MW to Avista’s system.
The company’s thermal generation consists of five natural gas plants, a biomass facility and a 222-MW
share of the output at the Colstrip coal plant. The Colstrip plant consists of four units located east of
Billings, Montana.
Avista owns 15 percent of Units 3 and 4, which began operating in 1984 and 1986, respectively. Units
1 and 2 went into operation in the mid-1970s and are set for retirement by 2022. Avista said it ana-
lyzed a number of scenarios for Colstrip Units 3 and 4, including early retirement and significant reduc-
tions in generation.
But its preferred strategy calls for the two units to remain in service through the end of the planning pe-
riod, as it remains a cost-effective and reliable source of power.
Avista’s conservation efforts are expected to help meet 53.3 percent of the growth in load over the
next 20 years. Current conservation efforts reduce retail loads by more than 12 percent. The IRP evalu-
ated more than 8,700 options to reduce energy use.
These conservation and efficiency programs outlined in the IRP target not only customer consumption but
also Avista operations. Plans call for upgrades to distribution equipment throughout its service area, as
well as upgrades to boost efficiencies at Avista facilities. Overall, the company said it has identified
15,370 MWh of “achievable potential conservation” in Idaho.
Commission grants CPCN for transmission line in Wood River Valley
In September the Commission approved Idaho Power’s application for a Certificate of Public Conven-
ience and Necessity (CPCN) to build a new transmission line to serve the Wood River Valley.
In granting the request, the Idaho Public Utilities Commission said Idaho Power demonstrated that a re-
dundant line is necessary to mitigate the risk to public health and safety of the valley’s 9,000 residents.
The Wood River Valley is currently served by two substations fed by a
single transmission line that links substations near Hailey and Ketchum.
The need for a redundant transmission line in the valley was identified
in the mid-1970s, and a previous CPCN was canceled in 1995 at the
company’s request.
The existing line was built in 1962 on wooden poles in mountainous terrain that can be difficult to ac-
cess. It needs to be rebuilt, Idaho Power said, and a redundant line would also allow the line to be re-
built without planned power outages.
In its CPCN application, Idaho Power said structure failure along the line could lead to an extended
power outage. A redundant line would eliminate that risk, the company said.
In weighing the evidence, the Commission was persuaded that a major outage could last days or weeks
due to access limitations along the current line that would hamper repair efforts.
Granting the CPCN is not a mandate to build the new line. In fact, the Commission’s 18-page order
notes that while Idaho Code requires a public utility to obtain a CPCN before constructing certain facili-
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ties or infrastructure, a CPCN is not required to extend lines, plant or system in an area already served
by a utility.
The order also does not constitute approval of the cost of the project for ratemaking purposes.
Idaho Power is required to apply to the Commission in order to recover expenses associated with the
project from its customers.
The project is expected to cost $30 million, with the company’s proposed route calling for a transition
from overhead lines to underground lines for a portion of the route leading into Ketchum.
IPUC approves Idaho Power proposal to lower efficiency surcharge
In April, the Commission approved an Idaho Power request to lower the energy efficiency rider paid
by customers to fund conservation and efficiency programs. The move to lower the rider from 4 per-
cent of monthly billed amounts to 3.75 percent led to a 22-cent decrease on the monthly bill of the av-
erage residential customer who uses 1,000 kWh per month.
The Commission also approved the company’s request to refund customers $13 million in rider funds on
June 1, reducing the impact of an increase to the Purchased Cost Adjustment billing mechanism.
Battery storage facilities eligible for contracts with Idaho Power
In July, the Commission determined that five proposed battery storage facilities were eligible for two-
year, negotiated contracts with Idaho Power.
Plans call for the batteries to be charged with energy from nearby solar projects capable of generat-
ing 2.5 average megawatts, with the electricity dispatched to Idaho Power under the provisions of the
Public Utility Regulatory Policies Act (PURPA).
PURPA requires electric utilities to purchase energy from qualifying in-
dependent power producers but gives state regulators authority to de-
termine the contract terms for PURPA-eligible facilities.
In Idaho, PURPA projects larger than 100 kilowatts and powered by intermittent sources such as solar
and wind are eligible for two-year contracts at a rate negotiated between the utility and the develop-
er (IRP methodology).
The developer, Franklin Energy, contended that its storage projects should qualify for 20-year con-
tracts at the more favorable published rate set by the Commission.
Franklin petitioned the Commission to reconsider its decision. In denying the request to reverse its deci-
sion, the Commission said Franklin failed to show that the final order was “unreasonable, unlawful, er-
roneous or not in conformity with the law.”
Commission approves modifications to billing mechanisms
In May, the Commission approved several cost adjustments for Idaho Power Company, leading to a
rate increase of almost $2 on monthly bills of a typical residential customer as of June 1.
The Power Cost Adjustment increased by an average of 0.93 percent, leading to a 59-cent increase
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on the monthly bill for Idaho Power’s typical residential customer using 1,000 kilowatt-hours., while a
1.29-percent increase to the Fixed Cost Adjustment led to an average monthly increase of $1.31.
The FCA is adjusted annually based on changes in energy use during the previous year by customers in
two classes, Residential and Small General Service.
The mechanism separates revenues and energy sales, enabling the company to recover fixed costs in-
curred delivering energy to its Idaho customers even if energy sales decrease.
Without the FCA, the company would have a disincentive to help customers use less energy, or use it
more efficiently, since there would be a loss of revenue as energy use declined.
In 2016, the company’s residential energy sales decreased by
245,027 megawatt-hours (MWh) from 2015 levels, due in part
to the growth of its energy efficiency programs.
That decrease in energy sales, combined with an increase in the
number of customers in the Residential and Small General Service
customer classes, left the company unable to recover its fixed
costs for the year.
The FCA is now assessed at .6728 cents per kilowatt-hour (kWh) for Residential customers and .8576
cents per kWh for customers in the Small General Service class. The increase is projected to boost reve-
nue by approximately $6.96 million, matching the amount under-collected in 2016.
The PCA allows Idaho Power to modify its rates each year to contend with fluctuations in the cost of
serving customers due to factors beyond its control. Those factors include market prices for power,
power transmission costs, revenue earned from selling surplus power and stream flows that diminish the
hydropower generation on which the company relies.
The PCA is examined annually and adjusted up or down to either pay down already-incurred expens-
es if power costs exceed forecasts, or credit customers when expenses fall short.
The company said last year’s power costs exceeded forecasts due in part to worse-than-expected wa-
ter conditions. While stream flows have improved for 2017, the company expects to incur greater costs
associated with solar and wind generation, and the unexpected collapse and abandonment of the Joy
Longwall by the Bridger Coal Company.
As a result, the Commission approved raising the surcharge to .7361 cents per kWh, from .6187 cents.
Idaho Power seeks prudency determination for relicensing effort
In late 2016, Idaho Power asked the Commission to find that it had prudently incurred approximately
$221 million in expenses related to a years-long effort to relicense the Hells Canyon Complex, the util-
ity’s largest hydropower facility. The company’s application asks the Commission to deem those ex-
penses prudently incurred and eligible for inclusion in customer rates in the future.
The Hells Canyon Complex provides more than one-third of the company’s total generating capacity.
Its license with the Federal Energy Regulatory Commission expired in 2005 and the company has been
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operating under an annual license issued by FERC since then. The relicensing effort began in 1991, ac-
cording to the company, which led to filing for a new license in 2003. It estimates a new 40- or 50-
year license will be issued after 2021.
Idaho Power proposal would reclassify net metering customers
In July, Idaho Power asked the Commission to approve its plan to overhaul its treatment of customers
with on-site generation systems such as rooftop solar.
Idaho Power customers who generate their own electricity are currently included in the same rate class
as traditional electric customers.
Since net metering customers can offset their energy consumption via
their on-site generation resources, Idaho Power contends they do not
pay their fair share for the operation and maintenance of the compa-
ny’s electric distribution system.
This shifts the financial burden of maintaining and running that system onto Idaho Power’s traditional
customers, creating a “wealth transfer from lower-income customers to higher-income customers,” the
company’s filing states.
The company’s proposed solution is to separate net metering customers into two distinct customer clas-
ses, Residential and Small General Service. The company said this would allow it to better understand
those customers’ impact on the distribution system.
The proposal applies to customers with on-site generation who sign up for new service on or after Jan.
1, 2018, existing net metering customers would “transition over some period of years” to one of the
proposed new customer classes.
Idaho Power’s proposal does not call for any changes to rates. Any such changes would be addressed
in a future rate case.
Rocky Mountain Power submits plan for Commission acceptance
Rocky Mountain Power expects to transition away from coal over the next 20 years, according to the
utility’s Integrated Resource Plan (IRP).
The IRP outlines the utility’s strategy for meeting customer demand for electricity through 2036.
It calls for the retirement of more than 3,500 megawatts of coal-fired generation, and for that genera-
tion to be replaced primarily with renewables such as wind and solar.
Efficiency measures, wholesale power purchases and two new natural gas facilities are also expected
to help meet the demand for energy through 2036.
The Commission’s acknowledgement of the IRP does not necessarily mean the projects highlighted will
be completed, but rather that the utility has met its long-range planning requirements.
The first new natural gas-fired resource is expected to be added in 2029, a year later than anticipat-
ed in the utility’s previous IRP, filed in 2015.
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The utility expects incremental energy-efficiency resources to provide a 2,077 MW reduction - enough
to meet 88 percent of the forecasted load growth through 2026. The 2017 plan does not call for up-
grades to coal plants in order to meet environmental regulations, a decision that will “save customers
hundreds of millions of dollars,” according to the company.
Instead, the IRP calls for 3,650 MW of existing coal capacity to be retired by the end of 2037.
The company expects to offset a portion of that lost generation with
market purchases, although Rocky Mountain intends to construct two
new natural gas facilities – a 200-MW frame simple cycle combus-
tion turbine in 2029, and a 436-MW combined combustion turbine in
2030.
Over the life of the IRP, the preferred portfolio includes 1,313 MW of new natural-gas capacity. That
is a reduction of 1,540 MW relative to the 2015 IRP.
Rocky Mountain seeks approval for wind and transmission projects
In July, Rocky Mountain Power asked the Commission to approve its plans to build or acquire four wind
farms in Wyoming, upgrade or “repower” 13 existing wind facilities and improve its transmission sys-
tem.
The projects are expected to cost $3.13 billion and would significantly boost the utility’s capacity to
generate wind energy.
Rocky Mountain Power asserted that the transmission projects are necessary in order to relieve conges-
tion on the transmission system and improve the utility’s ability to manage the intermittent load pro-
duced by wind.
Rocky Mountain requested that the Commission allow the projects’ capital costs to be incorporated into
customer rates, and for approval of Certificates of Public Convenience and Necessity (CPCN) for the
new wind facilities and transmission improvements.
Rocky Mountain Power also asked the Commission to expedite the approval process to ensure that the
projects meet deadlines for federal renewable electricity production tax credits. The wind projects must
be in operation by the end of 2020 in order to achieve the full benefit of the production tax credits.
The projects are pending before the Commission in two cases.
One is the $1.13 billion wind repowering project and the other is the $2 billion project that calls for
construction of the four wind facilities and the construction of or improvements to several transmission
facilities in eastern Wyoming.
A tentative settlement agreement has been reached in the wind repowering case. The company’s pro-
posal calls for repowering, or upgrading, eight wind projects in Wyoming, four in Washington state
and one in Oregon.
The facilities now represent 999.1 megawatts (MW) of installed capacity, and the project is expected
to increase generation between 11 and 35 percent. Upgrades would include installation of higher-
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capacity generators and rotors with longer blades, which produce more energy at lower wind
speeds.
In addition to increased energy output, the project’s benefits would include greater control of power
quality and voltage, which would allow the utility to more efficiently integrate wind energy into its
transmission system and enhance the reliability of the electric grid, Rocky Mountain Power said.
The company also noted that the project’s benefits can be achieved without the costs and complexity
of permitting and constructing new facilities, while extending the facilities’ useful life and cutting oper-
ating costs.
Rocky Mountain Power asked the Commission to issue its decision on the proposal by Dec. 29 in order
to receive the full benefit of the production tax credits.
The current tax credit is $24 per megawatt-hour. That amount is adjusted annually but expires 10
years after a facility goes into service.
The tax credits for most of the facilities proposed for repowering
are set to expire in 2018 and 2019. Overall, the company said,
the repowering projects would lead to customer savings of between
$41 million to $589 million, with natural gas prices and federal
regulations representing the biggest variables.
The economic benefits are derived by a number of factors, includ-
ing increased energy output, reduced operating costs, extended
operational life, requalification for the production tax credits and
the sale of renewable-energy credits.
Capital expenses related to the project would be assessed on customer rates through the Energy Cost
Adjustment Mechanism, which can be adjusted up or down annually depending on costs incurred, and
benefits reaped, by the company.
Rocky Mountain’s $2 billion proposal requests Commission approval for CPCNs for four Wyoming
wind projects with a combined capacity of 860 MW. Three have a capacity of 250 MW and one is
capable of generating 110 MW.
The proposal also includes the construction of or improvements to several transmission facilities in east-
ern Wyoming. Most of the improvements are associated with the company’s Energy Gateway West
transmission project, which calls for the addition of approximately 2,000 miles of transmission lines in
order to alleviate congestion on the transmission system, address growth and incorporate new gener-
ation sources such as wind.
The projects are mutually dependent, according to the company: The wind projects are not economic
without the transmission projects, and the transmission projects are not economic without the wind re-
sources.
The $2 billion cost estimate would lead to a rate increase of less than 1.9 percent in 2021, which is
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expected to be the first full year of operation of the new facilities, according to the company.
However, Rocky Mountain Power said the work is expected to save $137 million in avoided costs
through 2050, when the wind projects are fully depreciated.
RMP proposal would lower wind integration rate, set solar rate
In August, Rocky Mountain Power requested approval to significantly lower the rate it charges to inte-
grate wind energy into its system.
The company’s proposal calls for lowering the integration rate from $3.06 per megawatt-hour (MWh)
to 57 cents per MWh, and setting the rate for the purchase of solar
energy at 60 cents per MWh.
The rates would apply to facilities that qualify for 20-year contracts
under the Public Utility Regulatory Policies Act (PURPA). The law re-
quires regulated utilities to purchase energy from qualifying inde-
pendent power producers at rates established by state commissions.
In Idaho, facilities smaller than 100 kilowatts that are powered by
intermittent sources such as wind and solar are eligible for 20-year
contracts at the published rate set by the Idaho Public Utilities Com-
mission.
The rate is referred to as the avoided-cost rate because it is intended that it not be higher than the
rate at which the utility could generate the power on its own, or the rate at which the utility could pur-
chase the energy elsewhere.
The integration rate for solar and wind facilities that qualify for power purchase agreements under
PURPA is deducted from the avoided-cost rate paid by the utility.
In its proposal, Rocky Mountain said its analysis had found that the costs of wind energy and its inte-
gration had fallen significantly since the current integration rate was set in 2008.
Commission approves decrease to surcharge to reflect lower costs
In May the Commission approved a decrease to the Energy Cost Adjustment Mechanism to reflect a
drop in power supply costs.
The ECAM allows the utility to adjust its rates each spring to account for expenses tied to the previous
year’s power purchases and sales. It appears on customer bills as a separate line item that increases if
those costs are higher than the revenue generated through base rates. The ECAM surcharge decreases
if the power supply costs are lower than the revenue generated through base rates.
Rocky Mountain said its power supply costs in 2016 were approximately $7.53 million lower than pro-
jected, primarily due to a decline in natural gas prices.
The change to the ECAM took effect June 1 and led to a decrease of 0.8 percent for residential cus-
tomers, or about 73 cents per month for a typical residential customer who uses 800 kilowatt-hours of
electricity. It is now assessed at .4958 cents for each kilowatt-hour used.
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Commission approves change to federal rate credit
In the fall the Commission approved a change to a federal rate credit that led to a slight decrease in
the power bills of Rocky Mountain customers.
The change to the Residential and Small Farm Energy Credit took effect Oct. 1 and lowered the bill of
the average residential customer by $6.60 – or 51 cents more
than the current credit, which expired Sept. 30.
The credit is the result of an agreement between the company
and the Bonneville Power Administration (BPA) that passes through
to customers the benefits of the federal Columbia River hydro-
power system.
BPA markets and distributes the wholesale power generated
through the system, which consists of 31 federal hydroelectric pro-
jects on the Columbia and Snake rivers.
While customers of publicly owned utilities (rural co-ops, for example) have preferential access to BPA
power, the Northwest Power Act of 1980 requires that customers of private, investor-owned utilities al-
so share in the benefits of the federal hydro projects through a rate credit as part of BPA’s Residential
Exchange Program.
ELECTRIC CASES
Idaho Public Utilities Commission
Page 35
Consumption increased and prices declined in FY2017
In Idaho, natural gas is supplied to customers by Avista Utilities, Dominion Questar Gas and Intermoun-
tain Gas Company.

Idaho is fortunate to be located between two large natural gas storage basins: The Rocky Mountain
Basin (Rockies) and the Western Canadian Sedimentary Basin (WCSB).

These basins are connected through the Williams Northwest Pipeline and the TransCanada Gas Trans-
mission Northwest pipelines allowing the utility companies serving Idaho to take advantage of capacity
and of pricing at both basins.

NATURAL GAS
Transportation is nonutility owned gas transported for another party under contractual agreement.
FY 2017 Statistics Total Residential Commercial Industrial Transportation

Intermountain Gas

Customers 346,894 314,444 32,330 19 101
% of Total 100% 90.65% 9.32% 0.01% 0.03%
Therms (millions) 783 247 129 8 399
% of Total 100% 31.53% 16.48% 1.03% 50.96%
Revenue (millions) $277.60 $178.97 $83.58 $3.43 $11.57
% of Total 100% 64.48% 30.11% 1.24% 4.17%

Avista Utilities

Customers 80,915 72,000 8,812 95 8
% of Total 100% 88.98% 10.89% 0.12% 0.01%
Therms (millions) 145.60 52.54 30.79 2.49 59.78
% of Total 100% 36.09% 21.15% 1.71% 41.06%
Revenue (millions) $67.6 $45.25 $20.43 $1.35 $0.54
% of Total 100% 66.97% 30.24% 2.00% 0.80%

Dominion Questar Gas

Customers 2,160 1,910 250 0 0
% of Total 100% 88.43% 11.57% N/A N/A
Therms (millions) 2.41 1.36 1.05 N/A N/A
% of Total 100% 56.50% 43.50% N/A N/A
Revenue (millions) $1.91 $1.17 $0.74 N/A N/A
% of Total 100% 61.34% 38.66% N/A N/A
Idaho Public Utilities Commission
Page 36
Individual Idaho Gas Utility Profiles

Consumption
Overall consumption of natural gas in Idaho increased 2.1 percent during the fiscal year. All segments
consumed more natural gas than the previous year with the exception of gas for electric generation,
which declined approximately 13.5 percent.

0
20000
40000
60000
80000
100000
120000
2010 2011 2012 2013 2014 2015 2016
Idaho Natural Gas Consumption 7 Year View Source EIA October 19, 2017
Pipeline and Distribution Residential Commercial Industrial Vehicle Fuel Electric Power
Million Cubic Feet
Pipeline and
Distribution, 5.19%
Residential, 23.28%
Commercial, 16.46%
Industrial, 32.51%
Vehicle Fuel, 0.14%
Electric Power,
22.42%
FY 2017 Idaho Natural Gas Consumption by End Use
Source: EIA, Oct. 19, 2017
NATURAL GAS
Idaho Public Utilities Commission
Page 37
Demand
The Northwest Gas Association (NWGA) forecasts demand for natural gas in the Northwest to grow at
a Compound Annual Growth Rate (CAGR) of approximately 0.8% per year over the next 10 years.
A number of factors could impact demand for natural gas:
 Pricing
 Natural gas used for generating electricity
 Significant incremental industrial loads
 The potential for natural gas as a transportation fuel
 LNG and petrochemical production and exports
 Energy policies, regulations and legislation

Prices
Recently, prices at the Henry Hub have been hovering near $3.00/MMBtu and are anticipated to re-
main close to this level in 2017. Prices in 2018 are expected to increase slightly over 2017.

Natural gas spot prices are projected to increase in 2018 to an average of $3.19/Dth (dekatherm*),
at the Henry Hub.

*Dekatherm = 10 therms or 1,000,000 British thermal units (MMBtu)
0
1
2
3
4
5
6
7
8
9
10
2010 2011 2012 2013 2014 2015 2016
Idaho Residential Natural Gas Price Source EIA, October 19, 2017
City Gate Price Residential Price
Year
$/1000 cubic feet
NATURAL GAS
Page 38

A number of market dynamics could influence future natural gas prices:
 North American economic growth
 Regulatory costs that add to the cost of accessing, producing or transporting natural gas
 Advances in exploration and production tools and technologies

Production
In 2016, Idaho completed its first full year of natural gas production for commercial use. Alta Mesa
Holdings LP is currently the only natural gas producer in Idaho.
Alta Mesa operations overview:
 17 wells located in the Payette, Idaho basin.
 8 wells are producing natural gas, condensate, oil, and other liquids.
The Company’s processing facility is located at Willow Creek near Payette.
End Uses:
 Oil and condensate are collected at the Willow Creek facility and transported by truck to the On-
tario Oregon railyard and shipped to Salt Lake City and other destinations for processing.
 Intermountain Gas Company is connected to one of Alta Mesa’s wells and purchases natural gas to
serve the Payette Idaho area.
 Williams Northwest Pipeline Company is connected to Alta Mesa and purchases natural gas for its
interstate pipeline business.

Summary
Idaho residential, commercial and industrial users of natural gas continue to benefit from low natural
gas prices and plentiful supply. Advancements in exploration, extraction, and production techniques
continue to transform the industry.
Idaho Public Utilities Commission
NATURAL GAS
Page 39
Idaho Public Utilities Commission
NATURAL GAS
NOTABLE LEGISLATIVE DEVELOPMENTS
Law establishes Oil and Gas Conservation Commission
In the 2017 Legislative session, Idaho lawmakers unanimously passed House Bill 301 to regulate the
exploration, drilling and production of oil and gas resources on private, state and federal land
throughout the state.
The law called for the creation of the Idaho Oil and Gas Conservation Commission consisting of three
technical experts, the state Department of Lands director and a county commissioner from a county in
which oil and gas production is underway.
The law clarifies definitions and reporting requirements for the production and sale of oil and gas in
Idaho, while providing protection for landowners, penalties for noncompliance and public access to in-
formation related to the production of oil and gas. The information is hosted on a new website,
https://ogcc.idaho.gov.
Law establishes requirements for oil and gas producers
Senate Bill 1098 requires oil and gas producers to file monthly statements with the Idaho Tax Commis-
sion documenting the name, description and location of every well or oil and gas field that contains
wells. The law, which took effect July 1, authorizes the state Tax Commission to conduct audits of oil and
gas producers every three years.
The intent of the new law was to clarify the reporting requirements of oil and gas producers.
Page 40
Tentative settlement reached in Avista rate case
In June, Avista asked for approval of a two-year plan calling for rate increases in 2018 and 2019. The
company said the request was driven by the need to replace or upgrade its aging infrastructure.
A tentative settlement agreement was reached in late September. If approved by the Commission, the
settlement would lead to an average rate increase for natural gas service of 1.9 percent in 2018 and
1.8 percent in 2019.
The company’s original proposal called for increases of 5.7 percent in 2018 and 3.3 percent in 2019.
The proposed settlement also calls for an increase of 75 cents to
the basic charge, raising it to $6 per month.
Among the planned capital investments necessitating the need to
increase revenue are an ongoing project to replace portions of
a natural gas distribution line, upgrades to the company’s trans-
mission and distribution system and technological improvements.
The proposed settlement calls for reductions or delays in a num-
ber of projects included in the company’s original proposal, in-
cluding a delay in a new meter data management system that
decreases the revenue requirement by $415,000, and
$300,000 in reductions tied to miscellaneous expenses.
The proposed settlement agreement was reached between several parties to the case after a settle-
ment conference in late September. Those parties include Clearwater Paper, Idaho Forest Group and
the Community Action Partnership Association of Idaho. Sierra Club and the Idaho Conservation League
opposed the settlement agreement.
For natural gas service, the settlement terms are designed to increase annual billed revenue by $1.2
million in 2018 and $1.1 million in 2019. The original proposal would have increased annual billed
revenue by $3.5 million in 2018 and $2.1 million in 2019.
The revenue increases are based on a 9.5-percent return on equity, down from a 9.9-percent return on
equity in Avista’s original proposal.
It the settlement is approved, a residential natural gas customer using an average of 63 therms per
month would see an increase of $1.13 per month, for a monthly bill of $53.74. In 2019, that customer
would see an increase of $1.09 per month for a monthly bill of $54.83.
Commission accepts Avista long-range planning document
In February, the Commission accepted Avista’s Natural Gas Integrated Resource Plan (IRP). The utility is
required to file an updated IRP with state regulators every two years. The plan outlines the ways in
which Avista expects to meet the demand for natural gas among its customers.
The IRP anticipated annual growth of about one-half percent over the next decade, with about a 0.8
percent increase in peak-day use. The IRP said the utility was well-positioned to meet the increased de-
Idaho Public Utilities Commission
NATURAL GAS CASES
Page 41
mand through a diversified portfolio of natural gas supply resources, including storage, firm capacity
rights on six pipelines and contracts to purchase natural gas from several supply basins.
Among the projects highlighted in the plan were an $8 million Coeur d’Alene High Pressure Reinforce-
ment project to address low-pressure conditions in the Hayden Lake system that generally occur when
demand is high during winter conditions, the Schweitzer Mountain Road High Pressure Reinforcement
($1.5 million) and 2019 gate station improvements at Athol, Bonners Ferry and Genesee.
Commission approves Intermountain Gas efficiency program
The Idaho Public Utilities Commission in September approved an Intermountain Gas proposal to create
and fund a new efficiency program for residential customers.
Intermountain’s Demand Side Management (DSM) Program is funded through an efficiency rider or sur-
charge of 0.367 cents per therm – that is 22 cents per month for the average customer using 61 therms
per month.
Intermountain’s DSM program is expected to cost $770,000 in its first
year, with $600,000 earmarked for rebates to customers who enact
efficiency measures on new or existing homes.
In order for the program to be funded by the efficiency rider, the
Commission requires that a utility demonstrate that costs related to the programs over the previous 12
months were prudently incurred.
If the costs are found to be unreasonable, or to exceed the benefit to customers, they are borne by
shareholders rather than customers.
Several tests are used to determine prudency, or whether the benefits outweigh the costs.
In a successful DSM program, all customers benefit because the change in energy use helps the utility
avoid or defer building costly new generation resources or avoid the need to procure additional re-
sources at an additional cost.
Commission approves decrease to surcharge
In September, the Commission approved an Intermountain Gas proposal to decrease a recovery mech-
anism known as the annual Purchased Gas Cost Adjustment (PGA).
The change lowered the monthly bill for the average residential customer by $3.32. Commercial cus-
tomers saw an average decrease of $16.42 per month, while two customer classes – large volume and
transportation – saw a slight rate increase.
The PGA is adjusted each fall with Commission approval, to reflect changes in expenses related to the
natural gas purchased from suppliers as well as changes in transportation, storage and other variable
costs.
In addition to changing the PGA to reflect the cost of providing natural gas to Intermountain’s custom-
ers, the company requested Commission approval to recover $699,114 in expenses incurred for audit-
Idaho Public Utilities Commission
NATURAL GAS CASES
Page 42
ing and consultation from third parties during its recently resolved general rate case.
The Commission approved the recovery via the PGA of $378,614 over five years, or $75,723 per
year. It did not disallow the recovery of the balance of the expenses but said the prudency of the re-
maining $319,963 had not been determined.
Those expenses will be considered during the company’s next general rate case.
Idaho Public Utilities Commission
NATURAL GAS CASES
Page 43
Idaho Public Utilities Commission
WATER
Company Customers Nearest city/town
CDS Stoneridge Utilities, LLC 358 Blanchard
Diamond Bar Estates Water Company 46 Rathdrum
Eagle Water Company, Inc. 3,546 Eagle
Falls Water Company, Inc. 4,500 Ammon
Grouse Point Water 24 Kuna
Happy Valley Water System 27 Athol
Island Park Water Company 362 Island Park
Kootenai Heights Water System, Inc. 11 Kootenai
Mayfield Springs Water Company 76 Kuna
Morning View Water Company, Inc. 108 Rigby
Picabo Livestock Company 28 Picabo
Ponderosa Terrace Estates Water System, Inc. 22 Sandpoint
Resort Water Company 422 Sandpoint
Rickel Water Company 38 Coeur D'Alene
Rocky Mountain Utility Company, Inc. 101 Rigby
Schweitzer Basin Water LLC 439 Sandpoint
Spirit Lake East Water Company 301 Coeur D'Alene
Suez Water Idaho Inc. 88,400 Boise
Sunbeam Water Company 22 American Falls
Teton Water and Sewer Company, LLC 285 Driggs
Troy Hoffman Water Corporation 147 Coeur D'Alene
Regulated water companies
Page 44
Grouse Point Water receives approval to raise rates and charges
In September, the Commission approved increases to rates and charges for customers of Grouse Point
Water Company near Kuna.
The changes included an increase to the monthly customer charge, from $22 to $86, and to charges
based on the amount of water used.
The changes took effect Oct. 15 and call for usage charges based on an inclining block rate structure
that assesses a higher rate when usage exceeds certain amounts.
Grouse Point customers who use up to 8,000 gallons in a month are now charged $2.50 per 1,000 gal-
lons used. The rate increases to $3.75 per 1,000 gallons for monthly usage between 8,001 and
20,000 gallons. It climbs to $5 per 1,000 gallons for monthly usage exceeding 20,000 gallons.
Under the previous rate structure, customers paid 50 cents per 1,000 gallons used when monthly con-
sumption exceeded 8,000 gallons. There were no usage charges for customers who consume less than
8,000 gallons per month.
Grouse Point Water provides service to 24 customers.
In requesting Commission approval to raise rates, the company said revenue had fallen short of opera-
tional expenses every year since 2003, when its previous rates were set. Without a rate increase, the
company said, it would be unable to continue operations.
Grouse Point had proposed raising the monthly customer charge to $113.86 and implementing con-
sumptive charges with two tiers separated at 8,000 gallons - $1.83 per 1,000 gallons for those who
use less than 8,000 gallons in a month, and $5 per 1,000 gallons for usage in excess of 8,000 gallons.
In its proposal, the company said revenue between 2012 and 2015 covered approximately 40 percent
of its expenses for basic operations and maintenance, creating a deficit in excess of $10,000. In addi-
tion, the company contended its rates did not reflect $127,441 in capital improvements made in 2009
and 2013. Those improvements included installation of a new well, two pumps and associated equip-
ment needed to comply with federal drinking water standards involving uranium that were established
in 2004.
Commission approves Falls Water request to build new well
In September, the Commission approved a request from Falls Water Company to construct a new well
in order to resolve problems with water pressure in its service territory.
The project is estimated to cost $647,215 and calls for construction of a well, well house, pumping
equipment and controls.
The decision does not immediately impact rates; however, the Commission’s order allows project ex-
penses to be considered in Falls Water’s next rate case. Company estimates indicate the project could
lead to a rate increase of between 3.4- and 4.4 percent, but all expenses related to the project will be
reviewed for accuracy and reasonableness before they are included in future rates.
Idaho Public Utilities Commission
WATER CASES
Page 45
Idaho Public Utilities Commission
WATER CASES
Falls Water serves approximately 4,700 customers in Bonneville County, east of Idaho Falls.
Officials with the Idaho Department of Environmental Quality notified the company in July 2016 that it
had failed to comply with water pressure requirements of the Idaho Rules for Public Drinking Water
Systems.
DEQ officials suggested that corrective action could include water-use restrictions or an increase in sys-
tem capacity through additional sources, storage or pumping.
When the potential solutions were deemed inadequate or cost prohibitive, Falls Water sought to add
capacity through the construction of a new well.
The Commission found that the company’s proposal “appears to be the most cost-effective means of
providing adequate service to its customers.”
Morning View Water receives approval to raise rates and charges
In late 2016, the Commission approved a rate increase for customers of Morning View Water Compa-
ny in Rigby.
The change raised the monthly minimum charge from $32.62 to $50 for quarter-acre lots, and intro-
duced volumetric charges based on the amount of water used each month.
These consumption-based charges are now split into two tiers. For a customer with a quarter-acre lot,
the first tier is 15 cents per 1,000 gallons used per month, up to 10,000 gallons. Usage beyond that
amount is assessed at 48 cents per 1,000 gallons used per month.
The changes were expected to increase the company’s annual revenue by $93,727, or nearly $8,000
less than the revenue generated under Morning View’s proposal, which did not call for volumetric
charges.
In its application to the Commission, the company said its first rate increase since 2007 was needed in
order to meet expenses related to the installation of a third well, along with upgrades to two existing
wells.
Morning View provides water service to approximately 100 customers in and around Rigby in eastern
Idaho.
The Commission received a number of comments from customers opposed to the company’s request.
Page 46
Idaho Public Utilities Commission
TELECOMMUNICATIONS
Albion Telephone Corp. Albion
Cambridge Telephone Co. Cambridge
CenturyLink* Boise
CenturyTel of Idaho, Inc.* Salt Lake City, UT
CenturyTel of the Gem State* Salt Lake City, UT
Citizens Telecommunications Company of Idaho* Beaverton, OR
Columbine, dba Silver Star Communications Freedom, WY
Frontier Communications Northwest, Inc.* Beaverton, OR
Direct Communications Rockland, Inc. Rockland
Inland Telephone Co. Roslyn, WA
Fremont Telecom, Inc. Missoula, MT
Midvale Telephone Company Midvale
Oregon-Idaho Utilities, Inc. Nampa
Pine Telephone System, Inc. Halfway, OR
Potlach Telephone Company Kendrick
Rural Telephone Company Glenns Ferry
Regulated telecommunications companies
* These companies are no longer rate regulated; however, they are still regulated for customer service.
ITSAP surcharge suspended for 2017 budget year
In May, the Commission suspended a surcharge assessed on all telephone lines. The surcharge had been
1 cents per month per line, with the revenue earmarked for the Idaho Telecommunications Service Assis-
tance Program, which provides qualified low-income landline and cell phone users with a discount of
$2.50 per month.
While the number of telephone lines supporting the fund decreased in 2016, the number of recipients
of the subsidy declined more sharply. That prompted the Commission to suspend the charge for the
2017 budget year.
The surcharge has declined significantly in the last two dec-
ades, from 13 cents per month in 1998, to 7 cents in 2013,
and 3 cents in 2014.
In addition to ITSAP, a federal program, Lifeline, provides
$9.25 per month to help qualifying low-income citizens ac-
cess phone and broadband service.
A number of factors played into the Commission’s decision to
suspend the surcharge, including:
 The number of ITSAP recipients dropped 42 percent from 2015 to 2016, and more than 85 percent
since 2011 (from 25,310 to 3,880).
 The number of “land lines” declined 17 percent, to an average of 363,888 per month, from 2015
to 2016, and the number of wireless lines dropped 2 percent, to 1,384,720.
 The gross surcharge revenue for 2016 was reported at $235,421, of which 18 percent was as-
sessed on wireline services and 82 percent was assessed on wireless services.
 Administrative costs for the program reported by eligible telecommunications carriers decreased
from $33,089 in 2015 to $23,235 in 2016.
 The ITSAP fund cash balance at the end of 2016 was $1,354,852.
Surcharge on land lines increases, Universal Service Fund scrutinized
Faced with declining revenue as Idahoans increasingly abandon land line phone service, in August 2017
the Commission raised a monthly surcharge on land lines and questioned the sustainability of the Idaho
Universal Service Fund (IUSF).
The fund was established in 1988 to ensure all Idahoans have access to local telephone service at rea-
sonable rates.
This is accomplished by taking revenue collected from a surcharge on land-line users and long-distance
call minutes, and distributing it to telecommunications carriers that meet eligibility requirements.
Over the last several years, however, revenue has been insufficient to cover distributions. In the most
Page 47
Idaho Public Utilities Commission
TELECOMMUNICATION CASES
Page 48
Idaho Public Utilities Commission
TELECOMMUNICATION CASES
recent fiscal year, the fund collected nearly a half-million dollars less than it distributed. The trend
prompted the Commission to raise the monthly surcharge on each residential line to 25 cents, up from 12
cents, and to 44 cents for each business line, up from 20 cents.
The change took effect Sept. 1, 2017.
The cost for each minute of a long-distance call also increased, from ½ cent per minute to 0.9 cents per
minute.
The changes are expected to allow the fund to meet its obligations for the 2018 fiscal year, but the
Commission expressed concern that raising the surcharge will cause more Idahoans to abandon their
land lines, exacerbating the trend and eventually making the fund unsustainable.
To address this, the Commission opened a generic docket to facilitate communication with the general
public, telephone company representatives and other stakeholders, with a goal of developing a sustain-
able approach for the fund in a declining industry where land lines are being replaced with new tech-
nology such as cell phones and Voice over Internet Protocol.
Page 49
Idaho Public Utilities Commission
CONSUMER ASSISTANCE
Commission issues annual consumer assistance report
The Consumer Assistance staff responded to 1,424 complaints and inquiries in calendar year 2017*,
91 percent of which were from residential customers. The first chart below illustrates the complaints
and inquiries by industry, while the second chart summarizes the types of issues reported to the IPUC.

While the Consumer Assistance Staff is able to respond to most inquiries without extensive research,
about 75 percent of complaints required investigation by the staff. About 44 percent of investigations
resulted in reversal or modification of the utility’s original action. Payment terms were negotiated in
20 percent of the investigations.
*As of Nov. 15, 2017
Page 50

REGULATING IDAHO’S RAILROADS

More than 900 miles of railroad track in Idaho have been abandoned since 1976. Federal law gov-
erns rail line abandonments. The federal Surface Transportation Board (formerly the Interstate Com-
merce Commission) 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 pro-
posed 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 compli-
ance with state and federal laws, rules and regulations concerning the transportation of hazardous ma-
terials, locomotive cab safety and sanitation rules, and railroad/highway grade crossings.
Hazardous material inspections are conducted in rail yards. In 1994, Idaho was invited to participate
in the Federal Railroad Administration’s State Participation Program. IPUC has a State Program Man-
ager and one FRA certified hazardous material inspector.
The IPUC inspects railroad-highway grade crossings where incidents occur, investigates citizen com-
plaints of unsafe or rough crossings and conducts railroad-crossing surveys.
Idaho Public Utilities Commission
Page 51
Idaho Code 61-515 empowers the Idaho Public Utilities Commission to require every utility to “maintain
and operate its line, plant, system, equipment, apparatus, and premises in such a manner that promote
and safeguard the health and safety of its employees, customers and the public.”
Pursuant to 49 U.S.C Section 60105, Chapter 601, the Idaho Public Utilities Commission is a certified
partner with the U.S. Department of Transportation Pipeline Hazardous Material Safety Administration.
The federal/state partnership provides the statutory basis for the pipeline safety program and estab-
lishes a framework for promoting pipeline safety through federal delegation to the states for all or
part of the responsibility for intrastate natural gas pipeline facilities under annual certification.
Under the certification, Idaho assumes inspection and enforcement responsibility with respect to more
than 8,300 miles of intrastate natural gas pipelines over which it has jurisdiction under state law. With
the certification, Idaho may adopt additional or more stringent standards for intrastate pipeline facili-
ties provided the standards are compatible with federal regulations.
The Idaho Public Utilities Commission has a state program manager and three trained and certified
pipeline safety inspectors who conduct records audits and field installed equipment inspections on all
intrastate natural gas pipeline operators under its jurisdiction.

Idaho Public Utilities Commission
REGULATING IDAHO’S PIPELINES
202
5
5.5
93
19.5
18
21
18
0 50 100 150 200 250
Standard inspection days
Compliance inspection days
Damage prevention inspection days
Construction inspection days
Operator qualification inspection days
Integrity Management Program inspection days
Incident/Accident inspection days
Operator training inspection days
Pipeline Safety Activity Summary
Page 52

This report satisfies Idaho Code 61-214; this is a “full and complete account” of the most significant cases to
come before the commission during the 2017 calendar year. (The financial report and natural gas report cover
Fiscal Year July 1, 2016 through June 30, 2017.)
Interested parties may 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 Com-
mission’s Boise office, 472 W. Washington St., Monday through Friday, 8 a.m. to 5 p.m.
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 en-
suring 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.

Costs associated with this publication are available from the Idaho Public Utilities Commission in accord-
ance with Section 60-202, Idaho Code, PUC 12-20-2017.

Questions?
Contact Matt Evans, Public Information Officer
[phone]
[e-mail]
Idaho Public Utilities Commission