2016 Annual Report FINAL 12 1 16 (Repaired).doc

ANNUAL REPORT
2016

Table of Contents

Commissioners 8
Financial Summary Fund 0229 11
Fiscal Years 2012 – 2016 11
Commission Structure and Operations 12
Administration 14
Legal 15
Utilities Division 15
Railroad and Pipeline Safety Section 16
Pipeline Safety 16
Why can’t you just tell them no? 17
2016 MAJOR EVENTS 18
Electrical Power in Idaho 43
Electric RATE CHANGES 44
Natural Gas 66
Gas Cases 68
Water 73
Telecommunications 79
Consumer Assistance 82
Regulating Idaho’s Railroads 83
Regulating Idaho’S PIPELINES 84

Idaho Public Utilities Commission

Contact us: 208-334-0300 Website: www.puc.idaho.gov
Commission Secretary 334-0338
Executive Assistant 334-0330
Public Information 334-0339
Utilities Division 354-0367
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 2016 Annual Report.”
Front cover photograph courtesy of Idaho Power Company.

December 1, 2016

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 2016 Annual Report. This report is a detailed description of the most significant cases, decisions and other activities during 2016. The financial report on Page 10 is a summary of the commission’s budget through the conclusion of Fiscal Year 2016, which ended June 30, 2016.
It has been a privilege and honor serving the people of Idaho this past year.

Sincerely,

Paul Kjellander
President, Idaho Public Utilities Commission

Commissioners

Paul Kjellander
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 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 FCC’s 706 Joint Board and serves as vice chairman of the NARUC Telecommunications Committee. He is currently serving as a NARUC representative to the North American Numbering Council (NANC) and an at-large member of the National Council on Electricity Policy (NCEP).
Kjellander is a licensed youth soccer coach and has qualified teams for various state and regional tournaments.
Kristine (Sasser) Raper
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, Raper served seven years as a deputy attorney general assigned to the Public Utilities Commission. In her time as an attorney for the PUC, Raper was involved in electric, gas, water and telecommunications cases. Commissioner Raper defended the Idaho PUC’s decisions regarding PURPA in front of the Idaho Supreme Court, District Court and Federal Energy Regulatory Commission.
Prior to 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 matters appealed through the state Department of Labor.
Commissioner Raper serves on the Electricity Committee of the National Association of Regulatory Utility Commissioners (NARUC) and is the incoming vice president of the Western Conference of Public Service Commissioners. She also currently serves on the Member Advisory Committee of the Western Electric Coordinating Council (WECC) and as a member of the State Provincial Steering Committee.
Commissioner Raper was born in Delaware and moved to Utah with her family in the early 1980s. She moved to Boise in 1990 to attend Boise State University. 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.
The commissioner and her husband, Mark, share three children.

eric anderson
Eric Anderson of Priest Lake was appointed to the commission in December 2015. Commissioner Anderson’s term expires in January 2019.
Anderson, a Republican, served 10 years in the Idaho Legislature from 2005-14. He chaired the House Ways and Means Committee during his final term. He also served on these committees: Environment, Energy and Technology; Resources and Conservation; and State Affairs. He chaired a legislative Interim Subcommittee on Renewable Energy.
He received his Bachelor of Arts degree in political science and government from Eastern Washington University in 1979.
A general contractor and real estate broker, he also served as director and vice president of Sandpoint-based Northern Lights Inc. He’s also served as a director on the Idaho Consumer Owned Utilities Association, the National Rural Electric Cooperative Association and the Idaho Energy Resources Authority. He is a past member and more recently an advisor to the Pacific States Marine Fisheries Council and the Pacific Northwest Economic Region’s Executive Council.

Financial Summary Fund 0229
Fiscal Years 2012 – 2016

Description FY 2012 FY 2013 FY 2014 FY 2015 FY 2016     Personnel Costs $3,304,100 $3,491,500 $3,528,900 $3,563,500 $3,835,900 Communication Costs $29,500 $31,300 $31,000 $23,500 $28,700 Employee Development Costs $62,500 $55,600 $53,200 $99,200 $98,700 Professional Services $9,800 $9,700 $12,300 $8,500 $18,600 Legal Fees $525,300 $551,600 $519,700 $538,400 $579,400 Employee Travel Costs $115,400 $123,600 $141,100 $152,500 $159,200 Fuel & Lubricants $4,100 $4,700 $2,700 $5,600 $2,900
Insurance $1,000 $3,100 $4,400 $4,300 $2,000 Rentals & Leases $294,200 $276,100 $584,600 $308,600 $223,800 Misc. Expenditures $85,600 $117,000 $104,700 $84,400 $83,900 Computer Equipment $24,300 $29,200 $66,400 $73,600 $52,200 Office Equipment $0 $13,000 $11,900 $16,500 $8,100 Motorized/Non-Motorized Equip $52,300 $0 $0 $32,500 $0 Specific Use Equipment $0 $0 $0 $0 $1700     Total Expenditures $4,508,100 $4,706,400 $5,060,900 $4,911,100 $5,095,100     Fund 0229-20 Appropriation $4,768,200 $4,916,800 $5,061,700 $5,595,600 $5,766,500               Unexpended Balance $260,100 $210,400 $800 $684,500 $671,400

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.
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 testimony and evidence, subject to cross-examination by attorneys from the other parties, staff and the commissioners. At public hearings, members of the public may testify before the commission.
Many public hearings are conducted in cities and towns that are part of the service territory of the utility seeking a rate increase. In less contested rate cases, the commission will sometimes conduct hearings telephonically to save expense and allow customers to testify from the comfort of their own homes. Commissioners and other interested parties gather in the Boise hearing room and are telephonically connected to ratepayers who call in on a toll-free line to provide testimony or listen in to those 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 Meetings Law, commissioners may also privately deliberate fully submitted matters.

Commission Staff
OUR MISSION

Determine fair, just and reasonable rates and utility practices for electric, gas and water consumers.
Ensure that delivery of utility services is safe, reliable and efficient.
Ensure safe operation of pipelines and rail carriers within the state.
To help ensure its decisions are fair and workable, the commission employs a staff of about 50 people – engineers, rate analysts, attorneys, accountants, investigators, economists, secretaries and other support personnel. The 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 is the primary contact for matters concerning Information Technology, Fiscal and Human Resources. He also serves as a liaison between the commission and other state agencies and the Legislature. Contact IT, Fiscal, Human Resources. 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 Karl Klein, legal division director, at 334-0320.

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 six auditors and one manager 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, two analysts and one supervisor 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 Mike Louis, engineering section supervisor, at 334-0316.
The Technical Analysis Section of four utility analysts and one supervisor 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.
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. Contact Carolee Hall, 334-0364 or Grace Seaman, 334-0352.

The Consumer Assistance Section includes five division investigators and one supervisor 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, Consumer Assistance administrator, at 334-0302.

Railroad Section

Our rail inspector 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 four-member 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.

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 more than 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.
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. 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.
2016 MAJOR EVENTS

Idaho commissioners part of FERC technical conference

Idaho Commission President Paul Kjellander and Commissioner Kristine Raper testified at a Federal Energy Regulatory Commission technical hearing on June 29, 2016, regarding FERC’s implementation of PURPA. Kjellander and Raper and Montana Commissioner Travis Kavulla (testifying as president of the National Association of Regulatory Utility Commissioners) were the only state regulators among the 20 panelists who testified at the day-long hearing.
PURPA is the Public Utility Regulatory Policies Act. Enacted in 1978 during the energy crisis to incent renewable generation, PURPA requires that electric utilities buy power produced from qualifying independent small-power producers. The rate to be paid small-power producers is determined by state commissions and is called an “avoided-cost rate” because it is to be equal to the cost the electric utility avoids if it would have had to generate the power itself or purchase it from another source. In Idaho, 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.
Over the last decade, Idaho has been a focal point in the national debate over how states manage a rapid increase in the number of new PURPA projects that are intermittent in their generation, particularly wind and solar projects. After the Idaho commission reduced the size of projects that can qualify for the state’s published rates and stopped the practice of project disaggregation (under which the same developer broke up a large project into several smaller projects and spaced them a mile apart, the minimum required by FERC to be considered a separate project), wind developers filed complaints at FERC. In response, FERC filed a complaint in federal court in March 2013 asking the court to find that the Idaho commission had violated PURPA and enjoin the PUC from imposing conditions on sales agreements between Idaho Power Company and the developers of several wind projects. It was the first time FERC had taken a state to court over a PURPA-related action. Some of the same wind developers also appealed to the state Supreme Court.
On Dec. 18, 2013, the state Supreme Court unanimously affirmed the PUC’s decision to deny approval of the Grouse Creek wind contracts. Six days later, FERC and the Idaho commission signed a Memorandum of Agreement under which FERC dismissed its court claims and the PUC dismissed any counterclaims.
Some of the same issues resurfaced two years later with the rapid development of new solar PURPA projects. In the three months from November 2015 to January 2015, the Idaho PUC approved 13 solar projects totaling 400 MW, some of which were later canceled.
While supportive of the overall goals of PURPA to incent renewable generation, the Idaho commission has expressed growing concern over rates customers must pay for PURPA projects and whether those projects are needed by the utility.
Idaho’s three investor-owned utilities have about 135 PURPA projects under contract representing a nameplate capacity of more than 1,200 megawatts. In the first 25 years of PURPA, Idaho Power had accumulated less than 200 MW of PURPA generation and PacifiCorp had about 300 MW in eastern Idaho. Since 2007, the amount of PURPA generation for Idaho Power increased nearly six-fold and seven-fold for PacifiCorp.
This rapid development of new projects came at the same time utilities were experiencing flat or slight growth in energy consumption. The rapid development of PURPA projects prompted a number of concerns from the Idaho commission including, 1) PURPA generation that is not needed to serve loads, 2) large amounts of intermittent generation requiring stand-by generation, 3) long-term, fixed-price PURPA contracts that place greater risks on both the utilities and customers, 4) operating and reliability issues, and 5) planning issues caused by the “must purchase” obligations of PURPA, resulting in the procurement of large amounts of unneeded power.

The FERC technical conference focused on two issues: the “mandatory purchase obligation,” that utilities have under PURPA and the determination of avoided costs. Participants were asked to submit post-technical conference comments. Below (pages 19-32) are the comments the Idaho commission submitted to FERC in early November 2016.

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

TECHNICAL CONFERENCE ON IMPLEMENTATION ISSUES UNDER THE PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978 )
)
)
)
)
DOCKET NO. AD16-16-000
POST-TECHNICAL CONFERENCE COMMENTS OF
THE IDAHO PUBLIC UTILITIES COMMISSION
The Idaho Public Utilities Commission (Idaho PUC) again thanks the Commission for the opportunity—through written comments and as panelists at the technical conference—to offer our perspective on issues concerning implementation of the Public Utility Regulatory Policies Act of 1978. The Idaho PUC is the state agency that regulates public utilities operating in Idaho. Our responsibilities include ensuring the reliability of electric service in Idaho at just and reasonable rates, and implementing PURPA in accordance with the Commission’s regulations. We now submit the following post-technical conference comments in response to the Commission’s September 6, 2016 notice inviting comments on specific issues enumerated below.

The One-Mile Rule and Project Manipulation through Disaggregation
The “one-mile rule” refers to the Commission’s test for determining whether facilities are located at the same site for purposes of eligibility under PURPA. Under PURPA Section 201, the maximum size of a small power production facility seeking Qualifying Facility status is 80 megawatts (MW) “together with any other facilities located at the same site (as determined by the Commission).” The Commission’s regulations—originally adopted in Order No. 70—provide in relevant part:

§ 292.204 Criteria for qualifying small power production facilities.

(a) Size of the facility –

(1) Maximum size. Except as provided in paragraph (a)(4) of this section [which addresses certain QFs certified before 12/31/1994], the power production capacity of a facility for which qualification is sought, together with the power production capacity of any other small power production facilities that use the same energy resource, are owned by the same person(s) or its affiliates, and are located at the same site, may not exceed 80 megawatts.

(2) Method of calculation.

(i) For purposes of this paragraph, facilities are considered to be located at the same site as the facility for which qualification is sought if they are located within one mile of the facility for which qualification is sought and, for hydroelectric facilities, if they use water from the same impoundment for power generation.

(ii) For purposes of making the determination in clause (i), the distance between facilities shall be measured from the electrical generating equipment of a facility.

18 C.F.R. § 292.204(a)(1) and (2).
To determine whether a facility is within the 80 MW limit, the facility’s capacity is combined with the capacity of any other facilities which use the same energy resource, are owned by the same person(s) or its affiliates, and are located at the same site. 18 C.F.R. § 292.204(a)(1). Facilities are presumed to be at the same site as a facility for which qualification is sought if they are within one mile of that facility (measured from electrical generating equipment). Id. at § 292.204(a)(2). This is referred to as the “one-mile rule.”
Applying this rule, if two facilities share the same energy resource, are owned by the same person, and are located within one mile of each other, their capacities are aggregated for purposes of determining whether they are under the 80 MW limit. On the other hand, if two facilities share the same energy resource, are owned by the same person, but are located one mile and 10 feet from each other, they are considered two separate facilities and their capacities will not be aggregated. The Commission asked for comments on three specific questions about the rule. The Idaho PUC’s comments are as follows.

1. Should the presumption inherent in the one-mile rule be made rebuttable? If so, who—the interconnecting utility or the QF—should bear the burden of overcoming the presumption?
The Commission has stated that:
. . . [S]ection 292.204(a)(2)(i) of the Commission’s regulations was not intended to establish and did not establish merely a rebuttable presumption. Instead, section 292.204(a)(2)(i) established a rule that facilities that use the same energy resource, and that are owned by the same person(s) or its affiliates and that are located within one mile of each other are at the same site. There is certainly no language in that rule that suggests otherwise, i.e., that it is merely a rebuttable presumption. To the contrary, the language reads, as it was supposed to read, as a rule.

Recognizing both that the one-mile rule in its current form is not rebuttable and that “when we hear about costs totaling potentially in the billion dollars or more over relatively sparsely populated states, it’s a big enough deal . . . to get our attention,” we respectfully suggest that the administrative considerations that originally led the Commission to adopt a hard-and-fast rule may be worth revisiting. The one-mile rule’s current prescription that facilities within a mile of each other are located at the same site (and conversely, that those that are more than a mile apart are not at the same site) should be rebuttable by the facility/project developer. The burden of overcoming the presumption must be on the project developer because only the project developer—not the utility—has the information that would be necessary to meet or rebut the presumption. Under the rule, a facility that is within one mile of others with which it has a common owner and shares an energy resource will be presumed to be a single QF together with those other facilities. To qualify for PURPA, the aggregate sum of their capacity has to be within 80 MW.
If the facility wishes to challenge this presumption, it is the party that has the information to rebut it and should bear the burden of doing so. Conversely, a facility that is located at the same site as others and shares an energy resource, but has different ownership, will be presumed to be a separate QF. If a utility or a state regulator believes the facilities really do share common ownership, or that a single facility has been segmented or disaggregated artificially in order to gain the advantage of PURPA’s must-purchase obligation, it might refuse to offer or to approve (as the case may be) separate contracts to the facilities. In that case, the project developer can bring a complaint to the state regulatory agency. If the utility presents evidence that the facilities share ownership, the project developer has the information to prove otherwise and should bear the burden of demonstrating that they do not.
In his earlier written comments in this docket, Commissioner Kjellander proposed several criteria that could be used to determine whether certain QF facilities are located at the same site. These factors could be used by the QF, or by utilities, to challenge the presumption. The proposed parameters are reproduced here for ease of reference and would allow for a detailed, fact-based analysis. The parameters include, but are not intended to be limited to, whether facilities that are in close proximity:

Use the same motive force or fuel source
Are owned or controlled by the same person(s) or affiliated person(s)
Are placed in service within 12 months of an affiliated project’s commercial operation dates as specified in the power sales agreement
Share a common point of interconnection or interconnection facilities
Share common control, communications, and operation facilities
Share a common transmission interconnection agreement
Have a power sales agreement executed within 12 months of a similar facility in the same general vicinity
Are operated and maintained by the same entity
Are constructed by the same entity within 12 months
Use common debt or equity financing
Are subject to a revenue sharing arrangement
Obtain local, state and federal land use permits under a single application or as a single entity
Share engineering or procurement contracts

We believe that PURPA and the Commission’s regulations provide state regulatory agencies discretion and tools to address disaggregation. However, the Commission should clarify, perhaps via a Policy Statement, that state regulatory agencies have discretion and tools such as those described above. In the alternative, the Commission could revise its regulations to provide additional clarity. In response to Commissioner Clark’s request, Tr. at 63:19-66:12, we attach Appendix A to our comments, which provides an example of how the Commission’s regulations might be changed to make the presumption rebuttable.

2. Alternatively, should the Commission consider modifying the rule to either require projects seeking QF status to be spaced further apart or allowed to be closer together?

There is no “correct” distance that would—by itself—ensure the rule’s effectiveness. First, the “right” allowed distance may depend on geography and climate, among other regional factors. Also, the allowed distance may need updates to account for advancements in technology and industry, or economic and societal changes. Without an ability to rebut the presumption using other criteria, such as those proposed by Commissioner Kjellander, changing the allowed distance would merely set a different distance around which a project’s technical, financial or other structures could be manipulated. To avoid the adverse consequences of “manipulating” QF status through project disaggregation, states must have the discretion, using objective criteria, to determine whether multiple facilities in proximity to one another are separate QFs that fit within, or a single QF that exceeds, the 80 MW project capacity limit imposed by PURPA Section 201 and implemented in the Commission’s regulations.

3. Should the Commission consider a more fact-based analysis based on criteria such as those proposed by Edison Electric Institute (EEI) and Idaho Commissioner Kjellander?

The Commission should allow states the discretion to engage in a fact-based analysis of a project’s circumstances to determine whether multiple facilities in proximity to one another are separate QFs or a single QF. We continue to support the reasonable parameters proposed by EEI and Commissioner Kjellander. However, the parameters should be a guide, not a strictly-applied checklist, and the inquiry should be whether the proposed project adheres to PURPA’s intent: to encourage small power production facilities—those of a maximum generating capacity of 80 MW at the same site. Because the inquiry requires evaluation of a multitude of factors, including region-specific factors, we believe the state commissions are in the best position to assume this analysis and determination.

4. Cooperative federalism: a federal-and-state solution to achieve PURPA’s goals.

Based on the definitional language of PURPA Section 201 and the Commission’s regulations, we believe that the state regulatory agencies must have responsibility and discretion to determine whether a proposed project meets or exceeds the 80 MW size limit placed on QF status by the statute and regulations. In order for this cooperative effort between the federal and state commissions to be effective, it is important to recognize all of PURPA’s stated goals, which include ensuring reasonable rates that are in the public interest.

a. We must recognize all—and not just some—of PURPA’s goals.
PURPA’s goals are “(1) to encourage ‘conservation of energy supplied by . . . utilities’; (2) to encourage ‘the optimization of the efficiency of use of facilities and resources’ by utilities; and (3) to encourage ‘equitable rates to . . . consumers.’” FERC v. Mississippi, 456 U.S. 742, 746 (1982), quoting 16 U.S.C. § 2611 (other citations omitted). Consistent with these goals, section 210 of the statute “seeks to encourage the development of cogeneration and small power production facilities [that is, QFs].” Id. at 750, citing 16 U.S.C. § 824a-3 (other citations omitted). PURPA requires that rates paid for purchases from QFs “(1) shall be just and reasonable to the electric consumers of the electric utility and in the public interest, and (2) shall not discriminate against [QFs].” 16 U.S.C. § 824a-3(b). As is evidenced by the great number of PURPA projects producing energy in Idaho, the IPUC fully supports and embraces these goals. However, encouraging development of QFs without regard for whether customers are paying equitable, just and reasonable rates is inconsistent with PURPA and the regulations and not in the public interest. This is precisely why regulators charged with implementing PURPA and the Commission’s regulations must have adequate tools to ensure that the Act’s intent is satisfied and that no single goal is advanced at the expense of others.

b. Duty to safeguard ratepayers from harm caused by manipulation through disaggregation.

In addition to encouraging development of QFs and resource optimization, we have a duty as regulators to ensure equitable, just and reasonable rates to consumers. As noted in our opening comments and at the technical conference, the Idaho PUC has seen the negative impacts to consumers’ rates from projects that are disaggregated solely to qualify for more lucrative PURPA contracts. We have seen disaggregated projects seeking to stay under 80 MW to qualify for PURPA’s avoided cost rates generally, as well as disaggregation to meet the lower threshold for standard published rate contracts. Disaggregation inevitably results in increased costs to consumers by increasing the number of projects eligible for PURPA contracts and avoided cost rates, including standard published rates. Comments of Commissioner Paul Kjellander at 4-6 (June 29, 2016) (Kjellander Comments); Tr. at 34-36.
As an example of the cost to ratepayers of PURPA purchase contracts, PacifiCorp, whose subsidiary, Rocky Mountain Power, is a public utility regulated by the IPUC, estimated in 2015 that it would be required under PURPA to purchase 39 million MW hours over the 2015-2025 time period, at a cost to ratepayers of $1.1 billion above market prices. “Discussion Draft on Accountability and Department of Energy Perspectives on Title IV: Energy Efficiency” Hearing before the Subcommittee on Energy and Power, Committee on Energy and Commerce, House of Rep., 114th Cong., Testimony of Paul Weisgall, Tr. at 28 (June 4, 2015). This cost is being incurred at a time when PacifiCorp does not forecast a need for additional generation until 2028. Id. at 27-28.
Idaho Power Company, another of the public utilities regulated by the IPUC, estimated in 2015 that its total PURPA purchase obligations, excluding approved but not yet constructed projects, was $2.6 billion over the life of the contracts. Pet. of Idaho Power Co. to Modify Terms and Conditions of Prospective PURPA Energy Sales Agreements at 3, Idaho PUC Case No. IPC-E-15-01 (Jan. 30, 2015). This was also at a time when the company did not forecast a need for capacity or energy until at least 2021. Id.
As a final example, in 2011 Rocky Mountain Power applied for an order accepting or rejecting a standard rate PURPA purchase contract with each of five disaggregated projects. App. of Rocky Mountain Power for Approval of Power Purchase Agreements between Rocky Mountain Power and Cedar Creek Wind, pt. 6, Idaho PUC Case No. PAC-E-11-05 (Jan. 10, 2011). Rocky Mountain Power explained that the group of five projects had originally been proposed as a single project, greater than 80 MW and not eligible for PURPA. Id. It then proposed two 78-MW projects, eligible for negotiated rates. Id. It then disaggregated further into five smaller projects, each separated by one mile, eligible for Idaho’s standard published rate contracts at that time. Id. The company estimated that the cost impact of a group of five projects that had disaggregated to qualify for more favorable standard rate contracts was $10 million per year over the life of the contract ($10 million per year was the difference between standard published avoided cost rates and the negotiated avoided cost rates). Id.
The one-mile rule is currently a categorical standard that does not allow for consideration of other, potentially relevant factors to determine whether facilities are one or multiple QFs for purposes of FERC size limits. Projects with the same ownership, same energy source, same operations and interconnection dates, etc., that have been disaggregated in order to qualify as a PURPA project eligible under the 80 MW threshold, or for standard published rate contracts violate the Act and the regulations. Our review of these projects did not allow for inquiry into whether the facility was truly a small power production facility intended to receive the benefits of QF status under PURPA.
The following chart shows the wind projects brought before the IPUC in 2009 and 2010, for approval as standard rate 20-year contracts with deliveries not to exceed 10 aMW per month. They are grouped by common location (if a group had common ownership, each project within the group was at least one mile apart) and other shared characteristics, including contract date. The approved projects were each treated as separate QFs, although if tools had been available to perform a more fact-based analysis, a different result might have been reached in some cases. Disapprovals of contracts dated on or after December 14, 2010, were based on the contracts containing incorrect pricing contained in the contract.

Project Name Location
(approximate)
Utility
Contract Date Date of Approval /Disapproval Capacity (MW) Camp Reed Wind Park Hagerman, Idaho Idaho Power 9 Jul 2009 Approved
8 Oct 2009 22.5 Yahoo Creek Wind Park Hagerman, Idaho Idaho Power 9 Jul 2009 Approved
8 Oct 2009 21 Payne’s Ferry Wind Park Hagerman, Idaho Idaho Power 9 Jul 2009 Approved
8 Oct 2009 21 Sawtooth Wind Project Glenns Ferry, Idaho Idaho Power 1 Sep 2009 Approved
16 Dec 2009 21 Power County Wind Park North Power County, Idaho PacifiCorp 18 Aug 2010 Approved
6 Oct 2010 21.78 Power County Wind Park South Power County, Idaho PacifiCorp 18 Aug 2010 Approved
6 Oct 2010 21.78 Cold Springs Windfarm Mountain Home, Idaho Idaho Power 12 Nov 2010 Approved
23 Dec 2010 23 Desert Meadow Windfarm Mountain Home, Idaho Idaho Power 12 Nov 2010 approved
23 Dec 2010 23. Hammett Hill Windfarm Mountain Home, Idaho Idaho Power 12 Nov 2010 Approved
23 Dec 2010 23 Mainline Windfarm Mountain Home, Idaho Idaho Power 12 Nov 2010 Approved
23 Dec 2010 23 Ryegrass Windfarm Mountain Home, Idaho Idaho Power 12 Nov 2010 Approved
23 Dec 2010 23 Two Ponds Windfarm Mountain Home, Idaho Idaho Power 12 Nov 2010 Approved
23 Dec 2010 23 Deep Creek Wind Park, LLC Rogerson, Idaho Idaho Power 10 Dec 2010 Approved
11 Feb 2011 20 Cottonwood Wind Park LLC Rogerson, Idaho Idaho Power 10 Dec 2010 Approved
11 Feb 2011 20 Rogerson Flats Wind Park LLC Rogerson, Idaho Idaho Power 10 Dec 2010 Approved
11 Feb 2011 20 Salmon Creek Wind Park LLC Rogerson, Idaho Idaho Power
Idaho Power 10 Dec 2010 Approved
11 Feb 2011 20 Coyote Hill / Cedar Creek LLC Bingham County, Idaho PacifiCorp
22 Dec 2010 Approved
21 Dec 2011 26.7 North Point / Cedar Creek LLC Bingham County, Idaho PacifiCorp 22 Dec 2010 Approved
21 Dec 2011 80 Five Pine / Cedar Creek LLC Bingham County, Idaho PacifiCorp 22 Dec 2010 Approved
21 Dec 2011 26.7 Rattlesnake Canyon / Cedar Creek LLC Bingham County, Idaho PacifiCorp 22 Dec 2010 Disapproved
21 Dec 2011 27.6 Steep Ridge / Cedar Creek LLC Bingham County, Idaho PacifiCorp 22 Dec 2010 Disapproved
21 Dec 2011 25.3 Murphy Flat Mesa Murphy, Idaho Idaho Power 15 Dec 2010 Disapproved
8 Jun 2011 25 Murphy Flat Energy Murphy, Idaho Idaho Power 15 Dec 2010 Disapproved
8 Jun 2011 25 Murphy Flat Wind Murphy, Idaho Idaho Power 15 Dec 2010 Disapproved
8 Jun 2011 25 Rainbow Ranch Wind Declo, Idaho Idaho Power 15 Dec 2010 Disapproved
8 Jun 2011 23 Rainbow West Wind Declo, Idaho Idaho Power 15 Dec 2010 Disapproved
8 Jun 2011 23 Grouse Creek Wind Park Lynn, Utah Idaho Power 28 Dec 2010 Disapproved
8 Jun 2011 21 Grouse Creek Wind Park II Lynn, Utah Idaho Power 28 Dec 2010 Disapproved
8 Jun 2011 21 Alpha Wind Burley, Idaho Idaho Power 15 Dec 2010 Disapproved
8 Jun 2011 29.9 Bravo Wind Burley, Idaho Idaho Power 15 Dec 2010 Disapproved
8 Jun 2011 29.9 Charlie Wind Burley, Idaho Idaho Power 15 Dec 2010 Disapproved
8 Jun 2011 27.6 Delta Wind Burley, Idaho Idaho Power 15 Dec 2010 Disapproved
8 Jun 2011 29.9 Echo Wind Burley, Idaho Idaho Power 15 Dec 2010 Disapproved
8 Jun 2011 29.9 The circumstances of these projects suggest that they were disaggregated to qualify for the more favorable (higher) standard rate, or to take advantage of PURPA’s must-purchase obligation—at a cost to ratepayers. They are precisely the type of projects that should be reviewed for a determination whether they satisfy the intent of PURPA Section 201 and the Commission’s implementing regulations. To protect the state’s retail ratepayers, state regulatory commissions need the ability and discretion to determine whether a QF is manipulating its project contrary to PURPA’s and the regulations’ intent.
c. Solution: fact-based, discretionary determination that a project satisfies the rule’s intent.
During the technical conference, Commissioner Clark asked whether anyone cared to defend disaggregation. Tr. at 65. No one responded. Later, Todd Glass, representing the Solar Energy Industries Association, stated that he would not want changes to the one-mile rule to “eliminate the value of economies of scale.” Tr. at 66. Mr. Glass continued “we don’t want abuse and nobody in the solar industry [wants to] play games or abuse the . . . one-mile rule,” adding, “we do want to encourage the efficient development of strong players that can actually follow through on their commitments and deliver . . . renewable power to the grid.” Tr. at 67. Also, Laura Chappelle, representing the Independent Power Producers Coalition of Michigan, stated that she wanted to defend the one-mile rule “in the context of existing facilities,” then clarified that she hoped whatever the Commission did would “lend some clarity and [not] affect existing resources who have very real reasons for being a mile or less apart.” Id.
About the one-mile rule, Don Sipe, representing the American Forest and Paper Association, stated that if somebody is “trying to use the rules to get me a better deal . . . that doesn’t sound like gaming to me.” Tr. at 153. Mr. Sipe considered, “What is it that I’m being deprived of by having that other project within a mile?” then continued, “what we want to see is . . . projects built that are the lowest cost, that have the best chance of working out in the market.” Id. In our view, the problem with this scenario and disaggregation in general is that the price the utility (and ultimately its customers) pay for PURPA projects is not based on project cost—it is based on avoided cost; and the use of disaggregation to qualify for standard rates leads to projects receiving an even higher avoided cost rate. Disaggregation and “lower project costs” do not lead to ratepayers getting a better deal.
State regulatory agencies need clarity and guidance from the Commission as to how facilities should be evaluated for purposes of determining compliance with PURPA’s and the regulations’ size limits. Guidance is also needed regarding any other tools available to the state regulatory agencies in their efforts to enforce PURPA and the regulations. This need was echoed throughout pre-technical conference comments and at the technical conference itself. See Tr. at 45 (Commissioner Kjellander), 46-47 (Joe Schmidt, of Alliant Energy, representing EEI), 47 (Todd Glass), 48 (Allison Clements, representing the Sustainable FERC Project); Comments of the Industrial Energy Consumers of America at 4 (Sept. 14, 2016). As noted above, we believe the intent of the one-mile rule was to ensure that QFs that truly meet the law’s requirements—that is, small power production facilities of 80 MW or less and cogeneration facilities—receive the benefits of the law. We suggest that the Commission make this intent clear.
As proposed above and in our prehearing comments, a set of guidelines would provide QFs with some predictability as they develop their projects and would provide state regulatory agencies tools to ensure that the statute and regulations are implemented as Congress and the Commission intended. Any parameters must be guidelines only. If the parameters are a definitive test, then they would defeat the state’s discretion and ability to address disaggregation.
To successfully deter manipulation through disaggregation and effectively implement the Act, the state regulatory agencies must have discretion to determine whether a project is truly a small power producer or instead a large developer that has disaggregated a single project into multiple facilities in order to maximize its profit at the expense of the utility’s ratepayers.

5. Summary
As we expressed at the technical conference and in our prefiled comments, the IPUC believes in the intent and goals of PURPA. Tr. at 34, 141, 144; Comments of Commissioner Kristine Raper at 1-2 (June 29, 2016) (Raper Comments); Kjellander Comments at 2-3 (June 29, 2016). To ensure that PURPA’s goals are being advanced symbiotically with—and not to the detriment of—the interests of electricity ratepayers, the states should be given discretion to address problems arising from disaggregation that is contrary to the Act’s intent. For this reason, we believe that the presumption in the rule should be made rebuttable, with the burden on the facility seeking certification, to demonstrate it is satisfying the intent of the rule. The state commissions should have the duty of presiding over such challenges, and discretion to do so.

Minimum Standards for PURPA Purchase Contracts
PURPA requires the Commission’s regulations to ensure that rates paid for purchases from QFs “(1) shall be just and reasonable to the electric consumers of the electric utility and in the public interest, and (2) shall not discriminate against [QFs].” 16 U.S.C. § 824a-3(b). In addition, PURPA requires that the purchase rate shall not exceed the “incremental cost” to the utility, defined as the cost of electric energy which, “but for the purchase from [the QF], such utility would generate or purchase from another source.” Id. §§ 824-3(b), (d). The Commission’s regulations repeat these requirements and adopt the “avoided cost” definition and construct. 18 C.F.R. §§ 292.304(a), 292.101(6). In Order No. 69, the Commission elaborated on the avoided cost requirement, explaining that its mandate under PURPA Section 210(a) is to ensure that “the total costs to the utility and the rates to its other customers should not be greater than they would have been had the utility not made the purchase from the qualifying facility or qualifying facilities.” Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,868 (1980)(emphasis added) (explaining why it would not change its rule in 18 C.F.R. § 292.301 to address cogenerators and small power producers who entered into contracts prior to the promulgation of Order 69 under terms and conditions that might be less favorable than those available under Order 69). As the Commission described it, “the intention [of Congress] was to make ratepayers indifferent as to whether the utility used more traditional sources of power or the newly encouraged alternatives.” Southern Cal. Edison, San Diego Gas & Elec., 71 FERC ¶ 61,269 at 62,080 (1995).
The Commission has requested comment regarding minimum standards for PURPA purchase contracts. See Notice, 81 Fed. Reg. 64455. In summary, any minimum requirements for PURPA-purchase contracts must give equal priority to PURPA’s requirements of encouraging QF development and ensuring that rates to consumers are just and reasonable and in the public interest. Each state’s regulatory agency is in the best position to ensure that these competing requirements are met, considering the unique circumstances in each state. If the Commission chooses to adopt guidelines or terms and conditions, it should ensure state regulatory agencies retain the discretion and tools to ensure that rates to consumers remain just and reasonable. We provide comments on the specific questions raised by the Commission below.
We believe that under PURPA and the Commission’s regulations, state agencies currently have discretion and limited tools with which to meet regulatory obligations. However, the Commission should clarify, perhaps through issuance of a Policy Statement, that state regulatory agencies have the discretion necessary to meet their regulatory obligations. Alternatively, the Commission could amend its regulations to provide the additional clarity. In response to Commissioner Clark’s request, Tr. at 66, we provide an example of how the Commission’s regulations might be changed in Appendix A.

There may not be a single appropriate minimum length of a PURPA purchase contract or other minimum contract terms and conditions.

Several panelists at the technical conference and commenters took the position that fixed avoided cost rate contracts must be “long-term” in order for QF developers to obtain financing or otherwise incent generation to be built. See Tr. at 100-101 (Todd Glass), 164-165 (Don Sipe), 186-187 (Todd Foley), 184 (John Hughes). In their conference remarks or written comments, Todd Glass and Thomas Melone indicated that contracts must be 15 years or more to be financeable. Tr. at 100-101 (Todd Glass); Comments of Allco Renewable Energy Ltd., at 2 (June 7, 2016). However, thus far we have not seen evidence (financial statements or otherwise) to demonstrate that this is the case. See Tr. at 171 (Commissioner Raper).
Other commenters, including Commissioner Raper, explained that long-term fixed-rate contracts lead to the utility’s customers paying more for the QF purchase than they would have otherwise, in violation of PURPA. See Tr. at 126-127 (Jeff Burleson) and 142-144 (Commissioner Raper); Comments of the Honorable Travis Kavulla at 6 (June 29, 2016); Comments of Al Brogan at 4-5 (June 29, 2016). This overpayment occurs because the projected avoided cost rate that is fixed at the time of contracting has proven to be, over time, higher than the utility’s ongoing avoided costs. In this situation, ratepayers are not held indifferent.
In the Idaho PUC’s experience, avoided cost rates for larger QFs are declining and will continue to decline in the future. See Raper Comments at 3-4; Idaho PUC Order No. 33357 at 22 (Aug. 20, 2015); Idaho PUC Order No. 33419 at 6, 17-19. When a utility signs a long-term contract with a QF with a locked-in avoided cost rate, and the utility’s actual avoided costs are lower in year 10 of the contract, then the utility is paying more than its avoided costs, and its customers are paying higher rates due to that QF purchase contract and locked-in rate. This is contrary to the intent of PURPA and the Commission’s express regulations. It results in rates that are not just, not reasonable, and not in the public interest—in short, rates that are not consistent with the requirements of PURPA Section 210(b) (16 U.S.C. § 824a-3(b)). State regulatory agencies need the discretion and tools to balance the interests expressed in the Act.
Shorter term PURPA purchase contracts can provide a useful and effective safeguard for the justness and reasonableness required by PURPA Section 210(b)(1). With a shorter term, the must-purchase obligation implemented by 18 C.F.R. § 292.303(a) ensures that the contract will be renewed for subsequent terms, for as many terms as the QF wants, with only the avoided cost rate subject to adjustment each term. Alternatively, longer term contracts can provide a solution to the problem of the divergence of an historic avoided cost from just and reasonable rate levels on a current basis if the avoided cost rate in the contract is subject to adjustment during the term of the contract. Both approaches encourage QF development because the QF has a mandatory purchaser for as long as the QF produces energy.
Several panelists in the technical conference and commenters voiced similar concerns or made similar suggestions. As Jeff Burleson of Southern Company put it, “[t]he combination of increased uncertainty around natural gas prices and the growing share of natural gas combined cycle generation have increased the risk of economic harm to retail customers associated with locking in long-term avoided energy cost payments based on projections of natural gas prices and associated avoided electricity energy costs.” Comments of Jeff Burleson at 6 (June 29, 2016). Mr. Burleson added that outside of the PURPA context, Southern Company generally does not enter into long-term contracts with fixed energy rates—instead, to minimize risk to customers, Southern Company enters into shorter term contracts, or long-term contracts in which the energy rate is linked to market prices and is adjustable. Tr. at 167-168, 200-201.
Al Brogan, representing the Edison Electric Institute (EEI), identified the same risk, stating

[t]he various [avoided cost calculation] methods . . . routinely fail to reflect dynamic market conditions and often force utilities to enter into long-term contracts at prices that are substantially above-market, the costs of which are then passed through to our customers. This problem is only exacerbated by the mandatory purchase obligation that requires utilities to purchase power from a QF even if the power is not needed.

Comments of Al Brogan at 4 (June 29, 2016). He explained that as a result, utilities with large amounts of QF power must often curtail or shutdown less expensive generation in order to take the higher-cost QF power. Id. Mr. Brogan explained that the primary reason for the difference between QF pricing and a utility’s actual avoided cost of energy is the requirement that QFs be allowed to lock-in a fixed-price for a long-term contract. Id. at 10. While those prices have remained fixed, the prices for clean energy resources have declined significantly. Id. These long-term fixed-price QF contracts are resulting in costs to consumers that are higher than they otherwise would have been, contrary to the intent of PURPA.
Mr. Brogan presented EEI’s suggestion for remedying this problem: change the Commission’s regulations to require that avoided cost energy rates will be based on utility’s avoided costs calculated at the time of delivery, and that the avoided cost capacity rates will be calculated either at the time of delivery or when the legally enforceable obligation is incurred, but not more than 12 months prior to the time of delivery. Id. at 5.
Travis Kavulla of the Montana Public Service Commission and commenting on behalf of the National Association of Regulatory Utility Commissioners, identified the same risk in his earlier comments. Comments of the Honorable Travis Kavulla at 6 (June 29, 2016). Commissioner Kavulla suggested that shorter term avoided cost calculations could be appropriate in certain situations, such as where resource solicitations are routinely held and genuinely competitive for needs identified in a utility’s IRP or where a utility, in its IRP, does not forecast a need for an additional owned or long-term contracted energy resources for the next five to seven years. Id. at 9.
These examples illustrate the point that regardless of what term length may be most beneficial for financing a QF, a long-term contract with a fixed avoided cost rate can result in customers paying more than they otherwise would have. This is not what PURPA envisions. A different solution, like one of those discussed above, is needed to protect customers and still encourage QF development. The contract length and other terms and conditions must give equal priority to encouraging QF development and ensuring that customers remain indifferent as to whether a utility uses more traditional resources or purchases from a QF.
The Idaho PUC believes that a variety of factors have led to the prolific development of QFs. Long-term PURPA purchase contracts with favorable avoided cost rates may not be the sole driver. Other factors may include federal and state tax incentives, such as the federal production tax credit and investment tax credit, state Renewable Portfolio Standards and other policies, or a utility need for new generation (that is, through an Integrated Resource Plan or competitive bidding process). Any rules regarding PURPA contract length or other terms and conditions should allow each state’s regulatory agency the discretion to consider the circumstances and factors at play in that state, and to craft policies and solutions that meet the two goals of encouraging QF development and ensuring that customers’ rates are just and reasonable and in the public interest.
Finally, while we acknowledge that availability of financing may be an important factor in encouraging the development of QFs, other PURPA requirements continue to encourage QF development. Such requirements include the mandatory purchase obligation, which ensures a long-term purchaser for the QF’s power; the obligation to purchase at avoided cost rates (even if they may be subject to adjustment); and the exemption for QFs from certain federal and state ratemaking standards. 16 U.S.C. § 824a-3(a), (b), and (e); 18 C.F.R. §§ 292.303, 292.304, and 292.601, 292.602. These requirements are enumerated in the statutory and regulatory language—ensuring of the availability of financing is not. In any case, the PUC’s task is to (1) encourage the development of QFs, including by ensuring that rates do not discriminate against QFs (See 18 C.F.R. § § 292.304); (2) ensure that rates to customers are just and reasonable and in the public interest (Id.; Idaho Code §§ 61-301, 61-502); and (3) outside the PURPA context, ensure that utility investments included in rate base are used and useful, that expenses included in rates were prudently incurred, and that utility service is adequate and reliable (See, e.g., Idaho Code §§ 61-302, 61-502A). For these reasons, state PUCs must have discretion and tools to set contract lengths, terms, and conditions that result in rates to consumers that are just, reasonable, and in the public interest, and that encourage QF development.

Establishing a required minimum contract length or other required contract terms and conditions may affect QF development. The requirement to encourage QF development must be given equal weight with the mandate to ensure that rates to consumers are just and reasonable and in the public interest.

The goal of encouraging QF development must be given equal priority with the requirement to ensure that rates to customers are just and reasonable and in the public interest. 16 U.S.C. § 824a-3(a) and (b). Any minimum required contract length or contract terms and conditions must ensure that customers remain “indifferent” to the purchase from the QF. If a minimum required contract length or other required terms and conditions result in rates to customers that are higher than they otherwise would have been, the purpose of the Act will not be achieved. Any changes to the requirements must ensure that customers’ rates remain just and reasonable.

The 100 kW minimum size threshold for requiring standard rates, and the states’ discretion to set a higher threshold, are appropriate.

The minimum size threshold for requiring standard rates set forth in the Commission’s regulations is 100 kW. 18 C.F.R. § 292.304(c)(1). The states have discretion to establish a higher nameplate capacity cap on the availability of standard rates. Id. § 292.304(c)(2). The Idaho PUC believes that the 100 kW minimum size threshold set forth in the Commission’s regulations, in conjunction with the states’ discretion to adopt higher thresholds, is appropriate. Each state’s regulatory agency is in the best position to evaluate the circumstances in that state and determine whether the minimum threshold or a higher one is appropriate to achieve PURPA’s goals.

Utilities do provide the data to be used in avoided cost calculations, as described in Sections 292.302 and 292.304(e) of the Commission’s regulations. The calculations, in and of themselves, are not the problem.

In our experience, utilities provide the required information and it is useful and helpful in calculating avoided cost rates. Our concern is not necessarily with the calculation itself. As discussed above, our concern is that locking in the calculated rate for a long-term period, when we know that the calculation will soon be outdated and result in a contract price that exceeds actual avoided costs, leads to unjust and unreasonable rates to consumers. Each state regulatory agency must have discretion and tools to allow it to ensure that all its statutory mandates are met.

Conclusion
As expressed in our prehearing comments, Idaho has abundant and available renewable resources, including hydropower, geothermal, solar, wind, and cogeneration resources. Raper Comments at 1. Idaho’s richness in renewable resources ensured us a leading role in tackling the challenges of how to implement PURPA. While the IPUC enjoyed minimal regulatory excitement during PURPA’s first 25 years, the amount of PURPA generation for Idaho’s two largest investor-owned utilities (Idaho Power and PacifiCorp) increased six- and seven-fold respectively, since 2007, resulting from advancements in conservation, energy efficiency, and technology, as well as federal and state tax incentives. Id. at 2; see Kjellander Comments at 1. Given our involvement in the development of PURPA to date, we appreciate the opportunity to provide these comments and participate in the technical conference. We hope to help shape PURPA’s next 25 years and beyond.
The IPUC fully supports and embraces all of PURPA’s goals, including the advancement of renewable energy and energy conservation, the promotion of optimal efficiency in the use of utility resources, and the encouragement of equitable consumer rates in the public interest. See FERC v. Mississippi, 456 U.S. at 746; 16 U.S.C. §§ 2611, 824a-3(b). We believe PURPA remains an important piece of the statutory and regulatory framework concerning energy in this country and in Idaho. We have made every effort to work within the statutory and regulatory framework to resolve issues of PURPA’s implementation in Idaho.  We recognize, like many others, that in the years since PURPA was passed there have been many changes in the energy industry and that, in today’s marketplace, there are avenues for the development of QFs apart from PURPA that did not exist previously. Given the changed circumstances, state regulatory agencies need discretion and tools to continue to be able to implement PURPA effectively considering the facts of each case.
In addressing the issues raised in this technical conference, we urge the Commission not to eliminate the existing tools that we and other state regulatory agencies have successfully used to balance and fulfill our regulatory obligations.  Instead, we propose that the Commission clarify the intent of its regulations, and allow the state agencies broader discretion to implement them, in keeping with the Commission’s intent.  Certain clarifications to the one-mile rule and to the regulations regarding avoided cost pricing would be helpful to ensure that all of PURPA’s goals can be advanced. With the clarifications, state regulatory agencies would have the discretion and the tools to more successfully implement the statute and the Commission’s regulations and ensure the viability of PURPA and the advancement of PURPA’s goals well into the future.

2016 Major Events

Permissive 10-digit dialing launched Nov. 5 in preparation for Idaho’s second area code

Case No. GNR-T-15-06
October 28, 2016 – Beginning Nov. 5, Idahoans started getting accustomed to 10-digit dialing when placing local calls. That date kicked off a nine-month “permissive dialing period,” before mandatory 10-digit dialing begins in August 2017 to accommodate a second area code in the state.
The second area code – “986” – will be issued to new telephone numbers beginning in the fall of 2017. Assigning the 986 code to only new numbers means that no existing numbers will need to be changed. However, all users will need to dial 10-digits (area code, plus prefix, plus 4-digit number) to have calls completed. Long-distance or toll calls on landlines will require a “1” before the area code, the same as long-distance calls now require.
The second area code is necessary because numbers under the 208 code are running out, due primarily to increased use of cell phones, the Internet, Voice over Internet Protocol (VoIP), and other advancing technologies.
The nine-month permissive dialing period will also include an educational campaign from telecommunication providers.
“The commission, as well as the telecommunications industry, wanted to allow plenty of time for customers to prepare for the change and get used to 10-digit dialing,” said Paul Kjellander, president of the Idaho Public Utilities Commission.
Most telecommunications devices, even landline phones, now have number storage capability that allows customers to program numbers into their phones and reach their contacts with the press of one or two buttons. Over the next nine months, customers should change the numbers they have programmed into their phones to include the area code. When mandatory 10-digit dialing begins next August, all calls, even local calls, without an area code will not be completed. Callers will get a recording telling them to hang up and dial again and include the area code.
Local calls on landline phones will still not cost anything, even though dialing the area code will be required. The move to a second area code will not impact rates.
Callers will still dial just three digits when calling 911, 211, 411 and 811.
Customers should ensure all services such as automatic dialing equipment, software or other types of equipment recognize 986 as a valid area code. Examples include life-safety systems, facsimile machines, Internet dial-up numbers, alarm and security systems, security gates, ankle monitors, speed-dialers, call-forwarding settings and voicemail services. Contact your medical alert or security provider if you are not sure whether your equipment needs to be reprogrammed to accommodate 10-digit dialing.
Idaho is one of few states that still has one area code. The 208 code was issued in 1947. In August 2001, Neustar, Inc., the administrator of the North American Numbering Plan, projected that Idaho would run out of available numbers under its 208 area code by 2003. In response, the commission implemented various numbers conservation plans that have been successful in delaying a second area code by 15 years.
While the commission acknowledged that 10-digit dialing may be inconvenient for some, the move to 10-digit dialing is inevitable due to advancing technology, regardless of whether Idaho had to acquire a second area code. Developing technology “will eventually drive seven-digit dialing into obsolescence,” 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.”
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QUICK FACTS: Idaho’s Area Code
Idaho telecommunications providers were informed in 2015 that Idaho’s “208” area code is projected to exhaust by mid-2018, necessitating a second area code by no later than Fall 2017. The second area code will be “986.” There is no impact on rates.
Idaho has been able to avoid a second area code for 16 years. The state was informed in 2001 that the area code would exhaust by 2003. The commission implemented a numbers conservation plan in the Boise metro area that worked until 2007 when the state was notified that the area code would exhaust in 2010. The commission then extended the numbers conservation plan statewide, bringing us to a mid-2018 exhaust. As of August, 95.5% of available numbers have been assigned.
In June 2016, Idaho’s telecommunications providers asked the Idaho PUC to begin a 16-month implementation period for a second area code. Beginning Nov. 2, 2016, customers can begin using 10-digit dialing. If you forget and dial seven digits, your call will still be completed. Beginning Aug. 5, 2017, customers must use 10-digit dialing or you will receiving a recording asking you to hang up and dial again. Beginning Sept. 5, 2017, new numbers may be assigned using the 986 area code.

The commission had two options to implement a second area code. An all-services overlay would superimpose a new area code over the entire state, but assign it to new numbers only. All existing callers would retain their 208 area code and their original number. However, this method requires 10-digit dialing for all calls: area code, prefix and four-digit number.

The geographic split would have divided the state into two regions with the new area code assigned to one region. Citizens in the region assigned the new area code would be required to change their telephone numbers. Ten-digit dialing would not be required for calls within the same area code.

The all-services overlay was the unanimous recommendation of Idaho telecommunications providers. No state in the last decade has chosen the geographic split. In its Order issued Nov. 2, 2016, the PUC adopted the all-services overlay and a schedule for its implementation. The commission’s Order is here: http://www.puc.idaho.gov/fileroom/cases/tele/GNR/GNRT1506/ordnotc/20151102FINAL_ORDER_NO_33414.PDF . A press release summarizing the Order is here: http://www.puc.idaho.gov/fileroom/cases/tele/GNR/GNRT1506/staff/20151102PRESS%20RELEASE.PDF

The industry’s Best Practices recommendation accepted by the Federal Communications Commission cites these benefits to an all-services overlay:
All existing customers would retain their current area code and would not have to change their existing numbers.
Does not require about half of customers to change their numbers, thus creating winners and losers and avoiding statewide conflict over who retains the existing area code and who must adapt to a new number.
Less financial impact on business customers because there is no need to change signage, advertising, stationery, business cards and billing forms. No discrimination by forcing some business customers to incur significant expense that other business customers do not.
Does not split legislative districts, cities, counties and school districts into different area codes.
No technical impacts to number portability, text messaging or multi-media messaging.
Less customer confusion and an easier education process.
Avoids negative impacts to E-911, industry and alarm system databases that would have to be updated with new numbers.
Avoids negative impacts to directories and directory assistance databases.
While an all-services overlay would require 10-digit dialing, technological advances, especially in Voice over Internet Protocol (VoIP) will require everyone to move to 10-digit dialing anyway, likely within the next decade.

While 10-digit dialing will be an adjustment and may appear inconvenient, most all phones, both landline and cellular, can now be programmed to automatically dial 10-digits with the press of just one or two numbers for all the people you frequently call.

2016 Major Events
PUC gives green light to community solar project
Case No. IPC-E-16-14, Order No. 33638
November 3, 2016 – The commission approved an Idaho Power application to build a 500-kilowatt community solar project in southeast Boise.
The $1.16 million single-axis solar project on the southwest corner of Amity and Holcomb roads will allow up to 1,093 residential customers and 470 non-residential customers to buy one or more subscriptions (one subscription is a 320-watt panel) for the solar farm’s anticipated 25-year life. Completion of the project is anticipated by June 2017.
Some 350 kilowatts of the 500-kW project will be apportioned to residential customers and 150-kW for commercial customers. Subscriptions will be rewarded on a first-come, first-served basis until program capacity is reached.
Commission staff and parties to the case, including the Idaho Conservation League, the Idaho Irrigation Pumpers Association, the Sierra Club, Snake River Alliance and the City of Boise, differed with Idaho Power’s initial subscription fee proposal and the method that would be used to calculate the monthly credit subscribers would get for their part of the solar generation.
The parties engaged in settlement discussions to work out their differences. Members of the public also provided comment.
“The record demonstrates that there is great interest and enthusiasm” for the program, the commission said. “We appreciate the intervening parties’ willingness to engage in settlement negotiations to address the various concerns raised … In this way, the public interest is best served,” the commission said. It also thanked citizens who provided input. “Our service to the public in hearing and deciding these matters is better informed when it includes input from the public itself.”
Idaho Power originally proposed a one-time fee of $740 for each subscription. After negotiation, the company and parties agreed on $562, while also allowing customers to pay either at one time or in monthly installments of $26.31 over 24 months.
Parties also said the company’s proposed 3-cent per kWh credit would not be enough for subscribers to recoup their investment. Idaho Power originally proposed the credit be calculated based on the embedded cost-of-service to serve each customer class. But commission staff and other parties said that method does not take into account the value that a new generation resource provides to Idaho Power’s system, particularly a solar resource that provides energy during high-use hours of the day.
Because Idaho Power operates its system to minimize ratepayer costs, a new generation project would allow the company to avoid using its most expensive resource, thus providing greater value than just embedded cost-of-service. Therefore, the credit given to customers should be based on an avoided-cost calculation and not on embedded cost-of-service, commission staff and other parties maintained.
Every two years, Idaho Power files an Integrated Resource Plan, which includes an avoided-cost calculation for its energy efficiency and demand-side management (DSM) programs. Commission staff and parties proposed that Idaho Power base the customer credit on that biennial calculation. The calculation of DSM avoided costs is more current because it is updated every two years, whereas embedded cost-of-service studies are updated only when the utility files a rate case, which for Idaho Power, was five years ago.
Eventually, the company and parties agreed on a solar energy credit that reflects Idaho Power’s recommended embedded cost of energy, but one that gradually increases as the retail energy rate increases.  Idaho Power projects the credit could increase from about 3 cents now to about 4.4 cents in 25 years. The credit is in the form of a reduction in kilowatt-hours billed customers based on the previous month’s solar generation. The total monthly credits given over 12 months cannot exceed that subscriber’s energy use from the prior year.
The parties agreed to reduce the subscription fee to include 1) the net present value of the difference between the DSM avoided costs – which include energy and capacity – and the forecasted embedded costs over the 25-year life of the project, 2) the value of deferred transmission and 3) the removal of the cost of smart inverters.  These benefits, plus the original agreement from Idaho Power shareholders to contribute 15 percent of project costs ($175,000), brought the subscription down from $740 to $562.
The project was requested by Idaho Power customers who cannot install their own rooftop solar panels because they live in rental properties or multi-unit dwellings, have aging rooftops, too much shading or an unsuitable rooftop orientation.
Both Idaho Power and the commission said the pilot status of the program will help the company and commission develop future, perhaps larger, projects. Small-scale pilot programs, the commission said, “are valuable for learning what works and what does not.” Idaho Power said the pilot will assist the utility in learning the “complexities associated with offering community solar programs including: customer commitment, construction, contracting, interconnection, maintenance and billing.”
Idaho Power will retain ownership of the Renewable Energy Credits (RECs) and all other environmental attributes. The RECs would be retired by Idaho Power on behalf of subscribers.

2016 Major Events
Idaho Power seeks OK to join western EIM by April 2018
Case No. IPC-E-16-19, Order No. 33595
Sept. 20, 2016 – Idaho Power Company is taking the initial steps toward possible entry into an Energy Imbalance Market (EIM), which would allow it to pool its generation with neighboring entities to more accurately match production to demand. The move could reduce power supply costs to customers by as much as $4 million to $5 million annually, according to an independent estimate.
The utility is asking the commission to make a finding that its participation in the EIM could benefit customers in the long-term, authorize a deferral account to track the costs and allow the company to recover those costs from customers in a future rate case. Idaho Power hopes to join the EIM in April 2018.
Utilities like Idaho Power typically begin each hour with generation to match its anticipated load. But during the hour, imbalances occur when the supply of energy does not equal demand. When that happens, Idaho Power relies on dispatches from its own generation and extra reserves to balance supply with demand.
By joining the EIM, administered by the California Independent System Operator (CAISO), Idaho Power would have access to an automated five-minute energy dispatch service across a broader footprint in the West with many more deployable resources.
Idaho Power would be joined with neighboring utilities, such as PacifiCorp and NV Energy, to balance supply and demand more efficiently and cost-effectively. Joining the EIM does not mean that Idaho Power would give up its control over its own generating resources, but it would no longer independently operate its own generation dispatch.
Idaho Power claims that participation in the EIM will likely result in cost savings that will benefit customers over the long-term. Moving from an hourly market to a five-minute imbalance market is expected to lead to increased surplus sales opportunities when Idaho Power is generating more electricity than it needs as well as cost savings from increased access to other suppliers’ lower-cost generation.
Further, Idaho Power claims, the EIM would allow for more efficient integration of intermittent wind and solar resources, which currently make the management of energy imbalance more complex. The renewable energy could be dispatched to serve customers in other service territories helping to prevent curtailment of intermittent resources, which would benefit wind and solar operators.
According to Idaho Power, the increased sales and lower cost power supply would lead to lower net power supply expense for the company, 95 percent of which is passed on to customers. The company’s supporting testimony also indicates that participation in the EIM may result in improved transmission congestion and enhanced reliability.
An independent consultant contracted by Idaho Power claims the potential cost savings of participation in the regional market could be between $4 million and $5 million per year.
But there are upfront costs, estimated to be about $11.1 million, which includes start-up expense of $1.7 million, software integration costs of $7.9 million and metering investment of $1.5 million. In addition to the upfront expense, is the ongoing operational expense of about $836,000 annually for labor and ongoing market and hosted software fees of about $786,000 per year beginning in April 2018.
Idaho Power claims the net decrease in power supply costs will more than offset start-up and operational expenses. Idaho Power is proposing to defer collection of start-up costs until after participation in the EIM begins and benefits start flowing to customers.
The Western EIM was created by CAISO and PacifiCorp in 2014. Since then, NV Energy has joined along with Puget Sound Energy and Arizona Public Service Company. Portland General Electric is scheduled to join in October 2017.
The EIM is governed by a five-member body that is financially independent from market participants. Members are selected by a nominating committee that includes several stakeholders, including EIM participants, transmission owners, suppliers and marketers of generation, publicly owned utilities, state regulators and public interest and consumer advocate groups.

2016 Major Events
Rwanda Utilities Regulatory Authority
spends week in Idaho with commission staff

Program is joint effort of NARUC, USAID and Power Africa

June 17, 2016 – Two officials from the Rwanda Utilities Regulatory Authority (RURA) were in Idaho during June to “job shadow” staff of the Idaho Public Utilities Commission.

Idaho was the first state to host an activity under a new partnership between the National Association of Regulatory Utility Commissioners (NARUC) and RURA, with the support of the U.S. Agency for International Development (USAID) and Power Africa.

NARUC’s partnership with RURA enables regulators from the United States and Rwanda to share experience and best practices as well as to problem-solve to support more effective regulation.

“Our objective is to support RURA’s efforts to improve its rate-setting practices so that Rwanda will be able to attract private investment in its power sector and, thus, increase access to electricity for its people,” said Matt Elam, who heads up the Idaho commission’s Technical Analysis Section.

Visiting from Rwanda were Aimee Nshimirimana, a business plan analysis officer in the Economic Regulation Unit and Alex Mudasingwa, a technical compliance and monitoring officer in RURA’s Electricity and Renewable Energy Unit.

Elam, who serves on NARUC’s Staff Subcommittee for International Relations, said Idaho was selected partly because utilities here get most of their generation from hydroelectric resources as in Rwanda.

To date, only about 24 percent of Rwanda’s households are connected to the electrical grid. The central-east African nation of 11.7 million people has an ambitious goal to increase connected households to 70 percent by the end of 2018. Rwanda has 190 MW of installed capacity, up from just 46 MW in 2004. Its forecasted generation for 2018 is about 563 MW, enough electricity to connect 70 percent of Rwandans to the electrical grid.

The job shadow is also designed to assist RURA in devising cost-reflective tariffs (rates) that will phase-out government subsidies to the nation’s only electric utility by the end of fiscal year 2017-18.

Mudasingwa, who has a master’s degree in engineering, and Nshimirimana, who has a master’s degree in business administration, said they appreciated specifically learning about rate mechanisms in Idaho that encourage energy efficiency; that track changes in water, fuel costs and other variable expenses; and that allow ratepayers to share revenue with utilities once utility earnings reach a certain level. As in Idaho, Rwanda also has a number of independent power generators, so the Rwandan visitors were interested in the way the Idaho commission approves or denies power purchase agreements between utilities and independent generators.

“We appreciate very much the hospitality of the Idaho staff,” Mudasingwa said. “It has been perfect, 100 percent.”

“This has been a valuable experience for everyone,” said Paul Kjellander, president of the Idaho Public Utilities Commission. “Our staff has learned a great deal from Alex and Aimee and we hope we have been as much help to them,” Kjellander said. The PUC president expressed thanks to Elam, who was instrumental in bringing the Rwandan delegation to Idaho.
Idaho is a state member of NARUC, whose members include the state agencies that regulate utilities and carriers in the 50 states, District of Columbia, Puerto Rico and the Virgin Islands.
Power Africa is a U.S. government program seeking to attract needed investment in the power sector within sub-Saharan Africa. Its ultimate goal is to increase access to electricity by adding 30,000 MW of clean, efficient energy on the African continent.

Electrical Power in Idaho

Idaho Power Company
2015 Average Number of Customers/Avg. Revenue/kwh*
418,906 Residential Customers/$0.1030
80,261 Commercial Customers/$0.0767
113 Industrial Customers/$0.0567

Avista Utilities

2015 Average Number of Customers/Avg. Revenue/kwh*
110,267 Residential Customers/$0.0949
17,267 Commercial Customers/$0.0890
449 Industrial Customers/$0.0590

Rocky Mountain Power

2015 Average Number of Customers/Avg. Revenue/kwh*
60,959 Residential Customers/$0.1112
8,425 Commercial Customers/$0.0895
5,544 Industrial Customers/$0.0733

*Computed from data available in FERC Form 1 Annual Reports dated June 30, 2016.
Electric RATE CHANGES

PUC adopts settlement to Rocky Mountain case

Case No. PAC-E-15-09, Order No. 33440

Dec. 23, 2015 – The commission adopted a settlement to various issues surrounding Rocky Mountain Power Company’s request to transfer some of its variable power supply expense into permanent base rates.

The settlement increases base rates about 3.9% in 2016 (2.8% for residential customers), but customers will notice a reduction of near the same size when the company files its annual Energy Cost Adjustment Mechanism (ECAM) to be effective in 2017. A residential customer who uses the average 801 kilowatt-hours per month would pay about $2.35 more each month.  

The settlement replaces a base rate case that Rocky Mountain Power would have filed during 2016. It also includes a “stay-out” provision that prevents another base rate increase until Jan 1, 2018 at the earliest. Rocky Mountain serves about 75,000 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 shifts $10.2 million of expense currently collected through the ECAM into base rates. Customers will be credited about that same amount when the company files its ECAM in 2017. Commission staff estimated that the combined net impact of the base rate increase in 2016 and the projected ECAM decrease in 2017 will be about $889,000 per year or 0.34% more than what customers would have paid through current base rates and the current ECAM.

About $6.5 million of the $10.2 million shift is expense related to revenue the company no longer receives from the trading of Renewable Energy Certificates (RECs).  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. 

The commission said the settlement represents a “reasonable compromise” of various positions raised by the parties, which included the company, commission staff, the PacifiCorp Idaho Industrial Customers and Monsanto Company.

“The hallmark of reasonable compromise is a mutually beneficial resolution for both sides of a transaction,” the commission said. “Accordingly, the commission finds that the stipulation offers substantive benefits to both ratepayers and company.”

The Snake River Alliance, while not a party to the case, submitted written comments in support of the settlement.

Idaho Power attributes the higher PCA to 1) increased PURPA generation, 2) less revenue sharing with customers due to a lower Return on Equity in 2015; 3) lower than projected hydro generation; and 4) lower than forecasted wholesale market prices for electricity, resulting in lower sales volumes for Idaho Power when it sells its surplus power into the market.

The utility has about $10 million additional expense related to power purchase contracts with solar developers. The solar contracts fall under the provisions of the Public Utility Regulatory Policies Act (PURPA), which requires utilities to purchase generation from qualifying renewable energy projects. The company said about 320 megawatts of PURPA solar projects and 50 MW of PURPA wind projects are expected to come online during the 2016-17 PCA year.

Reservoir levels in the region are lower than the 2015 forecast. While Idaho Power had a better water year in some parts of its service territory, last year’s dry winter left reservoirs in the Upper Snake River Basin very low by summer’s end. Actual hydro generation was 27 percent less than the company forecast.

Wholesale electric market prices declined due primarily to lower natural gas prices. Lower market prices reduced surplus sales volumes by 26 percent. Also, because wholesale market prices were lower, the company’s market purchase volumes were 92 percent higher than forecasted.

Fixed Cost Adjustment

The FCA, implemented in 2007, is designed to ensure Idaho Power recovers its fixed costs of delivering energy when energy sales decline due to reduced consumption. Before the FCA, Idaho Power had no incentive to invest in energy efficiency programs because it lost revenue as customer consumption declined. To remove that disincentive, the Fixed Cost Adjustment was created to allow the utility to recoup its fixed costs of doing business. Even though consumption may decline, the fixed cost to serve customers does not.

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 2015, Idaho Power under-collected fixed costs of serving residential and small business customers by $28 million, or $11.17 million more than the amount already included in the FCA account. To recover those fixed costs, the commission approved an FCA increase of 2.2 percent, which will increase an average residential and bill would by about $2.16 per month. The new FCA rate is 0.5416 cents per kWh. The FCA applies only to residential and small business customers.

During 2015, Idaho Power achieved a 22 percent increase in energy savings compared to 2014. In a separate case filed before the commission every year, Idaho Power must demonstrate that the programs that create energy efficiency savings must result in lower overall rates to customers than if the programs were not in place. Several studies have shown that energy efficiency and demand reduction are the least expensive source of energy for utilities. The FCA makes it possible for the company to aggressively pursue energy efficiency and demand-side management programs without fear of losing fixed costs to serve customers.

The 2015 PCA was a 1.1 percent decrease and last year’s FCA was a 0.35 percent increase, resulting in an overall net decrease to customers.

PCA is up for Avista, but higher BPA credit
results in 0.3% decrease for most customers

Case No. AVU-E-16-05, Order No. 33605

Oct. 4, 2016 – Two rate adjustments that became effective Oct. 1 for customers of Avista Utilities will result in an overall rate reduction of about 0.3 percent for residential and small-farm customers.

Customers will be given a $516,000 rebate as part of Avista’s annual Power Cost Adjustment (PCA), but that rebate is not as large as last year, so the result is a slight increase in the PCA of about 0.2 percent as approved by the Idaho Public Utilities Commission. However, at the same time, a rebate given residential and small-farm customers from the Bonneville Power Administration’s Residential Exchange Program is increasing slightly. The net result of both the PCA and BPA’s credit is a decrease of 0.3 percent or about 30 cents per month on an average residential monthly bill.
Every year on October 1, the variable portion of Avista rates is adjusted up or down depending on the previous year’s power supply expense, which is largely determined by changes in hydroelectric generation and market prices for natural gas and electricity.
Lower natural gas prices and less operating expense at the Colstrip and Kettle Falls plants kept power supply costs down for Avista. But hydro generation that was 13 percent below normal, more expense related to the operation of the Palouse Wind plant and a change in the contract between Avista and Clearwater Paper resulted in overall greater PCA expense. Thus, the size of the PCA rebate to customers is reduced from 0.032 cents per kilowatt-hour to 0.017 cents per kWh.
Offsetting the PCA increase is a larger credit than currently given residential and small-farm customers as a result of the BPA Residential Exchange Program. BPA credits residential and small-farm customers of utilities who live near BPA’s hydroelectric projects along the Columbia River. The credit fluctuates each year depending on a formula BPA uses to calculate the benefit. A higher benefit this year results in an overall decrease to residential and small-farm customers of 0.5 percent.

Parties to Avista rate case propose settlement
that reduces average hike from 6.3% to 2.6%

Case No. AVU-E-16-03, Order No. 33641

Nov. 15, 2016 – At the end of the year, the commission was considering a proposed settlement to the Avista Utilities rate case filed in June. The proposed settlement reduces the increase from an average 6.3 percent to 2.6 percent.

Parties to the case including commission staff, the Clearwater Paper Corporation, Idaho Forest Products, the Snake River Alliance and the Community Action Partnership Association of Idaho signed a negotiated settlement that, if approved by the commission, would reduce the size of Avista’s requested annual revenue requirement increase from $15.4 million to $6.25 million.

The proposed settlement reduces the company’s requested annual revenue increase by $9.2 million.

Some of the most significant adjustments were a $4.5 million reduction by moving Palouse Wind project net expenses from base rates to the annual Power Cost Adjustment process, a $2.47 million reduction in Cost of Capital; $1.33 million removed from revised net rate base; $1 million removed from 2015 storm costs; $333,000 reduced in administrative and general expense, board of director expense and other items; a $310,000 reduction in non-union labor expense; and a $171,000 reduction by removing all company officer incentives.

The proposed settlement reduces Avista’s requested Return on Equity from 9.9 percent to 9.5 percent and its proposed Rate of Return from 7.78 percent to 7.58 percent. It also reduces the size of the increase in the Residential Basic Charge from the company’s requested $6.25 per month to $5.75 per month. The current charge is $5.25 per month.

The parties also agreed to meet before the next rate case to assess Avista’s Low-Income Weatherization and Low-Income Energy Conservation education programs for possible improvements.

Avista serves about 125,000 customers in north-central and northern Idaho.

ENERGY EFFICIENCY FILINGS

Idaho commission begins prudency review
of Avista Utilities’ electric conservation programs

Case No. AVU-E-16-06, Order No. 33617

October 11, 2016 – Avista Utilities is seeking a determination from the Idaho Public Utilities Commission that nearly $10 million it spent during 2014 and 2015 on electric efficiency programs was prudently incurred. (A final order in this case had not been issued by the time this report was published.)

The electric efficiency programs are expected to be cost-effective in order to be funded by the Energy Efficiency Rider paid by Avista’s customers. Residential customers pay 0.245 cents per kilowatt-hour for the programs. The prudency review will 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 are screened by at least three cost efficiency tests to demonstrate that the savings realized are greater than the programs’ costs.

Avista claims it energy efficiency savings for 2014 of 16,292 megawatt-hours exceeded its target of 15,330 MWh. Its 2015 savings of 14,789 MWhs fell short of its target of 15,666 MWhs, but for the two-year period, its total savings of 31,081 MWhs met the target of 30,996 MWhs.

Avista hired an independent contractor, Nexant, to evaluate the cost-effectiveness of its efficiency programs. According to Nexant, the total benefit to all customers in 2014 was $6 million and $2.4 million in 2015. To be cost-effective, the programs must benefit not only those who participate, but all customers because the energy saved is less costly than if Avista were to generate an equal amount of energy itself or buy it from other sources. The programs may also delay the company’s need to build or buy new generation.

Most of Avista’s residential programs included rebates to customers who installed low-cost lighting and water-saving measures and weatherization materials and participated in appliance recycling programs. More than $575,000 in rebates were provided to Idaho residential customers, according to Avista.

Avista reports that the revenue raised by the rider did not cover all program expenses. As of Dec. 31, 2015, the tariff rider balance is $431,784 underfunded.

Commission OKs Idaho Power efficiency programs
but asks company to review 4 percent rider

Case No. IPC-E-16-03, Order No. 33583

Sept. 19, 2016 – State regulators have approved the $35.2 million spent by Idaho Power Company on energy efficiency and demand-response programs during 2015 as prudently incurred.

The purpose of the commission’s annual review is to ensure the programs are cost-effective, meaning customers would be paying more for energy without the programs in place. The commission is asking Idaho Power to submit a proposal by year’s end that could revise downward the 4 percent Energy Efficiency Rider currently assessed customers to pay for a number of the efficiency programs. According to a commission staff analysis, Idaho Power has collected, on average, about $13.5 million more each year than it spends on efficiency programs. The proposal will help determine how the surplus funds should be used.

The commission is also asking Idaho Power to work with commission staff and Idaho Power’s Energy Efficiency Advisory Group to consider offering more programs for residential and small-business customers and look at what is being offered by utilities in neighboring states.

Idaho Power offers 19 efficiency programs funded by the 4 percent Energy Efficiency Rider. It also offers three demand-response programs that are included in the annual Power Cost Adjustment (PCA), which is part of the Annual Adjustment Mechanism listed on customer bills.

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. The company claims these programs increased annual energy savings by 18 percent.

About $28.5 million of the total $35.2 million investment during 2015 was related to energy efficiency. The remaining $6.7 million was spent on demand-reduction and included incentive payments to customer who volunteered to shift their consumption to non-peak times of the day.

Energy efficiency programs resulted in 162,533 megawatt-hours of savings, which includes 21,900 MWh from Idaho Power’s participation in market transformation initiatives offered through the Northwest Energy Efficiency Alliance. Some of Idaho Power’s energy efficiency programs include offering customer rebates for increased use of heating and cooling efficiencies and energy efficient lighting and appliances as wells as creating efficiencies in commercial and industrial buildings. The largest amount of energy efficiency savings came from the commercial/industrial sector (102,074 MWh), followed by the residential sector (24,532 MWh), followed by the irrigation sector (14,027 MWh).

Demand reduction programs that provided financial incentives to residential air conditioning customers, large commercial and industrial customers and irrigators to shift or curtail consumption to off-peak periods reduced demand on Idaho Power’s system by 376 megawatts, saving customers about $1.6 million.
Rocky Mountain seeks prudency finding
for investment in efficiency programs

Case No. PAC-E-16-14, Order No. 33639

November 4, 2016 – Rocky Mountain Power is asking the Idaho Public Utilities Commission to determine that about $7.46 million of the company’s investments in energy efficiency programs during 2014-15 were prudently incurred and benefitted customers. This application does not impact rates. (A final decision had not been made when this report was published).

The programs encourage customers to use less energy or shift consumption to off-peak hours.

The programs are funded by a rider that appears as “Customer Efficiency Services” on bills. The rider is currently set at 2.7% of a customer’s monthly billed amount. Part of the commission’s prudency review is to determine if the programs benefit all customers, not just those who directly participate in the programs.

Rocky Mountain Power claims the programs saved the utility 11,410 megawatt hours in 2014 and 15,692 MWh in 2015. That decreased consumption reduces power supply expense for all customers and eliminates or delays the need for the company to build new generating facilities.

Rocky Mountain Power offers five energy efficiency programs.

“Home Energy Saver” provides products and services to residential customers such as insulation, duct sealing, CFL and LED lighting and other services.
“Refrigerator Recycling” offers customers rebates for removal and recycling of inefficient refrigerators and freezers.
“Low Income Weatherization” provides energy efficiency services to residential customers meeting income guidelines.
“Low Income Conservation Education” targets customers receiving low-income energy assistance and provides them information about how to better conserve energy and understand their bill.
“Non-Residential Energy Efficiency” is a consolidation of commercial and industrial energy efficiency programs into a single portfolio the company calls “wattsmart.” It helps commercial and industrial customers improve efficiency in lighting, HVAC systems, motors, building envelopes and other equipment.

Rocky Mountain reports that, overall, the programs were cost-effective, meaning their benefits outweighed their cost. However, the low-income weatherization program, failed to pass two of three cost-effectiveness tests.

Rocky Mountain Power, a division of PacifiCorp, serves 75,500 customers in its eastern Idaho territory.

OTHER MAJOR ELECTRIC CASES

Idaho Power Company seeks 3.1 percent rate increase
for accelerated Valmy closure and updated depreciation

Case No. IPC-E-16-23, Order No. 33652
Case No. IPC-E-16-24, Order No. 33650

November 18, 2016 – At year’s end, the commission had opened dockets to consider two Idaho Power Company requests: an accelerated depreciation for the Valmy coal plant in Nevada and an updated depreciation study for the remainder of the utility’s plant assets. A final decision had not been made when this report was published.

Idaho Power and Nevada Energy, co-owners of the Valmy plant, want to shut down the two-unit plant by 2025, six years earlier than the planned retirement of Unit 1 and 10 years earlier than the planned retirement of Unit 2. Consequently, Idaho Power is asking the commission to compress the remaining depreciation on the plants into the shorter 2025 time period, which, if approved, would increase base rates by $28.5 million, or about 2.5 percent. The company maintains that an earlier retirement of the plant would save customers about $103 million in today’s dollars if it continues to operate the plant until it is fully depreciated in 2035.

Idaho Power is also seeking a 0.6 percent increase to update the depreciation on its remaining plant assets, excluding Valmy and the Boardman, Oregon coal plant. The combined 3.1 percent increase, if granted, would increase the monthly bill of a residential user who uses the system average of 1,000 kilowatt-hours per month by about $3.08.

If the commission were to approve both applications, the rate changes would not occur until June 1, 2017, the same time the annual Power Cost Adjustment (PCA) is also implemented.

Idaho Power is a 50-50 owner with Nevada Energy in the Valmy coal-fired plant near Winnemucca, Nev. The plant consists of two units that can generate up to 284 megawatts.

A significant decrease in market prices for electricity has made it uneconomical for Idaho Power to operate Valmy except to meet peak energy needs during extremely cold or hot weather. In 2011, the average price Idaho Power and its customers received for off-system sales was $22.71 per megawatt. In 2016, that has declined to $8.76 per MW. Consequently, the cost to dispatch Valmy generation is usually higher than the market price, Idaho Power claims.

Idaho Power further claims that since its last general rate case in 2011, Valmy plant balances have increased about $70 million due to a number of investments required for environmental compliance, as well as investments for routine maintenance and repair.

In a separate application, Idaho Power is seeking a 0.6 percent increase, effective June 1, 2017, following an update of its deprecation on its remaining assets.

Utilities are allowed a depreciation component in retail rates to help cover the costs to replace facilities. Depreciation rates establish the amount of time over which Idaho Power recovers from customers its investment in its electrical system. Depreciation means the loss in the service value of a utility’s various plants due to wear and tear or decay that is not otherwise restored by maintenance or covered by insurance. A loss in service value can also be caused by the obsolescence of plant due to new technologies and by new requirements imposed by federal or state governments.

Every five years, Idaho Power conducts a study to determine depreciation rates for each of its plant accounts. Idaho Power’s depreciation study was conducted by Gannett Fleming Valuation and Rate Consultants, LLC.

Commission accepts Idaho Power long-range plan

Case No. IPC-E-15-19, Order No. 33441

Dec. 29, 2015 – The commission accepted a 20-year planning document filed by Idaho Power Company, although there is some disagreement from commission staff and other parties over whether the utility has chosen the most cost-effective, least-risk plan to meet load growth.

However, the commission noted that the Integrated Resource Plan (IRP) is for planning purposes only and that acceptance of the plan does not mean all its components will be implemented. The IRP is a “working document that incorporates many assumptions and projections at a specific point in time,” the commission said. “It is a plan, not a blueprint, and by issuing this order we merely acknowledge the company’s ongoing planning process, not the conclusions or results reached through that process.” Regulated electric and gas utilities are required to file an IRP every two years with the commission.

The plan does not anticipate significant new generation resources through the 2020s. It projects customer growth to be about 196,000 from now until 2035, adding about 1.2% to the company's average energy demand and 1.5% to its peak demand.

To meet load growth, Idaho Power anticipates acquiring 60 megawatts from new demand response programs, 20 megawatts from development of an ice-based thermal energy storage plan, and the construction of a 300-MW natural gas plant in about 2031.

The plan also assumes that much of the increased demand in the near future will be met by completion of the 500-kilovolt Boardman (Oregon) to Hemingway transmission line, expected to be operational by 2020 or shortly thereafter.

Idaho Power is anticipating that Units 1 and 2 of the North Valmy, Nevada, coal plant it co-owns with Nevada Energy will be retired by 2025. Commission staff and other intervenors to the case said the company’s preferred portfolio is more costly and risky than portfolios that would close the North Valmy Unit 1 six years earlier in 2019. But Idaho Power claims that early closure would immediately increase customer rates by $6 million annually in depreciation expense. North Valmy Unit 1 isn’t fully depreciated until 2031 and Unit 2 until 2034. Idaho Power gets about 260 MW from the North Valmy units.

Commission staff said Idaho Power’s preferred portfolio was the sixth-most risky of 11 studied. Idaho Power said that while 2019 North Valmy retirement performed well in an economic analysis, early closure carries considerable risk due to a number of factors including the administration’s Clean Power Plan and uncertainty surrounding PURPA solar projects, the completion date of the Boardman to Hemingway Transmission line, and whether regulators will allow depreciation expense of early coal plant retirement to be included in customer rates.

Since Idaho Power’s IRP was filed last June, some of those risk factors have been lessened, commission staff said. Idaho’s emission-reduction targets under the Clean Power Plan have been reduced and the compliance period extended. Furthermore, a recent commission order limits solar and wind PURPA contracts to two years. The commission encouraged the company “to more clearly explain” to stakeholders why the company chose a portfolio with a 2025 closure of North Valmy instead of 2019.

Staff and other stakeholders said Idaho Power’s cost models that deduct achievable energy savings from the company’s load forecast does not treat supply-side resources and demand-side resources equally. (Supply-side resources include traditional generation while demand-side resources include programs that reduce or shift demand from peak-use periods.) Idaho Power claims doing so would give demand-side resources preferential treatment.

In its order, the commission said Idaho Power should further explore whether it could more effectively incorporate energy efficiency by using cost models similar to those used by PacifiCorp, Avista Utilities, Puget Sound Energy and the Northwest Power and Conservation Council.

The Idaho Conservation League said Idaho Power overestimates solar costs and Clean Power Plan compliance costs while underestimating achievable energy efficiency.

The Snake River Alliance said Idaho Power should not rely too much on completion of the Boardman to Hemingway transmission line because of the project’s history of delays. The utility should also take into account “social costs” related to carbon-based generation. It also said Idaho Power is not progressing rapidly enough in developing community solar projects.

The Sierra Club said Idaho Power should make an effort to more fairly estimate solar costs and should also consider transmission and distribution expense and not just generation expense in its financial analyses.

All of the intervening parties commended Idaho Power for inviting participation from various stakeholders in what they said was an improvement over past IRPs.

Update to Idaho Power green energy program approved

Case No. IPC-E-16-13, Order No. 33570
The commission approved Idaho Power Company’s application to modify a program approved in 2001 that allows customers to participate in the purchase of green energy from primarily wind and solar resources in the Northwest.
Customers currently designate a dollar amount to be added to their monthly bills specifically to be used toward the purchase of Renewable Energy Certificates (RECs). A REC is created when one megawatt-hour of renewable energy is produced and delivered to the electrical grid. Purchase of the RECs means the utility uses less power generated from fossil fueled sources like coal or natural gas plants.
Idaho Power proposed to change the fixed dollar contribution to one of two other options for customers: buying blocks of power at $1 for every 100 kilowatt-hour block of renewable energy or a “100 percent of usage option,” which means the customer elects to buy renewable energy equal to the customer’s total monthly use at a premium price of 1-cent per billed kWh.
Switching to these options, Idaho Power claims, will allow it to better comply with national green energy standards, create a more transparent program for participants and align Idaho Power’s Green Power Program with similar programs offered in the Northwest.
As a second modification, Idaho Power proposed that the Bonneville Environmental Foundation (BEF), the Portland-based non-profit that secures REC sources for Idaho Power, give preference to RECs within or closest to Idaho Power’s service territory when possible.
Thirdly, Idaho Power proposed that 15 percent of the program’s funds be used for marketing to invite greater customer participation. Currently, about 1,700 customers participate as well as a 15 schools, under the utility’s Solar 4R Schools program. No program monies are currently used for marketing. If REC prices change significantly, Idaho Power may choose to use the marketing funds to cover the increase in REC prices rather than change the price to participants, but in no case, the company claims, will program funds by used for purposes other than the Green Power Program.
The company is considering, though not in this filing, later expanding the program to include a bulk-purchase option for large customers and adding a solar option, under which customers can direct that all the green energy they purchase come from solar sources. The market for solar RECs is not liquid enough at this time to include that option in this filing, Idaho Power said.
The commission approved the 15 percent dedicate for marketing the program, but did ask that the company file a Green Energy Prudency Report every two years to monitor marketing activities and expenses. The report will also include customer count, monthly RECs purchased, monthly revenue and expenses, Solar 4Schools expenses, percentage of RECs bought within Idaho Power’s service territory and monthly funds transferred to the Power Cost Adjustment (PCA) from Idaho Power-owned REC purchases.

Integration costs to solar developers decline

Case No. IPC-E-16-11, Order No. 33563

August 12, 2016 – New solar developers will be paying significantly less to integrate their generation into Idaho Power Company’s transmission and distribution system under new integration rates approved by the Idaho Public Utilities Commission.

The solar integration charge paid by developers applies only to larger solar projects that enter into contracts with Idaho Power. It does not apply to smaller projects, such as residential and commercial rooftop solar.

Electric utilities incur costs based on the amount of solar generation added to their distribution and transmission system. Part of those integration costs are incurred when utilities need to provide back-up generation if solar output is less than anticipated.

In February 2015, the commission approved a settlement that adopted solar integration costs developers pay Idaho Power based on a 2014 study completed by the utility. However, the parties to that settlement did not agree on the tariffs recommended by the study. As part of the settlement, Idaho Power agreed to conduct a second study using a Technical Review Committee comprised of staff from the Idaho and Oregon public utility commissions, Idaho Power, and a technical expert designated by each of the parties to the settlement, which also included the Sierra Club, Idaho Conservation League and the Snake River Alliance.

The integration costs approved by the commission incorporate the results of the second study, which includes an updated tariff for each 100 MW of solar generation up to 1600 MW. (Idaho Power currently has 40 megawatts of solar generation online and another 290 MW under contract to be online by the end of this year.) At a total solar penetration of between 301 and 400 MW, the integration tariff to solar developers is 54 cents per megawatt-hour for a non-levelized contract signed this year. That compares to $2.63 per MWh using the 2014 study. Between 401 and 500 MW of penetration, the new tariff is 71 cents per MWh compared to the 2014 tariff of $3.31.

The Idaho Conservation League (ICL) and Renewable Northwest (RN) supported the changes Idaho Power made to its methodology to compute the tariff, but said the tariff should be based on an average rate rather than incremental approach that increases the rate for every 100 megawatts of solar generation added. That’s because future projects may have features that reduce integration costs, according to the ICL and RN. However, the commission declined to adopt that recommendation because averaging costs would “work to the detriment of early projects and to the benefit of later developers.” Integration costs to developers are determined at the time they sign the contract with Idaho Power and remain fixed for the duration of the contract. Subsequent changes to the tariff rate as solar integration increases would apply only to new contracts.

ICL and RN also requested that the methodology adopted by Idaho Power in its updated solar integration study be used to update the utility’s wind integration study. However, the commission said the “notable differences” between wind and solar generation make it impracticable to apply the solar study to wind integration.

The commission said the integration tariff should be updated frequently to account for changes that could be impacted by:

The potential impact of Idaho Power joining the Western Energy Imbalance Market;
Transmission changes, such as completion of the Boardman to Hemingway transmission line;
Resource changes or additions, including generation received through customer participation in demand response programs;
Energy storage;
The combined effects of new solar and new wind;
Changes in gas/fuel prices;
The effects of distributed generation and community solar projects as they develop.

Idaho Power asks for declaratory order
regarding solar project payments

Case No. IPC-E-16-21, Order No. 33619
October 7, 2016 – Idaho Power Company is asking state regulators to weigh in on a dispute between the utility and the developer of four 20-MW solar projects proposed to be built in southern Twin Falls County near the Nevada border. (A final decision had not been issued when this report was published).
The projects fall under the provisions of the Public Utility Regulatory Policies Act (PURPA), which requires utilities to buy from qualifying renewable generation at a negotiated rate that is to be based on the cost the utility avoids by not generating the power itself or buying it from another source.
Developers of generation projects can be paid two types of payments: energy payments and capacity payments. Energy payments are paid based on the energy produced at the time it is produced. Capacity payments are paid in addition to energy payments if the project’s output is during a time when the utility is capacity deficient.
Idaho Power’s latest filing with the commission regarding resource deficiency says the utility will be capacity deficient in 2024. The developer of the four proposed Jackpot Solar projects is seeking to enter into 10 successive two-year contracts, or 20 years of operation. The projects, if approved, would be eligible to start receiving capacity payments in 2024. Even if the resource deficient date were to change, projects with contracts signed this year would be eligible for capacity payments in 2024.
Jackpot Solar claims that the capacity price should be determined at the time of the initial two-year contract rather than at the beginning of the two-year term when the utility is capacity deficient. The developer claims that a 2015 Idaho Public Utilities Commission order that shortened contract lengths for these types of projects to two years, and a follow-up clarifying order, both determined that the deficiency date and the capacity rate are both calculated at the time of the initial contract.
Idaho Power is asking the commission to issue a declaratory order stating that the 2015 orders said just the opposite: that the capacity rate is determined at the beginning of each two-year term and that a PURPA project is not able to lock in an avoided-cost rate beyond the two-year maximum contract term. The four projects – Jackpot Solar North, Jackpot Solar South, Jackpot Solar West and Jackpot Solar East – are all 20 megawatts and all developed by Robert Paul.
Commission accepts Avista long-range plan

Case No. AVU-E-15-08, Order No. 33463

Feb. 11, 2016 – The commission accepted a long-range planning document that details how Avista Utilities plans to meet its projected load growth over the next 20 years.

The utility, which serves about 125,000 electric customers in northern Idaho, plans to acquire nearly all its energy from energy efficiency programs, natural gas plant upgrades and the construction of natural gas peaker plants and a combined-cycle natural gas plant.

Avista, like other electric utilities, must file the plan every two years. Acceptance of the plan does not necessarily mean the anticipated projects will be built. Instead, the report informs the commission and its customers about the utility’s plans. The resource planning process can change as circumstances change.

While population and employment growth are starting to recover from the Great Recession, the utility nonetheless revised downward – from 1% to 0.6% -- its annual load growth projection from its 2013 IRP.

Efforts in energy efficiency have reduced Avista’s load requirement by 127 average megawatts, about 11% of the utility’s total load. Energy efficiency and market purchases push out the first anticipated long-term capacity deficit to 2021 at the earliest.

The first anticipated resource addition is a 96-megawatt natural gas-fired peaking plant at the end of 2020 to replace expiring contracts and serve load growth. In 2026, the company anticipates building a 286-MW combined-cycle combustion turbine natural gas plant, another 96-MW peaker plant in 2027 and a 47-MW peaker plant in about 2034. (Smaller peaker plants are built primarily to meet customer demand during peak-use periods while larger combined-cycle plants run year-round to meet load requirements.)

In total, the utility plans on adding about 565 MW of new natural gas generation through 2035 and acquiring another 132 average megawatts through energy efficiency programs.

Most of Avista’s generation (51% in the winter and 38% annual average) comes from hydroelectric resources. Natural gas provides about 37% in the winter and 42% of annual generation. Avista also owns a 15% share in each of two Colstrip coal plant units in Montana, from where it gets about 222 MW. Coal comprises about 13% of Avista’s annual generation.

The Snake River Alliance favored acceptance of the plan, but criticized what it believes to be Avista’s over reliance on natural gas plants that, it says, are subject to unknown regulations and costs. Further, Snake River Alliance said, Avista’s intent to acquire 565 MW of new natural gas resources while simultaneously shutting down demand response programs sends mixed signals about the utility’s ability to achieve deeper carbon emissions reductions.

Demand response programs target typically larger-use customers who voluntarily agree to reduce or shift their consumption from peak-use periods in exchange for financial credits, thus reducing demand on Avista’s overall generation system. Avista claims its demand-response programs have higher costs than anticipated and are not cost-effective. Costs of the demand response programs would have to drop by nearly 50 percent to be cost-effective, Avista claims.

Commission removes net metering cap,
directs Rocky Mountain to file annual report

PAC-E-16-07, Order No. 33511

May 4, 2016 – The commission denied a request by Rocky Mountain Power to increase a cap on net metering generation in its Idaho territory from 714 kilowatts to 2,000 kW. Instead, the commission removed the cap entirely and required an annual report that monitors the growth and impacts of net metering.

Net metering customers generate their own power to offset part or all of their of their energy use. Excess generation from net metering customers is fed back into the grid. The number of net metering customers in Rocky Mountain’s Idaho territory has increased from just 2 in 2007 to 161 at the end of 2015, pushing net metering generation to about 1,049 kW. Nearly all of Rocky Mountain’s net metering customers use residential and commercial rooftop solar applications.

The utility, which operates in eastern Idaho, has expressed concern that customers who do not net-meter may be subsidizing those who do. That’s because a net metering customer who generates more than he or she consumers is paying little or no transmission or distribution costs to the company, even though the net metering customer is still on the grid. There is not enough net metering generation yet to make that subsidy significant, but the company believes the issue will need to be addressed as the amount of distributed generation increases. When net metering customers generate more than they consume, the utility credits the customer in future bills for the net amount of energy delivered back to the company. The credit is in the form of energy, not monetary payments.

The commission directed the company to file status reports with the commission on or about Oct. 31 of each year or when the company seeks to modify its net metering tariff. “We also expect the company to promptly notify us whenever changes to the net metering service materially affect the company’s system and/or its other customers,” the commission said.

The annual report should include customer participation levels, types of net metering generation, nameplate capacity, impacts on non-net metering customers and potential impacts to reliability, the commission said.

In response to a commission order when the net metering program was established, Rocky Mountain Power completed an analysis showing the difference between the value of the energy credited to net metering customers and energy market wholesale prices. On average, the company claims, it paid 10.34 cents per kilowatt-hour to net metering customers compared to a wholesale rate at the Mid-Columbia Trading Hub of 2.47 cents per kWh. The company claims that during 2015 it paid $44,446 for excess net metering generation that had a corresponding energy wholesale market value of $10,638.

In response to the company’s claim, the commission adopted a recommendation by the Idaho Conservation League that Rocky Mountain include in its report a comparison of the value of excess net metering generation to the value of delivering alternative sources of power to end-users at the same time of day, month and year that the company is benefitting from net metering generation.

PUC accepts Rocky Mountain curtailment plan

Case No. PAC-E-15-10, Order No. 33519

May 4, 2016 – The commission approved an updated Rocky Mountain Power plan spelling out the steps the utility would take to curtail energy consumption during energy supply emergencies.

The plan, last updated in 1993, is outdated by advances in technology, changes in industry practice and the utility’s generation capacity. Further, the 1993 plan addresses only long-term shortages and not the more typical short-term events. The updated plan addresses the more common short-term emergencies such as a temporary loss of generation, failed equipment, extreme weather and temperatures or a system disturbance within the Western Interconnection.
The commission said Rocky Mountain Power’s plan contains “appropriate procedures” to temporarily interrupt electric service to customers during emergencies and power shortages while, at the same time, minimizing adverse impacts to customers and maintaining system reliability.
Rocky Mountain Power, a division of PacifiCorp, serves customers in Utah, southeastern Idaho and much of Wyoming.
The plan states that the company will endeavor to contact the commission before outages. “Such reporting is significant because the commission is the designated Energy Emergencies Coordinator for response and recovery efforts dealing with significant disruptions in energy supplies for all hazardous emergency situations,” the commission said.
The plan recognizes that the utility already has demand-side management (DSM) programs under which customers reduce load during peak consumption during periods of short supply and it has large customers that already agree to be interrupted to achieve reductions in load.
The plan anticipates five stages that are used as the energy deficit increases.
The first stage is to implement load shedding from customers that can be contractually interrupted or are part of the company’s existing DSM program. The second stage is a public appeal to voluntary load reduction by all customers. Third is a mandatory up to two-hour curtailment during peak hours by customers who have been grouped into blocks of about 100 megawatts near selected distribution feeders. However, distribution feeders serving facilities essential to the public welfare are avoided during this rotational curtailment. These include, among others, hospitals, 911 centers, airports, large water and sewer treatment plants, prisons, police and fire stations and facilities critical to electric system operation. The commission said it expected Rocky Mountain “to take serious its commitment to identify and avoid curtailment of circuits that serve essential services.”
The fourth step is a mandatory curtailment in two-hour block rotations during peak or non-peak hours. The fifth and final step is mandatory emergency load reduction.
Under the former plan, only the State of Idaho could declare an energy emergency that would trigger curtailment. The updated plan recognizes the role of the Western Electricity Coordinating Council (WECC) and its Regional Reliability Coordinator to implement and enforce regional reliability standards in the western United States. Emergencies that threaten the integrity of the electric system can develop at any time due to a shortage of generation or disturbances on the system, either locally or within the Western Interconnection. Thus, the updated plan states that WECC or the Idaho Commission may order energy curtailments. However, nothing precludes Rocky Mountain Power from requesting voluntary load reduction at any time.
The plan eliminates financial penalties that could be assessed parties for noncompliance with curtailment orders.
“We encourage and look forward to more frequent updates by all utilities regarding their curtailment plans,” the commission said.

PacifiCorp updates net power costs; proposes plan
that may keep rates stable through 2018

Case No. PAC-E-16-12, Order No. 33597

September 15, 2016 – PacifiCorp, which does business as Rocky Mountain Power in eastern Idaho, is asking the commission to update the base level of its net power costs to reflect reduced load and lower prices. The result would be a reduction in rates of about 0.4 percent effective Jan. 1, 2017. (The commission had not yet issued a final order at the completion of this report.)

In the alternative, the company is proposing a “Rate Mitigation Plan,” that would take this small reduction with a slightly larger reduction the company anticipates next fall and apply both against a future base rate increase. The plan, according to PacifiCorp, would keep rates stable through 2018 and mitigate the size of a future base rate increase. If the commission were to adopt the plan, the company says it would not file a general rate case before June 1, 2018 with new rates effective in early 2019 at the earliest.

Net power costs throughout PacifiCorp’s six-state territory were $1.485 billion, less than the $1.529 billion currently in base rates. Idaho’s portion of net power costs are $91.6 million, down from $94.8 million now in rates.

Rocky Mountain Power anticipates that its annual Energy Cost Adjustment Mechanism (ECAM) could be a $4.5 million to $5.5 million reduction next fall. The Rate Stability Plan would leave the ECAM at current levels and also apply the anticipated lower ECAM against the amount that would be sought in the company’s next rate case.

Net power costs are those costs the company pays to provide generation to customers, whether from its own generation plants, the wholesale market or power purchase contracts as well as related fuel, transportation and transmission costs. They do not include fixed costs like physical plant and operations and maintenance. Net power costs are always variable because of changing weather and market conditions.

The net power cost that is included in base rates is the basis from which the annual ECAM is calculated. If net power costs are greater than that included in base rates, customers get a one-year surcharge. If they are less, customers get a one-year credit.

Idaho commission approves two-year extension
of cost-sharing arrangement among PacifiCorp states

Case No. PAC-E-15-16, Order No. 33623

October 18, 2016 – The commission approved a two-year extension of a plan that allocates PacifiCorp’s cost of serving its customers across its six-state territory based on each state’s share to PacifiCorp’s total system load. PacifiCorp does business in eastern Idaho, Utah and Wyoming as Rocky Mountain Power.

The “Multi-State Protocol,” increases the revenue requirement by 1.7%, or $150,000 above the current Idaho share of $986,000. The increase does not immediately impact rates, but allows PacifiCorp to set aside $12,500 per month for possible recovery from customers in a rate adjustment that would be effective Jan 1, 2018 at the latest.

In 1989, Pacific Power and Light merged with Utah Power & Light to create PacifiCorp. After that merger, each of the six state commissions in PacifiCorp’s territory apportioned costs to customers using different methods. PacifiCorp claimed at the time that each state’s differing methods resulted in the utility not being able to fully recover its costs. That led to uncertainty in financial markets about whether PacifiCorp would be able to recover its investment in capital improvements and additions. A multi-state process was formed in about 2002 to allow the company and all six states to continue discussions about an equitable way to allocate costs so that customers pay for the benefits they receive, while not subsidizing customers in other states. The first protocol was adopted in 2005 and the second in 2010.
The 2010 protocol still did not collect enough to fully recover PacifiCorp’s cost, the utility claimed. To address the shortfall, PacifiCorp and the signers of the agreement agreed to a fixed-dollar “equalization adjustment” to be added to each state’s revenue requirement. The total for all states is an additional $9.1 million, or about a two-tenths of 1 percent increase in each state’s annual revenue requirement.

The 2017 Protocol update was negotiated and agreed to by representatives of PacifiCorp, the staffs of the Idaho, Oregon, Utah and Wyoming commissions and other interested stakeholders. California did not participate in the discussions but implements the allocation methodology adopted by the other states. Washington participated in early discussions, but previously adopted a different allocation methodology.
The protocol does not make other changes to the 2010 agreement because of uncertainty over the impact of the federal government’s proposed Clean Power Plan as well as the possibility that PacifiCorp may become part of a regional independent system operator.
The protocol continues the past “rolled-in method,” that ensures each state pays only for PacifiCorp’s prudently incurred costs to serve that state.
“We recognize that different rolled-in methods exist, and that some of them could have increased PacifiCorp Idaho’s revenue requirement beyond the increase proposed here,” the commission said.
The 1.7 percent increase to the Idaho revenue requirement “appropriately follows the principle that cost-causers should be the cost-payers and reasonable ensures Idaho customers will pay only for the share of total system costs that PacifiCorp prudently incurs to serve them,” the commission said.

Natural Gas

Consumption and prices decline in 2015

In Idaho, natural gas is supplied to customers by Avista Corporation, Dominion Questar Gas (formerly Questar Gas) and Intermountain Gas Company. Idaho is fortunate to be located between two large natural gas storage basins: The Rocky Mountain Basin (Rockies) and the Western Canadian Sedimentary Basin (WCSB). These basins are connected through the Williams Northwest Pipeline and the TransCanada Gas Transmission Northwest pipelines allowing the utility companies serving Idaho to take advantage of capacity and of pricing at both basins.

Individual Idaho Gas Utility Profiles

2015 Statistics Total Residential Commercial Industrial Transportation Intermountain Gas Customers 338,251 306,026 32,106 18 101 % of Total 100% 90.47% 9.49% 0.01% 0.03% Therms (millions) 700.6 200 103 5.7 276.9 % of Total 100% 34.43% 17.64% 0.83% 55.92% Revenue (millions) $247.30 $160.40 $74.20 $3.00 $9.70 % of Total 100% 64.86% 30.00% 1.21% 3.92% Avista Corporation Customers 79,398 70,481 8,817 92 8 % of Total 100% 88.77% 11.10% 0.12% 0.01% Therms (millions) 113.92 42.01 25.33 2.07 44.51 % of Total 100% 36.88% 22.23% 1.82% 39.07% Revenue (millions) $61.90 $40.28 $19.78 $1.37 $0.44 % of Total 100% 65.10% 31.97% 2.21% 0.71% Questar Gas Customers 2,135 1,887 248 0 0 % of Total 100% 88.38% 11.62% 0% 0% Therms (millions) 2.11 1.12 0.91 0 0 % of Total 100% 56.74% 43.26% 0% 0% Revenue (millions) $1.80 $1.11 $0.69 $0.00 $0.00 % of Total 100% 61.54% 38.46% 0% 0%

Consumption
Regional consumption rates in all customer segments were lower than anticipated and are projected to slightly decline in 2016. Overall consumption declined 2.9 percent for the residential segment. Commercial increased slightly while industrial consumption grew 13.1 percent. Consumption for electric generation grew by 55.5 percent and is driving overall load growth.

A number of factors could increase demand for natural gas:
Natural gas used for generating electricity.
Significant incremental industrial loads.
The potential for natural gas as a transportation fuel.
LNG and petrochemical exports.
Energy policies, regulations, and legislation.

Prices
Natural gas spot prices are projected to decline in 2016 to an average of $2.36/Dth (dekatherm), which is 25.32 percent lower than the 2015 average of $3.16/Dth.
A number of market dynamics could influence future natural gas prices:
North American economic growth.
The rate of natural gas for exports, electric generation, industrial and transportation uses.
Regulatory costs that add to the cost of accessing, producing or transporting natural gas.
Advances in production tools and technologies.

Summary

Idaho residential, commercial and industrial users of natural gas continue to benefit from low natural gas prices and plentiful supply. Advancements in shale extraction and production techniques continue to transform the industry.

-by Kevin Keyt, IPUC Staff Analyst

Gas Cases

Intermountain Gas seeking 4% base rate increase

Case No. INT-G-16-02, Order No. 33593

September 9, 2016 – On Aug. 12, Intermountain Gas filed an application with the commission to increase its base rate an average 4 percent, or about $10.2 million. It is the first Intermountain Gas base rate case since 1985. (A decision in the rate case had not made by the time this annual report was published.)

If the full base rate request were granted, a residential customer who uses the company’s average of 747 therms per year and uses natural gas for space and water heating, would experience an increase of about $2.31 per month. A residential customer who uses natural gas only for space heating would see an increase of about $1.16 per month. Commercial customers’ monthly increase would be about $12.16. These numbers do not include the reduction in variable rates that would occur if the company’s PGA application were granted.

Intermountain Gas, which serves about 334,650 customers in 75 communities across southern Idaho, says the base rate increase is needed because of increased operating costs to meet customer growth, the need to replace customer service information and technology systems, and increased costs related to pipeline safety regulations and compliance.

Since its last rate case in 1985, the number of Intermountain Gas residential customers has increased from 85,400 to more than 300,000. In the same period, the number of commercial customers has increased from 13,300 to nearly 32,000. While more customers increase sales revenue, they also require more investment in non-revenue generating infrastructure such as pipeline expansion and replacement and customer care systems and information technology, Intermountain Gas claims.
The commission’s staff of auditors, engineers and attorneys are in the midst of a six-month investigation of Intermountain’s application. The commission, by state law, cannot accept or deny the requested increase without first considering the evidence. State law requires that regulated utilities be allowed to recover their prudently incurred expenses and earn a reasonable rate of return, which is also established by the commission.

Intermountain Gas is requesting a 9.9 percent return on equity and an overall rate of return of 7.42 percent. The burden of proof is on the utility to demonstrate that its additional capital investment is necessary to serve customers and if those expenses are prudently incurred. Commission decisions can be appealed to the state Supreme Court by either the utility or customer groups.

Another issue in the case is Intermountain Gas’ proposal to create demand side management (DSM) programs to help customers reduce natural gas consumption. One of those programs would provide rebates to customers who install high-efficiency natural gas equipment and ENERGY Star certified homes.
Natural gas utilities, like electric utilities, are sometimes discouraged from enacting programs to help customers reduce consumption because they depend on sales to meet their fixed costs of operating. In recent years, more efficient building code standards and appliances have resulted in customers using less natural gas, thus reducing the margin the company relies on to pay for fixed costs such as expanding or replacing its pipeline distribution system.
To address the financial disincentive to encourage conservation and the reduced fixed cost recovery, Intermountain Gas is proposing to implement a Fixed Cost Collection Mechanism (FCCM) – similar to Idaho Power’s Fixed Cost Adjustment – that ensures stability in revenues regardless of how much natural gas customers use. The company claims the yearly rate adjustment would allow Intermountain Gas to effectively promote DSM programs without the financial disincentives that currently exist.

Hefty natural gas supply results in lower PGA

Case No. INT-G-16-03, Order No. 33604

October 4, 2016 – Gas rates for the 335,000 southern Idaho customers of Intermountain Gas Company decreased an average 7.1 percent on Oct. 1 following regulators’ approval of the company’s annual Purchased Gas Cost Adjustment (PGA).

Every Oct. 1, the variable portion of Intermountain Gas rates is adjusted upward or downward by the Idaho Public Utilities Commission to reflect changes in the company’s costs to buy natural gas from its suppliers and also changes in transportation, storage and other variable costs.
Significant supplies of North American shale gas and substantial gas storage balances were the major factors contributing to lower gas supply costs for the company. In an effort to further stabilize prices, the company entered into various fixed-price agreements to lock in the price of its underground storage and other winter gas supply.
As a result, residential customers who use natural gas for both space and water heating will see a reduction of about $3.48 per month, while residential customers who use natural gas just for space heating will receive about a $2.03 monthly reduction. For commercial customers, the decrease is about $14.23 monthly.
Intermountain’s weighted average cost of gas, or WACOG, is reduced from 32.8 cents per therm to 29.7 cents. The WACOG represents just under half of a residential customer’s overall rate.
The other half of customer rates are primarily fixed costs. While the PGA addresses just variable costs, fixed costs are addressed in base rate cases. Intermountain Gas currently has an application before the commission to increase its base rates by an average 4 percent. (Case No. INT-G-16-02). That case will likely be decided by next March. It is the first Intermountain Gas base rate case since 1985.

Avista gas rates decreasing an average 7.8 percent

Case No. AVU-G-16-02, Order No. 33637

October 28, 2016 – The commission approved Avista Utilities’ application to decrease the variable portion of natural gas rates by 7.8 percent effective Nov. 1.

The variable portion of Avista rates, which is about 50 percent of the total overall rate on a customer bill, is adjusted every year to account for changes in Avista’s costs to buy natural gas as well as changes in transportation, storage and other related costs. Because these costs are based on always changing market conditions, the forecasted rate is adjusted every year to match actual cost.

The average residential or small commercial customer will see a decrease of about $4.65 per month as a result of Avista’s annual Purchased Gas Cost Adjustment (PGA).

The decrease is primarily attributable to a reduction in natural gas commodity costs due to a warmer than normal 2015-16 winter, an abundance of natural gas in storage and continued high production levels of natural gas.

During years when natural gas prices are lower than that already included in rates, customers get a one-year credit. When market prices are higher than included in rates, customers get a one-year surcharge. Neither an increase nor a decrease to the PGA impacts Avista’s earnings.

Convenience fee for Avista customers going away
Case No. AVU-E-16-01, AVU-G-16-01, Order No. 33494

April 1, 2016 – A $3.50 convenience fee paid by residential customers of Avista Utilities will soon be going away. The fee is charged by a third-party vendor when Avista electric or natural gas customers pay their bills online or by telephone.

Avista received approval from the commission to process the online and telephonic payments on its own, something the utility says it can do for as little as $1.50 per transaction.

According to Avista, the convenience fee is “one of the largest frustrations” expressed by the utility’s growing number of customers who pay electronically or by telephone. Only about 38 percent of customers mailed in payments in 2015, with the rest paying online or over the telephone.

Avista serves about 125,000 electric and 80,000 natural gas customers in northern Idaho.

Avista estimates it will cost about $195,000 per year to process the payments for its Idaho electric customers and $120,000 per year for natural gas customers. Avista will defer and record the costs it incurs to process the payments for possible inclusion in a later rate case. It will also file a report with the commission every six months detailing program expense and customer participation levels.

The utility has also received approval in its Washington and Oregon jurisdictions to eliminate the fee.

PUC updates contract with Utah commission
for natural gas service in Franklin County

Case No. QST-G-16-01, Order No. 33496

April 21, 2016 – The commission approved an updated contract with the Utah Public Service Commission that allows the Utah panel continued jurisdiction over Questar Gas Company’s service to customers in Franklin County, Idaho.

Questar, headquartered in Salt Lake City, has about 900,000 customers in Utah, southwestern Wyoming and Franklin County, Idaho (where it has about 2,000 customers).

Questar provides natural gas service to the communities of Preston and Franklin in Franklin County. In 2015, Questar’s service territory was expanded to include the community of Dayton and all of Franklin County.

Because of the county’s proximity to Utah and the small number of customers involved, the Idaho PUC and the Utah commission entered into an agreement in 1990 giving Utah the authority to set rates and customer service regulations for Questar’s Idaho customers.

Under the agreement, Idaho customers have full rights of participation before the Utah commission, including the opportunity to pursue service-related issues against the company. Rates, charges and service regulations for Idaho customers must be no less favorable than those in Utah. Idaho Code §61-505 allows the Idaho commission to contract with regulatory agencies of neighboring states to set rates and charges for customers in Idaho located in or nearby border communities who are served by utilities that are “principally” located in neighboring states.

The 1990 agreement has been updated, in part, because of a proposed merger between Questar and Virginia-based Dominion Resources. If the merger is approved by the Utah and Wyoming commissions, the company will change its name to Dominion Questar Gas. Existing rates and regulations will not be changed as a result of the proposed merger.

The commission noted that is “impractical” and not in the public interest for the Idaho commission to regulate a utility principally located in Utah with such a small Idaho customer base. However, Idaho maintains pipeline safety supervision over Questar facilities inside Idaho.

The agreement between the Idaho and Utah commissions will be automatically renewed each year on April 1 subject to termination by either commission upon written notice.

Water

PUC approves United Water rate case settlement

Case No. UWI-W-15-01, Order No. 33436

December 16, 2015 – The commission adopted a settlement to the United Water Idaho* rate case. The settlement increases rates by 6% effective Dec. 22, 2015, and another 1.4% on Dec. 22, 2016.

For a residential customer who uses the company’s average consumption the 6% increase is about $1.25 every two months, from $20.80 to $22.05.

In May 2015, United Water Idaho proposed a one-year, 13.2% increase, raising an additional $5.88 million in annual revenue. The settlement approved today reduces the revenue increase by 57%, to $2.73 million in 2016 and $670,000 in 2017.

Parties to the settlement included United Water, commission staff and the Community Action Partnership Association of Idaho (CAPAI), which represents primarily customers on low- and fixed-incomes.

The settlement also provides that United Water will increase its contribution to the “United Water Cares” program from $65 to $75 per customer per year to provide financial assistance to low-income customers. In future years, the company will increase its contribution by the same percent as the rate increase it is granted. None of the program’s costs are included in customer rates. United Water Idaho serves more than 90,000 customers in Ada County.

Commission staff supported the settlement, stating it represents “a significantly better deal for customers than could be achieved through either a one-year settlement or litigation of the current rate case.” Staff said a “stay-out provision” that prevents another increase until December 2017 at the earliest “provides rate stability for customers.”

United Water said the increase was 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.

The settlement reduced the company’s original revenue requirement considerably by establishing deferrals and amortization periods for power costs, rate case expense, tank paintings, pension expense, relocation expense and conservation expense.

The commission received 35 public comments before the proposed settlement, nearly all of them opposed to the increase. After the settlement was announced and offered for public comment, only one comment was received and that was in support of the settlement. A public hearing was held at which no customer attended or testified.

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.

###

(*During this rate case proceeding, United Water Idaho applied to the commission for a change to its name to SUEZ Water Idaho. The commission authorized the name change in Order No. 33429. All future orders and press releases will use the SUEZ Water Idaho name.)

Certificate approved for Bonner County company

Case No. SCH-W-15-01, Order No. 33543

June 30, 2016 – The commission issued a certificate for Schweitzer Basin Water, LLC., to operate as a regulated water utility in Bonner County and approved rates for the company’s customers.

Schweitzer is a privately-owned water system serving a residential area at the base of the Schweitzer Mountain ski resort. The water utility is owned by Mel Bailey with a business office in Sandpoint.

The company provides service to about 431 residential customers, but nearly all of those are seasonal customers. About 12 households are year-round customers with another five households present about three months of the year. The company anticipates significant growth. Only about 43 percent of the lots are developed and the company projects between 140 and 180 new living units will be built over the next 30 years.

The water system uses four wells, five reservoirs, and more than six miles of distribution system with seven pressure zones.

The commission approved the company’s request to continue with current flat rate of $41 per month for single-family homes more than 500 square feet and $39 per month for those smaller. The rate is $82 per month for a single unit with a second living area that can be rented and $65 a month for a single unit with an additional guesthouse or attached living unit that can be rented. Customers are billed quarterly. Customers who voluntarily disconnect and then re-connect must pay a $300 reconnection fee. The reconnection fee is designed to discourage customers from disconnecting during non-use times of the year. A number of customers disconnecting from the system during much of the year would make it impossible for the company to recover its fixed costs.

While approving most of the company’s application, the commission denied a proposed $500 fee for inspecting and testing relating to hooking up with the system. The commission said those expenses should be included in the initial infrastructure contribution fee of $6,950 for single-family units and $3,475 for additional living areas. The commission also denied the company’s request to assess a $500 fee if potential new customers receive a “Will Serve” letter for non-payment of hook-up fees.

Eagle Water surcharge delayed for up to one year

Case No. EAG-W-15-01, Order No. 33567

August 12, 2016 – A request by Eagle Water Company to implement a surcharge on customers’ water use has been stayed for up to one year to allow more time for the company to locate documents and consider settlement options and alternatives.

On Nov. 10, 2015, Eagle Water, which serves about 3,500 customers in and around the City of Eagle, asked the commission to approve a surcharge that would add about $3.64 to the average residential user’s monthly bill. (Eagle Water is a privately-owned water system and not the same entity as the City of Eagle Water Department.)

Eagle Water’s application has been suspended three times, first at the commission’s discretion and then two requests to suspend from the company were granted.

If a motion to lift the suspension is not made within one year of the commission’s August 10 order, the case will be dismissed.

Eagle Water seeks the surcharge to pay for a near $800,000 loan to finance about $935,000 in improvements. The portion of expense not funded by the loan would be paid from $150,000 in the utility’s existing surcharge account.

Eagle Water proposed that the surcharge apply only to consumption of more than 600 cubic feet (ccf) per month. (100 cubic feet is about 748 gallons.) For a residential customer who uses the company’s average of about 21 ccf/month, the proposed surcharge would have raised rates an average $3.64 more per month. A commercial customer who uses the company average of 69 ccf/month would pay about $15.29 more per month.

Eagle Water claimed the improvements are needed to alleviate water pressure problems in the northeastern part of its service territory. The largest portion of the improvements – nearly $600,000 – would go toward construction of a seventh well. Other improvements identified by the company are $150,000 for the main booster station, $62,200 for repairs to Well No. 4, $47,000 to upsize a line at another well, $26,000 for a Hill Road line relocation, $25,600 for repairs to Well No. 6, $13,400 for a State Street bridge line relocation and $6,500 for a bridge line relocation at Horseshoe Bend Road.

Commission OKs Diamond Bar Water rate increase

Case No. DIA-W-15-01, Order No. 33578

September 6, 2016 – The commission approved an approximate 46.7 percent revenue increase for Diamond Bar Estates Water Company effective Aug. 30. The increase is less than the company’s request of 79 percent. It is the first time base rates have been adjusted since 2007.

Diamond Bar serves about 44 residential customers, most living on five-acre lots near Rathdrum in Kootenai County.

The largest portion of expense the company sought related to several pump failures since the 2007 rate case. Four of the failures includes in this case totaled $51,444 in expense for which the company sought rate recovery. The commission allowed $31,258 after removing expense the company should have received from insurance and accumulated depreciation.

The company wanted to recover the pump failure expense from customers over a four-year period, but the commission extended the amortization over 18 years, which is the average remaining life of the pumps. That reduced the yearly amortization required from customers to $1,737, or $4,013 less per year than the company requested.

The commission commended the active participation of the company’s customers in helping to determine the cause of the pump failures and the extent to which the company knew or should have known about the cause of the failures.

“It is clear to the commission, both from the detailed written submissions and the thoughtful testimony provided at the public hearing, that customers put a great deal of time and effort into their comments,” the commission stated. “These efforts have not gone unnoticed.”

While a number of factors contributed to the pump failures, the commission determined the primary cause was an electric transformer that was too small for the simultaneous starting and operation of the water system’s four pumps. The commission directed the company to confirm with its electric supplier, Kootenai Electric Cooperative, that the current transformer is sized in accordance with the National Electric Code and that the service drop complies with Kootenai Electric’s engineering guidelines.
The commission also directed the company to adopt customers’ recommendations that a “text alert service,” be implemented to promptly notify customers when the company knows it will have a service-related outage. Outages can cause customers’ re-circulating pumps to fail, requiring their replacement at a cost of $400 to $500 each.

Under the new rate structure, the minimum monthly charge for all customers is $41, up from the current $29. Diamond Bar requested a monthly minimum of $52.02. The commodity charge increases from 80 cents for every 1,000 gallons above 5,500 gallons per month to $1.16 per thousand gallons. The company requested $1.44. The commission approved an increase in the connection charge for new customers from $310 to $335. Diamond Bar requested a $475 connection charge. These adjustments will increase the company’s annual revenue by $37,704. Diamond Bar requested $47,248.

The commission said it recognizes the financial hardship the increase will cause for some customers, but cited its statutory duty to ensure utilities have the financial ability to perform essential services. The obligation to ensure reasonable rates “must be balanced with our duty – of equal importance – to ensure that rates are sufficient to ensure adequate service,” the commission said. The Idaho Supreme Court has held that the commission’s duty is “not only to fix just and reasonable, nondiscriminatory rates, but to see that adequate service is furnished and in fixing such rates to allow the utility furnishing the service to make a just and reasonable profit or return on its investment.” All commission orders are subject to appeal to the state Supreme Court by either the company or its customers and other interested parties to the case.

The commission approved a 12 percent rate of return, which is consistent with what it has allowed in other small water company cases. Commission staff conducted a workshop on April 19, attended by more than 30 customers. Several customers also attended a public hearing on June 7. The commission also received about 18 written comments.

Packsaddle Estates Water Corporation is sold to Teton County homeowners

Case No. PKS-W-15-01, Order No. 33603

September 21, 2016 – The commission approved an application by Packsaddles Estates Water Corporation to sell the water system to the homeowners residing in the Teton County, Idaho subdivision, thus allowing the homeowners to operate the previously privately owned and regulated water corporation and remove it from PUC jurisdiction.

The 35 residential customers of Packsaddle Estates Water Corporation formed Packsaddle Water Systems, Inc., leaving matters such as rates and customer service issues to be determined by the owners, who will operate the company on a non-profit basis.

The homeowners formed a mutual, non-profit organization represented by board members in a “democratically run corporation,” according to the application. The directors said they were approached about taking over the company by the owner who was experiencing health-related issues.

The homeowners association claims that all of the fees collected from subdivision customers will be used for the operation and maintenance of the water system. The association said it has access to individuals who will ensure that the water system will comply with state Department of Environmental Quality requirements. Some of the homeowners objected to the application, maintaining they had not been properly notified.

The treasurer of the homeowners association is Robert Vostrejs of Driggs.

Telecommunications

Commission adopts proposal to disburse Qwest funds
for suicide prevention hotline, E-911 dispatch training

Case No. GNT-T-16-04, Order No. 33532

June 13, 2016 – The commission adopted a proposal of commission staff to disburse about $90,000 remaining in a commission-maintained Qwest Corporation compliance account to Idaho’s Suicide Prevention Hotline and to Idaho’s Police Officer Standards and Training Academy (POST).

Qwest, the predecessor company to what is now CenturyLink, paid into the fund when it failed to meet performance standards designed to ensure that other telecommunications providers were allowed access to Qwest facilities to provide competitive telecommunications services. Payments to the fund were discontinued in 2010.

Commission staff proposed that $44,900 be allocated to the Idaho Department of Health & Welfare’s Suicide Prevention Action Network and $44,910 be allocated toward training and certification of E-911 emergency dispatchers at POST.

The commission adopted staff’s recommendations, stating that the proposed uses of the remaining funds were in the public interest.

Suicide is the second-leading cause of death for Idahoans ages 15-34. Idaho’s overall suicide rate is 52 percent higher than the national average and double the national average for youths ages 10-19. To address this priority at-risk age group, the Suicide Prevention Hotline is launching “Texts for Life,” to reach people more comfortable texting or using an on-line chat service. While the new service will be open to all ages, the focus is on support for youths and others who favor these technologies, including veterans. The new money will improve the hotline’s capacity to handle several thousand text messages as well as chats and calls from those in crisis.

The allocation to POST will pay for about four years (at about $10,000 a year) to fully develop the certification program required for emergency dispatchers at “911” centers while other funding solutions are identified.

Telecommunications Utilities Under IPUC Jurisdiction

Consumer Assistance

Commission issues annual consumer assistance report
The Consumer Assistance staff responded to 1,463 complaints, and inquiries in calendar year 2016, of which 92 percent were from residential customers.

Breakdown by type of utility:

Contacts regarding telecommunications companies: 33 percent
Contacts regarding energy (electric, gas) companies: 43 percent
Contacts regarding water companies: 14 percent
Miscellaneous: 11 percent

(CenturyLink had 52 percent of telecommunication complaints; Idaho Power had 56 percent and Intermountain
Gas16 percent of energy utility complaints and United Water had 36 percent of water complaints.)

Summary of issues:

Billings 21 percent
Credit and collection issues 28 percent
Miscellaneous 23 percent
Utility rates and policies 12 percent
Telecommunications issues 5 percent
Line extensions and service upgrades 4 percent
Service quality and repair 8 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 71 percent of consumer complaints required investigation by the staff. About 39 percent of investigations resulted in reversal or modification of the utilities’ original action.

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

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 one FRA certified hazardous material inspector.

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 2016

Inspections 61
Rail cars inspected 647
Violations 0
Rail cars with defects 44
Crossing accidents investigated 16
Locomotives Inspected 2
Defects within locomotives inspected 0

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 three trained 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 194.5
Compliance inspection days 10
Damage prevention inspection days 0
Construction inspection days 12
Operator Qualification inspection days 9.5
Integrity Management Program inspection days 4
Incident/Accident inspection days 0
Operator Training inspection days 0

Compliance Enforcement Actions:
Notice of Probable Violation 0
Notice of Amendment 0
Warning Letters 0

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 2016 calendar year. (The financial report on Page 11 covers Fiscal Year July 1, 2015 through June 30, 2016.) 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 12-100-2016.

Questions:

Gene Fadness, Policy Strategist/Public Information Officer
334-0339
[e-mail]

Order No. 70, FERC Stats. & Regs. ¶ 30,134, at 30,943-44, order on reh'g, Order Nos. 69-A and 70-A, FERC Stats. & Regs. ¶ 30,160 (1980), aff'd in part and vacated in part, American Elec. Pwr. Svc. Corp. v. FERC, 675 F.2d 1226 (D.C. Cir. 1982), rev’d in part, American Paper Inst., Inc. v. American Elec. Pwr. Svc. Corp., 461 U.S. 402 (1983).
North Laramie Range Alliance, 139 FERC ¶ 61,190 at P 22 (2012).

AD16-16-000 Technical Conference Transcript, June 29, 2016 (“Tr.”) at 65:25-66:3 (Commissioner Clark).

The Commission’s Notice of Proposed Rulemaking in Docket No. RM79-54 (FERC Stats. & Regs. [1977-1981 Proposed Regulations] ¶ 32,028 at 32,332 (June 27, 1979) would have established the one-mile rule as a rebuttable presumption. However, the Commission determined in Order No. 70 that “the requirement to rebut the presumption was burdensome and confusing” and revised the final rule “enable a small power producer . . . to apply to the Commission for a waiver for good cause” (FERC Stats. & Regs. ¶ 30,134 at 30,944).
As of December 14, 2010, standard rate contract pricing was only available to wind and solar projects producing 100 kW or less (the threshold for standard rates had been 10 aMW prior to December 14, 2010). IPUC Order No. 32260.

Ultimately, in a settlement approved by the IPUC, the five Cedar Creek projects were reduced to three projects (Coyote Hill, North Point, and Five Pine), at standard (published) avoided cost rates; applications to approve the Rattlesnake Canyon and Steep Ridge projects were withdrawn. See IPUC Order No. 32419.
By “larger QFs,” we mean those not subject to standard published rates.

The Idaho PUC has not adopted this latter approach because it is our interpretation that the Commission’s regulations do not allow for it. See 18 C.F.R. § 292.304(d)(2). The Commission’s regulations state that a QF has the option “[t]o provide energy or capacity pursuant to a legally enforceable obligation . . . over a specified term.” Id. In that case, the QF has the option of electing for its rates to be based on the avoided costs calculated at the time of delivery or on the avoided costs “calculated at the time the obligation is incurred.” Id. Section 292.304(d)(2)(ii)(emphasis added). We have interpreted “calculated at the time the obligation is incurred” to mean that an avoided cost rate is calculated and then fixed for the specified term. See also Freehold Cogen. Assocs. v. Bd. of Reg. Comm’rs, 44 F.3d 1178, 1192 (3rd Cir. 1995) citing 18 C.F.R. § 385.602(c) (exempting qualifying facilities from state laws regulating rates of electric utilities).
18 C.F.R. §§ 292.302, 292.304(e) (2015).

Transportation is nonutility owned gas transported for another party under contractual agreement.
NWGA 2016 Gas Outlook
EIA (Energy Information Administration)
Dekatherm = 10 Therms or 1,000,000 British thermal units (MMBtu)

Report (Median design)

Idaho Public Utilities Commission

Page 2

Page 19

IDAHO PUBLIC UTILITIES COMMISSION

472 W. Washington St., Boise PO Box 83720 83720-0074 208.334.0300
www.puc.idaho.gov

PUC hearing room

PUC headquarters at 472 W. Washington St., Boise.

Idaho Public Utilities Commission staff pictured with representatives from the Rwanda Utilities Regulatory Authority. Participants include, (front row from left) Bentley Erdwurm, Stacey Donohue, Aimee Nshimirimana (RURA), Alex Mudasingwa (RURA), Terri Carlock and Kathy Stockton; (middle row from left) Matt Elam, Yao Yin, Mark Rogers, Donn English and Gene Fadness; (back row from left) Mike Morrison, Mike Louis, Joe Terry and Johnathan Farley.

PUC adopts settlement to Avista case

Case No. AVU-E-15-05, AVU-G-15-01, Order No. 33437

Dec. 22, 2015 – The commission adopted a settlement to the Avista Utilities electric and natural gas rate case that increased electric rates an average 0.6% (six-tenths of 1%) and natural gas rates by 3.5% effective Jan. 1, 2016. The settlement is a significant reduction from Avista’s original electric rate request of 10.3% over two years – 5.2% in 2015 and 5.1% in 2017. On the gas side, Avista originally requested 4.5% in 2016 and 2.2% in 2017. The settlement reduces Avista’s requested annual electric revenue increase from $13.2 million to $1.7 million. It reduces the requested natural gas annual revenue increase from $3.2 million to $2.5 million. Avista sought a 9.9% return on equity and was granted 9.5%.

For a residential customer who uses the company average of 929 kilowatt-hours per month, the increase is about 75 cents per month. The original request would have increased bills by about $5.92 per month in 2016 and $6.10 in 2017. For a natural gas customer who uses the company average of 61 therms per month, the increase is about $3.20 per month, counting the $1 per month increase in the basic service charge. The original request would have increased natural gas bills $3.90 per month in 2016 and $1.79 per month in 2017. 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.

The commission approved the company’s request for an annual rate adjustment called the Fixed Cost Adjustment (FCA). The FCA will be a surcharge or a rebate granted every year depending on whether Avista recovers its fixed costs of doing business. During some years, the utility may not recover its fixed costs due to changes in conservation, weather or the economy. By ensuring that Avista recovers its fixed costs when electricity and natural gas sales decline, the FCA removes the disincentive for Avista to invest in and promote energy efficiency programs.

The FCA will have an initial term of three years and will be reviewed to determine whether the adjustment should continue. During those years when there is a surcharge, the charge cannot exceed 3%. There is no cap on the amount a rebate can be.

Rocky Mountain ECAM is slight decrease
while efficiency surcharge is slight increase

Case No. PAC-E-16-05, Order No. 33492
Case No. PAC-E-16-02, Order No. 33491

April 1, 2016 – The commission approved two rate adjustments – on an increase and the other a decrease – for Rocky Mountain Power customers that become effective April 1, 2016. Rocky Mountain Power’s annual Energy Cost Adjustment Mechanism (ECAM) will be a slight decrease to customers of 0.7 percent, or about 58 cents less on an average residential monthly bill. Its Customer Efficiency Services Rate is a 0.6 percent increase, from the current 2.1 percent of the monthly billed amount to 2.7 percent. For a residential customer who uses the company average of 837 kilowatt-hours per month, the increase will be 61 cents per month. Rocky Mountain Power serves about 73,000 customers in eastern Idaho.

Energy Cost Adjustment Mechanism

Rates for Rocky Mountain customers are adjusted either up or down every April 1 to account for power supply expense that varies from year to year depending on the previous year’s natural gas and coal, surplus power sales, power purchases and the market price of power. If variable costs are higher than what is already included in base rates, customers get a one-year surcharge; if they are lower, customers get a one-year credit. For the 12-month period ending Nov. 30, 2015, Rocky Mountain’s net power supply costs were $9.3 million less than that included in base rates, resulting in a rate credit to customers.

Customer Energy Efficiency Services

Rocky Mountain invests in a number of programs that either shift consumption to off-peak hours (demand response) or reduce consumption (energy efficiency). Funding for those programs is collected from the Energy Efficiency Services line item on customer bills.
Expenditures for the programs increased by about 38 percent from $3.2 million in 2014 to $4.4 million in 2015 due to increased customer participation. Savings from energy efficiency programs increased from 11,410 megawatt-hours in 2014 to about 15,440 MWh in 2016.

The commission said it aware of the impact that any rate increase can have on customers, particularly those on low- and fixed-incomes. But, the commission also noted that effective demand-side management programs delay the need for the company to build or buy from higher-cost generation resources.

Customers benefit in two ways from the programs. Participating customers benefit from lower bills by taking part in the programs. Customers who do not participate also benefit because the cost of the electricity saved is about half of what it would cost Rocky Mountain to generate or buy the same amount of energy.

Neither the ECAM decrease nor the Customer Efficiency Services Rate increase impact Rocky Mountain’s earnings. Money collected in the ECAM and the energy efficiency rate must go directly toward the deferred accounts established for each program.

Idaho Power’s annual adjustment mechanisms
result in average 3.5% increase for customers

Case No. IPC-E-16-08, Order No. 33526
Case No. IPC-E-16-02, Order No. 33527

May 31, 2016 – Rates for most Idaho Power Company customers will increase by about 3.5 percent June 1. Rates go up or down every June 1 as part of the company’s annual Power Cost Adjustment (PCA) and Fixed Cost Adjustment (FCA).

Power Cost Adjustment

Since 1993, the PCA allows Idaho Power to adjust rates up or down to reflect the company’s “power supply costs” that change from year to year. Idaho Power gets about half its generation from hydroelectric facilities, so a large portion of its costs to provide electricity to its customers is dependent on Snake River streamflows. Other costs that vary each year are the market price of wholesale electric power, fuel costs, transmission costs for purchased power and the revenue it earns from selling surplus power.

Idaho Power reported and commission staff verified that power supply expense for the company is $17.3 million less than what is included in the current PCA surcharge of 0.5405 cents per kilowatt-hour. The commission approved an increase in the surcharge to 0.6187 cents per kWh, which will increase an average residential bill by about 1.35 percent or $1.32 per month. The PCA increase is 1.35 percent for residential customers and an average 1.57 percent increase for all customer classes. To offset that increase, the commission approved $3.16 million in revenue sharing with Idaho Power customers and a $4 million credit given customers from unused demand-side management (DSM) rider revenue.

Idaho Power shares its revenue with customers when its Return on Equity is greater than 10 percent. The utility’s 2015 year-end ROE was 10.13 percent, which means the company will share $3.16 million with customers. However, Idaho Power’s earnings are down slightly from the 11.19 percent ROE during 2014, so the proposed $3.16 million revenue sharing with customers is about $5 million less than the revenue sharing customers received in last year’s PCA.
The commission said it is sensitive to economic conditions affecting ratepayers but has a “responsibility to balance the ratepayers’ desire for affordable energy prices with the company’s right to recover its costs and earn a reasonable return on its investments.” The commission emphasized that money collected through the PCA can be used only for recovery of actual power supply costs and cannot be used to increase earnings or salaries. Power supply expense is tracked in a deferred account, audited annually by the commission.

Idaho Power attributes the higher PCA to 1) increased PURPA generation, 2) less revenue sharing with customers due to a lower Return on Equity in 2015; 3) lower than projected hydro generation; and 4) lower than forecasted wholesale market prices for electricity, resulting in lower sales volumes for Idaho Power when it sells its surplus power into the market.

The utility has about $10 million additional expense related to power purchase contracts with solar developers. The solar contracts fall under the provisions of the Public Utility Regulatory Policies Act (PURPA), which requires utilities to purchase generation from qualifying renewable energy projects. The company said about 320 megawatts of PURPA solar projects and 50 MW of PURPA wind projects are expected to come online during the 2016-17 PCA year.

Reservoir levels in the region are lower than the 2015 forecast. While Idaho Power had a better water year in some parts of its service territory, last year’s dry winter left reservoirs in the Upper Snake River Basin very low by summer’s end. Actual hydro generation was 27 percent less than the company forecast.

Wholesale electric market prices declined due primarily to lower natural gas prices. Lower market prices reduced surplus sales volumes by 26 percent. Also, because wholesale market prices were lower, the company’s market purchase volumes were 92 percent higher than forecasted.

Fixed Cost Adjustment

The FCA, implemented in 2007, is designed to ensure Idaho Power recovers its fixed costs of delivering energy when energy sales decline due to reduced consumption. Before the FCA, Idaho Power had no incentive to invest in energy efficiency programs because it lost revenue as customer consumption declined. To remove that disincentive, the Fixed Cost Adjustment was created to allow the utility to recoup its fixed costs of doing business. Even though consumption may decline, the fixed cost to serve customers does not.

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 2015, Idaho Power under-collected fixed costs of serving residential and small business customers by $28 million, or $11.17 million more than the amount already included in the FCA account. To recover those fixed costs, the commission approved an FCA increase of 2.2 percent, which will increase an average residential and bill would by about $2.16 per month. The new FCA rate is 0.5416 cents per kWh. The FCA applies only to residential and small business customers.

During 2015, Idaho Power achieved a 22 percent increase in energy savings compared to 2014. In a separate case filed before the commission every year, Idaho Power must demonstrate that the programs that create energy efficiency savings must result in lower overall rates to customers than if the programs were not in place. Several studies have shown that energy efficiency and demand reduction are the least expensive source of energy for utilities. The FCA makes it possible for the company to aggressively pursue energy efficiency and demand-side management programs without fear of losing fixed costs to serve customers.

The 2015 PCA was a 1.1 percent decrease and last year’s FCA was a 0.35 percent increase, resulting in an overall net decrease to customers.

Regulated water companies

ITSAP assessment unchanged

Case No. GNR-T-16-03, Order No. 33495

April 6, 2016 – The number of Idahoans receiving low-income telephone assistance declined sharply during 2015, even while the number of wireline and wireless users increases.

The Idaho Telecommunications Service Assistance Program (ITSAP) provides a $2.50 per month discount for qualifying telephone and cell phone users. A federal program, Lifeline, provides another $9.25 per month. Funds for the Idaho program are raised through a surcharge on all end-user business, residential and wireless lines.

The Idaho Public Utilities Commission recently decided to leave that assessment at 1-cent per line per month to fund the Idaho portion of the program. The surcharge has declined from a high of 12 cents per line per month to 7 cents in 2013 and 3 cents in 2014.

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

Those who seek telephone assistance must be the head of a household and meet narrowly targeted eligibility criteria established by the state Department of Health and Welfare. The Public Utilities Commission establishes the amount of surcharge necessary to fund the program.

The average number of ITSAP recipients per month in 2015 was 6,693, down from 10,674 in 2014, 17,626 during 2013, 23,434 in 2012 and 25,310 in 2011.

The number of telephone lines to support the fund, both wireline and wireless, increased during 2015 after declining in 2014. Average wireline access lines per month increased from 427,065 in 2014 to 435,822 in 2015. The average number of wireless access lines per month in Idaho increased to 1,414,763 during 2015, compared to 1,329,112 in 2014.

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.
*Citizens Telecommunications Company of Idaho, dba as Frontier Communications of Idaho, 20575 NW Von Neuman Dr. Ste. 150, Beaverton, OR, 97006, 503-629-2459
Columbine, dba Silver Star Communications, PO Box 226, Freedom, Wyo., 83120, 877-883-2411
*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
Inland Telephone Co., 103 South Second Street, Box 171, Roslyn, WA 98941
509-649-2211
Fremont Telecom, Inc., dba Fremont Communications, 1221 N. Russell St., Missoula, MT, 59808, 406-541-5454
Inland Telephone Co., 103 S. Second St., Box 171, Roslyn, WA 98941, 509-649-2211
Midvale Telephone Company, Box 7, Midvale, Idaho 83645, 208-355-2211
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.