FINAL ANNUAL REPORT 2015.pdf

IDAHO PUBLIC UTILITIES COMMISSION

2015 ANNUAL REPORT

P.O. Box 83720 Boise, ID 83720-0074
472 W. Washington Boise, ID 83702
208.334.0300
www.puc.idaho.gov

Table of Contents

IDAHO PUBLIC UTILITIES COMMISSION ......................................................... 1
COMMISSIONERS ................................................................................... 3
Commission Changes ............................................................................. 6
FINANCIAL SUMMARY FUND 0229 .............................................................. 9
Fiscal Years 2011 – 2015 ......................................................................... 9
COMMISSION STRUCTURE AND OPERATIONS ............................................... 10
Administration ................................................................................... 12
Legal .............................................................................................. 13
Utilities Division ................................................................................. 13
Railroad and Pipeline Safety Section ......................................................... 14
Pipeline Safety .................................................................................. 14
WHY CAN’T YOU JUST TELL THEM NO? ..................................................... 15
AVERAGE RESIDENTIAL RETAIL PRICES OF ELECTRICITY BY STATE 2013 ............. 16
SOLAR ISSUES DOMINATE 2015 ............................................................... 18
OTHER MAJOR ISSUES: TRANSMISSION SWAP, SECOND AREA CODE.................... 26
ELECTRICAL POWER IN IDAHO ................................................................ 30
ELECTRIC ......................................................................................... 31
NATURAL GAS .................................................................................... 49
WATER ............................................................................................ 57
TELECOMMUNICATIONS ........................................................................ 60
CONSUMER ASSISTANCE ........................................................................ 65
REGULATING IDAHO’S RAILROADS ........................................................... 69
REGULATING IDAHO’S PIPELINES ............................................................. 70

Idaho Public Utilities Commission

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IDAHO PUBLIC UTILITIES COMMISSION

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

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

This report and all the links inside can be accessed online from the Commission’s Website at www.puc.idaho.gov. Click on “File Room,” in the upper-left-hand-
corner and then on “IPUC 2015 Annual Report.”
Front cover photograph courtesy of Idaho Power Company.
Idaho Public Utilities Commission

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December 1, 2015

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 2015 Annual Report. This report is a detailed description of the most significant cases, decisions
and other activities during 2015. The financial report on Page 9 is a summary of the commission’s budget
through the conclusion of Fiscal Year 2015, which ended June 30, 2015.
It has been a privilege and honor serving the people of Idaho this past year.

Sincerely,

Paul Kjellander
President, Idaho Public Utilities Commission
Idaho Public Utilities Commission

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COMMISSIONERS

P A U L K J E L L A N D E R
Paul Kjellander rejoined the Idaho Public Utilities Commission in April 2011
following his service as administrator of the Office of Energy Resources (OER).
Kjellander, who serves as Commission president, was appointed to his current
six-year term by Idaho Governor C.L. “Butch” Otter.
Kjellander previously served on the Commission from January 1999 until
October 2007. In 2007, Governor Otter appointed Kjellander to head up the
newly created OER. During his 3.5 years at OER, Kjellander created an
aggressive energy efficiency program funded through the federal stimulus act.
Kjellander was also elected to serve as a board member on the National
Association of State Energy Officials.
Kjellander, a Republican, was elected to three terms (1994-1999) in the Idaho
House of Representatives, where he served as a member of the House State
Affairs, Judiciary and Rules, Ways and Means, Local Government and Transportation committees. During his last
term in office, Kjellander was elected House Majority Caucus Chairman. His legislative service includes
membership on the Legislature’s Information Technology Advisory Council and the House/Senate Joint
Committee on Technology. He also served as co-chairman of the Legislative Task Force on the Federal
Telecommunications Act of 1996 and vice chairman of the Council of State Governments-West “Smart States
Committee.” His interim legislative committee assignments included the Optional Forms of County Government
Committee, Capital Crimes Committee and the Private Property Rights Committee.
Kjellander has also served as director of Boise State University’s College of Applied Technology Distance
Learning, program head of broadcast technology, station manager of BSU Radio Network, director of the Special
Projects Unit for BSU Radio, and BSU Radio’s director of News and Public Affairs. Kjellander’s undergraduate
degrees from Muskingum College, Ohio, are in communications, psychology and art. He has a master’s degree in
telecommunications from Ohio University.
As a member of the National Association of Regulatory Commissioners (NARUC), Kjellander has served on the
Telecommunications, Consumer Affairs, and Electricity Committees. He also served as Chairman of the Joint
Board on Jurisdictional Separations. Kjellander is a member of the NARUC Presidential Federalism Task Force
and serves as vice chairman of the NARUC Telecommunications Committee. He is currently serving as a NARUC
representative to the North American Numbering Council.
Kjellander is a licensed youth soccer coach and has qualified teams for various state and regional tournaments.
Idaho Public Utilities Commission

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M A R S H A S M I T H
Commissioner Smith returned to the commission on an interim basis on July
30, 2015, following the untimely passing of Commissioner Mack Redford.
Appointed by former Gov. Cecil Andrus in 1991, she served four terms until her
retirement in February 2015. Just five months after her retirement, she was re-
appointed by Gov. C.L. “Butch” Otter to serve through December 2015 to allow
the Governor and Legislature time to appoint and confirm a new commissioner
to fill out the remainder of Commissioner Redford’s term.
Commissioner Smith represented Idaho on the Western Interconnection
Regional Advisory Body and the State-Provincial Steering Committee. She is
past chair of the Western Electricity Coordinating Council and a past president
of the National Association of Regulatory Utility Commissioners (NARUC). She
served on the NARUC Board and is a past chair of the association’s Electricity
Committee. She was also a member of the Steering Committee of the
Northern Tier Transmission Group. She chaired the Western Interstate Energy Board’s Committee for Regional
Electric Power Cooperation from October 1999 to October 2005. She was a member of the National Council on
Electricity Policy Steering Committee, the Harvard Electricity Policy Group and is a member of the Idaho State
Bar.
Smith received a Bachelor of Science degree in biology/education from Idaho State University, a master of
library science degree from Brigham Young University and her law degree from the University of Washington.
Before joining the commission, Commissioner Smith served as a deputy attorney general in the business
regulation/consumer affairs division of the Office of the Idaho Attorney General. She became a deputy attorney
general for the commission in 1981 and was chair of the NARUC Staff Subcommittee on Telecommunications. In
1989, she became the commission’s director of policy and external relations until 1991, when Gov. Andrus
appointed her to the commission.
A fourth-generation Idahoan, Commissioner Smith has two sons.
Idaho Public Utilities Commission

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K R I S T I N E ( S A S S E R ) R A P E R
Kristine (Sasser) Raper was appointed to the commission effective February 19,
2015, by Governor C.L. “Butch” Otter. Commissioner Raper’s term expires in
January 2021.
Before her appointment, Commissioner Raper served seven years as a deputy
attorney general assigned to the Public Utilities Commission. While a deputy
attorney general for the PUC, she was involved in electric, gas, water and
telecommunications cases. She successfully represented the PUC in Federal
District Court against a lawsuit brought by the Federal Energy Regulatory
Commission. That matter resulted in a settlement between the parties.
Before her work in the Attorney General’s office, she served for eight years as a
law clerk to Commissioner R.D. Maynard on the Idaho Industrial Commission.
Raper developed expertise in Idaho workers’ compensation law and
unemployment law matters appealed through the state Department of Labor.
Commissioner Raper was born in Delaware and moved to Utah with her family in the early 1980s. She spent the
summer between high school graduation and the start of college working in Grand Teton National Park. She
moved to Boise in 1990 to attend Boise State University. In 1995, she earned a Bachelor of Science in criminal
justice from BSU and in 2001 received her juris doctor from the University of Idaho.
Commissioner Raper serves on the Electricity Committee of the National Association of Regulatory Utility
Commissions.
The commissioner and her husband, Mark, share three children.
Idaho Public Utilities Commission

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Commission Changes

Governor Otter appoints Kristine Raper to six-year term on Idaho Public
Utilities Commission

Feb. 19, 2015 – Idaho Governor C.L. “Butch” Otter this week announced the
appointment of Kristine (Sasser) Raper to a six-year term on the Idaho Public
Utilities Commission. While Raper’s term officially begins today, her appointment
is subject to confirmation by the Idaho State Senate.

Raper, 43, succeeds Commissioner Marsha Smith, who is retiring after serving
four terms as a commissioner and nearly 35 years in state government.

Before her appointment to the commission, Raper served for seven years as a
state deputy attorney general assigned as legal counsel to the Public Utilities
Commission. She represented the commission on two cases that were appealed
to the state Supreme Court and one case in federal district court.

Prior to her work in the attorney general’s office, she served for eight years as a law clerk to Commissioner R.D.
Maynard of the Idaho Industrial Commission.

Raper was born in Delaware and moved to Utah with her family in the early 1980s. In 1995, she earned a
Bachelor of Science degree in criminal justice from Boise State University and in 2001 received her juris doctor
from the University of Idaho.

Raper serves with Commission President Paul Kjellander and Commissioner Mack Redford on the three-member
commission.

“I’m pleased to be appointed by Governor Otter to serve the citizens of Idaho in this important role. I will work
diligently alongside President Kjellander and Commissioner Redford to continue the PUC’s tradition of integrity
and fairness,” Raper said. “Commissioner Marsha Smith served the state and the commission with great
distinction and it is an honor to succeed her.”

In his statement, Gov. Otter said, “Over the past seven years, Kristine has distinguished herself as someone who
is thorough, professional, collegial and devoted to fulfilling the vital role of an ombudsman for ratepayers and
regulator for our public utilities. The electricity, natural gas and other services enjoyed by Idaho citizens are in
good hands with Kristine’s knowledge, skills and temperament ensuring that our system works.”

Idaho Public Utilities Commission

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Idaho PUC Commissioner Mack Redford passes away

July 1, 2015 - The Public Utilities Commission and the State of Idaho lost an
outstanding public servant with the passing of Commissioner Mack Redford
Tuesday, June 30.

Since Gov. C.L. “Butch” Otter appointed him to the Commission in 2007, Mack
served the commission with dedication and genuine enthusiasm. All those who
worked with Mack were impressed with his interest in PUC-related issues and in
his ability to add a personal touch to the work environment.

Mack made a practice of visiting the offices of his co-workers regularly. During
contested cases that came before the Commission, Mack treated all parties with
fairness and respect. A diehard Vandal, he was gracious even to Bronco fans.

“Mack was the true embodiment of what it means to be a public servant,” said Governor Otter. “His wealth of
international business experience coupled with his numerous positions inside government gave Mack the kind
of insight and combination of skills that is extremely difficult to find and even harder to replace. The people of
Idaho lost a true champion and I have lost a good friend. The First Lady and I are keeping Mack, his wife Nancy,
and their family in our prayers.”

At the time of his appointment, Commissioner Redford, 77, practiced law for the Boise-based firm of Elam &
Burke PA, specializing in commercial transactions, construction and engineering law, mediation, real estate and
general business.

Commissioner Redford grew up in the Weiser and Caldwell areas, graduating from Caldwell High School. He
received both his bachelor’s and law degree from the University of Idaho and in 1967 became a deputy in the
Idaho attorney general’s office. In 1977, he became a deputy attorney general for the Trust Territory of the
Pacific Islands, headquartered in Saipan, Northern Mariana Islands.

In 1981, Commissioner Redford became general counsel for Morrison Knudsen Engineers and Morrison Knudsen
International, a position that took him to Saudi Arabia where MK was building the King Khalid Military City. In
1991, Commissioner Redford was retained by TransManche Link, based in Folkestone, England, where he was
legal counsel for the Channel Tunnel Contractors, the builders of the 31-mile Channel Tunnel connecting England
and France. It is the second-largest rail tunnel in the world.

In 1992, Commissioner Redford joined the Boise firm of Park Redford & Burkett. In 1993, he was retained by the
World Bank of the Government of Nepal as contract and claims counsel for the Arun Ill Hydroelectric Project. In
1996, he became general counsel for Micron Construction, which was later acquired by Kaiser Engineers. He
joined the Boise law firm of Elam & Burke in 2001.

He was also very active in community service serving as chair of the Idaho Pardons and Parole Commission, the
Board of Directors for Zoo Boise, a volunteer for the Service Corps of Retired Executives and a volunteer in
CASA’s Guardian Ad Litem program. He was a past president of both the University of Idaho Foundation and the
University of Idaho Vandal Boosters.

Commissioner Redford is survived by his wife, Nancy and two children.
Idaho Public Utilities Commission

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Governor to re-appoint Marsha Smith to PUC on an interim basis

July 30, 2015 - Governor C.L. “Butch” Otter announced today that Marsha Smith,
a long-time Commissioner for the Idaho Public Utilities Commission (PUC), will
be re-appointed to the PUC on an interim basis. Smith fills the Commissioner
position left open after Commissioner Mack Redford’s sudden passing in June.

“I wish to extend my sincere thanks to Marsha, who after retiring has agreed to
step back in to her familiar and valuable role as public servant at a time of
need,” said Governor Otter. “In the wake of the untimely death of my good
friend Commissioner Mack Redford, I can think of no better person to fill that
void than Marsha because she knows the issues and has invaluable experience.”

Smith’s interim appointment period on the PUC is effective immediately and will
expire at the end of 2015. At that time, a new commissioner will be appointed to
replace her, pending Idaho Senate confirmation. Smith was first appointed to the PUC by then-Governor Cecil
Andrus in 1991, and previously served the commission as a deputy attorney general. She served as a
Commissioner for 24 years before retiring last February.

“I deeply regret the circumstances that created this vacancy,” said Smith. “I am honored to step in on a
temporary basis to assist the commission with an unusually heavy case load as well as facilitate a thoughtful
process that will allow timely confirmation of a permanent replacement.”

Smith re-joins President Paul Kjellander and Kristine Raper on the Commission.

Idaho Public Utilities Commission

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FINANCIAL SUMMARY FUND 0229
Fiscal Years 2011 – 2015

Description FY 2011 FY 2012 FY 2013 FY 2014 FY 2015

Personnel Costs $3,275,500 $3,304,100 $3,491,500 $3,528,900 $3,563,500
Communication Costs $29,300 $29,500 $31,300 $31,000 $23,500
Employee Development Costs $46,700 $62,500 $55,600 $53,200 $99,200
Professional Services $12,500 $9,800 $9,700 $12,300 $8,500
Legal Fees $522,200 $525,300 $551,600 $519,700 $538,400
Employee Travel Costs $123,300 $115,400 $123,600 $141,100 $152,500
Fuel & Lubricants $2,900 $4,100 $4,700 $2,700 $5,600

Insurance $1,300 $1,000 $3,100 $4,400 $4,300
Rentals & Leases $283,900 $294,200 $276,100 $584,600 $308,600
Misc. Expenditures $102,100 $85,600 $117,000 $104,700 $84,400
Computer Equipment $0 $24,300 $29,200 $66,400 $73,600
Office Equipment $34,400 $0 $13,000 $11,900 $16,500
Motorized/Non-Motorized Equip $0 $52,300 $0 $0 $32,500
Specific Use Equipment $0 $0 $0 $0 $0

Total Expenditures $4,434,100 $4,508,100 $4,706,400 $5,060,900 $4,911,100

Fund 0229-20 Appropriation $4,820,700 $4,768,200 $4,916,800 $5,061,700 $5,595,600

Unexpended Balance $386,600 $260,100 $210,400 $800 $684,500

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
utilities.
The governor appoints the three commissioners with confirmation by the Idaho Senate. No more than two
commissioners may be of the same political party. The commissioners serve staggered six-year terms.
The governor may remove a commissioner before his/her term has expired for dereliction of duty, corruption or
incompetence.
The three-member commission was established by the 12th Session of the Idaho Legislature and was organized
May 8, 1913 as the Public Utilities Commission of the State
of Idaho. In 1951 it was reorganized as the Idaho Public
Utilities Commission. Statutory authorities for the
commission are established in Idaho Code titles 61 and 62.
The IPUC has quasi-legislative and quasi-judicial as well as
executive powers and duties.
In its quasi-legislative capacity, the commission sets rates
and makes rules governing utility operations. In its quasi-
judicial mode, the commission hears and decides
complaints, issues written orders that are similar to court
orders and may have its decisions appealed to the Idaho
Supreme Court. In its executive capacity, the commission
enforces state laws and rules affecting the utilities and rail
industries.
Commission operations are funded by fees assessed on
the utilities and railroads it regulates. Annual assessments
are set by the commission each year in April within limits
set by law.
The commission president is its chief executive officer.
Commissioners meet on the first Monday in April in odd-numbered years to elect one of their own to a two-year
term as president. The president signs contracts on the commission’s behalf, is the final authority in personnel
matters and handles other administrative tasks. Chairmanship of individual cases is rotated among all three
commissioners.

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 proceedings and are recorded and transcribed by a court reporter.
There are technical hearings and public
hearings. At technical hearings, formal
parties who have been granted
“intervenor status” present witness
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.
In 2009, the commission began
conducting telephonic public hearings to
save expense and allow customers to
testify from the comfort of their own
homes. Commissioners and other interested
parties gather in the Boise hearing room and
are telephonically connected to ratepayers who call in on a toll-free line to provide testimony or listen in. A
court reporter is present to take testimony by telephone, which has the same legal weight as if the person
testifying were present in the hearing room. Commissioners and attorneys may also direct questions to those
testifying.
The commission also conducts regular decision
meetings to consider issues on an agenda prepared by
the commission secretary and posted in advance of the
meeting. These meetings are usually held Mondays at
1:30 p.m., although by law the commission is required
to meet only once a month. Members of the public are
welcome to attend decision meetings.
Typically, decision meetings consist of the commission’s
review of decision memoranda prepared by commission
staff. Minutes of the meetings are taken. 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 Meeting Law,
commissioners may also privately deliberate fully
submitted matters.
PUC hearing room
PUC headquarters at 472 W. Washington St.,
Boise.
Idaho Public Utilities Commission

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Commission Staff
OUR MISSION

- Determine fair, just and reasonable rates and utility practices for
electric, gas, telephone 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 commission staff is organized in three divisions – administration, legal and utilities.

The staff analyzes each petition, complaint, rate increase request or application for an operating certificate
received by the commission. In formal proceedings before the commission, the staff acts as a separate party to
the case, presenting its own testimony, evidence and expert witnesses. The commission considers staff
recommendations along with those of other participants in each case - including utilities, public, agricultural,
industrial, business and consumer groups.

Administration

The Administrative Division is responsible for coordinating overall IPUC activities. The division includes the three
commissioners, two policy strategists, a commission secretary, an executive administrator, an executive
assistant and support personnel.

The policy strategists are executive level positions reporting directly to the commissioners with policy and
technical consultation and research support regarding major regulatory issues in the areas of electricity,
telecommunications, water and natural gas. Strategists are also charged with developing comprehensive policy
strategy, providing assistance and advice on major litigation before the commission, public agencies and
organizations. Contact Wayne Hart, 334-0354 or Gene Fadness, 334-0339, policy strategists.

The commission secretary, a post established by Idaho law, keeps a precise public record of all commission
proceedings. The secretary issues notices, orders and other documents to the proper parties and is the official
custodian of documents issued by and filed with the commission. Most of these documents are public records.
Contact Jean Jewell, commission secretary, at 334-0338.

The executive administrator has primary responsibility for the commission’s fiscal and administrative
operations, preparing the commission budget and supervising fiscal, administration, public information,
personnel, information systems, rail section operations and pipeline safety. The executive administrator also
serves as a liaison between the commission and other state agencies and the Legislature.
Idaho Public Utilities Commission

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Contact Joe Leckie, executive administrator, at 334-0331.

The public information office is responsible for public communication between the commission, the general
public and interfacing governmental offices. The responsibility includes news releases, responses to public
inquiries, coordinating and facilitating commission workshops and public hearings and the preparation and
coordination of any IPUC report directed or recommended by the Idaho Legislature or Governor.
Contact Gene Fadness, public information officer at 334-0339 or Diane Holt, assistant public Information
officer, 334-0323.

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 federal courts and
before other state or federal regulatory agencies. Contact Don Howell, legal division director, at 334-0312.

Utilities Division

The Utilities Division, responsible for technical and policy analysis of utility matters before the commission, is
divided into four sections. Contact Randy Lobb, utilities division administrator, at 334-0350.

The Accounting Section of seven auditors audits utility books and records to verify reported revenue, expenses
and compliance with commission orders. Staff auditors present the results of their findings in audit reports as
well as in formal testimony and exhibits. When a utility requests a rate increase, cost-of-capital studies are
performed to determine a recommended rate of return. Revenues, expenses and investments are analyzed to
determine the amount needed for the utility to earn the recommended return on its investment.
Contact Terri Carlock, accounting section supervisor, at 334-0356.

The Engineering Section of three engineers and two utility analysts reviews the physical operations 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 establishes 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 services and frequently help resolve customer complaints.
Contact Rick Sterling, engineering section supervisor, at 334-0351.
The Technical Analysis Section of three utility analysts and one economist determines the cost effectiveness of
all Demand Side Management (DSM) programs including energy efficiency and demand response. They identify
potential for new DSM programs and track the impact on utility revenues. They review utility forecasts of
energy, water and natural gas usage with focus on residential self-generation and rate design.
Contact Matt Elam, Technical Analysis section supervisor, at 334-0363.
Idaho Public Utilities Commission

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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 commission on
technical matters that include advanced services, 911 and other matters as requested. During 2014 and 2015,
telecommunications staff is conducting an analysis of the potential for broadband expansion.
Contact Carolee Hall, 334-0634 or Grace Seaman, 334-0352.

The Consumer Assistance Section includes five division investigators who resolve conflicts between utilities and
their customers. Customers faced with service disconnections often seek help in negotiating payment
arrangements. Consumer Assistance may mediate disputes over billing, deposits, line extensions and other
service problems.

Consumer Assistance monitors Idaho utilities to verify they are complying with commission orders and
regulations. Investigators participate in general rate and policy cases when rate design and customer service
issues are brought before the commission.
Contact Beverly Barker, administrator for the Consumer Assistance section, at 334-0302.

Railroad and Pipeline Safety Section

The Rail Section oversees the safe operations of railroads that move freight in and through Idaho and enforces
state and federal regulations safeguarding the transportation of hazardous materials by rail in Idaho. The
commission’s rail safety specialist inspects railroad crossings and rail clearances for safety and maintenance
deficiencies. The Rail Section 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 authority to grant or deny line abandonments.
Contact Joe Leckie, rail section manager, at 334-0331.
Pipeline Safety

The pipeline safety section oversees the safe operation of the intrastate oil and natural gas pipelines in Idaho.

The commission’s 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 factors and
to implement practices to avoid accidents. All reportable accidents will be investigated and appropriate reports
filed with the U.S. Department of Transportation in a timely manner.
Contact Joe Leckie, pipeline safety program manager, at 334-0331.
Idaho Public Utilities Commission

Page 15

WHY CAN’T YOU JUST TELL THEM NO?

One of the most frequently asked questions the PUC receives after a utility files a rate increase
application is, “Why can’t you just tell them no?” Actually, we can, but not without evidence.
For nearly 100 years, public utility regulation has been based on this regulatory compact
between utilities and regulators: Regulated utilities agree to invest in the generation,
transmission and distribution necessary to adequately and reliably serve all the customers in
their assigned territories. In return for that promise to serve, utilities are guaranteed recovery
of their prudently incurred expense along with an opportunity to earn a reasonable rate of
return. 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 unreasonable for customers.
In setting rates, the commission must consider the needs of both the utility and its customers. The commission serves the
public interest, not the popular will. It is not in customers’ best interest, nor is it in the interest of the State of Idaho, to
have utilities that do not have the generation, transmission and distribution infrastructure to be able to provide safe,
adequate and reliable electrical, natural gas and water service. This is a critical, even life-saving, service for Idaho’s citizens
and essential to the state’s economic development and prosperity.
Unlike unregulated businesses, utilities cannot cut back on service as costs increase. As demand for electricity, natural gas
and water grows, utilities are statutorily required to meet that demand. In Idaho recently, and across the nation, a
continued increase in demand as well as a number of other factors have contributed to rate increases on a scale we have
not witnessed before. It is not unusual now for Idaho’s three major investor-owned electric utilities to file annual rate
increase requests.
In light of these continued requests for rate increases, the Commission walks a fine line in balancing the needs of utilities to
serve customers and customers’ ability to pay.
When a rate case is filed, our staff of auditors, engineers and attorneys will take up to six months to examine the request.
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 independently of the commission, will also file its own comments that result from its
investigation of the company’s request. The three-member Commission will also conduct technical and public hearings.
Once testimony from the company, commission staff and intervening parties is presented and testimony from hearings and
written comments is taken, all of 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 decision.
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 utilities seek to recover from customers if the commission is
confident it has the legal justification to do so. (See pages 18 and 19 of this report.) Utilities and parties to a rate case have
the right to petition the Commission for reconsideration. If reconsideration is not granted, utilities or customer groups can
appeal the Commission’s decision to the state Supreme Court.
In the end, the Commission’s job is to ensure that customers are paying a reasonable rate and are receiving adequate and
reliable service and that utilities are allowed to recover their prudently incurred expenses and earn a fair rate of return.
Idaho Public Utilities Commission

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AVERAGE RESIDENTIAL RETAIL PRICES OF ELECTRICITY BY STATE 2013

The information below was provided by the Energy Information Administration, a division of the U.S.
Department of Energy. It is an average of retail rates by state, including rates for investor-owned utilities as well
as publicly-owned utilities, such as rural electric co-ops and municipalities. This data was released in 2015, but is
an average of rates in 2013. Idaho’s average rate ranks 50th of 50 States and the District of Columbia. Louisiana’s
average retail rate was the lowest in the nation during 2013.

Name Average Retail Price
(cents/kWh)
Net Summer
Capacity (MW)
Net Generation
(MWh)
Total Retail Sales
(MWh)
Alabama 9.18 32,547 152,878,688 86,182,548
Alaska 16.30 2,119 6,946,419 6,416,411
Arizona 9.81 27,587 110,904,994 75,063,343
Arkansas 7.62 16,355 65,005,678 46,859,567
California 13.50 71,329 199,518,567 259,538,038
Colorado 9.39 14,947 52,556,701 53,685,297
Connecticut 15.50 9,060 36,117,544 29,492,338
Delaware 11.10 3,357 8,633,694 11,519,331
District of
Columbia
11.90 10 71,787 11,258,845
Florida 10.40 59,139 221,096,136 220,674,333
Georgia 9.37 38,488 122,306,364 130,978,872
Hawaii 34.00 2,730 10,469,269 9,639,157
Idaho 6.92 4,911 15,499,089 23,711,859
Illinois 8.40 45,146 197,565,363 143,540,004
Indiana 8.29 26,837 114,695,729 105,173,425
Iowa 7.71 16,019 56,675,404 45,709,100
Kansas 9.33 14,093 44,424,691 40,293,476
Kentucky 7.26 21,089 89,949,689 89,048,490
Louisiana 6.90 25,548 103,407,706 84,730,743
Maine 11.80 4,491 14,428,596 11,561,059
Maryland 11.30 12,215 37,809,744 61,813,552
Massachusetts 13.80 14,321 36,198,121 55,313,324
Michigan 10.98 30,332 108,166,078 104,818,191
Minnesota 8.86 15,447 52,193,624 67,988,535
Mississippi 8.60 15,404 54,584,295 48,387,675
Missouri 8.53 22,004 91,804,321 82,435,359
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Name Average Retail Price
(cents/kWh)
Net Summer
Capacity (MW)
Net Generation
(MWh)
Total Retail Sales
(MWh)
Montana 8.25 6,317 27,804,784 13,863,383
Nebraska 8.37 8,273 34,217,293 30,827,939
Nevada 8.95 10,476 35,173,263 35,179,918
New Hampshire 14.20 4,323 19,264,435 10,870,261
New Jersey 13.70 18,924 65,263,408 75,052,914
New Mexico 8.83 8,373 36,635,909 23,178,568
New York 15.20 39,520 135,768,251 143,162,668
North Carolina 9.15 30,391 116,681,763 128,084,893
North Dakota 7.83 6,490 36,125,159 14,716,956
Ohio 9.12 32,854 129,745,731 152,456,864
Oklahoma 7.54 23,485 77,896,588 59,340,624
Oregon 8.21 15,544 60,932,715 46,688,856
Pennsylvania 9.91 45,406 223,419,715 144,709,727
Rhode Island 12.70 1,781 8,309,036 7,708,334
South Carolina 9.10 23,083 96,755,682 77,780,953
South Dakota 8.49 4,057 12,034,206 11,734,210
Tennessee 9.27 21,322 77,724,264 96,381,472
Texas 8.55 109,568 429,812,510 365,104,131
Utah 7.84 7,631 39,402,961 29,723,368
Vermont 14.20 1,235 6,569,670 5,510,764
Virginia 9.07 24,849 70,739,235 107,794,985
Washington 6.94 30,910 116,835,474 92,336,441
West Virginia 8.14 16,285 73,413,405 30,817,241
Wisconsin 10.30 18,031 63,742,910 68,820,090
Wyoming 7.19 8,380 49,588,606 16,971,354
U.S. Total 9.84 1,063,033 4,047,765,259 3,694,649,786

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SOLAR ISSUES DOMINATE 2015

Idaho commission reduces contract length for
some PURPA projects to two years
Case No. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
August 19, 2015 – The commission is granting a request by the state’s three major
electric utilities to reduce the length of negotiated PURPA contracts to two years.

The commission found the previous 20-year contract length resulted in utilities
and, consequently, customers paying unreasonable costs for renewable
generation.

The federal Public Utility Regulatory Policies Act (PURPA) requires utilities to buy
from qualifying renewable facilities (QFs) at an “avoided cost rate,” set by the
commission. The avoided cost rate is to be equal to what the utility avoids by not
having to generate the power itself or buy it from another source. Thus,
customers are to be held harmless by the PURPA requirement that utilities
purchase from QFs. However, the commission determined that long-term
contracts unreasonably overestimate future avoided cost, resulting in higher costs
to utilities and their ratepayers, contrary to PURPA’s avoided-cost principle. One
hundred percent of PURPA power supply costs are passed on to ratepayers.

Last February, Idaho Power Company asked the commission to reduce QF
contract lengths in response to a flood of solar project applications that it said
would force it to buy energy it did not need, drive up rates and threaten the
utility’s ability to reliably deliver energy. At the time, the commission had already
approved 13 Idaho Power agreements with QF developers for 400 megawatts of
solar energy. (The contracts for four of those projects, totaling 141 MW were
later terminated.) Idaho Power claims it has 1,326 MW of QF solar capacity
actively seeking energy sales agreements. Idaho Power now has 1,297 MW of
renewable energy (not counting hydro) on its system or under contract. That’s
40% of its 2014 peak load of 3,184 MW and 120% of its total minimum load of
1,073 MW.

In response, the commission temporarily reduced contract lengths for negotiated
PURPA contracts to five years while it investigated Idaho Power’s petition. Later,
PacifiCorp, operating as Rocky Mountain Power in eastern Idaho, joined the case,
claiming to have projects seeking contracts totaling 275.5 MW in its Idaho
territory. PacifiCorp has 189.6 MW of existing Idaho PURPA contracts – for a
total of 465 MW of existing and proposed PURPA generation, enough power
to supply 108 percent of PacifiCorp’s average Idaho retail load.

Idaho Power argued that allowing developers to obtain fixed prices over the
long term causes electric rates to increase. Idaho Power’s average cost for
PURPA generation since 2001 has always exceeded the regional market price.
The average cost for PURPA purchases, according to Idaho Power, is $62.49
per megawatt-hour compared to coal ($22.79), gas ($33.57) and non-PURPA,
off-system purchases ($50.64). PacifiCorp claims that over the next decade the
energy it will buy from its 141 PURPA contracts in its six-state territory will
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PURPA contracts – for a total of 465 MW of existing and proposed PURPA generation, enough power to supply
108 percent of PacifiCorp’s average Idaho retail load.

Idaho Power argued that allowing developers to obtain fixed prices over the long term causes electric rates to
increase. Idaho Power’s average cost for PURPA generation since 2001 has always exceeded the regional market
price. The average cost for PURPA purchases, according to Idaho Power, is $62.49 per megawatt-hour compared
to coal ($22.79), gas ($33.57) and non-PURPA, off-system purchases ($50.64). PacifiCorp claims that over the
next decade the energy it will buy from its 141 PURPA contracts in its six-state territory will cost customers an
average price of $66.32 per MWh, significantly higher than the regional market price of $38.11 per MWh.

Renewable developers claim the reduction in contract length will end solar and wind development in Idaho.
They argued that during 1996-2001 when contract length was five years, Idaho Power executed only one PURPA
contract. The commission said it was not persuaded that setting negotiated contracts to two will years will result
in a substantial decline of renewable resources. “The utilities all have ample amounts of PURPA on their systems
and additional renewable generation is in the queue,” it said, adding that 20-year published rate* contracts are
still in place.

The commission said shorter contract lengths will benefit consumers because the rate paid developers
“becomes a truer reflection of the actual costs avoided by the utility and allows QFs and ratepayers to benefit
from normal fluctuations in the market.” Utilities will still be required to purchase from qualifying renewable
developers, but with a shorter contract length that “merely functions as a reset for calculation of the QFs
avoided costs in order to maintain a more accurate reflection of the actual costs avoided by the utility over the
long term.”

Once a two-year contract is approved, the commission noted, the new QF then becomes part of the utility’s
resource stack and the contract is eligible for continuous renewal for as long as the developer chooses to
continue selling power to the utility. Rocky Mountain Power, for example, states that limiting contract length
does not mean the project will have only a two-year life. “Rocky Mountain Power will be required to purchase
the power produced as long as PURPA requirements exist,” Rocky Mountain stated in its testimony. Limiting
contract length “simply means that the price Rocky Mountain Power and its customers will be required to pay to
the QF will be subject to adjustment ... and be more closely aligned with Rocky Mountain Power’s current
avoided cost.”

Further, the commission noted, PURPA is not the only means through which a utility can acquire renewable
resources. Utilities have developed non-PURPA renewable resources such as Avista’s agreement with Palouse
Wind and Idaho Power’s agreement with Elkhorn Wind.

Renewable developers claimed the utilities are overreacting to the flood of applications, asserting that many of
the projects seeking contracts will not be developed because, in Idaho Power’s case, as more projects are added
to its queue, the avoided cost rate to be paid QFs declines. The utilities argued they must take each request for a
contract seriously and that any added generation impacts the utility’s power supply cost.

The change in the mandatory minimum contract length is “not intended to be punitive to QFs,” the commission
said. For several years, the commission has been adjusting terms and conditions of PURPA contracts “in order to
establish avoided cost rates that are just and reasonable to electric consumers, in the public interest and not
discriminatory against QFs.”

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Those opposing the change in contract length also argued that QFs should be treated similarly to utilities, which
are able to build large generation sources with recovery for investment spread over as long as 30 to 50 years.
However, the commission said, QFs differ from utility sources in several significant ways. For example, utilities
cannot be compensated for energy produced from a generating facility without first establishing the need for
that generation through the PUC’s Certificate of Need process. That’s different than PURPA, which requires
utilities to buy QF power whether the power is needed or not. Second, a utility-authorized resource is typically
subject to competitive bidding, cost scrutiny and oftentimes is able to fit into the utility’s need for dispatch
better than a mandatory QF. Third, the fuel component for utility plants is adjusted annually, but is fixed for the
duration of fuel-based, long-term QF contracts. PURPA contracts are special, the commission said, because
federal law compels utilities to buy power without arms-length bargaining and without regard to whether the
utility needs the power.

The commission said it has a long history of encouraging PURPA projects and renewable energy development in
Idaho. PURPA generation increased modestly in the first 25 years (1982-2007) to 200 MW. Since 2007, Idaho
Power, in particular, has experienced a six-fold increase in PURPA generation to 1,161 MW. Its power supply
expense, it claims, will have increased by 575% from 2004 to 2024. During the course of this case, the
commission conducted two public hearings, a technical hearing and received more than 200 written comments
from customers.

Those commenting in favor of shortened contracts included a number of companies that are large consumers of
power. Those companies cited an interest in keeping power costs low and fair and ensuring reliable service.
Several of the companies said utilities should not be required to buy electricity they do not need. A number of
Idaho school districts and community colleges also supported the petitions, noting the importance of
maintaining low operational costs and supporting a balanced approach to encouraging wind and solar power.

Those opposing the utilities’ petition included the City of Ketchum, the League of Women Voters and
environmental organizations. They cited the need to promote renewable energy and claimed shorter contracts
would eliminate solar development in Idaho. The Renewable Northwest Coalition, among other parties,
supported keeping 20-year contracts but adjusting the energy rate component of the contracts annually after 10
years. Commission staff argued in favor of reducing contract lengths to five years.

Parties to the case in addition to the three utilities and commission staff included the Idaho Conservation
League/Sierra Club, Intermountain Energy Partners, Micron, JR Simplot Co., Snake River Alliance, Ag Power
DCD/Ag Power Jerome, Amalgamated Sugar Co., Twin Falls Canal Company/Northside Canal Company/American
Falls Reservoir District, Clearwater Paper Corp., Idaho Irrigation Pumpers Association and the Renewable Energy
Coalition.

PUC says solar projects must identify owner or owners

Case No. IPC-E-15-18, Order No. 33383

Sept. 24, 2015 – The commission denied an Idaho Power Company petition to declare that solar projects
proposed in the Wood River Valley are actually one, large project that has been divided into 10 smaller projects
in order to qualify for more attractive contract terms.

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The commission did not rule on Idaho Power’s claim regarding the disaggregation of the projects, but denied
Idaho Power’s request because the project or projects do not identify an owner, which is a requirement under
the Schedule 73 tariff that governs projects 100 kilowatts or smaller.

Site Based Energy claims the ten, 100-kilowatt projects are separate, each with a distinct limited liability
corporation (LLC) and distinct owners. Idaho Power claims it is a large 1-megwatt project with the same
developer, John Reuter of Site Based Energy, and that the project or projects are “all located at the same site, on
the same contiguous property, and divided into ten sections.” Site Based Energy claims the projects have
common ownership only of interconnection equipment and are seeking economies of scale by purchasing and
building together.

The project or projects are seeking sales agreements with Idaho Power under the provisions of the Public Utility
Regulatory Policies Act or PURPA.

Intermittent projects (primarily wind and solar) larger than 100 kilowatts must negotiate with the purchasing
utility for a rate, rather than receiving the commission’s published rate. Further, published rate contracts are for
20 years, while negotiated contracts are for two years.

In an attempt to resolve the impasse, the commission asked Site Based Energy to provide additional information
regarding the owners and copies of the articles or certificates for each LLC. Site Based provided letters from 10
individuals who wrote they “intend to proceed with the solar project using a Special Purpose Entity, LLC DBA,”
but qualified their intent with, “if the projects are approved by the PUC.” Nine of the ten proposed owners
further conditioned their intent with the condition “if all the approvals are completed and the economics work
out.”

“Site Based did not provide any evidence that these LLCs exist, nor that they existed at the time the applications
were submitted,” the commission said. Idaho statutes state an LLC is created when a certificate of organization
is filed with the secretary of state.

The commission said Idaho Power could have rejected the applications outright because they did not comply
with the requirements of Schedule 73, calling for identification of a project or projects’ owner. Instead, the
utility opted to file a petition seeking a disaggregation finding. “Having determined that Site Based Energy’s
applications do not satisfy Schedule 73, the commission need not reach the other complex issues presented by
the parties,” the commission said.
Parties agree to temporary solar integration costs until a second Idaho
Power study is completed

Case No. IPC-E-14-18, Order No. 33227

Feb. 13, 2015 – The commission adopted a settlement that sets the rates solar developers will pay to have their
projects integrated into Idaho Power Company’s distribution and transmission system until a new solar
integration study can be completed.

The integration charge applies only to larger solar developers and does not impact residential or small-
commercial customers who have rooftop solar installations.
Idaho Public Utilities Commission

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The parties agreeing to the settlement include Idaho Power, commission staff, the Sierra Club, the Idaho
Conservation League and the Snake River Alliance.

Solar and wind generation that varies in its energy output depending on sun and wind conditions requires back-
up generation to ensure system reliability. Utilities must provide operating reserves from baseload (non-
intermittent) generation resources – such as a natural gas or hydro plant – that can be quickly ramped up or
down to offset changes in generation from variable generation. Restricting the use of baseload resources to
provide back-up for intermittent generation results in higher power supply costs that are eventually passed on
to customers, Idaho Power claims.

To prevent customers from paying those costs, Idaho Power proposed a solar integration charge that would be
discounted from the amount the utility pays to solar developers. The charge gradually increases as solar
generation increases. Developers will pay about 40 cents per megawatt-hour when there is 100 megawatts or
fewer of solar generation on Idaho Power’s system. That cost increases to $1.50 per MWh when solar
penetration is between 100 and 300 MW; $2.80 per MWh at a solar penetration of between 300 and 500 MW;
and $4.40 per MWh at a solar penetration of between 500 and 700 MW. Those amounts are for contracts signed
this year and would gradually change during the length of the sales agreement.

Because there was disagreement among the parties regarding the methodology Idaho Power used in its 2014
solar integration study, the parties agreed that Idaho Power will initiate a second study this year. A Technical
Review Committee will be used in that study that consists of staff from the Idaho and Oregon public utility
commissions, Idaho Power personnel and technical experts from the parties to the settlement.

The settlement also outlines the issues a second study will consider. In the last three months, the commission
has approved power purchase agreements between Idaho Power and developers of 13 solar projects totaling
400 megawatts. Integration charges have already been included in those contracts. Idaho Power also buys the
output from 60 MW of solar projects in its Oregon territory.

The commission recently reduced the length of solar contracts from 20 years to five years while it processes an
Idaho Power application to reduce the length of those contracts even further to two years. Idaho Power claims
there are about another 885 MW of solar projects seeking contracts under federal PURPA provisions with the
company.

Commission approves Idaho Power agreements with five solar projects

Case Nos. IPC-E-14-32, -33, -34;-35; and -36

Dec. 29, 2014 – The Commission approved Idaho Power Company sales agreements with five solar projects
owned by Boston-based First Wind. The contracts, totaling about $322.5 million over 20 years, are for a total
100 megawatts, 20 MWs for each project.

The commission has yet to rule on another six solar projects totaling about 181 MW. Last month, the
commission approved applications from two other solar projects, Boise City Solar and Grand View Solar II,
totaling 120 MW. Idaho Power also recently signed six contracts for 60 MW of solar generation in Oregon.

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While stating that the projects qualify under federal PURPA provisions, the commission’s order expresses
concern that the federal law may be compelling utilities to buy energy they do not need. The order states that
utilities should inform the commission as to whether additional review of contract terms and conditions for
federal PURPA projects is necessary.

PURPA requires regulated utilities to buy energy from independent, renewable generation projects at rates
established by state commissions. The rate to be paid small-power producers is called an “avoided-cost rate,”
because it is based on the cost the utility avoids by not having to generate the energy itself or buy it from
another source. The commission must ensure the avoided-cost rate is reasonable for utility customers because
100 percent of the price utilities pay to qualifying small-power producers is included in customer rates.

Congress enacted PURPA in response to a national energy crisis in the late 1970s with a goal to lessen the
nation’s dependence on foreign oil. “Unfortunately, PURPA does not address and FERC (Federal Energy
Regulatory Commission) regulations do not adequately provide for consideration of whether the utility being
forced to purchase QF power is actually in need of such energy,” the commission said. Idaho Power’s 20-year
Integrated Resource Plan does not indicate the utility is in need of more energy sources. “And yet, in less than
four months time, 13 QFs have contracted with Idaho Power for nearly 400 MW of solar generation – all
expected to be on-line and producing power by the end of 2016,” the commission said.

The commission reiterated that the combined potential contractual obligation of $1.4 billion for what could be
13 projects is passed on to ratepayers. While the projects will displace the fuel costs of Idaho Power’s existing
resources, “the capital costs of the displaced resources (such as baseload natural gas, coal and hydroelectric
plants) will continue to be recovered through ratepayers’ bills along with the costs of QF power.” Because solar
and wind generation is intermittent, other resources are sometimes needed to balance their variability as well
as provide back-up generation.

The First Wind projects include American Falls Solar and American Falls Solar II in Power County, Murphy Flat
Power in Owyhee County, Simco Solar in Elmore County and Orchard Ranch Solar in Ada County.

The developers will be paid a non-levelized avoided-cost rate over the 20-year term of the agreements, which
means payments increase over the course of the agreement and vary according to light-load and heavy-load
hours of the day and seasons of the year. The average levelized rate for the First Wind projects is about $63 per
megawatt-hour and the value of the five 20-year contracts ranges from $60.2 million to $68 million. (See
attached chart.)

Included in each contract is an integration charge the developer pays Idaho Power to cover the cost of
integrating the energy into Idaho Power’s transmission and distribution system. The integration cost increases
as the amount of solar generation on Idaho Power’s system increases. For these contracts, the charge ranges
from $2.46 per MWh to $5.05 per MWh.

The agreements allow for a 2 percent deviation in estimated energy output before the price can be adjusted. A
consistent deviation from the hourly energy generation estimates would be considered a material breach of the
agreements. Also included is a “90/110” firmness requirement. If a project’s generation exceeds 110 percent of
estimated output, the developer is paid 85 percent of a market-based price for the generation above 110
percent of forecasted output. If the developer does not produce at least 90 percent of forecasted generation,
then all output is paid at 85 percent of the market price.

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Revenue from the sales of Renewable Energy Certificates associated with the projects will be split 50-50
between the developer and Idaho Power.

PUC approves six more solar projects

BOISE Jan. 8, 2015 – Sales agreements between the developer of six solar projects and Idaho Power Company
have been approved, adding another 181 megawatts to the utility’s rapidly growing portfolio of solar
generation.

Since November, the Idaho Public Utilities Commission has approved Idaho Power agreements for 13 solar
projects, totaling 400 MW and valued at $1.4 billion. Idaho Power also recently signed contracts for 60 MW of
solar generation in its Oregon territory. (Four of these projects, totaling 141 MW, were eventually terminated.)

The projects approved this week are owned by Ketchum-based Intermountain Energy Partners. Mark van Gulik
is the developer. Five of the projects are in Elmore County and one is in Power County.

In its order approving the agreements, the commission repeated the same concern it did a month ago that the
federal government’s must-buy provisions for qualifying renewable energy projects may be compelling utilities
to buy energy they do not need.

The federal Public Utility Regulatory Policies Act of 1978 (PURPA) requires regulated utilities to buy energy from
independent, renewable generation projects at rates established by state commissions. The rate to be paid
small-power producers is called an “avoided-cost rate,” because it is based on the cost the utility avoids by not
having to generate the energy itself or buy it from another source. The commission must ensure the avoided-
cost rate is reasonable for utility customers because the price utilities pay to qualifying small-power producers is
included in customer rates.

The commission recently concluded a major review of PURPA contract terms and conditions and updated how it
calculates avoided-cost rates. Developers continue to request contracts with Idaho Power in significant enough
numbers “that we remain concerned about the company’s ability to balance the substantial amount of must-
take intermittent generation and still reliably serve customers,” the commission said. The order says utilities
should inform the commission as to whether additional review of PURPA contract terms and conditions is
necessary.

Congress enacted PURPA in response to a national energy crisis in the late 1970s with a goal to lessen the
nation’s dependence on foreign oil. “Unfortunately, PURPA does not address and FERC (Federal Energy
Regulatory Commission) regulations do not adequately provide for consideration of whether the utility being
forced to purchase QF power is actually in need of such energy,” the commission said.

Idaho Power’s 20-year Integrated Resource Plan does not indicate the utility is in need of more energy sources.
“And yet, in less than four months time, 13 QFs have contracted with Idaho Power for nearly 400 MW of solar
generation – all expected to be on-line and producing power by the end of 2016,” the commission said.
The developer will be paid a non-levelized avoided-cost rate over the 20-year term of the agreements, which
means payments increase over the course of the agreement and vary according to light-load and heavy-load
hours of the day and seasons of the year. The average levelized rate for these projects is about $61 per
megawatt-hour and the values of the six 20-year contracts range from $67.8 million to $243.8 million.
Idaho Public Utilities Commission

Page 25

Included in each contract is an integration charge the developer pays Idaho Power to cover the cost of
integrating the energy into Idaho Power’s transmission and distribution system. The integration cost increases
as the amount of solar generation on Idaho Power’s system increases. For these contracts, the charge ranges
from $2.01 per MWh to $4.60 per MWh in the first year of the contract and escalates through the end of the 20-
year term in 2036.

The agreements allow for a 2 percent deviation in estimated energy output before the price can be adjusted. A
consistent deviation from the hourly energy generation estimates would be considered a material breach of the
agreements. Also included is a “90/110” firmness requirement. If a project’s generation exceeds 110 percent of
estimated output, the developer is paid 85 percent of a market-based price for the generation above 110
percent of forecasted output. If the developer does not produce at least 90 percent of forecasted generation,
then all output is paid at 85 percent of the market price.
Revenue from the sales of Renewable Energy Certificates associated with the projects will be split 50-50
between the developer and Idaho Power.

Idaho Public Utilities Commission

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OTHER MAJOR ISSUES: TRANSMISSION SWAP, SECOND AREA CODE

PUC approves swap of transmission assets between Idaho Power, PacifiCorp

Case No. IPC-E-14-41, Case No. PAC-E-14-11, Order No. 33313

June 10, 2015 – The commission approved a $43 million transmission asset swap between Idaho Power
Company and PacifiCorp, which does business in eastern Idaho as Rocky Mountain Power.

In its order approving the transaction, the Idaho Public Utilities Commission said the swap, which will replace
outdated sharing agreements between the utilities, will better serve the utilities and their transmission and
retail customers.

Under the swap, Idaho Power and PacifiCorp will re-allocate ownership in each of three 345-kilovolt
transmission lines that transmit generation from Wyoming’s Jim Bridger coal-fired power plant to Idaho Power
customers across southern Idaho and to PacifiCorp customers in Oregon, Washington and California. The swap
would allocate to PacifiCorp two-thirds ownership in each line and Idaho Power one-third ownership. Currently,
PacifiCorp owns two of the three 345-kV lines and Idaho Power owns one. In addition, PacifiCorp would obtain
full ownership of two 230-kV lines and substation that connect the Bridger plant to Point of Rocks and Rock
Springs, Wyoming.

Because the transaction involves interstate transmission, it must also be approved by the Federal Energy
Regulatory Commission (FERC).

Idaho state statute requires that whenever a regulated utility buys or sells major generation or transmission
assets, the commission must find that the transaction is in the public interest, that costs and rates of existing
service are not increased as a result of the transaction and that new owners have the bona fide intent and
financial ability to operate and maintain the transferred assets.

The commission determined the asset swap meets all those conditions. Further, the commission said, the
increased operational flexibility resulting from the transaction will ensure more efficient management of
transmission system upgrades, facilitate expected load growth, and, ultimately, improve reliability for
customers.

Under the swap, PacifiCorp would be provided about 1,600 megawatts across Idaho Power’s system to move
energy from the Bridger plant to its Western service territory in Washington, Oregon and California. About 510
MW of that 1,600 MW would be firm transmission service that PacifiCorp will purchase under Idaho Power’s
Open Access Transmission Tariff. (The OATT is a tariff or rate that a utility or any transmission provider can
charge those seeking available capacity. To encourage a competitive wholesale electric market, the OATT must
be approved by FERC as cost-based and non-discriminatory to those who seeking access.)

Because the transaction is expected to result in greater transmission revenue to Idaho Power from PacifiCorp
and other transmission customers, the commission directed Idaho Power to establish a deferred account for
those revenues and annually report the amounts for possible later sharing with customers. PacifiCorp is also
expected to pay reduced transmission wheeling expense, which will also be tracked and reported for possible
Idaho Public Utilities Commission

Page 27
later benefit to customers. The Industrial Customers of Idaho Power urged the commission to wait until after the
FERC proceeding resolved. The commission said the conditions of the Idaho statute are met regardless of what
FERC may decide. ICIP also said transmission upgrades by Idaho Power resulting from the transaction may
increase Idaho Power’s retail rates. The commission said transmission upgrades are reviewed for prudency in
future rate cases.

Up until this agreement, Idaho Power and PacifiCorp operated under a series of “Legacy Agreements” -- dating
to as far back as 1969 -- regarding the construction, ownership and operation of the Bridger coal plant and its
associated transmission lines. The agreements were drafted before the advent of FERC’s open-access policies,
which allow access to the transmission grid for more transmission providers on a non-discriminatory basis. The
Legacy Agreements are outdated, inefficient and don’t recognize the changing load characteristics of each
utility, Idaho Power and PacifiCorp said.

Currently, 1400 MW of PacifiCorp’s east-to-west transfer rights are tied only to generation from the Bridger
plant. Under the new agreement, PacifiCorp would be able to make east-to-west transfers without restriction on
the source of energy, using a combination of transmission service rights over Idaho Power’s system and its own
newly owned assets. Further, Idaho Power’s ownership of the Three Mile Knoll to Goshen line south of Idaho
Falls limits PacifiCorp’s ability to reliably and cost-effectively respond to Goshen area customer load
requirements during certain outage scenarios.

PacifiCorp would also have access to 400 MW of “dynamic service,” a 200 MW increase. Dynamic transfers are
firm energy transfers that can be scheduled using a shortened time frame (within the hour) and for intervals as
briefly as four seconds. Dynamic transfers produce benefits for participants by more effectively stabilizing
electric load within the hour, increasing the pool of available energy services and reducing the cost of integrating
renewable energy into energy delivery.

Idaho Power would be provided capacity on various portions of PacifiCorp’s transmission system.

Further, Idaho Power claims the OATT paid it by PacifiCorp would more accurately reflect Idaho Power’s cost of
service, benefitting Idaho Power’s retail customers. Idaho Power claims that the transaction will reduce its
revenue requirement by $56 million over the next 10 years, due primarily to higher transmission revenues it will
get from transmission customers. Those revenues serve as a credit to retail customer rates.

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Idaho’s second area code – 986 – launches in late 2017
Case No. GNR-T-15-06, Order No. 33414

Nov. 2, 2015 – The commission approved a 16-month plan for Idaho’s second area code to be implemented in
late 2017. An hour after the Idaho Public Utilities Commission issued its order approving the plan, the agency
that contracts with the federal government to administer the nation’s area code numbering plan, Neustar,
issued Idaho’s second area code: 986.

The second area code will be issued only to new telephone numbers beginning in late 2017. Idaho is one of few
states that still has one area code, “208” issued in 1947.

The commission adopted the unanimous recommendation of Idaho’s telecommunications providers and
commission staff that the state implement an “all services overlay,” which assigns the new area code statewide
to new numbers. This option will ultimately require that all customers in Idaho dial 10 digits (area code, plus
prefix, plus four-digit number) beginning in late 2017.

A second option was to implement a “geographic split,” which would have assigned the new area code to all
numbers in one-half the state, requiring all customers assigned the new code to change their telephone
numbers. This option would have retained seven-digit dialing for calls within the same area code. About 27 of 41
written comments the commission received favored the split option, but none of the comments addressed
future trends that will eventually end seven-digit dialing.

“Neither option is ideal,” the commission said, but the overlay will not cause the same level of disruption and
expense as a geographic split would have forced on the half of the state required to change its numbers.
Furthermore, the commission said, developing technology “will eventually drive seven-digit dialing into
obsolescence in the future.” Implementation of a geographic split may serve only to prolong seven-digit dialing
for a short period, the commission said. “Thus, any future dialing change and relief planning will be eased by the
implementation of 10-digit dialing now rather than later.” Under the split, the commission said, businesses of all
sizes would have experienced significant disruptions. “Any goodwill of business identification associated with
existing phone numbers” would have been lost, the commission said, as businesses would be required to change
advertising, letterhead, web pages and business cards. “This is no small expense nor a minor nuisance,” the
commission said.

A commission staff investigation determined that every area code addition for the last eight years has been a
geographic overlay, rather than a split. In 2008, the West Virginia Public Service Commission reversed its original
decision when it found the geographic split created too much of an economic burden and that current
technology generally “alleviates most of the problems (associated) with 10-digit dialing.” Commission staff
noted that most telecommunications devices, even landline phones, have number storage capability that allows
customers to dial entire numbers with the press of one or two buttons.

Neustar has been informing the state that a second area code will be needed since its original forecasted
exhaust date of August 2001. In response, the commission implemented various numbers conservation plans
that have been successful in delaying a second area code by at least 15 years. However, the proliferation of
wireless telephones, new competitive telephone companies, paging and messaging services and Voice over
Internet Protocol (VoIP) is contributing to the increase in demand for new numbers, making further delay
impossible.
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The plan adopted by the commission initiates a 16-month transition and customer education process.
Telecommunications providers will begin customer education in about six months and commission staff will
conduct customer education workshops throughout the state beginning in spring of next year. A “permissive 7-
digit and 10-digit dialing period,” will begin at about the end of 2016. This nine-month period will allow
customers to begin 10-digit dialing even though seven-digit dialing will still work. Then, in the fourth quarter of
2017, mandatory 10-digit dialing begins.

Idaho Public Utilities Commission

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ELECTRICAL POWER IN IDAHO

Idaho Power Company
2014 Average Number of Customers/Avg. Revenue/kwh*
411,689 Residential Customers/$0.1007
79,248 Commercial Customers/$0.0769
111 Industrial Customers/$0.0564

Avista Utilities

2014 Average Number of Customers/Avg. Revenue/kwh*
108,571 Residential Customers/$0.0921
16,937 Commercial Customers/$0.0867
455 Industrial Customers/$0.0555

Rocky Mountain Power

2014 Average Number of Customers/Avg. Revenue/kwh*
PacifiCorp/Rocky Mountain Power
59,974 Residential Customers/$0.1102
8,246 Commercial Customers/$0.0886
5,534 Industrial Customers/$0.0613

*Computed from data available in FERC Form 1 Annual Reports dated June 30, 2015.
Idaho Public Utilities Commission

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ELECTRIC
Avista Rate Case

Proposed settlement significantly reduces Avista
rate electric, natural gas rate increase request

Case No. AVU-E-15-05, AVU-G-15-01, Order No. 33400

October 26, 2015 –Parties to an Avista Utilities rate case are proposing a
settlement that reduces the Spokane-based utility’s requested electric rate
increase from 10.3% over two years to 0.7% in one year and its requested
gas rate increase from 6.8% over two years to a one-year increase of 3.5%.
All parties to the case, including Avista, are asking the commission to
approve the settlement, with rates proposed change on Jan. 1. 2016.
Avista serves customers in northern Idaho.

While base electric and gas rates, which reflect Avista’s fixed costs, would
increase Jan. 1, 2016, under the proposed settlement, customers are
getting substantial reductions to the variable portion of their rates that
more than offset the base rate increases. On the electric side, the annual
Power Cost Adjustment reduced electric rates by 3.5% on Oct. 1. On the
gas side, the annual Purchases Gas Cost Adjustment will reduce gas rates
by 14.5% on Nov. 1. However, base rate changes are permanent, while the
variable PGA and PCA adjustments either increase or decrease rates yearly.

On June 1, Avista filed an application to increase electric rates by 5.2% in
2016 and 5.1% in 2017 and natural gas rates by 4.5% in 2016 and 2.2% in
2017. Under the original proposal, Avista’s annual increase in revenue
would have been $13.2 million on the electric side. The proposed
settlement reduces that to $1.7 million. Annual gas revenues would have
increased by $3.2, with the settlement proposing $2.5 million.

Parties signing the settlement include Avista, commission staff, the Idaho
Conservation League, Snake River Alliance, Clearwater Paper Corporation,
Idaho Forest Group LLC and the Community Action Partnership Association
of Idaho, which represents primarily customers on low- and fixed-incomes.

While the settlement proposes reductions to Avista’s annual revenue
requirement, it does allow Avista to establish an annual rate adjustment
called the Fixed Cost Adjustment (FCA). The FCA will allow the company to
recover fixed costs of doing business when electricity or natural gas sales
decline due to changes in conservation, weather or the economy. The
mechanism removes the disincentive for the company to invest in and
promote energy efficiency programs.

Under the FCA, the company’s natural gas and electric revenues would be
adjusted monthly to reflect revenues based on the number of customers
rather than kilowatt-hour and therm sales. The yearly adjustment will be
either a surcharge or rebate to customers. The FCA would have an initial
term of three years and will be reviewed to determine whether the
adjustment should continue.

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Under the FCA, the company’s natural gas and electric revenues would be adjusted monthly to reflect revenues
based on the number of customers rather than kilowatt-hour and therm sales. The yearly adjustment will be
either a surcharge or rebate to customers. The FCA would have an initial term of three years and will be
reviewed to determine whether the adjustment should continue.

These are some of the major revenue reductions from Avista’s original request proposed by the settlement:

 Leaving expense related to the Palouse Wind Project in the annual Power Cost Adjustment mechanism
rather than shifting it to base rates, reducing annual base rate revenue requirement by $3.5 million.

 Shifting expense related to an upgrade of the Nine Mile Hydroelectric project from 2015 to 2016,
reducing revenue requirement by $3.34 million.

 Establishing a 9.5% Return on Equity, rather than the 9.9% proposed by Avista, reducing annual revenue
requirement by $2.44 million.

 Spreading the cost of Avista’s new customer information and billing service called Project Compass over
four years rather than two years, reducing revenue requirement by $669,000.

 Reducing various capital additions that bring revenue requirement down by $548,000.

 Removing projected 2016 expense related to information services and technology to reduce revenue
requirement by $521,000.

 Removing 2016 non-executive labor expense to reduce revenue requirement by $385,000 and removing
incentives this year for company officers to reduce annual revenue requirement by $100,000.

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Avista will award grants for commercial
solar applications

Case No. AVU-E-14-10, Order No. 33218

February 4, 2015 – The commission approved an Avista Utilities
application to award grants for rooftop solar applications on small
commercial buildings in its northern Idaho territory.

Avista has a $200,000 surplus in its “Buck-a-Block” renewable energy tariff
that will accrue an additional $150,000 to $200,000 by the end of 2016.
“Buck-a-Block,” in place since 2002, allows Avista customers who want to
buy renewable power from regional wind and solar sources to buy in
blocks of 300 kilowatt-hours at $1 per block.

During 2013, about 3,500 Avista customers in Washington and northern
Idaho purchased nearly 227,000 blocks or 68,000 megawatt-hours.
However, due to the availability of low-cost renewable energy credits in
recent years and a plateau in the number of Avista customers signing up
for the program, there is a surplus of about $200,000 in the Buck-a-Block
tariff.

Avista proposed to use that surplus to award grants for rooftop solar
installations of 20 kilowatts or smaller on commercial buildings. Successful
grant recipients would agree to allow their installation to be made
available for educating building occupants and members of the community
on the benefits of both solar energy generation and Avista’s Buck-a-Block
program. Preference would be given to school buildings and other public
buildings where the visibility of the installation will have the greatest
impact for both educational purposes and solar energy generation.

Commission staff reviewed the proposal to determine its impact on Buck-
A-Block participants and on other ratepayers. Staff expressed concern
about uncollected fixed costs from program participants that would be
shifted to other customers.

However, staff determined that the level of uncollected fixed costs
associated with this program is so low that it will have little impact on
customer rates. Staff recommended that the commission monitor the
growth of the program.

Staff was also concerned that a disproportionate amount of the surplus
funds would go to Washington customers of Avista because the cost of
solar panels is as much as three times higher in that state than in other
places.

To address that concern, the commission determined that Avista manage
and disburse the funds in proportion to what it collects from participating
customers in the utility’s Washington (77.6%) and Idaho (22.4%)
jurisdictions.

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Page 34

Avista expenses determined prudent;
utility exceeds electric, gas conservation goals

Case No. AVU-E-14-07 and AVU-G-14-02, Order No. 33126

Jan. 30, 2015 – The commission determined that $7.7 million Avista Utilities
spent on electric and natural gas efficiency programs during 2013 was
prudently incurred.

Money spent on electric and gas conservation programs must be shown to be
prudently incurred in order to be funded by the Energy Efficiency Rider paid by
Avista’s customers. Residential customers currently pay 0.245 cents per
kilowatt-hour for the programs. The commission’s prudency review does not
impact rates.

All three of Idaho’s major investor-owned utilities have “efficiency riders” that
pay for programs to incent either the efficient use of electricity or reduce
demand on a utility’s generation system. The programs must pass multiple
cost efficiency tests that demonstrate that the savings realized are greater
than the programs’ costs. Further, the programs must benefit all customers,
not just those who participate in them.

Avista claims it energy efficiency savings for 2013 were 25,899 megawatt-
hours, well over its target of 19,009 MWh. Reduced demand on its system is
122 average megawatts. Company-sponsored conservation is reducing retail
loads by 10.6%, Avista claims. This is the fourth consecutive year Avista
exceeded its Conservation Potential Assessment for electric savings. Its gas
savings are 51,722 terms.

Commission staff conducted a review of Avista’s programs and expenditures.
The commission commended Avista for exceeding its goals. “The commission
urges the company to continue this favorable trend and even improve upon its
commitment to the implementation of cost-effective demand-side
management programs,” the commission said.
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Avista PCA results in 3.5% reduction for electric customers

Case No. AVU-E-15-07

October 5, 2015 – The variable portion of Avista Utilities’ electric rates decreased by an average 3.5 percent
effective October 1.

Avista electric rates are adjusted up or down every year on Oct. 1 depending on the previous year’s weather and
market conditions and other variable factors. Because variable rate impacts cannot be predicted, rates are
adjusted annually through the Power Cost Adjustment (PCA) mechanism to match what customers paid in the
PCA account with actual expense.

Avista’s variable power supply costs decreased by about $1.2 million from July 1, 2014, through June 30, 2015.
Most of that – $820,000 – came from lower payments owed to Clearwater Paper, which owns a cogeneration
plant that sells power to Avista. Another $400,000 credited customers is the result of a settlement between
electric utilities and the Bonneville Power Administration.

With the Oct. 1 adjustment, the PCA changes from a surcharge of 0.252 cents per kilowatt-hour to a rebate of
0.032 cents per kWh. For a residential customer who uses the company’s average of 929 kWh per month, the
reduction is about $2.64 per month.

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Page 36

Result of two annual rate adjustments is net
decrease for Idaho Power customers

Case No. IPC-E-15-05, Order No. 33302; Case No. IPC-E-15-14, Order No.
33306

May 28, 2015 – Rates for residential customers of Idaho Power Company decrease slightly on June 1 due to
annual updates of two rate adjustments approved by the Idaho Public Utilities Commission.

The annual Fixed Cost Adjustment (FCA) increases rates by 0.35 percent, but that is offset by a slightly more than
1 percent decrease in the annual Power Cost Adjustment (PCA). The FCA increase is about 36 cents per month
for a residential customer who uses the customer average of 1,050 kilowatt-hours per month. The PCA decrease
is about 58 cents per month for a residential customer.

Power Cost Adjustment
Since 1993, the PCA mechanism allows Idaho Power to adjust rates up or down to reflect that portion of costs
that change every year due to factors largely beyond the company’s control. Because about half of Idaho
Power’s generation is from hydroelectric facilities, Idaho Power’s actual cost of providing electricity varies
depending on changes in Snake River streamflows. Other costs that vary each year are the market price of
power, fuel costs, transmission costs for purchased power and the revenue it earns from selling surplus power.

Idaho Power’s forecasted net power supply expense is $384.4 million, $42.7 million higher than the $305.7
million of power supply expense already included in base rates, necessitating a surcharge. However, the total
amount of power supply expense above base rates is lower than that collected in last year’s PCA resulting in a
smaller-sized surcharge and, thus, a slight reduction to customers.

Actual hydro generation (3.4 million acre-feet) is about 7 percent lower than forecast (3.6 million acre-feet.) Less
hydro generation forces the company to use more expensive generation sources, driving up power supply
expense. That expense is reduced by Idaho Power’s sale of surplus power on the market, but revenue from off-
system sales continues to decline. Because of lower prices on the wholesale energy market, Idaho Power is
forecasting only $39 million in sales, down from the $51.7 million included in base rates. However, the loss in
off-system sales is somewhat offset by lower priced purchases from the market and reductions in coal and gas
production costs.

The PCA rate effective June 1 will be about 0.53 cents per kilowatt-hour, less than the current rate of 0.73 cents
per kWh. (The approximate one-half cent per kWh PCA rate is a relatively small component of overall rates. A
customer who uses the company’s average of 1050 kWh per month now pays an energy rate of about 8.2 cents
per kWh during the non-summer months and 9 cents during the summer months.)

To mitigate the surcharge even further, Idaho Power proposed to apply $8 million in revenue sharing to
customers and to credit customers $4 million in additional energy efficiency rider funds collected last year.

As part of a settlement to a 2011 base rate case, the company agreed to share revenue with customers if it
exceeded a 10 percent Return on Equity. Any earnings greater than 10 percent ROE up to and including 10.5
percent would be split 50-50 with customers to be applied against the PCA. Earnings above 10.5 percent will be

Idaho Public Utilities Commission

Page 37
shared 75 percent with customers and 25 percent for the company. Those earnings are applied against what
customers would otherwise be paying to fund the company’s pension balancing account.

Idaho Power’s 2014 year-end ROE was 11.19 percent, meaning customers will receive a benefit of $24.7 million.
About $8 million is applied as a rate credit passed through the PCA, while the remaining $16.7 million is used to
offset the pension balancing account.

The FCA is designed to ensure Idaho Power recovers its fixed costs of delivering energy even when energy sales
and revenue decline due to reduced consumption. Before the FCA, Idaho Power had a financial disincentive to
invest in energy efficiency programs because it lost revenue as consumption declined. Even though consumption
may decline, fixed costs to serve customers do not. To remove that disincentive, the Fixed Cost Adjustment was
created to allow the utility to recoup its fixed costs.

If actual fixed costs recovered from customers are less than the fixed costs authorized in the most recent rate
case, residential and small-commercial customers get a surcharge. If the company collects more in fixed costs
than authorized by the commission, customers get a credit.

During 2014, Idaho Power under-collected fixed costs of serving customers by $16.88 million. About $14.9
million of that is already collected in the FCA. To recover the additional $1.96 million, the commission approved
an increase the Fixed Cost Adjustment from 0.29 cents per kWh to 0.326 cents per kWh for residential
customers and from 0.37 cents per kWh to 0.41 cents per kWh for small commercial customers. In a separate
case, the commission adopted a settlement to a docket opened last year to evaluate the effectiveness of the
FCA.

Beginning this year, Idaho Power will modify the way it calculates the FCA deferral by replacing an average of
weather-normalized billed sales with actual billed sales.

Parties to the settlement also agreed to further clarify how a 3% cap on annual FCA increases should be
calculated. All parties agreed that without the FCA, current rate design creates a financial disincentive for Idaho
Power to pursue cost-effective energy efficiency. However, they also stated that the commission could pursue a
modified rate design for residential and small commercial customers to address this issue, in lieu of an FCA
mechanism. Possible rate design changes could include reduced energy charges but higher monthly
service charges or the introduction of demand charges.

IPUC approves Idaho Power agreement to continue participation in regional
conservation effort

Case No. IPC-E-14-38, Order No. 33210

Jan. 21, 2015 – The Commission approved an Idaho Power Company proposal to invest $13.45 million in energy
efficiency programs operated by the Northwest Energy Efficiency Alliance (NEEA), but agreed with commission
staff findings that the utility is not doing enough to make customers aware of energy efficiency programs.

The $13.45 million investment by Idaho Power covers five years, from 2015-19, and is down from the $16.5
million the utility invested in NEEA during 2010-14.

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NEEA is a non-profit organization that seeks to maximize energy efficiency in four Northwest states through the
adoption of energy efficient products, services and practices. NEEA is funded by the Energy Trust of Oregon, the
Bonneville Power Administration and by electric utilities in Washington, Oregon, Idaho and Montana. Idaho
Power’s investment represents about 9 percent of NEEA’s total budget.

From 1997-2014, NEEA delivered 1,024 average megawatts of regional energy savings. Idaho Power’s portion of
NEEA-related savings during the same period was 28.2 aMW.

Idaho Power had notified NEEA that once the 2010-14 funding cycle ended, its participation would end. Idaho
Power claimed the NEEA funding model duplicated services that it could perform on its own at a lower cost or
more effectively.

Since then, however, NEEA and Idaho Power reached an agreement that allows Idaho Power to opt out of some
NEEA programs that Idaho Power said were duplicative or did not directly benefit customers, while still
participating in others.

The 2015-19 plan agreed upon by Idaho Power and NEEA is customized to better meet its customers’ needs,
Idaho Power said. The plan includes funding for continued research at the University of Idaho Integrated Design
Lab and market transformation efforts aimed at acquiring energy efficient lighting, appliances and building
materials in the residential, commercial and industrial sectors.

Of the four optional NEEA programs, Idaho Power chose to participate in only one, a program that targets
commercial lighting contractors, training resources and utility programs to accelerate market adoption of
advanced lighting practices.

The company chose to opt out of NEEA’s Marketing and Stakeholder Support program which, commission staff
said, “leaves Idaho Power responsible for creating all marketing, such as website development, press releases,
consumer awareness campaigns” and other promotions. The commission said it expects Idaho Power to bolster
its marketing and customer awareness by using savings from its decreased investment in NEEA.

The agreement does not change customer rates because Idaho Power’s investment in NEEA energy efficiency
programs is funded by a portion of the Energy Efficiency Rider on customer bills, currently set at 4% of a
customer’s monthly billed amount. However, before investment can be included in the rider, the commission
will conduct a prudency review of the programs after the 2015-19 funding cycle to ensure “customers received a
sufficient benefit,” from Idaho Power’s participation. Further, Idaho Power and NEEA’s agreement holds NEEA
accountable for delivering on its projected energy savings. Under the agreement, NEEA will hire an independent
CPA firm to complete an annual financial audit and internal control review.

NEEA’s business plan for the entire region is to deliver 145 aMW of energy savings in the four states from 2015-
19, with a planned expenditure of between $145 million and $169 million. The total resource cost for NEEA
programs is equal to are less than 3.5 cents per kilowatt-hour, considerably less than energy from most other
sources

Idaho Public Utilities Commission

Page 39
Commission OKs Idaho Power proposal to operate its own demand
response program

Case No. IPC-E-15-03, Order No. 33292

May 13, 2015 – The Commission agreed to allow Idaho Power Company to operate its own energy demand
reduction program for its large commercial and industrial customers.

Idaho Power maintains it can operate a program at less cost and with better or equal results than has the third-
party vendor that has been operating the program since 2009. The “Flex Peak” program, previously operated by
EnerNoc Inc., provided financial incentive to large commercial and industrial customers to curtail their energy
use during peak-use hours of the summer months.

The Commission granted Idaho Power authority to operate its own program beginning this summer. “The
commission strongly supports the use of commercial and industrial demand-response programs,” the
commission said. “And while EnerNoc’s program was robust and cost-effective, customers will benefit if the
company (Idaho Power) can deliver similarly reliable demand response at the same or less cost.”

Now is a good time to let Idaho Power try its own program since the utility is not anticipating capacity deficits
for the next few years, the commission said.

Under Idaho Power’s program, the utility will call at least three “dispatch events” between June 15 and August
15, notifying volunteer customers on or about two hours in advance that they will need to reduce or curtail their
energy use. The dispatch events will be during peak-use hours when demand on Idaho Power’s system is the
greatest. Those hours are typically between 2 p.m. and 8 p.m. on weekdays, excluding holidays. Each dispatch
event will last between two and four hours, but no more than 15 hours per week or 60 hours per summer
season. Idaho Power proposes to provide incentive payments to customers who agree to participate. The utility
says operating Flex Peak internally will cost from $1.1 million up to $1.4 million if the entire 35 megawatts of
potential savings were dispatched for the maximum allowed 60 hours. Costs under the EnerNoc program were
about $2 million.

Idaho Power said savings from internal operation of Flex Peak will be passed directly to customers. Further, all
customers benefit when Idaho Power does not have to buy or generate as much power from other more costly
sources during peak-use hours when power is the most expensive.

The commission noted the concerns expressed by commission staff, the Industrial Customers of Idaho Power
and the Idaho Conservation League about Idaho Power operating its own program. Consequently, it directed
Idaho Power to file a report within one year detailing its experience running the program, cost-and-benefit
comparisons to those achieved under EnerNoc, participant performance and any proposed changes to further
improve the program. The company will also file an annual end-of-season report that will specify, among other
items, number of participants, number of megawatts of demand response achieved and a detailed cost analysis.

Idaho Power also offers demand-response programs to residential and irrigation customers. According to Idaho
Power, the cost of operating all its demand response programs in 2014 was $10.6 million, but the value accrued
to the company and its customers as a result of the reduced demand was $16.7 million. Idaho Power plans at
least 390 MWs of demand reduction from all its programs during 2015.
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Idaho Power, Simplot contract is approved

Case No. IPC-E-15-13, Order No. 33303

May 22, 2015 – The Commission approved an Idaho Power Company special contract with J.R. Simplot
Company’s new Caldwell plant.

Until recently, the Caldwell plant was under a tariff rate (rather than a special contract) for Large Power Service
customers. But Simplot’s new Caldwell plant, which replaces Simplot facilities in Aberdeen, Nampa and Caldwell,
is anticipated to exceed the maximum amount of demand – 20,000 kilowatts – that qualifies for the Large Power
Service rate. Customers with demand larger than 20,000 kW must negotiate a special contract with the utility.

Idaho Power and Simplot have been negotiating a proposed contract since spring 2013. In late 2013, Idaho
Power asked the commission to resolve some contract issues where the parties had reached an impasse. Those
issues included liability provisions and Simplot’s contention that Idaho Power was using an outdated formula to
determine Simplot’s rate.

The commission directed the parties to renegotiate the liability provisions and said a rate could be determined
by using Idaho Power’s most recent cost-of-service study as a starting point for negotiation. The company
agreed to do so and the parties reached agreement. “We appreciate the parties’ efforts in reaching an
agreement consistent with guidance provided by the commission,” the commission said.

The contract, which becomes effective June 1, requires Idaho Power to initially provide 25,000 kW per month.
During the first year of the contract, Simplot may increase or decrease its contract demand so long as the
changes for the year collectively do not exceed 10,000 kW, absent company agreement. After one year, Simplot
may increase or decrease its monthly contract demand in 1,000 kW increments so long as it does not change
contract demand by more than 15,000 kW in any 12-month period.

Rates for special contract customers must take into account Idaho Power’s existing operational conditions and
the impact new load may have on the utility’s generation and transmission system. Because the new Caldwell
facility consolidates load previously used at the Aberdeen, Nampa and old Caldwell facilities, the contract rates
will recover the cost it incurs to serve Simplot while also limiting upward rate pressure on other customer
classes.

Commission OKs Idaho Power efficiency program expense

Case No. IPC-E-15-06, Order No. 33365

August 31, 2015 – The Commission determined that Idaho Power Company’s $33.5 million investment in energy
efficiency and demand-response programs during 2014 was prudently incurred. The determination does not
impact rates.

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The efficiency programs are funded through a 4 percent Energy Efficiency Rider that appears on customer bills.
The demand-response programs are included in the annual Power Cost Adjustment (PCA), listed on bills as the
Annual Adjustment Mechanism.

Idaho Power’s energy savings rebounded significantly in 2014, surpassing 2013 numbers by 33 percent, more
than exceeding the company’s target. Idaho Power offers 18 energy efficiency programs and three demand
reduction programs. (An energy-efficiency program is one in which less energy is used to perform the same
function. A demand-reduction program is one that shifts consumption to non-peak times of the day, reducing
demand on a utility’s generation system.)

About $25.5 million of the total $33.5 million investment is related to energy efficiency and is recovered through
the 4 percent rider. The remaining $8 million includes demand reduction incentive payments to program
participants and is recovered through the PCA.

Energy efficiency programs resulted in 118,670 megawatt-hours of savings. That doesn’t include savings realized
from Idaho Power’s participation in the Northwest Energy Efficiency Alliance’s market transformation initiatives.
That resulted in another 20,000 MWh saved in Idaho Power’s service territory.

The company rolled out several new programs in 2014 including a Home Energy Audits marketing and education
program and the distribution of residential clothes lines. It also expanded its successful Shade Tree program.
Other energy efficiency programs include offering rebates to customers for using heating and cooling
efficiencies and energy-efficient lighting and appliances. Demand reduction programs provide financial
incentives to residential air conditioning, large commercial and industrial customers and irrigators to shift or
curtail consumption to off-peak periods. These programs reduced demand by 378 megawatts, saving customers
about $6.5 million. All the programs must pass cost-effectiveness tests to ensure that their cost does not exceed
the benefit to customers.
In other issues related to the case:

 The Industrial Customers of Idaho Power expressed concern about a $9.8 million surplus in the Energy
Efficiency Rider account that could grow to $15 million by the end of this year. The Snake River Alliance
argued that reducing the 4 percent rider now as a response to the surplus would be premature because
room exists to improve and expand existing DSM programs. The commission declined to reduce the
rider at this time, but asked that all parties continue to monitor and rider balance and apprise it of
positive or negative trends. The funds in the rider account cannot be used for any other purpose than
expense related to energy efficiency and demand-side reduction.

 The commission encouraged Idaho Power to ensure that documentation requirements for customers
who sign up for the programs not become so burdensome that they discourage participation.

 Both commission staff and the Idaho Conservation League said Idaho Power should be counting the
including reduced transmission and distribution investment when it calculates the benefits of its DSM
program. Idaho Power claims its investigation into that issue is ongoing.

Commission staff commended the company for improving its DSM marketing efforts through television, radio,
Facebook and Pandora advertising and other means. Staff said Idaho Power should further improve its
marketing by creating a branded campaign similar to those offered by Avista and Rocky Mountain Power.
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However, the commission said Idaho Power exceeded its targets and, therefore, did not direct the company to
incur additional marketing costs.

Commission approves one-year energy sales agreement between Idaho
Power and Simplot’s Pocatello plant

Case No. IPC-E-15-02, Order No. 33240

March 4, 2015 – State regulators approved an Idaho Power Company sales agreement with a J.R. Simplot
company-owned cogeneration project at Simplot’s Pocatello plant.

Cogeneration (also known as “combined heat and power” or CHP) produces power from the heat or steam that
is the byproduct of a manufacturing process. The cogeneration plant at Simplot’s fertilizer plant near Pocatello
can produce up to 15.9 megawatts of electricity, but the contact is for 10 average megawatts per month.

The cogeneration plant is a qualifying facility under the provisions of the federal Public Utility Regulatory Policies
Act of 1978. PURPA requires regulated utilities to buy energy from qualifying renewable generation projects at
rates established by state commissions. The rate to be paid qualifying facilities is called an “avoided-cost rate,”
because it is based on the cost the utility avoids by not having to generate the energy itself or buy it from
another source. The commission must ensure the avoided-cost rate is reasonable for utility customers because
the price utilities pay to qualifying small-power producers is included in customer rates.

The Commission approved the company’s proposed a rate of $52.72 per megawatt-hour to be paid Simplot
during 2015 and $52.28 per MWh in 2016. The rate varies according to heavier and lighter load hours of the day
and seasons of the year. The agreement is for one year.
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Parties propose settlement to Rocky Mountain
Energy Cost Adjustment Mechanism
Proposed settlement avoids base rate case filing

Case No. PAC-E-15-09

Oct. 28, 2015 – Staff to the Idaho Public Utilities Commission, Rocky Mountain Power and other parties are
proposing a settlement to a Rocky Mountain company request to transfer some variable power supply expense
into permanent base rates. The settlement had not been approved by the time this report was prepared.

The proposed settlement would increase base rates about 3.9% in 2016, but customers would notice a reduction
of near the same size when the company files its annual Energy Cost Adjustment Mechanism (ECAM) to be
effective in 2017.

The settlement replaces a base rate case the company would have filed this year and also includes a stay-out
provision that prevents another base rate increase until Jan 1, 2018 at the earliest.

Under the proposed settlement, a residential customer who uses the average 801 kilowatt-hours per month
would pay about $2.35 more each month. Rocky Mountain Power serves customers in eastern Idaho.

There are two primary components of customer rates. The base rate covers fixed costs that rarely change from
year to year, while the ECAM includes expenses that vary each year depending on weather, fuel costs and
wholesale market prices. If variable expense is less than that already included in rates, customers receive a
credit. If variable expenses are greater than that already included in rates, customers are assessed a one-year
surcharge.

The settlement proposes to shift $10.2 million of expense currently collected through the ECAM into base rates.
About $6.5 million of that expense is related to revenue the company no longer receives from the trading of
Renewable Energy Certificates (RECs). However, customers will be credited about that same amount when the
company files its ECAM in 2017. Another $3.2 million is power supply expense for generation fuel and
buying/selling power.

The settlement also changes the way the yearly ECAM is calculated, measuring it on a dollar-per-megawatt hour
basis using load at the meter rather than load at the generator.

Rocky Mountain’s annual power supply costs increase, resulting in 1.8%
increase to most customers

Case No. PAC-E-15-01, Order No. 33265

April 2, 2015 – Rates for most customers of Rocky Mountain Power will increase by an average of 1.8% as a
result of the utility’s annual Energy Cost Adjustment Mechanism (ECAM). Rocky Mountain Power serves about
73,000 customers in eastern Idaho. According to the company’s calculations, the increase for an average
residential customer is about $1.70 per month. Rates for the company’s two large industrial customers,
Monsanto and Agrium, Inc., increase by about 8 percent.

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The ECAM, which takes effect every April 1, accounts for the difference between the utility’s actual power
supply costs, which vary from year to year, and the amount of power supply costs already included in customer
rates.

Most of the expense an electric utility incurs to provide power supply to its customers is included in base rates.
However, the expense required to provide power to customers varies each year due to a number of factors
including wholesale market prices for electricity and natural gas, transportation expense and expiration of older,
lower-price contracts with energy suppliers.

Because these variable expenses can never be precisely forecast, the ECAM allows Rocky Mountain Power to
make a one-year adjustment every April 1 to capture the difference between actual expense and that included
in base rates. The adjustment is a one-year increase to customers if power supply costs are higher than the
amount already included in base rates or a one-year decrease if power supply costs are lower. Since the ECAM
went into effect in 2010, there have been two increases, one decrease and two years of no change in rates.

Rocky Mountain Power’s earnings are not impacted by the ECAM because all the money collected from the
ECAM must go directly to pay power supply expense and cannot be used for any other purpose such as
increased salaries or dividends to shareholders.

Commission staff audited the company’s books and reviewed internal work papers, invoices and contracts.
Staff’s audit recommended a $240,725 reduction to Rocky Mountain’s total ECAM recovery request of about
$23.3 million. The $23.3 million is about $10.7 million more than that already collected in the ECAM account.
About $12.7 million and $1 million of that will be collected from Monsanto and Agrium Inc.

The biggest drivers increasing Rocky Mountain Power’s power supply costs were decreased revenue from the
company’s energy sales into the wholesale energy market and increased expense to fuel its coal plants. Sales
from energy Rocky Mountain sold to other companies decreased 42 percent while, at the same time, prices for
power purchased by the company from the market were 7 percent higher than the amount included in base
rates.

Coal fuel expense increased by 16 percent, which appeared to be driven by higher coal mining costs combined
with an increase in the price for the coal the company buys.

The Lake Side 2 combined cycle combustion turbine natural gas plant in Vineyard, Utah, began commercial
operation in May 2014 and is included as part of the ECAM until the company files its next rate case. At that
time the commission will determine if the new plant is to be included in permanent base rates.

To encourage the company to be prudent in its power supply expenditures, the commission requires that
shareholders pay 10 percent of ECAM expense.

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Commission finds Rocky Mountain Power investment in demand-side
management program is prudently incurred

Case No. PAC-E-14-07, Order No. 33188

Dec. 19, 2014 – About $25.76 million of Rocky Mountain Power company investment in demand-side
management (DSM) programs during 2010-13 was prudently incurred and beneficial to both the company and
its southeast Idaho customers, state regulators determined. The commission’s finding does not impact customer
rates.

DSM refers to programs that encourage customers to use less energy or shift use away from peak hours, thus
reducing demand on Rocky Mountain’s generation system. Customers pay for most of the programs through a
rider that appears on customer bills called “Customer Efficiency Services.” The rider is currently set at 2.1% of a
customer’s monthly billed amount. Investment in an irrigation load control program (about $8.1 million of the
total $25.76 million) has been shifted to recovery through base rates rather than through the rider.
The commission’s prudency review is to determine if the funds invested in the programs are reasonable and
beneficial to customers, including customers who do not directly participate in the programs.

The programs, directed toward residential, commercial, industrial and irrigation customers, saved the utility
11,963 megawatt hours in 2010; 8,688 MWh in 2011; 11,420 MWh in 2012 and 18,324 MWh during 2013. That
reduced consumption lowers power supply expense for all customers and eliminates or delays the need to build
new generating facilities.

Commission staff audited the company’s internal controls and processes and interviewed DSM program
managers. Staff said Rocky Mountain has “rigorous internal controls” to help ensure precise allocation of the
costs and benefits within each DSM program. The staff noted that in 2012 and 2013 the company surpassed its
Conservation Potential Assessment and that in all years except 2010 exceeded its energy savings goals as
outlined in its long-range Integrated Resource Plan.

Rocky Mountain Power offers three programs to residential customers. “Home Energy Saver” provides products
and services such as attic insulation and floor insulation, energy efficient windows, CFL lighting and other
services. “Refrigerator Recycling” offers rebates for removal and recycling of inefficient refrigerators and
freezers. “Low-Income Weatherization” provides energy efficiency services to residential customers meeting
income guidelines. Three other programs targeted commercial, industrial and agricultural customers.
“FinAnswer Express” helped commercial and industrial customers improve the efficiency of their lighting, HVAC,
electric motors, building envelopes and other equipment. “Energy FinAnswer” was available to commercial and
industrial customers in excess of 20,000 square-feet and included incentives for improvements to HVAC
systems, motors, refrigeration, lighting and other equipment. “Agricultural Energy Services” was designed to
improve overall efficiency of irrigation systems. (In a separate case, these programs were consolidated into a
single program to be marketed as “wattsmart Business.” All three were merged effective Nov. 1, 2014, under one
tariff called Non-Residential Energy Efficiency, Schedule 140.)

Only two of the programs did not pass cost-effectiveness tests. The portion of the Agricultural Energy Services
program that offered irrigation customers a nozzle exchange as well as measures to make pivot and linear
equipment more efficient has been discontinued. The Low-Income Weatherization program, while not yet cost-
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effective, will be continued while the company works with the commission and southeast Idaho community
action agencies to increase participation.

The commission staff found that many of Rocky Mountain’s industrial and commercial customers are not aware
of the energy efficiency programs available to them. The commission directed the company to work more
closely with staff to develop a more structured advertising method targeting non-residential customers.

Commission approves accounting treatment related to closure of Utah’s
Deer Creek mine

Case No. PAC-E-14-10, Order No. 33304

June 2, 2015 – The Commission approved an application by Rocky Mountain Power to set aside expenses related
to the utility’s decision to close a Utah coal mine for possible later recovery from customers.

The Deer Creek Mine near Huntington, Utah, is operated by Energy West Mining Company, a wholly-owned
subsidiary of PacifiCorp, which does business in eastern Idaho as Rocky Mountain. The utility is seeking authority
from the six states where it has customers to 1) incur costs for closing the mine; 2) withdraw from a contract it
has with the United Mine Workers of American Pension Trust, which will incur a withdrawal liability; 3) sell the
assets it has in the mine and; 4) enter into an agreements with Kentucky-based Bowie Resource Partners to
provide replacement coal for the Huntington and Hunter plants in Utah that had been previously provided coal
from the Deer Creek mine. Bowie trucks in coal to the Huntington plant from its mines in Utah’s Carbon and
Sevier counties.

The Idaho commission is required by state statute to approve any sale or purchase of property owned or to be
owned by a utility it regulates. The commission is to determine whether the transaction is in the public interest,
that rates will not be impacted and that a potential buyer has the bona fide intent and financial ability to
operate and maintain the property in the public service.

The commission said the proposed sale is in the public interest because it mitigates the company’s potential
exposure to increasing pension and medical obligations to the mine’s 182 employees and that the resulting cost
for supplying electric service will be less going forward than it would have been without the transaction.

However, the commission denied the company’s request to recover carrying charges before the next rate case.
The commission also did not approve the company earning a return on expenses related to the mine’s closure.
Instead, the commission agreed to grant the company an accounting order that will allow it to defer costs
related to the transaction for review by the commission after the company files its next rate case. A return on
deferral during recovery may also be argued in the next rate case.

Included in the deferred account can be Idaho’s portion (about 6 percent) of any loss on the sale of assets,
construction work in process, closure costs and costs related to a retirees’ medical obligation settlement. The
commission denied the company’s request to include carrying charges or a return on those costs because the
plant is no longer “used and useful” to customers. Rocky Mountain said not allowing carrying charges and a
return penalizes the company for a decision that benefits customers and puts the company in a position of
financing the benefits of the transaction for customers over time. That ratemaking treatment limits the
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company’s ability to fully recover costs and could dissuade utilities from undertaking similar actions in the
future, Rocky Mountain Power said.

The commission said it “was not persuaded by Rocky Mountain’s assertion that approval of a carrying charge is
necessary to incentivize well-reasoned and cost-effective business decisions ...” Utilities should not to be
“incentivized to act rationally in order to limit their losses,” the commission said. Further, the commission said,
delaying recovery of deferred items until after a rate case is filed “will enable the commission to fulfill its
statutory duty to scrutinize and evaluate the actual costs of the transaction prior to making its decision
regarding a reasonable return for those costs.”

The PacifiCorp Idaho Industrial Customers and Monsanto opposed the application, stating it is too early to
determine actual costs related to the closure until after a rate case is filed.

The mine, purchased in 1977, produces an average 3.5 million tons of coal annually. The mine had been the
primary source of coal for the Huntington Power Plant in east-central Utah, which annually consumes about 2.9
million tons. It also supplied some coal to the Hunter Power Plant. The mine’s depreciable life runs through
2019.

The mine’s employees were represented by the United Mine Workers of America. Rocky Mountain said Energy
West’s health care costs and contributions to the pension trust were sharply increasing. Under the most recent
labor settlement, Energy West was responsible for almost 100 percent of the health care costs, with employees
paying a minimal co-payment and no premium cost-sharing. The deficit between the market value of the
pension trust’s assets and the present value of the vested benefits is about $5.5 billion.

In addition to labor issues, the mine is producing lower quality coal as it ages, which, in turn, reduces the volume
of coal produced. As Energy West sought to develop additional areas of the mine’s reserves, it discovered
significant volumes of high-ash, high-sulfur coal, meaning much of it had to be transferred to a preparation plant
nearby to be blended with lower-ash coals to meet coal quality specifications. More coal is available on the
market, making it less advantageous to own coal mining assets, Rocky Mountain claimed.

PUC accepts Rocky Mountain Power long-range plan to reduce reliance on
coal-fired generation

Case No. PAC-E-15-04, Order No. 33396

October 19, 2015 – The Commission accepted a long-range planning document filed by Rocky Mountain Power
that spells out how the electric utility intends to meet future load growth. Rocky Mountain Power serves
customers in eastern Idaho and much of Utah and Wyoming.

Acceptance of the Integrated Resource Plan, required by the commission to be filed every two years, does not
mean the commission endorses all components of the plan, but acknowledges the utility meets the
requirements for a long-range plan. “It is the ongoing planning process that we acknowledge,” the commission
said. Rocky Mountain Power intends to meet most of its growth in energy demand through an expansion of
energy efficiency programs and from short-term wholesale market purchases.

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A 59 percent increase in projected energy efficiency savings from the 2013 plan is anticipated to meet 86
percent of the company’s forecasted load growth over the next decade. Rocky Mountain is also projecting a
reduction in the rate of load growth from what it anticipated in 2013 due to the continued phase-in of federal
lighting standards and increased efficiencies in heating, cooling, water heating, use of appliances and industrial
process end-uses. PacifiCorp’s preferred portfolio of energy sources includes 816 megawatts from power
purchase agreements with 36 wind and solar projects, all scheduled to come on line by the end of 2016. While
offering “no commentary on the prudency” of the decision for increased reliance on solar resources, the
commission suggested Rocky Mountain consider “conducting a reasonable evaluation,” of the costs and benefits
associated with the integrating additional solar resources into its system.

Commission staff said the company may want to include a solar integration study in its 2017 plan. Rocky
Mountain said it will consider a study, but noted that solar energy will comprise only about 2 percent of its
projected load by 2017, rather than the 6 percent claimed by commission staff. The commission commended
the company for responding positively to the commission’s recommendation in 2013 that the utility expand its
energy efficiency programs in response to anticipated increased federal regulation on fossil-fueled generation.
This year’s IRP is greatly impacted by the Environmental Protection Agency’s recently announced Clean Power
Plan.

Rocky Mountain plans to convert some coal generation to natural gas by 2018 and install emissions control
equipment at its Wyodak and Dave Johnston Unit 3 coal projects in Wyoming and its Cholla Unit 4 project in
Arizona. The plan states that about 2,800 MW of existing coal generation will either be retired or converted to
natural gas-fired generation over the next decade.

While commending the company for its plan to phase out 2,800 MW of coal generation, the Snake River Alliance
said the plan does not go far enough. The environmental organization said the company will still be relying on
coal for as much as 30 percent of its generation two decades from now, which exposes customers to undue risk
from increased regulation on coal-fired generation.

The Idaho Conservation League believes the company’s modeling of future costs related to coal pollution costs is
“fundamentally flawed.”

In addition to increased reliance on energy efficiency programs, Rocky Mountain is also planning on transmission
expansion. The utility plans to have access to more generation, much of it from wind, from three 500-kV
transmission projects: Energy Gateway West (from Casper, Wyo. to the Hemingway Substation southwest of
Boise), Energy Gateway South (from south-central Wyoming, through southeastern Idaho to central Utah) and
Boardman to Hemingway (from Boardman, Oregon to the Hemingway Substation).

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NATURAL GAS

Consumption declines while prices increase in 2014

In Idaho, natural gas is supplied to customers by Avista Corporation, Intermountain Gas Company and Questar
Gas. 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 Transmission Northwest pipelines allowing the utility
companies serving Idaho to take advantage of capacity and pricing of both basins.

Individual Idaho Gas Utility Profiles

2014 Statistics Total Residential Commercial Industrial Transportation1
Intermountain Gas
Customers 333,810 301,865 31,821 19 105
% of Total 100% 90.43% 9.53% 0.01% 0.03%
Therms (millions) 589.6 203 104 5.7 276.9
% of Total 100% 34.43% 17.64% 0.97% 46.96%
Revenue (millions) $251.20 $162.60 $76.50 $3.00 $9.10
% of Total 100% 64.73% 30.45% 1.19% 3.62%
Avista Corporation
Customers 78,052 69,309 8,635 101 7
% of Total 100% 88.80% 11.06% 0.13% 0.01%
Therms (millions) 116.86 46.26 27.48 2.43 40.69
% of Total 100% 39.59% 23.52% 2.08% 34.82%
Revenue (millions) $71.53 $46.55 $22.84 $1.67 $0.47
% of Total 100% 65.08% 31.93% 2.33% 0.66%
Questar Gas
Customers 2,098 1,858 240 0 0
% of Total 100% 88.56% 11.44% 0% 0%
Therms (millions) 2.02 1.26 0.76 0 0
% of Total 100% 62.38% 37.62% 0% 0%
Revenue (millions) $1.75 $1.16 $0.59 $0.00 $0.00
% of Total 100% 66.29% 33.71% 0% 0%

Consumption

Growth rates in residential and commercial segments were lower than forecasted for 2014 and are projected to
decline in both 2015 and 2016.2 In the residential space, customer additions are keeping pace with declines in
per-customer use of natural gas. In 2014, industrial growth rates remained relatively flat and electricity
generation demand declined but is driving overall load growth.

1 Transportation is non-utility owned gas transported for another party under contractual agreement.
2 EIA Short-Term Energy Outlook Sept. 9, 2015
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Northwest Gas Association (NWGA) members are watching a number of demand drivers that have yet to be
quantified, including:3
 The magnitude and nature of the use of natural gas for generating electricity.
 The possibility of new significant industrial loads.
 The regional growth potential for natural gas as a transportation fuel.
 The adequacy of natural gas infrastructure to support regional growth opportunities.
 The impact of future energy policies on demand, particularly GHG (greenhouse gas) legislation.

Prices

Natural gas spot prices are expected to decline in 2015 to an average of $3.16/Dth (dekatherm) at Henry Hub,
which is one third lower than the 2014 average of $4.52/Dth at Henry Hub.4

Northwest Gas Association (NWGA) members are tracking a number of market dynamics that could influence
future natural gas prices:5
 North American economic growth.
 The pace of adoption of natural gas for generation, industrial and transportation uses.
 Whether future regulations add to the cost of production or limit access to reserves.
 The effect of new and improved production technologies.
 The effect of infrastructure constraints on regional pricing.
 Benefits and costs of North American natural gas, such as LNG (Liquefied Natural Gas) exports to
premium overseas markets.

3 NWGA 2015 Gas Outlook
4 EIA, Short-Term Energy Outlook, April 7, 2015.

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Summary

Idaho residents, commercial and industrial users of natural gas continue to benefit from low natural gas prices
and plentiful supply. Continued advancement in shale extraction and production techniques are transforming
the industry and continue to exceed expectations. Existing natural gas providers’ infrastructure is sufficient to
meet current needs and forecasts. However, system capacity could be strained if load requirements exceed
forecasts. Increased capacity could be required if sustained cold weather events occur, industrial and electricity
generation demand accelerate above forecasts, and implementation of the EPA’s Clean Power Plan (111[d])
stimulates increased use of natural gas.

-by Kevin Keyt, IPUC Staff Analyst

Commission accepts Avista Utilities’ 20-year natural gas plan

Case No. AVU-G-14-03, Order No. 33196

Dec. 26, 2014 – The Commission accepted a plan by Avista Utilities to meet customer demand for natural gas
over the next 20 years. The company’s Integrated Resource Plan (IRP) is updated every two years.

However, the commission said neither Avista’s IRP nor its 2015 Business Plan address when it might be cost-
effective for Avista to resume offering incentives to customers to reduce natural gas consumption. Avista
suspended its demand-side management (DSM) programs for natural gas customers in 2012 after natural gas
prices dropped to the point that the DSM programs were no longer cost-effective. Still, Avista’s 2014 IRP
indicates a Conservation Potential Assessment for 228,000 therms of natural gas savings in 2015, increasing to
3.6 million therms by 2034.

Avista maintains its Conservation Potential Assessment uses “high-level assumptions” that may be overly
optimistic and that the issue should be further explored in the company’s 2015 Business Plan rather than in the
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context of its IRP. The commission directed Avista to file an addendum to its business plan within 60 days that
analyzes the CPA results and addresses whether it might be cost-effective to resume DSM programs.

The commission commended the company for its efforts to make its IRP planning process more transparent and
available to Avista’s northern Idaho natural gas customers. The Technical Advisory Committee, which includes
commission staff, peer utilities, customers and other stakeholders, conducted meetings in a number of locations
more convenient for Idaho stakeholders. Avista also recorded a meeting and made it electronically available to
customers.

Customer demand remains low, thus Avista does not anticipate a need to acquire additional natural gas
resources beyond what it already provides. Demand is down due partly to the recession, while the availability of
natural gas increases because of the abundant supply of shale gas. The company anticipates growth in customer
demand of only 0.7% annually.

However, due to enough uncertainties regarding future natural gas supply and price, Avista’s plan outlines a
number of scenarios and how it would respond to each one. The uncertainties that could impact demand for
natural gas include 1) the amount of liquefied natural gas (LNG) exports, 2) the market for natural gas vehicles
and 3) the amount of increased natural gas that may be needed for electric generation.

Existing and new LNG facilities are looking to export low-cost North American gas to higher-priced Asian and
European markets, the Avista IRP states. In Canada, 16 LNG export projects are in various stages of permitting
and there are two proposed terminals in Oregon. “LNG exporting has the potential to alter the price, constrain
existing pipeline networks, stimulate development of new pipeline resources, and change flows of natural gas
across North America,” the IRP states.

Avista claims it has a diversified portfolio of gas supply resources, including contracts to buy gas from several
supply basins, stored gas and firm capacity rights on six pipelines.

The company’s identifies a number of steps it will take in its “action plan,” to address future concerns:

 Monitor demand for indications of deviations from expected growth and provide a report twice yearly
to commission staff on forecasted customer growth and use per customer as compared to actual growth

 Continue to monitor supply-side resource trends including the availability and price of natural gas to the
region, LNG exports, Canadian natural gas supply and consumption, and the availability of storage
infrastructure.

 Meet regularly with commission staff to provide information on market activities and significant changes
in the IRP’s assumptions or natural gas procurement practices.

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PUC sets lower depreciation rate for Intermountain Gas

Case No. INT-G-14-02, Order No. 33260

April 2, 2015 – The Commission approved a small reduction to Intermountain Gas Company’s composite
depreciation rate from 3.07% to 3.05%.

The company had originally requested an increase to 3.12%, but agreed with changes proposed by commission
staff to slightly decrease the rate.

The commission did adopt the company’s proposed increase to its total General Plant amortizations from $1.75
million to $2.6 million.

The changes will not impact rates for Intermountain Gas’ 330,000 customers across southern Idaho.

Utilities are allowed a depreciation component in retail rates to help cover the costs to replace facilities.
Intermountain Gas updates its depreciation rate every three years. It contracts with an outside vendor, AUS
Consultants, to conduct the update study.

The AUS study determined Intermountain Gas is under-depreciating its assets. The study addressed, among
other items, adjustments to the projected lives of Intermountain’s electronic transmitters used to read meters,
its distribution mains and service lines and improvements made to the company’s Liquefied Natural Gas facility
in Nampa.

Intermountain began using the electronic read transmitters (ERTs) in 2002. The units were expected to continue
in service for 15 years. However, recent studies indicate that the devices will need to be replaced earlier than
anticipated, resulting in a shortening of their remaining useful life. After discussion, commission staff and the
company agreed to delay a change in the depreciation rate for the transmitters until after the company has
replaced all ERTs. The resulting more precise expense can then be included in the next depreciation study.

Commission staff also made downward adjustments to the proposed depreciation rates for the company’s
distribution mains and for the equipment that regulates the pressure in the pipelines. The commission did not
accept the company’s proposed depreciation rate increase from 2% to 2.55% for the Nampa Liquefied Natural
Gas facility.

Depreciation, as applied to Intermountain Gas’ plant, means the loss in service value not restored by
maintenance or covered by insurance, but incurred in connection with wear and tear, decay, inadequacy,
obsolescence and new requirements from public authorities.

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PUC accepts Intermountain Gas long-range plan

Case No. INT-G-15-01, Order No. 33314

June 11, 2015 – The Commission accepted Intermountain Gas’ five-year plan to meet customer demand.
The commission’s acceptance of the Integrated Resource Plan (IRP), filed every two years, does not mean the
commission endorses all the resource acquisitions planned or the company’s preferences for future gas supply.
Those issues are determined in separate cases or rate cases that address each matter separately. Rather,
acceptance of the IRP means Intermountain Gas has met its obligation to conduct an ongoing public planning
process and report that process to the commission.

Intermountain Gas delivers natural gas to 290,500 residential customers and 31,000 commercial customers
across southern Idaho. It does not anticipate any peak-day delivery deficits in the regions it serves over the next
five years. Some customers, like those in the Rexburg area, may require use of a portable liquefied natural gas
facility to meet customer demand on peak-use days. A number of industrial customers are able to use other
non-traditional sources on peak days, such as diesel/fuel oil, coal, wood chips and propane.

More than 149 miles of distribution and service lines were added during 2013 to accommodate new customer
additions and maintain service.

The IRP forecasts a 2.32% rate of growth each year for the next five years in its total residential, commercial and
industrial peak-day loads. In 2013, the company experienced a 1.8% growth rate in the number of residential
and commercial customers from 2008.

In its review of the plan, the commission encouraged the company to include the costs of natural gas storage
and distribution enhancements in its calculations to determine whether efficiency programs would be more
cost-effective. The commission also directed the company to summarize the scope, duration and cost of
Intermountain’s research and development projects in its future IRPs. The commission further directed the
company to provide more information on the level of participation in public meetings regarding the IRPThe
Idaho Conservation League also filed comments in the case, stating the company under estimates future gas
demand, does not indicate whether the company plans to augment its gas efficiency programs and does not
state how the company advocates for building and appliance standards to increase efficiency.

Intermountain states that its forecast is sound and, if not, the company updates its forecast at least biennially.
Gas efficiency programs have been temporarily suspended by both Avista Gas in northern Idaho and
Intermountain Gas, with commission concurrence, because they are not cost-effective with the current low
prices for natural gas. Regarding efficiency programs for buildings, the company stated that it regularly interacts
with the state Division of Building Safety and is open to participation in the Idaho Building Code Collaborative to
the extent that such participation is relevant to Intermountain’s business and services.

Intermountain Gas is served by the Williams Northwest Pipeline that enters southeast Idaho from Wyoming.
From that pipeline, Intermountain has built several laterals, the major ones being the Idaho Falls Lateral from
Pocatello to St. Anthony, the Sun Valley lateral from Shoshone to Sun Valley, the Canyon County Lateral, the
State Street Lateral in northwest Boise and the Central Ada Area Lateral.

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The agricultural economy and the price of alternative fuels strongly influence industrial demand for natural gas.
In 2013, industrial sales and transportation customers accounted for 44% of the throughput on Intermountain’s
system. Transportation customers are large industrial customers that use Intermountain Gas’s distribution
system to buy gas from Intermountain or other suppliers.

Natural gas rates to drop for Intermountain Gas customers

Case No. INT-G-15-02, Order No. 33386

September 30, 2015 – Rates for customers of Intermountain Gas Company will decrease an average 5.7%
effective Oct. 1.

The Commission approved the company’s annual Purchased Gas Cost Adjustment (PGA). Under the PGA, rates
are adjusted up or down every Oct. 1 to account for that portion of gas supply expense that changes every year.

Lower wholesale prices for natural gas and a decrease in transportation costs billed to Intermountain by its
supplier, Northwest Pipeline GP, contributed to this year’s reduction.

The $15.3 million passed on to customers is about a 6.1% decrease to customers who use natural gas for space
and water heating, a 3.56% decrease to those who use natural gas for space heating only and a 5.6% reduction
for commercial customers. The PGA portion of customer rates will be reduced from the current 39.5 cents per
therm to 32.8 cents per therm. With the approval, Intermountain’s combined residential and commercial rates
are 35% lower than in 2005.

Other factors contributing to the lower rate include increased natural gas production and Intermountain Gas’
management of its storage and firm capacity rights on its various pipeline systems.

Commission considering Avista proposal to resume gas efficiency programs
Case No. AVU-G-15-03, Order No. 33422
November 23, 2015 – Avista Utilities, which serves about 78,000 natural gas customers in northern Idaho, is
asking state regulators to resume its natural gas energy efficiency programs after they were suspended in 2012
because of low natural gas prices. At the publication of this report, the Commission had not yet issued a final
order.
The programs offer rebates and other incentives to customers who install weatherization as well as high-
efficiency natural gas appliances. The programs were suspended when natural gas costs dipped to about 50
percent lower than the expense the utility was avoiding with the programs in place.
If the Commission approves resumption of the programs, Avista would also re-institute its rider to fund the
programs, which would be about 1.7% of a customer’s billed rate. For a residential customer who uses the
company average of 61 therms per month, the monthly increase would be about $1.11, effective Jan. 1, 2016.
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Overall, natural gas rates just declined sharply with a 14.5% reduction in the company’s annual Purchased Gas
Cost Adjustment, the variable portion of gas rates adjusted every Nov. 1. The permanent portion of natural gas
rates – the base rate – is expected to increase by 3.5% on Jan. 1 if the commission approves a negotiated
settlement proposed by Avista and other parties.
In order for the Commission to approve resumption of the efficiency programs, the utility must demonstrate
that the savings from the program are greater than the expense to customers. Avista estimates that the first
year savings (2016-17) will be about 233,000 therms in its Idaho territory.

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WATER

Parties to United Water case announce proposed
settlement

Case No. UWI-W-15-01, Order No. 33398

October 26, 2015 – Rates for United Water Idaho customers would go up
about 6%, or about $1.25 per month during 2016 and another 1.4% in
2017 if a settlement proposed by parties to a general rate case is approved
by the Commission.

United Water Idaho initially proposed a one-year 13.2% increase, with an
additional $5.88 million in annual revenue. The proposed settlement
reduces that to $2.73 million in 2016 and $670,000 in 2017. Under the
proposed settlement, the monthly increase to standard residential
customers with up to a three-quarter inch meter would be from $20.80 to
$22.05, effective Dec. 16, 2015.

The proposed settlement also directs the company to increase its
contribution to its “United Water Cares” program from $65 to $75 per
customer per year. The program provides financial assistance to low-
income customers. None of the program’s costs are included in customer
rates. United Water Idaho currently serves more than 90,000 customers in
Ada County.

Parties to the settlement include United Water, commission staff and the
Community Action Partnership Association of Idaho.

United Water applied for the increase on May 21. The commission
suspended the company’s application for six months to allow time for its
staff of auditors, engineers, technical analysts and attorneys to review the
case. The commission cannot, by state law, arbitrarily refuse to consider
rate increase requests without first considering the evidence presented by
the utility, intervening parties and customers. The burden of proof is on
the utility to justify the expenses it seeks to recover as 1) necessary to
serve customers and 2) prudently incurred.

United Water claims the increase is needed to recoup more than $39
million of investment in its water system since the last rate case in 2011.
The capital improvements include $17.2 million to replace aging water
mains and meters, $3.5 million to replace treatment facilities, $900,000
for a replacement storage tank in the Bogus Basin Road area and $500,000
for auxiliary power equipment to ensure uninterrupted water supply
during electric outages.
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Commission OKs Falls Water request to expand service territory

Case No. FLS-W-15-01, Order No. 33356

August 19, 2015 – The commission is accepting a Falls Water Company application to extend its service territory
in Bonneville County.

Falls Water serves an area adjacent to the City of Ammon’s municipal water system. Over the last 16 years,
developers have built additional residences adjacent to the company’s original service areas. At the conclusion
of the company’s last rate case in 2012, the commission directed Falls Water to amend its certificate to include
subdivisions the utility is serving that were outside its assigned boundaries. At that time, the company was
serving about 3,840 customers. Now it serves about 4,340 customers.

The City of Ammon and Falls Water have signed a Memorandum of Understanding delineating an agreed upon
service boundary between the two systems.

Falls Water plans to provide service to the new areas through water mains and service lines installed by various
developers using the company’s Main Extension Contract. Falls Water claims it has adequate water supply to
provide service to the new area in a safe and reliable manner.

Commission OKs certificate, rates for water utility seeking to serve
Schweitzer ski resort in Bonner County

Case No. AWW-W-13-01, Order No. 33219

February 11, 2015 – The Commission awarded a Certificate of Public Convenience and Necessity to Acme Water
Works to operate as a water utility in Bonner County.

Acme will serve 23 residential customers on three lots within the Schweitzer Mountain Ski Resort, 15 miles
northwest of Sandpoint. If both Phase 1 and Phase 2 of the development are completed, the company may
eventually serve up to 260 residential customers on 107 lots. The water system consists of two wells, a 200,000-
gallon storage reservoir, distribution mains and fire hydrants.

The owners are Joel and Leslie Wahlin of Sandpoint. The company currently contracts all water master duties,
including water testing, billing and collections with Water Systems Management, operated by Bob Hansen of
Sandpoint.

Commission staff determined an annual revenue requirement of $8,067. To meet that revenue requirement, the
commission authorized a minimum monthly flat rate for residential customers of $29.25. That’s 40% less than
the company’s current monthly rate of $48 per month. The company originally proposed that customers pay a
monthly minimum charge plus a volume allowance based on monthly consumption.

The commission denied that proposal stating that without individual meters, the company did not have was to
accurately measure monthly consumption.

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The company proposed a hook-up fee for new customers of $9,430, up from the current $7,000. The
commission approved a hook-up fee of $150. Acme said the higher hook-up fee is needed to recover an
approximate $1.5 million investment in new utility construction. The commission said collecting hook-up fees
from new customers to pay off the loans used to build the water system is in violation of commission rules. The
commission also denied a company request to assess a monthly standby or availability charge to customers who
have paid a connection fee but are not yet connected to the system.

Finally, the commission directed the company to repair any system sanitary deficiencies identified by the state
Department of Environmental Quality and Panhandle Health Department.

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TELECOMMUNICATIONS

First Step Internet granted ETC status; hopes to
expand broadband in rural areas

Case No. FSI-T-14-01, Order No. 33226

Feb. 24, 2015 – A Moscow-based company seeking to qualify for federal
funds to expand broadband services in rural parts of Idaho has been
granted conditional Eligible Telecommunications Carrier (ETC) status.

The Federal Communications Commission will allocate about $4.5 billion
over a five-year period to new advanced networks in rural and insular
communities. ETC status is granted by state commissions after the
companies meet specified criteria.

First Step Internet is a facilities-based regional Internet Service Provider
that will use a combination of its own network and facilities as well as
resale of another carrier’s services. Kevin Owen of Moscow is listed as
president on the company’s application.

First Step Internet will offer a variety of services including dial-up, DSL,
fiber, cable Internet, fixed wireless broadband services and Voice Over
Internet Protocol (VOIP). The service area for which the company
requested ETC designation includes some 27 communities and
surrounding rural areas in north and central Idaho.

To be declared an ETC by the Commission, First Step Internet had to
meet a number of criteria including customer access to emergency
services such as 911 and enhanced 911. The company must also have a
reasonable amount of back-up power to ensure functionality without an
external power source, be able to re-route traffic around damaged
facilities and be capable of managing traffic spikes resulting from
emergencies. It must contribute to the Idaho Telephone Assistance
Program for low-income customers, E-911 emergency fund, the state
Universal Service Fund and the Telecommunications Relay Service for
those with hearing and speech disabilities.

The company must further demonstrate that the ETC is in the public
interest by increasing customer choice and making available new service
offerings including wireless broadband. It must also comply with the
state’s consumer protection and service quality standards.
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Telephone surcharge decreasing June 1

Case No. GNR-T-15-03, Order No. 33284

April 24, 2015 -- A surcharge that helps to ensure low-income Idahoans have access to a phone line is being
decreased to 1-cent per month for every wireline and wireless phone because of declining participation in the
Idaho Telecommunications Service Assistance Program (ITSAP).

The surcharge has declined from a high of 12 cents per line per month to 7 cents in 2013, 3 cents last year and 1
cent this year. Collections from the surcharge go to telephone companies who then disburse the funds to
qualifying customers. ITSAP provides a $2.50 per month discount for qualifying telephone and cell phone users.
That is on top of a $9.25 per month contribution from the federal Lifeline program. Legislation adopted in 2012
reduced the size of the Idaho contribution from $3.50 per month to $2.50.

Lifeline was established in 1985 to ensure that low-income citizens, including many senior citizens, have access
to local dial-tone service for medical and other emergencies.

Those who seek telephone assistance must be determined eligible by the state Department of Health and
Welfare. The Idaho Public Utilities Commission establishes the amount of surcharge necessary to fund the
program.

The commission decided to reduce the monthly contribution once again due primarily to fewer Idahoans either
qualifying or seeking eligibility for the program. The average number of ITSAP recipients per month in 2014 was
10,674, a 25 percent decrease from 17,626 during 2013. In 2012, the average number of recipients per month
was 23,434, down from 2011’s number of 25,310.

The number of telephone lines to support the fund, both wireline and wireless, is also declining. Wirelines in
Idaho continue their steady decline, from 512,672 in 2011, to 491,572 in 2012, to 454,941 in 2013 and 427,065
in 2014.

For the first time, the number of wireless lines in Idaho also decreased, from 1,395,896 in 2013 to 1,329,112 in
2014. Average wireless access lines per month were 1,276,830 in 2012 and 1,132,234 in 2011.

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PUC responds to request for report on broadband funding

In June 2014, the Idaho Public Utilities Commission received a letter from Senator Brent Hill, president pro tem of
the Idaho Senate, and Rep. Scott Bedke, speaker of the Idaho House of Representatives, regarding the rapid
changes taking place in the telecommunications industry, specifically in regard to the deployment of high-speed
broadband service. Since Congress passed the Telecommunications Act of 1996, “we have witnessed the
dramatic transformation of the entire industry with the explosion of the Internet and the advent of broadband
services and other new communication technologies,” wrote Senator Hill and Speaker Bedke.
With the rapid deployment of broadband technology, the Federal Communications Commission (FCC) is making
changes to how telecommunications and broadband services are funded, particularly in rural, high-cost areas.
“Some have suggested those changes may not ensure the continued availability of affordable
telecommunications and broadband services throughout Idaho,” wrote Hill and Bedke. “This is a concern to us.
Both traditional telecommunications and broadband services are critical to the economic future of Idaho,
particularly rural Idaho. We can ill-afford a digital divide that leaves our rural areas behind.”
The legislative leaders asked the PUC to begin assembling information from interested parties to evaluate the
sufficiency of the Idaho Universal Service Fund (ISUF) that provides financial support for traditional
telecommunications services and how that fund might be structured and allocated given the advent of
broadband deployment.
In response, the IPUC opened an investigation and conducted a survey on changing communication services for
both traditional and new services.
Below is the introduction to the report and the Commission’s recommendation. The entire report is available on
the Commission’s Website at www.puc.idaho.gov.
Executive Summary
Since 1996, the telecommunication industry has developed and deployed new technologies that have produced
a more robust infrastructure and a wide array of telecommunications services for consumers. This array of
services has also resulted in significant changes in how customers communicate with others and use the
Internet. A recent Federal Communications Commission report noted that the number of traditional wirelines
(“plain old telephone service” or “POTS”) has decreased and that more American households now rely
exclusively on wireless services. More residential customers subscribe to some form of broadband
telecommunications beyond POTS.
The changes in consumers’ preferences in telecommunications services have impacted federal and state
universal service mechanisms.
Since the 1930s, Congress has mandated that all telephone companies providing interstate service must
contribute to a federal Universal Service Fund (USF). The USF helps to make phone service affordable and
available to all Americans, including those living in areas where the cost of providing telephone service is high.
All telephone consumers pay into the fund, which is then disbursed to telephone companies to provide service,
mostly in rural under-served areas.
Idaho has a state fund, the Idaho Universal Service Fund, (IC 62-610A), which stipulates that "all consumers in
this state, without regard to their location, should have comparable accessibility to basic telecommunications
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services at just and reasonable rates. Currently, Idaho telecommunications customers pay 16 cents per
residential line, 25 cents per business line and $.0006 per minute on long distance calls. The fund is designed to
ensure that average rates in rural areas are no more than 25% higher than average rates in urban areas. The
Idaho rural carriers that receive IUSF support are ATC, Cambridge, Direct, Fremont, Inland, Midvale, Rural and
Silver Star.
However, the assessable base for Idaho Universal Service Fund contributions has eroded as customers migrate
to other services that do not support the fund. Simply put, as more customers move to newer services, the base
that supports the IUSF is eroding.
With the advent of nontraditional communications, such as broadband, wireless Voice over Internet Protocol
(VoIP) and cable-based communications, federal and state policymakers are grappling with how universal funds
should now be collected and disbursed to ensure new technologies are available at reasonable cost to all.
The Idaho Public Utilities Commission conducted a survey of Idaho communication providers seeking input and
suggestions as to how the changing telecommunications field will affect rural high-cost areas and evaluate the
sufficiency of the Universal Service Fund and other cost mechanisms to ensure continued availability of
telecommunications and broadband services in Idaho.
The survey responders included a selection of Idaho’s Incumbent Local Exchange Carriers, Rural Incumbent Local
Exchange Carriers, Wireless and Cable providers as well as some Competitive Local Exchange Carriers and a
wholesale provider. A few of the focused responses were:
 VoIP services should be included in the definition of Universal Service.
 All Federal funding in Idaho should be exhausted and then a reassessment of areas that still need
broadband services could then be targeted.
 Customers of all providers of telecommunications services should make equitable contributions to the
preservation and advancement of universal service.
 Idaho PUC should follow the federal lead and to the extent that broadband is included in either state or
federal universal service requirements, state and federal USF programs should be in place to fund those
requirements.
 A consensus that broadband to all of Idaho was necessary for economic development and that all
providers should pay into the USF to broaden the base and provide adequate funding to expand.
 Another common observation was that Idaho should wait until the Federal changes are enacted and
then follow those changes so that there will be certainty and continuity for business planning and
advancement of all communication services.

IPUC staff thanks industry participants for their thoughtful input and assistance.
The Commission is not, at this time, considering the assessment of broadband services or broadening the base
to include additional consumers not already contributing to the IUSF. Rather the PUC proposes that, in the
future it would be prudent to modernize and reform the contribution mechanism to promote an equitable
and sustainable framework in an evolving communications environment. Since, there are many unknowns at
the federal level, the Commission and many other survey participants believe it would be wise to defer any
actions in Idaho until there is more certainty from the FCC.

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Telecommunication Utilities under IPUC Jurisdiction

Albion Telephone Corp (ATC), P.O. Box 98, Albion, Idaho 83311-0098 208-673-5335
Cambridge Telephone Co. P.O. Box 88, Cambridge, Idaho 83610-0086 208-257-3314
*CenturyLink, (formerly Qwest Communications) North and South Idaho, Box 7888 (83723) or
999 Main Street, Boise, Idaho 83702 800-339-3929
*CenturyTel of Idaho, Inc., dba CenturyLink, 250 Bell Plaza, Room 1601, Salt Lake City, UT,
84010, 801-238-0240.
*CenturyTel of the Gem State, dba CenturyLink, 250 Bell Plaza, Room 1601, Salt Lake City, UT,
84010, 801-238-0240.
*Frontier Communications Northwest, Inc. (formerly Verizon Northwest, Inc.), 20575 NW Von
Neuman Dr. Ste. 150, Beaverton, OR, 97006, 503-629-2459
Direct Communications Rockland, Inc., Box 269, 150 S. Main St. Rockland, ID 83271
208-548-2345
Fremont Telcom, Inc., dba Fremont Communications, 1221 N. Russell St., Missoula, MT, 59808,
406-541-5454
Inland Telephone Co., 103 South Second Street, Box 171, Roslyn, WA 98941
509-649-2211
Midvale Telephone Company, Box 7, Midvale, Idaho 83645, 208-355-2211
*Citizens Telecommunications Company of Idaho, dba Frontier Communications of Idaho,
20575 NW Von Neuman Dr. Ste. 150, Beaverton, OR, 97006, 503-629-2459
Oregon-Idaho Utilities, Inc., 3645 Grand Ave., Ste. 205A, Oakland, CA 94610 510/338-4621
Local: 1023 N. Horton St., Nampa, Idaho 83653 208-461-7802
Pine Telephone System, Inc., Box 706, Halfway, OR 97834 541-742-2201
Potlatch Telephone Company, dba/ TDS Telecom, Box 138, 702 E. Main St.
Kendrick, Idaho 83537, 208-835-2211
Rural Telephone Company, 829 W. Madison Avenue, Glenns Ferry, Idaho 83623-2372
208/366-2614

*These companies, which represent more than 90 percent of Idaho customers, are no longer rate
regulated. However, they are still regulated for customer service.
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CONSUMER ASSISTANCE

Commission grants utilities’ request for waiver
from rule requiring face-to-face bill collection

Case No. GNR-U-14-01, Order No. 33229

Feb. 20, 2015 – State regulators have granted a request by Idaho’s three
major electric utilities to be exempted from a requirement that they
attempt to make face-to-face contact with a customer to either collect
payment or terminate electric service for nonpayment.

A section of the Commission’s Customer Relations Rules requires that
utilities try to meet customers at their homes or businesses to give them a
final chance to pay a past-due bill to avoid disconnection and also tell
customers how they can later have their service restored if they do not
pay.

However, Avista Utilities, Idaho Power Company and Rocky Mountain
Power say advances in metering, communication and electronic payments
negate the need for face-to-face visits and bill collection. Automated
meters give utilities the ability to disconnect and re-connect customers
from a remote location. Re-connection is quicker with automated metering
and customers avoid the extra charge that is imposed – up to $20 – when
an on-site visit is required. The utilities say waiver from the rule will reduce
operating costs for customers and increase the safety of utility employees
without sacrificing customer service.

Customers already receive multiple notices prior to disconnection,
including mailed past-due notices seven days and again three days before
disconnection. Twenty-four hours before disconnection, customers receive
a telephonic notice or an in-person visit.

Avista and Idaho Power’s waiver rule applies to those customers with
remote metering capability. But even with the waiver, Avista, which
operates in northern Idaho, and Idaho Power, in southern Idaho, are still
required to knock and leave a door hanger at businesses and residences
that are not equipped for remote disconnection.

Rocky Mountain Power, which operates in eastern Idaho, does not have
the type of meters that allow for remote disconnect capability, so it must
leave a door hangar notifying customers of upcoming manual disconnect.
The waiver does exempt all three utilities from being required to make
face-to-face contact and collect payments, per each company’s
implementation plan.
Idaho Power has installed 14,500 meters with automated connect-
disconnect ability. The utility claims that its one-time investment of $1
million in automated connect and disconnect meters will reduce annual
operating expenses by about $700,000. Avista has done the same in its
north Idaho territory with 600 meters. PacifiCorp, parent company of
Rocky Mountain Power, has already discontinued taking payments at the
door in Utah, Wyoming, Oregon and California and reports no escalated
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Idaho Power has installed 14,500 meters with automated connect-disconnect ability. The utility claims that its
one-time investment of $1 million in automated connect and disconnect meters will reduce operating expenses
by about $700,000. Avista has done the same in its north Idaho territory with 600 meters. PacifiCorp, parent
company of Rocky Mountain Power, has already discontinued taking payments at the door in Utah, Wyoming,
Oregon and California and reports no escalated customer service issues or increased complaints.

The commission attached conditions to the waiver, including the following:

 Utilities must “diligently” attempt to notify customers by phone or in person at least 24 hours before
disconnection. The commission declined to quantify “diligent” with a precise number of attempts, but
commended Avista for its practice of trying to call customers up to seven times.
 Utilities must educate their personnel and customers about the changes that will occur under the
exemption. Idaho Power and Avista must submit a revised plan within 30 days that details how they will
notify customers and train employees. The commission accepted Rocky Mountain Power’s plan.
 Idaho Power and Avista must reduce their reconnection charges to reflect the lower cost to utilities to
reconnect without having to dispatch field personnel.
 Utilities’ must notify a third-party designated by the customer at least one week before an impending
disconnection.

The Community Action Partnership Association of Idaho (CAPAI) said the commission should deny the utilities’
petition, but, if granted, should do only under limited conditions. CAPAI claimed the utilities were not able to
meet the rules’ requirement to prove that the rules create an “unreasonable hardship” and that the change
discriminates against low-income customers.

CAPAI argued that utilities did not present evidence of physical harm to employees who were trying to collect
overdue payments. However, PacifiCorp (Rocky Mountain Power’s parent company) reported 13 physical
incidents in its six-state territory during 2012-13 including employees being spit upon, one employee’s leg
slammed in a company truck door, one involved in a pit bull attack, one customer attempting to engage an
employee in a fistfight, one customer turning a hose on an employee and eight employees involved with
customers brandishing firearms. In Idaho, the company reports nine sites where “aggressive customer behavior”
was documented. All utilities report aggressive dogs are sometimes used to deter utility personnel.

Waiver from the rule, the commission said, will reduce safety risks to both utility employees and customers and
allow customers to realize the benefits of modern metering technologies. The current rule, for example, forces
Avista and Idaho Power customers to unnecessarily incur labor and transportation costs, expense that will be
avoided through remote disconnection and reconnection. Idaho Power, for example, estimates to save $700,000
each year. Customers will also avoid the field visit charge, $16 for Avista customers and $20 for Idaho Power and
Rocky Mountain customers.

CAPAI’s claim that a waiver from the rule discriminates against low-income customers is not borne out by an
Idaho Power statistic that only 8% of its 12,743 remote connect/disconnect customers are installed at locations
where customers were receiving low-income heating assistance.

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The commission did grant CAPAI requests to monitor the exemption’s effects on low-income persons as part of
their monthly report to the commission and that a third-party designee is contacted at least a week prior to
disconnection.

All three utilities claim they have expanded payment methods beyond traditional U.S. mail or payment at local
offices. Online and payment-by-telephone options allow customers to make payments from their homes, from
any Internet connection or through their mobile phones. The vast majority of customers now make their
payments by mail or by online banking methods. Commission staff noted that few customers pay at the door to
avoid disconnection, with only 20% of Avista and Idaho Power customers and 14% of Rocky Mountain Power
customers paying at the door during a disconnection visit in 2013.
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Commission issues annual consumer assistance report
The Consumer Assistance staff responded to 1,747 complaints, and inquiries in calendar year 2014, of which 93
percent were from residential customers.

Breakdown by type of utility:

Contacts regarding telecommunications companies: 25 percent
Contacts regarding energy (electric, gas) companies: 49 percent
Contacts regarding water companies: 11 percent
Misc.: 15 percent

(CenturyLink had 46 percent of telecommunication complaints; Idaho Power had 60 percent and Intermountain
Gas16 percent of energy utility complaints and United Water had 39 percent of water complaints.)

Summary of issues:

Billings 22 percent
Credit and collection issues 34 percent
Miscellaneous 24 percent
Utility rates and policies 8 percent
Telecommunications issues 3 percent
Line extensions and service upgrades 2 percent
Service quality and repair 7 percent

While dispute resolution remains an important task, it is hoped that by working with consumer groups,
social service agencies, and utilities, persistent causes of consumer difficulties can be identified and addressed.
Consumer complaints present an opportunity for utilities and the commission to learn the effect of
utility practices and policies on people. For example, the unintentional and perhaps unfair impact of a rule or
regulation might be discovered in the course of investigating a complaint. In such cases an informal, negotiated
remedy may not be possible, and formal action by the commission would be required. The Consumer Assistance
Staff’s participation in formal rate and policy cases before the commission is the primary method used to
address these issues.
While the Consumer Assistance Staff is able to respond to some consumer inquiries without extensive
research, about 77 percent of consumer complaints required investigation by the staff. About 52 percent of
investigations resulted in reversal or modification of the utilities’ original action.

Toll-Free Complaint Line
The commission has a toll-free telephone line for receiving utility complaints and inquiries from consumers
outside the Boise area. The toll-free line (1-800-432-0369) is reserved for inquiries and complaints concerning
utilities. Consumers may also file a complaint electronically via the commission’s Website at
www.puc.idaho.gov.

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REGULATING IDAHO’S RAILROADS

More than 900 miles of railroad track in Idaho have been abandoned since 1976. Federal law governs rail line
abandonments. The federal Surface Transportation Board (formerly the Interstate Commerce 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 proposed abandonment would
adversely affect the public interest. The commission then reports its findings to the STB.

In reaching a conclusion, the commission considers whether abandonment would adversely affect the service
area, impair market access or access of Idaho communities to vital goods and services, and whether the line has
a potential for profitability.

The Idaho Public Utilities Commission also conducts inspections of Idaho’s railroads to determine compliance
with state and federal laws, rules and regulations concerning the transportation of hazardous materials,
locomotive cab safety and sanitation rules, and railroad/highway grade crossings.

Hazardous material inspections are conducted in rail yards. In 1994, Idaho was invited to participate in the
Federal Railroad Administration’s State Participation Program. IPUC has a State Program Manager and two FRA
certified hazardous material inspectors.

The IPUC inspects railroad-highway grade crossings where incidents occur, investigates citizen complaints of
unsafe or rough crossings and conducts railroad-crossing surveys.

Railroad Activity Summary 2014

Inspections 150
Rail cars inspected 1580
Violations 1
Rail cars with defects 88
Crossing accidents investigated 28
Locomotives Inspected 7
Defects within locomotives inspected 0

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REGULATING IDAHO’S PIPELINES

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 establishes 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 facilities
provided the standards are compatible with federal regulations.

The Idaho Public Utilities Commission has a state program manager and two training and certified
pipeline safety inspectors who conduct records audits and field installed equipment inspections on all
intrastate natural gas pipeline operators under jurisdiction.

Pipeline Safety Activity Summary

Standard inspection days 175
Compliance inspection days 10
Damage prevention inspection days 0
Construction inspection days 8
Operator Qualification inspection days 12.5
Integrity Management Program inspection days 15
Incident/Accident inspection days 1
Operator Training inspection days 0

Compliance Enforcement Actions:
Notice of Probable Violation 3
Notice of Amendment 2
Warning Letters 3

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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 2014 calendar year. (The financial report on Page 9 covers Fiscal Year July 1, 2014 through June 30, 2015.) Anyone with access
to the Internet may also review the commission’s agendas, notices, case information and decisions by visiting the IPUC’s Web site at:
www.puc.idaho.gov. Commission records are also available for public inspection at the commission’s Boise office, 472 W. Washington St.,
Monday through Friday, 8 a.m. to 5 p.m.
The Idaho Public Utilities Commission, as outlined in its Strategic Plan, serves the citizens and utilities of Idaho by determining fair, just
and reasonable rates for utility commodities and services that are to be delivered safely, reliably and efficiently. During the period
covered by this report, the commission also had responsibility for ensuring all rail services operating within Idaho do so in a safe and
efficient manner. The commission also has a pipeline safety section that oversees the safe operation of the intrastate natural gas
pipelines and facilities in Idaho.

Costs associated with this publication are available from the Idaho Public Utilities Commission in accordance with Section 60-202,
Idaho Code, PUC 12-100-2015.

Questions:
Gene Fadness, PUC Public Information Officer
334-0339
[e-mail]