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0001057877-09-000113.txt : 20091109 0001057877-09-000113.hdr.sgml : 20091109 20091109165037 ACCESSION NUMBER: 0001057877-09-000113 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20091109 ITEM INFORMATION: Other Events ITEM INFORMATION: Financial Statements and Exhibits FILED AS OF DATE: 20091109 DATE AS OF CHANGE: 20091109 FILER: COMPANY DATA: COMPANY CONFORMED NAME: IDAHO POWER CO CENTRAL INDEX KEY: 0000049648 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 820130980 STATE OF INCORPORATION: ID FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03198 FILM NUMBER: 091169071 BUSINESS ADDRESS: STREET 1: 1221 W IDAHO ST STREET 2: PO BOX 70 CITY: BOISE STATE: ID ZIP: 83702 BUSINESS PHONE: 2083882200 MAIL ADDRESS: STREET 1: PO BOX 70 STREET 2: 1221 W IDAHO STREET CITY: BOISE STATE: ID ZIP: 83702-5627 FILER: COMPANY DATA: COMPANY CONFORMED NAME: IDACORP INC CENTRAL INDEX KEY: 0001057877 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 820505802 STATE OF INCORPORATION: ID FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-14465 FILM NUMBER: 091169070 BUSINESS ADDRESS: STREET 1: 1221 WEST IDAHO STREET CITY: BOISE STATE: ID ZIP: 83702-5627 BUSINESS PHONE: 2083882200 MAIL ADDRESS: STREET 1: PO BOX 70 STREET 2: 1221 WEST IDAHO STREET CITY: BOISE STATE: ID ZIP: 83702-5627 8-K 1 esa8k.htm _

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): November 6, 2009

	Exact name of registrants as specified in
Commission	their charters, address of principal executive	IRS Employer
File Number	offices and registrants’ telephone number	Identification Number
1-14465	IDACORP, Inc.	82-0505802
1-3198	Idaho Power Company	82-0130980
	1221 W. Idaho Street
	Boise, ID 83702-5627
	(208) 388-2200

State or Other Jurisdiction of Incorporation: Idaho

None

Former name or former address, if changed since last report.

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2.):

[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

IDACORP, Inc.
IDAHO POWER COMPANY
Form 8-K

ITEM 8.01 OTHER EVENTS.

Idaho Rate Settlement

In a stipulation filed with the Idaho Public Utilities Commission (“IPUC”) on November 6, 2009, Idaho Power Company (“Idaho Power”), its customer groups, and the staff of the IPUC reached an agreement (“Stipulation”) on a number of rate issues that, with IPUC approval, will be applicable through December 31, 2011. If approved, the Stipulation will enable Idaho Power to avoid filing a general rate case, as contemplated in Idaho Power’s Notice of Intent filed with IPUC in August 2009. The Stipulation and the supporting direct testimony before the IPUC of John R. Gale, Vice President of Regulatory Affairs of Idaho Power, are furnished as exhibits hereto.

The Stipulation provides for a moratorium on filing general revenue requirement cases that would result in a general rate case adjustment becoming effective prior to January 1, 2012. The moratorium is not applicable to rate proceedings specified in the Stipulation, including, among others, the annual Power Cost Adjustment (the “PCA”) and the annual Fixed Cost Adjustment.

The Stipulation also provides for sharing between customers and Idaho Power a currently estimated 2010 PCA reduction of approximately $160 million for the 2010-2011 PCA year. The actual amount of the 2010 PCA reduction will depend upon a variety of factors, including 2009-2010 snow pack levels, customer demand levels and wholesale power prices. The schedule below shows how the 2010 PCA sharing amounts would be allocated between the Company and its customers, depending on the amount of the 2010 PCA reduction (amounts shown are in millions of dollars).


PCA Reduction		Idaho Power Benefit		Idaho Retail Customer Benefit		Net Power Supply Expense Increase
$	220	$	25	$	120	$	75
200		25		100		75
180		25		80		75
160		25		60		75
145		25		45		75
135		20		40		75
120		20		40		60
100		20		40		40
80		20		40		20
60		20		40		-
40		20		20		-
20		10		10		-
-		-		-		-

Idaho Power’s share of any PCA reduction would increase its base rate revenues, while the customers’ share would reduce their PCA rates, in each case effective June 1, 2010. If the PCA reduction exceeds $60 million, the excess will be applied to offset any increase in base net power supply expenses. The Stipulation’s sharing mechanism will allow Idaho Power and its customers to benefit from Idaho Power earnings initiatives during the term of the Settlement.

The amounts shown in the PCA benefits schedule for Net Power Supply Expense Increase are estimates. Idaho Power will file a request with the IPUC to increase base net power supply expenses for ratemaking purposes prior to implementing the 2010 PCA. The parties to the Stipulation have agreed to work toward an agreement on the maximum increase in base net power supply expenses.

The Stipulation includes a provision to share earnings with customers if Idaho Power earns more than its authorized Return on Equity (“ROE”) in any year from 2009 through 2011 on year-end equity in the Idaho jurisdiction. The Idaho jurisdiction represents approximately 95 percent of Idaho Power’s total rate base. The Stipulation sets the Idaho jurisdictional ROE at the existing 10.5 percent in any regulatory matter to be determined by the IPUC before December 31, 2011. Any actual earnings above this level will be shared equally between Idaho Power’s customers and Idaho Power. Additionally, the Stipulation provides Idaho Power the opportunity to amortize additional Accumulated Deferred Investment Tax Credits (“ADITC”) of up to $45 million over the three-year period to help achieve a minimum ROE of 9.5 percent. In 2009, the dollar amount of additional ADITC that can be used toward increasing ROE is limited to $15 million. Any unused amount may be carried over for use in 2010 and 2011 provided that the additional amortization of ADITC cannot be greater than $25 million in either year. Idaho Power will not be permitted to use additional ADITC for any year during the three-year period in which its actual year-end ROE exceeds 9.5 percent.

The Stipulation is subject to the approval of the IPUC. Idaho Power has requested that the IPUC process the matter under modified procedure, which, if the IPUC agrees, will not require a technical hearing.

Certain statements contained in this Current Report on Form 8-K, including statements with respect to future earnings, ongoing operations, and financial conditions, are forward-looking statements within the meaning of federal securities laws. Although IDACORP and Idaho Power Company believe that the expectations and assumptions reflected in these forward-looking statements are reasonable, these statements involve a number of risks and uncertainties, and actual results may differ materially from the results discussed in the statements. Factors that could cause actual results to differ materially from the forward-looking statements include: the effect of regulatory decisions by the Idaho Public Utilities Commission, the Oregon Public Utility Commission and the Federal Energy Regulatory Commission affecting our ability to recover costs and/or earn a reasonable rate of return including, but not limited to, the disallowance of costs that have been deferred; changes in and compliance with state and federal laws, policies and regulations including new interpretations by oversight bodies, which include the Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, the Western Electricity Coordinating Council, the Idaho Public Utilities Commission and the Oregon Public Utility Commission, of existing policies and regulations that affect the cost of compliance, investigations and audits, penalties and costs of remediation that may or may not be recoverable through rates; changes in tax laws or related regulations or new interpretations of applicable law by the Internal Revenue Service or other taxing jurisdictions; litigation and regulatory proceedings, including those resulting from the energy situation in the western United States, and penalties and settlements that influence business and profitability; changes in and compliance with laws, regulations, and policies including changes in law and compliance with environmental, natural resources, endangered species and safety laws, regulations and policies and the adoption of laws and regulations addressing greenhouse gas emissions, global climate change, and energy policies; global climate change and regional weather variations affecting customer demand and hydroelectric generation; over-appropriation of surface and groundwater in the Snake River Basin resulting in reduced generation at hydroelectric facilities; construction of power generation, transmission and distribution facilities, including an inability to obtain required governmental permits and approvals, rights-of-way and siting, and risks related to contracting, construction and start-up; operation of power generating facilities including performance below expected levels, breakdown or failure of equipment, availability of transmission and fuel supply; changes in operating expenses and capital expenditures, including costs and availability of materials, fuel and commodities; blackouts or other disruptions of Idaho Power Company’s transmission system or the western interconnected transmission system; population growth rates and other demographic patterns; market prices and demand for energy, including structural market changes; increases in uncollectible customer receivables; fluctuations in sources and uses of cash; results of financing efforts, including the ability to obtain financing or refinance existing debt when necessary or on favorable terms, which can be affected by factors such as credit ratings, volatility in the financial markets and other economic conditions; actions by credit rating agencies, including changes in rating criteria and new interpretations of existing criteria; changes in interest rates or rates of inflation; performance of the stock market, interest rates, credit spreads and other financial market conditions, as well as changes in government regulations, which affect the amount and timing of required contributions to pension plans and the reported costs of providing pension and other postretirement benefits; increases in health care costs and the resulting effect on medical benefits paid for employees; increasing costs of insurance, changes in coverage terms and the ability to obtain insurance; homeland security, acts of war or terrorism; natural disasters and other natural risks, such as earthquake, flood, drought, lightning, wind and fire; adoption of or changes in critical accounting policies or estimates; and new accounting or Securities and Exchange Commission requirements, or new interpretation or application of existing requirements. Any such forward-looking statements should be considered in light of such factors and others noted in the companies’ Annual Report on Form 10-K for the year ended December 31, 2008, 10-Q for the first quarter ended March 31, 2009, 10-Q for the second quarter ended June 30, 2009, 10-Q for the third quarter ended September 30, 2009 and other reports on file with the Securities and Exchange Commission. Any forward-looking statement speaks only as of the date on which such statement is made. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

ITEM 9.01 FINANCIAL STATEMENTS AND EXHIBITS.

(d)

Exhibits.

Number		Description
99.1		Stipulation, dated November 6, 2009, filed with the Idaho Public Utilities Commission in Case No. IPC-E-09-30.
99.2		Direct Testimony of John R. Gale, Vice President of Regulatory Affairs of Idaho Power Company, before the Idaho Public Utilities Commission, filed in Case No. IPC-E-09-30.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned hereunto duly authorized.

Dated: November 9, 2009

IDACORP, Inc.

By: /s/ Darrel T. Anderson
Darrel T. Anderson
Executive Vice President -
Administrative Services
and Chief Financial Officer

IDAHO POWER COMPANY

By: /s/ Darrel T. Anderson
Darrel T. Anderson
Executive Vice President -
Administrative Services
and Chief Financial Officer

EX-99 2 esex99-21.htm

Exhibit 99.2

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION )

OF IDAHO POWER COMPANY FOR ) Case No. IPC-E-09-30

AN ACCOUNTING ORDER TO AMORTIZE )

ADDITIONAL ACCUMULATED DEFERRAL )

INCOME TAX CREDITS )

AND )

AN ORDER APPROVING A RATE CASE )

MORATORIUM. )

)

IDAHO POWER COMPANY

DIRECT TESTIMONY

JOHN R. GALE

Q. Please state your name and business address.

A. My name is John R. Gale and my business address is 1221 West Idaho Street, Boise, Idaho.

Q. By whom are you employed and in what capacity?

A. I am employed by Idaho Power Company (“the Company”) as the Vice President of Regulatory Affairs.

Q. Please describe your educational background and business affiliations.

A. I received a BBA in 1975 and an MBA in 1981 from Boise State University. I maintain a close affiliation with the university and serve on the College of Business and Economics’ Advisory Council. I have also attended the Public Utilities Executive Course at the University of Idaho and am now on the faculty of that program leading the section on “Regulation and Ratemaking.”

I am an active member of the Edison Electric Institute’s (“EEI”) Rates and Regulatory Affairs Committee, which is the committee that is concerned primarily with regulatory issues and ratemaking methods. I am the current Chair of this committee. I am also a member of EEI’s Retail Energy Services Executive Advisory Committee.

Q. Please describe your work experience.

GALE, DI 1

Idaho Power Company

A. From 1976 to 1983, I was employed by the State of Idaho primarily as an analyst in the Department of Employment. In October 1983, I accepted a position at Idaho Power Company as a Rate Analyst in the Rate Department. I initially worked on rate design, tariff administration, and line extension issues. In March 1990, I was assigned to the Company’s Meridian District Office where I held the position of Meridian Manager, which was a one-year cross training position established to provide corporate employees with an extensive field experience. I returned to the Rate Department in March 1991 and in June, I was promoted to Manager of Rates. In July 1997, I was named General Manager of Pricing and Regulatory Services. In March 2001, I was promoted to Vice President of Regulatory Affairs, my current position.

GALE, DI 2

Idaho Power Company

As Vice President of Regulatory Affairs, I oversee and direct the activities of the Pricing and Regulatory Services Department. These activities include the development of jurisdictional revenue requirements, the oversight of the Company’s rate adjustment mechanisms, the preparation of class cost-of-service studies, the preparation of rate design analyses, and the administration of tariffs and customer contracts. In my current position, I have the primary responsibility for policy matters related to the economic regulation of Idaho Power Company. I have testified frequently before the Idaho Public Utilities Commission (“the Commission”) on a variety of rate and regulatory matters. I have also testified before or submitted direct testimony to the regulatory commissions in Nevada and Oregon, the Federal Energy Regulatory Commission (“FERC”), the Bonneville Power Administration, and the United States Senate Committee on Energy and Natural Resources.

Q. What is the purpose of your testimony in this matter?

A. My testimony supports the settlement Stipulation (“Settlement”) filed in this case regarding the establishment of regulatory and ratemaking mechanisms to be in place until January 1, 2012. I will discuss the development of the Settlement and explain its benefits to the Company and its customers. The Settlement is Exhibit No. 1 to my testimony.

Q. Please describe the genesis of the Settlement.

GALE, DI 3

Idaho Power Company

A. Following the conclusion of Idaho Power’s last general rate case, Case No. IPC-E-08-10, the Company contemplated the value of setting the Return on Equity (“ROE”) for Idaho regulatory matters at an agreed-upon fixed level for a specified time period. The Company believed this issue could be settled among the various interested parties to Idaho Power’s rate proceedings because of the near proximity of the last Commission decision in a fully-contested revenue requirement case. Idaho Power determined this matter was ripe for discussion with customer groups and Commission Staff. Establishing a specified ROE to be fixed for a period of time is beneficial because it removes a resource-intense and time-consuming element from a rate case that may add little value to the ultimate rate recovery decision, particularly when the same issue was recently decided in a fully-contested proceeding. Additionally, setting the ROE at a fixed level helps to mitigate the size of a rate request by avoiding the need for the utility to request a higher ROE to respond to a lower recommended ROE that inevitably comes from the Intervenors.

Q. Besides establishing a ROE with some shelf life, was there another reason the Company wanted to talk with its customers and the Commission Staff?

GALE, DI 4

Idaho Power Company

A. Yes. Due to ongoing circumstances related to generally poor hydro conditions throughout this decade and the difficulty of playing “catch-up” with costs that, until very recently, were being driven by growing service territory, Idaho Power determined that the time was right to discuss an earnings sharing mechanism similar to one that existed during the last half of the 1990s. The Company asked customer groups and Commission Staff to attend an informal meeting on September 3 to discuss this possibility.

Q. Please describe the prior case in which earnings sharing was discussed.

A. The docket for that case was IPC-E-95-11. In that case, the earnings sharing mechanism was brought before the Commission in the form of a settlement Stipulation in September of 1995 (“1995 Settlement”). This was a seven-party agreement that included the Commission Staff, the Company, the United States Department of Energy, the Commercial Utility Customers, Micron Technology, FMC Corporation, and the Idaho Irrigation Pumpers Association. The Commission approved the 1995 settlement on December 1, 1995, through Order No. 26216. A copy of the 1995 settlement Stipulation is provided as Exhibit No. 2.

Q. What were the principal provisions of the 1995 Settlement?

GALE, DI 5

Idaho Power Company

A. There were four major provisions to the 1995 Settlement. The 1995 Settlement provided for the accounting and ratemaking treatment related to an ongoing significant Company reorganization. The 1995 Settlement provided limited use of an accelerated amortization of Accumulated Deferred Investment Tax Credits (“ADITC”) for purposes of supporting a minimum ROE level. The 1995 Settlement also provided for the sharing of earnings with customers above a specified ROE level. And finally, the 1995 Settlement provided a rate moratorium that lasted through December 1999.

Q. What were the circumstances leading up to the 1995 Settlement?

GALE, DI 6

Idaho Power Company

A. Throughout the late 1980s and early 1990s, southern Idaho experienced a prolonged series of drought years with poor hydro conditions for generating electricity. Accordingly, Idaho Power faced higher power supply expenses due to more power purchases, fewer surplus sales, and higher fuel costs as the Company relied more on its coal plants to replace the diminished hydro production. One result of the prolonged drought was the development, and Commission approval, of the Company’s Power Cost Adjustment (“PCA”) in 1992 with its first implementation in the spring of 1993. The PCA helped to mitigate the Company’s power supply cost exposure in the poor hydro years and provided benefits to customers in the better ones.

Also during this time, there was considerable general rate case activity in both Idaho and Oregon. The Company filed a general rate case before this Commission in 1994 based upon a 1993 test year (Case No. IPC-E-94-05) and in 1995 filed a single item case as the Twin Falls Hydro Upgrade came on line (Case No. IPC-E-95-05). However, despite the general rate case activity and the implementation of the PCA, the Company found that actually earning the authorized ROE remained elusive. It was at this point the revenue sharing concept embodied in the 1995 Settlement was introduced.

Q. What were the results of the 1995 Settlement?

A. The time period from 1995 through 1999 was characterized by much improved hydro conditions, which, along with the Company’s reorganizational efforts, translated to better earnings opportunities. Accordingly, during the time period of the 1995 Settlement – 1995 through 1999 – no ADITC had to be used to support a minimum ROE level.

GALE, DI 7

Idaho Power Company

In 1995 the actual ROE came within a dead band where neither ADITC was used nor earnings were shared. The results during the rest of the time period produced customer benefits as follows:

Year ROE Earned Customer Benefit

1996 12.55% $4,890,515

1997 12.95% $7,571,946

1998 12.73% $6,372,411

1999 13.10% $9,025,295

Additionally, the Company’s next Idaho general rate case was ultimately deferred until 2003 because the Western Energy Crisis of 2000 and 2001 put so much pressure on PCA rates that trying to change general rates was not practical.

Q. Will you please compare the circumstances in 1995 to the current situation?

GALE, DI 8

Idaho Power Company

A. As was the case in 1995, Idaho Power has actively pursued rate recovery throughout this decade through various mechanisms and general rate cases. Despite an active regulatory agenda, the Company has not been able to achieve its authorized rate of return in either its Idaho or Oregon jurisdiction. Idaho Power presented testimony from both internal and external witnesses describing the Company’s relative risks and supporting its ROE position in the 2003, 2005, 2007, and 2008 filings. These matters were fully litigated as part of the 2003 and 2008 test year determinations. While ROE evidence has not been a significant driver in the ultimate revenue requirement outcome, it often adds millions to a general rate case request and is one of the more significant rate case expenses.

Q. Does the Company have any ADITC currently on its books that could be utilized under an arrangement similar to the 1995 Settlement?

A. Yes. At this time Idaho Power has significant amounts of ADITC on its books, $30 million of federal and $43 million of state. The Company also expects to accumulate more state investment tax credits during the next several years.

Q. What happened at the September 3 meeting with customers and Commission Staff?

A. The Company reviewed much of the information just discussed with the group and presented a ratemaking concept that would stabilize ROE through the use of an agreed-upon ROE that would be used in any Idaho Power rate filing for a fixed period of years. Idaho Power proposed the potential use of ADITC in a prescribed manner to help buttress Company earnings from a non-cash standpoint. In return for shoring up the low side of ROE, Idaho Power proposed to share earnings above a threshold amount with its customers.

GALE, DI 9

Idaho Power Company

Q. What happened next?

A. The customers and Commission Staff presented a reply to the Company on September 21 that emphasized the customers’ interest in a rate moratorium. The Company was not able to respond on that day because it was in the process of preparing a general rate case and had not yet determined the revenue requirement that would be requested.

Q. Was the Company planning to file a general rate case this fall?

A. Yes. Idaho Power had submitted a notice of intent to the Commission on August 28, 2009, that expressed the Company’s intent to file on or after October 28, 2009. The Company was actively preparing the general rate filing during its discussions with the customers and Commission Staff. Idaho Power’s original earnings sharing concept did not include a rate moratorium.

Q. Assuming a normal procedural schedule, when would Idaho retail rates have changed to incorporate the impact of a general rate case filed in late October?

A. With an expected rate filing in late October, one could anticipate that rates would be in place by June 1, 2010, to coincide with the other annual rate mechanism changes, including the PCA.

GALE, DI 10

Idaho Power Company

Q. Does the Company anticipate a rate decrease for the PCA on June 1, 2010?

A. Yes. Idaho Power, Staff, and a number of other informed parties anticipate a substantial PCA decrease next spring. At the time of our settlement discussions, the expected PCA decrease was valued at nearly $160 million. At this writing our expectation has not come down from that level.

Q. Once Idaho Power completed its revenue requirement determination for the October 2009 general rate case filing, what happened next?

GALE, DI 11

Idaho Power Company

A. Idaho Power analyzed a number of factors in a side-by-side comparison of a general rate case proceeding versus an alternative that included a rate case moratorium. These factors included: (1) financial considerations, such as the need for base rate relief to cover operating expenses and adequate cash flow to maintain our financial ratios, (2) customer rate impacts, and (3) the awareness that a substantial rate reduction through the PCA would likely occur on June 1, 2010. As a result of these deliberations, the Company began to fashion a proposal that could utilize the expected PCA decrease to provide systematic benefits to both the customers and the Company. The Company asked the customer groups and Commission Staff to reassemble on October 13 to lay out its proposal. From there, negotiations progressed until final agreement was reached on October 25. That same day, the Company provided a Memorandum of Understanding and Final Term Sheet to the parties involved.

Q. How did the Company evaluate its ability to avoid a general rate case?

A. Idaho Power continues to be under pressure to operate reliably without some additional general rate relief. At the same time, the Company is well aware of the current effects of the recession on its service area. As Idaho Power prepared its general rate case, the Company worked to mitigate the total revenue requirement wherever it could. These mitigations included: (1) pushing items such as the second year deployment of Advanced Metering Infrastructure (“AMI”), and pension funding into a separate single-issue cases, (2) addressing an extremely large increase to net power supply expense as part of next year’s PCA change, (3) deferring any request to increase the amount of Construction Work in Progress (“CWIP”) included in rates until the future, and (4) filing with a stipulated ROE. Without the above-mentioned mitigation steps, the Company’s general rate case filing would have requested a rate increase of over 20 percent.

GALE, DI 12

Idaho Power Company

Q. How do these actions mitigate the Company’s revenue requirement?

A. I will start with AMI. Since the Company originally filed for the first year of AMI recovery as a separate rate matter, it would simply continue with similar one-issue filings in the second and third year of deployment and keep the AMI impact out of a general rate request. Pension funding has not been part of the Idaho jurisdictional revenue requirement since the Commission’s final order in Case No. IPC-E-03-13; however, regulatory accounting has been established to provide for rate recovery once funding begins again. Because of the potential for volatility in funding requirements over the next number of years, Idaho Power has proposed a tracking mechanism for pension investment that is before the Commission in a separate docket, Case No. IPC-E-09-29.

GALE, DI 13

Idaho Power Company

By far the largest single element of the unmitigated revenue requirement was the increase required for net power supply expense, an annual increase of approximately $75 million by itself. While the Company knows recovery of these increased expenses is needed due to higher fuel costs for coal, increased PURPA expense, and the impact of lower natural gas prices on the market price for the Company’s surplus sales, increasing the base net power supply expense in a general rate case has a net benefit to the Company of only 5 percent of the change. Accordingly, Idaho Power held the net power supply expense constant in preparing its general rate case with the thought of seeking to change this amount in a separate proceeding that could be implemented with next year’s PCA change.

The Company also has the ability to request CWIP in rates and has done so on a limited scale – the AFUDC on relicensing of the Hells Canyon project – in the last general rate case, Case No. IPC-E-08-10. While CWIP helps the Company through improved cash flow and customers through rate smoothing, it can be viewed as a pay-me-now or pay-me-later item. In trying to mitigate a high revenue requirement, it is a logical item to postpone. Accordingly all new CWIP was removed.

The last mitigation undertaken as part of developing the Company’s Idaho revenue requirement was utilizing the 10.5 percent ROE ordered in Case No. IPC-E-08-10 instead of arguing for a higher amount.

Despite the mitigation plan, the October 2009 general rate case filing would still have been more than a 10 percent rate increase. Though justified from Idaho Power’s perspective, the Company had to assess its ability to successfully obtain that degree of rate relief in the current economic environment.

GALE, DI 14

Idaho Power Company

Q. What is driving the need for a base rate change?

A. There are three areas that drive the increase: (1) a decrease in forecasted revenues as loads did not materialize as expected, (2) ongoing pressure on operating and maintenance expense as these costs continue to be higher than the level authorized in Case No. IPC-E-08-10, and (3) new plant additions since 2008.

Q. Please describe the provisions of the current Settlement previously identified as Exhibit No. 1.

A. The Settlement provides that the Company is under a general rate moratorium with specified ongoing exceptions. Under the moratorium, the Company cannot file for a change to general rates, unless otherwise specified, prior to January 1, 2012.

The Settlement provides for the establishment of a 10.5 percent ROE for regulatory matters through December of 2011. The Settlement provides for an equal sharing of actual earnings in excess of 10.5 percent for the Idaho jurisdiction between the Company’s customers and shareholders. Customers are to receive any earnings-sharing benefit directly through rate reductions.

GALE, DI 15

Idaho Power Company

Concurrent with the potential for revenue sharing, the Company has the ability to amortize additional ADITC during the years 2009 through 2011 to support earnings when the Idaho jurisdictional ROE is less than 9.5 percent. The use of additional ADITC is constrained in several ways to provide for a material amount of ADITC to remain after the Settlement term is over. Every year ADITC use is constrained to no more additional ADITC amortization than is necessary to reach the 9.5 percent Idaho ROE previously mentioned. Additionally, the 2009 ADITC is limited to a maximum $15 million, 2010 and 2011 are limited further to no more the $25 million, and the total ADITC used during the three-year period cannot exceed $45 million. Unused amounts in 2009 and 2010 may be carried over into subsequent years subject to the previously described limits.

Finally the Settlement provides for the ability to distribute the expected 2010 PCA decrease in a specified manner to address rate relief for customers, base rate recovery for the Company, and establish a new normalized net power supply expense level for both the Power Cost Adjustment and base rates. Exhibit No. 3 is a worksheet that shows how each increment of rate reduction will be treated.

GALE, DI 16

Idaho Power Company

Q. Why would the Company agree to the Settlement?

A. The Settlement should enable the Company to remain financially healthy while helping Idaho Power’s customers manage through a difficult time in the economy. Idaho Power is optimistic about the potential for a substantial PCA decrease and believes that the decrease can be used productively to address both customer and Company issues. The Company values the opportunity to set the net power supply expense at a more appropriate level, which will restore more symmetry to the mechanism. The Company views the potential for obtaining base rate relief without engaging in a contentious battle before the Commission, given the current economic circumstances, as a positive element of the Settlement. The fact that Idaho Power can participate in any earnings initiatives during the term of the Settlement through the sharing mechanism is also positive. In summary, Idaho Power maintains that the Settlement represents creative and collaborative thinking on behalf of all the parties involved.

Q. What do you think the customer benefits are?

GALE, DI 17

Idaho Power Company

A. First of all, the Company will delay a general rate change until on or after January 1, 2012. Secondly, the Settlement provides no base rate relief for the Company unless there is a real customer rate reduction through the PCA. Thirdly, setting a fixed ROE eliminates a normally contentious and expensive portion of any rate filing during the term of this Settlement. Fourthly, customers have the assurance that the use of ADITC would be limited. Customers will continue to have the benefit of the ADITC amortization that is currently in existing rates, which reduces allowed expenses. Additionally, customers will have certainty that the Company will not be over earning in the Idaho jurisdiction. And, finally, similar to the 1995 Settlement, the customers have the opportunity to share in any good earnings years.

Q. Do you believe that this Settlement is in the public interest?

A. Yes. I believe it is one of the most innovative and mutually beneficial endeavors that I have ever been involved with in my career with the Company.

Q. Does this conclude your testimony?

A. Yes, it does. GALE, DI 18

Idaho Power Company

EX-99 3 esex99-1.htm

&n bsp; Exhibit 99.1

BARTON L. KLINE (ISB No. 1526)

LISA D. NORDSTROM (ISB No. 5733)

Idaho Power Company

P.O. Box 70

Boise, Idaho 83707

Telephone: (208) 388-2682

Facsimile: (208) 388-6936

bkline@idahopower.com

lnordstrom@idahopower.com

Attorneys for Idaho Power Company

Street Address for Express Mail:

1221 West Idaho Street

Boise, Idaho 83702

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION

OF IDAHO POWER COMPANY FOR

AN ACCOUNTING ORDER TO AMORTIZE ADDITIONAL ACCUMULATED DEFERRAL INCOME TAX CREDITS

AND

AN ORDER APPROVING A RATE CASE MORATORIUM.

)

CASE NO. IPC-E-09-30

STIPULATION

This stipulation (“Stipulation”) is entered into by and among Idaho Power Company (“Idaho Power” or the “Company”), the Staff of the Idaho Public Utilities Commission (“Staff”), the Idaho Irrigation Pumpers Association, Inc. (“IIPA”), the Industrial Customers of Idaho Power (“ICIP”), Micron Technology, Inc. (“Micron”), the United States Department of Energy (“DOE”), the Community Action Partnership Association of Idaho (“CAPAI”), and the Kroger Co. (“Kroger”). These entities are collectively referred to as the “Parties,” and individually as “Party.”

I. INTRODUCTION

1. The Parties agree that this Stipulation represents a fair, just, and reasonable compromise of contested issues and that acceptance of the Stipulation by the Idaho Public Utilities Commission (“IPUC” or the “Commission”) would be in the public interest. Therefore, the Parties recommend that the Commission approve the Stipulation and all of its terms and conditions without material change or condition.

II. BACKGROUND

2. On August 28, 2009, in accordance with RP 122, Idaho Power filed a notice of intent to file a general rate case.

3. On September 21, 2009, the Parties met to discuss ways to establish an agreed upon return on equity (“ROE”) to be used in proceedings before the Commission for a fixed period of time and, additionally, to pursue a regulatory mechanism that would support the potential for the Company to actually achieve its authorized return level by providing for certain sharing mechanisms. During that meeting, Staff and several other Parties expressed a desire to implement a moratorium on new general rate case filings. The Parties agreed to meet again if the Company could confirm that further discussions, including rate case moratorium discussions, would be productive.

4. As a result of several follow-up meetings, the Parties have reached the following settlement agreement:

III. TERMS OF THE STIPULATION

5. Rate Case Moratorium.

5.1. Idaho Power will not file a general revenue requirement case which would result in a general rate adjustment becoming effective prior to January 1, 2012 (“the moratorium”).

5.2. The moratorium is not applicable to, and the Company may make filings with the Commission to adjust its revenue requirement and change rates to become effective prior to January 1, 2012, for the following:

(a) Annual Power Cost Adjustment (“PCA”);

(b) Annual Fixed Cost Adjustment;

(d) Annual Pension Expense Recovery;

(e) Energy Efficiency Rider Adjustment;

(f) Recovery of governmentally imposed fees, such as franchise agreements or local improvement district fees;

(g) Increased funding for low-income weatherization; and

(h) A filing (discussed in detail in paragraph 7.2.7 below) in which the Company could request the authority to recover a portion of a potential shortfall in the Company’s recovery of the $20 million amount described in Section 7.1.2. This filing would only be made if the 2010 PCA rate reduction is less than $40 million and there is a PCA rate reduction in June 2011.

(i) A filing to set the base rate level for net power supply expenses as described in Section 7.1.

6. Return on Equity and Related Sharing.

6.1. The Parties agree that it would be just and reasonable for the Commission to use a 10.5 percent ROE in any Idaho Power regulatory matter to be determined by the Commission before December 31, 2011.

6.2. The Company intends to continue to optimize its operations to reduce the likelihood it will need to use the tools described herein. Therefore, if during 2009, 2010, or 2011 the Company receives a financial benefit (e.g., regulatory fee refund, material expense reduction, lawsuit settlement, etc.), such financial benefit will be subject to this Stipulation and will benefit customers either by the sharing provisions in Section 6.3 or by reducing the Company’s need to amortize additional accumulated deferred income tax credits (“ADITC”) to achieve a 9.5 percent ROE as provided in Section 8.

6.3. If the Company’s actual earned return on year-end equity for the Idaho jurisdiction during 2009, 2010, or 2011 exceeds 10.5 percent, amounts in excess of a 10.5 percent return will be shared equally between the Company’s Idaho customers and the Company. Any shared earnings which are allocated to customers will be used to reduce customer rates.

6.4. For the years 2009, 2010, and 2011, there can be no additional ADITC amortization as provided in Section 8 if the Company has shared earnings pursuant to Section 6.3.

7. 2010 PCA Rate Adjustment and Related Sharing.

7.1. Setting the Base Level for Net Power Supply Expense. Prior to implementing the June 1, 2010, PCA and effective with the coincident PCA rate change, the Company will file with the Commission a request to change the base level for net power supply expenses to be used prospectively for both base rates and PCA calculations. The Parties will thereafter make a good-faith effort to reach agreement on the maximum change of the base level for net power supply expenses and submit any agreement to the Commission for approval.

7.2. Sharing the PCA Reduction. The Parties anticipate that the June 1, 2010, PCA rate calculation will indicate a substantial reduction in the PCA rates. However, sharing the PCA rate reduction between the Company and its customers will allow the Company to implement the moratorium. As a result, the Parties agree that if they are correct, and the 2010 PCA computation results in a rate decrease, the June 1, 2010, PCA rate change will be processed and allocated as follows:

7.2.1. The First $40 Million. The amount of any PCA reduction up to and including the first $40 million of any 2010 PCA rate reduction will be allocated equally between customers and the Company.

7.2.1.1. The Company’s share of this PCA rate reduction will be applied to increase permanent base rates on a uniform percentage basis to all customer classes and the special contract customers. Schedule 1 and Schedule 7 customer classes will have any increase placed on their respective energy rates. This increase in base rates will remain in effect until new base rates, which are ordered in a future Idaho Power Company general rate case, become effective.

7.2.1.2. The customers’ share of this PCA rate reduction will be provided to customers as a direct customer net rate reduction based on the 2010 PCA rate change being offset by the rate increase described in Section 7.2.1.1.

7.2.2. $40 Million to $60 Million. All of the portion of any 2010 PCA rate reduction that is above $40 million and up to and including $60 million will be allocated to customers. The customers’ share of this PCA rate reduction will be provided to customers as a direct customer rate reduction in the 2010 PCA rate change.

7.2.3. Above $60 Million. The portion of any 2010 PCA rate reduction which exceeds $60 million will be applied to absorb any increase in the base level for net power supply expenses. Section 7.1 describes how the base rate change will be initiated.

7.2.4. Should the 2010 PCA rate reduction exceed the $60 million amount plus the adjustment to the base level for net power supply expenses described in Section 7.2.3, the next $10 million of any such 2010 PCA rate reduction will be allocated equally between customers and the Company in the same manner as described in Section 7.2.1 above.

7.2.5. The portion of any PCA rate reduction which exceeds (1) the sum of $60 million plus (2) the amount of the increase in the base level for new power supply expenses described in Section 7.2.3 plus (3) the final $10 million sharing between Company and customers described in Section 7.2.4 will be allocated 100 percent to customers. The customers’ share of this PCA rate reduction will be provided to customers as a direct customer rate reduction in the 2010 PCA rate change.

7.2.6. Exhibit No. 1, attached hereto, is a chart that shows how the above-described sharing amounts would be allocated between the Company and its customers, depending on the amount of PCA reduction.

7.2.7. If the 2010 PCA rate reduction is less than $40 million and, as a result, the Company is unable to obtain its full $20 million benefit described in Section 7.2.1.1 and if the 2011 PCA rate should be a decrease from 2010 PCA rates, the Parties agree that the Company can request that the Commission allocate one half of the decrease to the Company up to the amount of the shortfall from the $20 million amount.

8. Accounting: ADITC Amortization.

8.1. For the years 2009, 2010, and 2011, if Idaho Power’s actual Idaho jurisdictional earned return on year-end equity falls below 9.5 percent, the Company will be permitted to amortize an additional amount of state and federal ADITC by debiting Account 255 (ADITC) and crediting Account 420 (investment tax credits, a non-utility income account), in an amount, up to $45 million over the above-referenced three year period, that would allow the Company to achieve a maximum actual ROE of 9.5 percent for the Idaho jurisdiction. The dollar amount that could be used to increase the actual 2009 ROE to no more than 9.5 percent is $15 million.

8.2. If Idaho Power does not utilize the full $15 million of additional amortization of ADITC in 2009, the unused amount of the $45 million maximum may be carried forward for use in subsequent years through 2011. For example, if in 2009 Idaho Power only amortized an additional $5 million of accumulated ADITC to achieve a 9.5 percent ROE, it could utilize additional amortization of ADITC of $20 million in 2010 and $20 million in 2011. Similarly, if Idaho Power does not use ADITC amounts available in 2010, the unused amount may be carried forward to 2011.

8.3. The additional amortization of ADITC cannot be greater than $25 million in any one year.

8.4. Except for the permitted use of additional ADITC described herein, for the years 2009, 2010, and 2011, Idaho Power will continue to amortize ADITC using the same method employed immediately prior to the issuance of a Commission Order in this matter.

8.5. In no event shall any additional amounts of ADITC amortized be reflected in the utility operating results of the Company for ratemaking purposes, financial statement purposes, and for purposes of the Company’s regulated books of account.

IV. ADDITIONAL PROVISIONS

9. The Parties agree that this Stipulation represents a compromise of the positions of the Parties. Therefore, other than any testimony filed in support of the approval of this Stipulation, and except to the extent necessary for a Party to explain before the Commission its own statements and positions with respect to the Stipulation, all statements made and positions taken in negotiations relating to this Stipulation shall be confidential and will not be admissible in evidence in this or any other proceeding.

10. The Parties submit this Stipulation to the Commission and recommend approval in its entirety. Parties shall support this Stipulation before the Commission, and no Party shall appeal a Commission Order approving the Stipulation or an issue resolved by the Stipulation. If this Stipulation is challenged by any person not a party to the Stipulation, the Parties to this Stipulation reserve the right to file testimony, cross-examine witnesses, and put on such case as they deem appropriate to respond fully to the issues presented, including the right to raise issues that are incorporated in the settlements embodied in this Stipulation. Notwithstanding this reservation of rights, the Parties to this Stipulation agree that they will continue to support the Commission’s adoption of the terms of this Stipulation.

11. If the Commission rejects any part or all of this Stipulation, or imposes any additional material conditions on approval of this Stipulation, each Party reserves the right, upon written notice to the Commission and the other Parties to this proceeding, within fourteen (14) days of the date of such action by the Commission, to withdraw from this Stipulation. In such case, no Party shall be bound or prejudiced by the terms of this Stipulation, and each Party shall be entitled to seek reconsideration of the Commission’s Order, file testimony as it chooses, cross-examine witnesses, and do all other things necessary to put on such case as it deems appropriate.

12. No Party shall be bound, benefited or prejudiced by any position asserted in the negotiation of this Stipulation, except to the extent expressly stated herein, nor shall this Stipulation be construed as a waiver of the rights of any Party unless such rights are expressly waived herein. Execution of this Stipulation shall not be deemed to constitute an acknowledgment by any Party of the validity or invalidity of any particular method, theory, or principle of regulation or cost recovery. No Party shall be deemed to have agreed that any method, theory, or principle of regulation or cost recovery employed in arriving at this Stipulation is appropriate for resolving any issues in any other proceeding in the future. No findings of fact or conclusions of law other than those stated herein shall be deemed to be implicit in this Stipulation.

13. The obligations of the Parties under this Stipulation are subject to the Commission’s approval of this Stipulation in accordance with its terms and conditions and upon such approval being upheld on appeal by a court of competent jurisdiction.

14. This Stipulation may be executed in counterparts and each signed counterpart shall constitute an original document.

DATED this 6^th day of November 2009.

Idaho Power Company

Barton L. Kline

Attorney for Idaho Power Company

Idaho Public Utilities Commission Staff

Weldon Stutzman

Attorney for Idaho Public Utility Commission Staff

Idaho Irrigation Pumpers Association, Inc.

Eric Olsen

Attorney for Idaho Irrigation Pumpers Association, Inc.

Industrial Customers of Idaho Power

Peter J. Richardson

Attorney for Industrial Customers

of Idaho Power

Micron Technology, Inc.

Conley E. Ward

Attorney for Micron Technology, Inc.

U.S. Department of Energy

Arthur Perry Bruder

Attorney for U.S. Department of

Energy

Community Action Partnership Association of Idaho

Brad M. Purdy

Attorney for Community Action Partnership Association of Idaho Energy Coalition

The Kroger Co.

Kurt Boehm

Attorney for the Kroger Co.

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-09-30

IDAHO POWER COMPANY

EXHIBIT NO. 1

Settlement Proposal

Expected PCA Rate Reduction "$160 million Expected Increase to Net Power Supply Expense "$75 million PCA Reduction Company Customer							NPSE
$	220	$	25	$	120	$	75
	200		25		100		75
	180		25		80		75
	160		25		60		75
	145		25		45		75
	135		20		40		75
	120		20		40		60
	100		20		40		40
	80		20		40		20
	60		20		40		-
	40		20		20		-
	20		10		10		-
	-		-		-		-