ITEM 1. BUSINESS
THE COMPANY
General -
Idaho Power Company (Company) is an electric public utility incorporated under the laws of the state of Idaho in 1989 as successor to a Maine corporation organized in 1915. The Company is engaged in the generation, purchase, transmission, distribution and sale of electric energy in an approximate 20,000- square-mile area in southern Idaho, eastern Oregon and northern Nevada, with an estimated population of 695,000 people. The Company holds franchises in approximately 70 cities in Idaho and 10 cities in Oregon, and holds certificates from the respective public utility regulatory authorities to serve all or a portion of 28 counties in Idaho, 3 counties in Oregon and 1 county in Nevada. The Company's results of operations, like those of certain other utilities in the Northwest, can be significantly affected by weather and streamflow conditions. Variations in energy usage by ultimate customers occur from year to year, from season to season and from month to month within a season, primarily as a result of weather conditions. With the implementation of a power cost adjustment mechanism (PCA) in the Idaho jurisdiction, which includes a major portion of the operating expenses with the largest variation potential (net power supply costs), the Company's future operating results will be more dependent upon general regulatory, economic, temperature conditions, and management decisions and less on precipitation and streamflow conditions. As of December 31, 1994, the Company supplied electric energy to 330,308 general business customers and employed 1,703 people in its operations (1,609 full-time).
The Company operates 17 hydro power plants and shares ownership in three coal-fired generating plants (see Item 2
ITEM 2. PROPERTIES
The Company's system includes 17 hydroelectric generating plants located in southern Idaho and eastern Oregon (detailed below) and an interest in three coal-fired steam electric generating plants. The system also includes approximately 4,648 miles of high voltage transmission lines; 21 step-up transmission substations located at power plants; 17 transmission substations; 7 transmission switching stations; and 195 energized distribution substations (excludes mobile substations and dispatch centers). Refer to Item 1 - Construction Program for facilities under construction.
The Company holds licenses under the Federal Power Act for 13 hydroelectric projects from the FERC. These and the other generating stations and their capacities are listed below:
Maximum Non-Coincident Operating Nameplate License Project Capacity kW Capacity kW Expiration
Properties Subject to Federal Licenses:
Lower Salmon 70,000 60,000 1997 Bliss 80,000 75,000 1998 Upper Salmon 39,000 34,500 1998 Shoshone Falls 12,500 12,500 1999 C J Strike 89,000 82,800 2000 Upper Malad 9,000 8,270 2004 Lower Malad 15,000 13,500 2004 Brownlee-Oxbow-Hells Canyon 1,398,000 1,166,900 2005 Swan Falls 27,170 27,170 2010 American Falls 112,420 92,340 2025 Cascade 14,000 12,420 2031 Twin Falls 10,000 8,437 2041 Milner 59,448 59,448 2038
Other Generating Plants:
Other Hydroelectric 10,400 11,300 Jim Bridger (Coal-Fired Station) 693,333 678,077 Valmy (Coal-Fired Station) 260,650 260,650 Boardman (Coal-Fired Station) 53,000 53,000
On December 31, 1994, the composite average ages of the principal parts of the Company's system, based on dollar investment, were: production plant, 15.8 years; transmission system and substations, 18.0 years; and distribution lines and substations, 13.8 years. The Company considers its properties to be well maintained and in good operating condition.
The Company owns in fee all of its principal plants and other important units of real property, except for portions of certain projects licensed under the Federal Power Act and reservoirs and other easements, subject to the lien of its Mortgage and Deed of Trust and the provisions of its project licenses, and to minor defects common to properties of such size and character that do not materially impair the value to, or the use by, the Company of such properties.
As a result of various federal legislative actions and proposals (such as the Electric Consumers Protection Act of 1986, Energy Policy Act of 1992, Clean Water Act Reauthorization and Endangered Species Act Reauthorization), a major issue facing the Company is the relicensing of its hydro facilities. Because the federal licenses for the majority of the Company's hydroelectric projects expire during the next 10 to 15 years, the Company has vigorously pursued the relicensing process. The relicensing of these projects is not automatic under federal law. The Company must demonstrate comprehensive usage of the facilities, that it has been a conscientious steward of the natural resource entrusted to it and that there is a strong public interest in the Company continuing to hold the federal licenses. The Company will submit its first applications for license renewal to the FERC in December 1995. These first applications will seek renewal of the Company's licenses for its Bliss, Upper Salmon and Lower Salmon Hydroelectric Projects. The Company cannot anticipate what type of environmental capital investment or operational requirements may be placed on the projects in the relicensing process, nor can it estimate what the eventual cost will be for relicensing. However, the Company anticipates that its efforts in this matter for all of the hydro facilities will be successful.
Idaho Energy Resources Co. owns a one-third interest in certain coal leases near the Jim Bridger generating plant in Wyoming from which coal is mined and supplied to the plant.
Ida-West owns a 50 percent interest in five PURPA-qualified facilities that have a total generating capacity of approximately 34 MW. The energy from these facilities is sold to the Company.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company is a defendant in a Superfund case entitled United States of America vs. Pacific Hide & Fur Depot, et al., Civil No. 83-4062, pending in the United States District Court for the District of Idaho. The suit involves PCB and PCB/lead contamination at a scrap metal/recycling facility near Pocatello, Idaho. The Company entered into a Partial Consent Decree which was signed by the District Judge on September 26, 1989, wherein the Company agreed to remediate PCBs at the site.
After completion of certain Initial Tasks and the Final Remedial Design, by letter dated October 4, 1990, EPA notified the Company of the discovery of lead and other metals contamination at levels of concern at the site, and instructed the Company to suspend further remedial action at the site until further notice.
On April 24, 1991, the Company initiated discussions with EPA in an effort to facilitate the commencement and completion of PCB remediation. On July 16, 1991, the Company submitted a proposal whereby the PCB and lead/other metal contaminants would be divided into at least two operable units for purposes of site remediation. On January 20, 1992, a Final Operable Unit Focused Feasibility Study was submitted by the Company to EPA.
On January 4, 1992, EPA issued a Proposal to Amend Record of Decision which proposed to divide the site into "operable units" to allow for immediate cleanup of PCB contamination at the site through the removal of the PCB and PCB mixed with lead contaminated soils from the site and disposal of the soils at an EPA approved waste facility.
An Amended Record of Decision authorizing the foregoing was issued on April 29, 1992.
Remedial Design Documents were approved by EPA on July 8, 1992.
In order to facilitate the commencement/completion of remedial activities during 1992, an "interim" Administrative Order directing the Company to undertake remedial activities was issued on July 13, 1992.
Remediation activities commenced on July 27, 1992, and were completed on October 21, 1992.
A Certification of Completion for the Operable Unit Remedial Action dated March 31, 1993, was issued by EPA to the Company. The Amended Partial Consent Decree will supersede EPA's "Interim" Administrative Order when it is entered by the court.
On August 30, 1993, Notice of the Lodging of the Amended Partial Consent Decree was published in the Federal Register, creating a 30-day period for public comment.
On September 30, 1993, the Company was advised that the public comment period would be extended until October 21, 1993, at which time, barring any disclosure of facts or considerations which indicate that the proposed settlement is inappropriate, improper or inadequate, the District Court for the District of Idaho should enter a final judgment in the matter resolving the government's claims against the Company.
Pursuant to the Request for Public Comment, a number of Potentially Responsible Parties involved with the lead contamination at the site filed objections to the proposed Amended Partial Consent Decree. The objections generally contend that the government's information relating to the Company's contribution to the lead contaminations at the site is erroneous, and that the Company's proposed settlement is disproportionately low in relation to its liability. On November 19, 1993, the Company provided the Department of Justice with its responses to the objections. Following receipt of the Company's responses, EPA undertook further factual investigations relating to the extent of lead contamination at the site and the nature and extent of lead contributions to the site, including the Company's involvement.
The Amended Partial Consent Decree was finally lodged together with EPA's Motion to Enter with the U.S. District Court for the District of Idaho on December 12, 1994. The Amended Partial Consent Decree provides that the Company is protected against any and all claims for contribution by other PRPs, both as to the PCB and lead contamination.
On January 24, 1995, the Company was advised that the PRP group associated with lead contamination was objecting to the proposed entry of the Amended Partial Consent Decree on the basis that the Company has not paid its "fair share" of the remaining lead clean- up costs which EPA currently estimates at approximately $5 million.
It is EPA's position that the Company, as an integral part of its clean-up of the PCB contamination and PCB/lead contamination, removed approximately 57 percent of the total lead contamination from the entire site, even though the Company contributed only 10.5 percent of the total lead contamination.
The Company believes that the objections filed by the PRPs are completely without merit, and both the Company and the EPA are responding to the objections of the PRPs.
This matter has been previously reported in Form 10-K dated March 9, 1989, March 8, 1990, March 14, 1991, March 16, 1992, March 12, 1993, March 10, 1994, and other reports filed with the Commission.
On February 16, 1994, an action for declaratory relief and breach of contract entitled Idaho Power Company vs. Underwriters and Lloyds London, et al., was filed by the Company in Federal District Court in Pocatello, Idaho, against its solvent liability insurers in the period of 1969 to 1974, arising out of the insurer's denial of coverage for the Company's environmental remediation of a hazardous waste site in Pocatello. The action seeks a declaratory judgment that the policies cover the Company's costs of defending claims related to the site and costs of site remediation, and damages for the insurers' breach of the insurance contracts based on the insurers' failure to pay such costs.
Due to a case backlog in the Idaho District, the case was assigned to a Federal Judge in the Eastern District of Washington. In the action, the Company seeks reimbursement for approximately $6,125,000 in indemnity and defense costs associated with the remediation, together with prejudgment interest and attorney fees and costs for the action.
The Company successfully settled its claim for coverage with the Liquidation Trustee for the first layer insurer (which insurer is now in liquidation) on several of the policies at issue, resulting in a one-time payment of $827,500 to the Company last fall. This sum is not reflected in the damages which the Company seeks in this litigation.
On December 6, 1991, a complaint entitled Nez Perce Tribe, Plaintiff, v. Idaho Power Company, Defendant, Civil No. CIV 91- 0517-S-EJL, was filed against the Company in the United States District Court for the District of Idaho. The Company was served with the Complaint on March 26, 1992. In the Complaint, the Tribe contends that pursuant to treaties with the United States Government including the Treaty of June 11, 1855, 12 Stat. 957, and the Treaty of June 9, 1863, 14 Stat. 647, the right to take fish at all usual and accustomed fishing places outside the Nez Perce Reservation and the exclusive right to take fish in all streams running through or bordering the reservation were reserved for the Tribe in said treaties. The Complaint further states that the Snake River supported substantial runs of anadromous fish and that the construction of Brownlee, Oxbow and Hells Canyon Dams in 1958, 1961 and 1967, respectively, created total barriers to the migration of the anadromous fish, thereby destroying the fish runs and violating the reserved fishing rights stated in the above-described treaties. In the Complaint, the Tribe seeks actual, incidental and consequential damages in amounts to be proven at trial together with $150,000,000 in punitive damages as well as pre and post-judgment interest and costs and attorney fees.
On September 11, 1992, the Tribe filed an Amended Complaint in which it amplified its original Complaint by asserting that Brownlee, Oxbow and Hells Canyon Dams were "constructed, operated and maintained in such a manner as to damage plaintiff's rights" to harvest fish, which rights the Tribe asserts to be "present, possessory property right(s)". As the basis for its alleged right to recover damages from the Company, the Tribe asserts that the Company negligently constructed, operated and maintained Brownlee, Oxbow and Hells Canyon Dams, that the Company negligently failed to prevent or mitigate harm to the Tribe, that the Company intentionally and willfully destroyed, interfered with, and dispossessed the Tribe of its property rights, and that the Company improperly exercised dominion over the Tribe's property, thus depriving the Tribe of its possession. The Tribe has requested to try its case to a jury. As was true for the Tribe's original Complaint, the Tribe seeks through its Amended Complaint to secure actual, incidental, and consequential damages in amounts to be proven at trial, together with pre and post- judgment interest, costs and disbursements of the action, attorney fees and witness fees. The Amended Complaint restates the Tribe's claim for punitive damages, but omits the prior reference to a sum certain in favor of requesting punitive damages in an "amount sufficient to punish the defendant and deter others".
On September 18, 1992, the Company filed a motion for summary judgment in the hope of securing dismissal of the Tribe's action. On January 19, 1993, a federal court hearing was held before a Federal Magistrate on the Company's motion for summary judgment. On July 30, 1993, the Magistrate issued a Report and Recommendation to the District Judge wherein it was recommended that the Company's motion for summary judgment be granted. The Tribe filed briefing in which it urged the District Court to reject the Magistrate's Report and Recommendation, and the Company responded with a request that the District Court enter summary judgment in accordance with the Magistrate's opinion.
On November 30, 1993, the District Court entered a Second Order of Reference, in which the Court sent the case back to the Magistrate for the Magistrate to make additional findings with respect to the Tribe's contention that it is entitled to compensation based on physical exclusion from its usual and accustomed fishing places. The Magistrate ordered the parties to brief this issue. That briefing was concluded, and oral argument was held before the Magistrate on February 11, 1994. On February 28, 1994, the Magistrate issued a Second Report and Recommendation wherein it was recommended that the District Court deny the Company's motion for summary judgment as to the Tribe's claim for damages arising from precluding the Tribe's access to its usual and accustomed fishing places and reaffirmed its recommendation in the original Report and Recommendation to grant the Company's motion for summary judgment as to all other claims.
On March 21, 1994, the Federal District Judge issued an order granting the Company's motion for summary judgment on all claims except the Tribe's claim for compensation based on exclusion from its usual and accustomed fishing places, which part of the motion the District Judge denied without prejudice.
On September 28, 1994, the Federal District Judge issued an Order rejecting the Second Report and Recommendation of the Magistrate and granting, in its entirety, the Company's motion for summary judgment.
On November 8, 1994, the Tribe filed its Notice of Appeal with the Ninth Circuit Court of Appeals. No date for oral argument on the appeal has yet been set.
The lawsuit is still in the early stages, and the Company is unable to predict the outcome of this case. However, the Company believes its actions were lawful and intends to vigorously defend this suit.
This matter has been previously reported in Form 10-K dated March 16, 1992, March 12, 1993, March 10, 1994, and other reports filed with the Commission.
On October 6, 1994, the Company brought an action, Idaho Power Company, v. Monsanto Company, et al., in the district court of the fourth judicial district of the State of Idaho, against Monsanto Company, General Electric Company, Westinghouse Electric Corporation, Schlumberger Industries, Inc., McGraw-Edison Company, Asea Brown Boveri, Inc. and Cooper Industries, Inc. The Complaint alleges fraudulent misrepresentation or omission of material facts, and/or knowing failure to warn Idaho Power Company of the hazards of polychlorinated biphenyls (PCBs), in connection with the sale, service, replacement, maintenance, and/or removal of electrical equipment utilizing or contaminated with PCBs. The case has been removed to the United States District Court for the District of Idaho and is still in an early stage. Discovery has not yet commenced and no trial date has been set.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages and positions of all of the executive officers of the Company are listed below along with their business experience during the past five years. Officers are elected annually by the Board of Directors. There are no family relationships among these officers, nor any arrangement or understanding between any officer and any other person pursuant to which the officer was elected.
Business Experience During Past Name, Age and Position Five (5) Years
J. W. Marshall, 56 Appointed August 18, 1989. Chairman of the Board and Chief Executive Officer
L. R. Gunnoe, 59 Appointed July 12, 1990. Mr. Gunnoe President and Chief was Vice President - Distribution Operating Officer prior to July 12, 1990.
Daniel K. Bowers, 47 Appointed July 10, 1986. Vice President and Treasurer
J. LaMont Keen, 42 Appointed November 14, 1991. Vice President and Mr. Keen was Controller prior to Chief Financial Officer November 14, 1991.
Douglas H. Jackson, 58 Appointed July 12, 1990. Vice President - Mr. Jackson was Senior Manager of Distribution Corporate Services prior to July 12, 1990.
Paul L. Jauregui, 53 Appointed June 4, 1988. Vice President - Human Resources
C. N. Olson, 45 Appointed July 11, 1991. Mr. Olson Vice President - was Senior Manager - Corporate Corporate Services Services prior to July 11, 1991, Senior Manager - Administrative Services prior to September 1, 1990 and Distribution Engineering and Construction Manager prior to February 1, 1990.
J. B. Packwood, 51 Appointed July 13, 1989. Vice President - Power Supply
Robert W. Stahman, 50 Appointed July 13, 1989. Vice President, General Counsel and Secretary
Harold J. Hochhalter, 59 Appointed January 9, 1992. Controller and Chief Mr. Hochhalter was Manager of Accounting Officer Corporate Accounting and Reporting prior to January 9, 1992.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
The Company has paid cash dividends on its common stock in each year since 1918. For the years of 1992, 1993 and 1994, cash dividends per share of common stock were $1.86. At the July 1994 meeting, the Board of Directors voted to maintain the annual common dividend at $1.86 per share. It is the intention of the Board of Directors to continue to pay dividends quarterly on the common stock, but such dividends in the future will depend on earnings, cash requirements of the Company and other factors.
The common stock is listed on the New York and Pacific stock exchanges. For years 1993 and 1994, the following table indicates the reported high and low sales price of the Company's common stock as reported by the Wall Street Journal as composite tape transactions. The Company's number of common stockholders of record at December 31, 1994 was 26,209.
1993 (Quarters) Common Stock, $2.50 par value: 1st 2nd 3rd 4th High $30 3/8 $31 1/2 $33 $32 7/8 Low 27 1/4 27 7/8 31 29 1/8 Dividends paid per share (cents) 46.5 46.5 46.5 46.5
1994 (Quarters) Common Stock, $2.50 par value: 1st 2nd 3rd 4th High $30 5/8 $27 5/8 $24 7/8 $24 1/8 Low 26 7/8 21 3/4 22 1/2 22 Dividends paid per share (cents) 46.5 46.5 46.5 46.5
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Idaho Power Company's consolidated financial statements represent the Company and its five wholly-owned subsidiaries: Idaho Energy Resources Company (IERCo); Ida-West Energy Company (Ida-West); IDACORP, Inc.; Idaho Utility Products Company (IUPCo); and Stellar Dynamics. This discussion uses the terms Idaho Power and the Company interchangeably to refer to Idaho Power Company and its subsidiaries.
EARNINGS PER SHARE AND BOOK VALUE
Two factors affected earnings per share in 1994. First, drought conditions returned to the Company's service area. These conditions have hampered the Company's hydroelectric operations six of the last eight years. Second, the Company entered into an agreement with a midwest utility regarding a substitution emission allowance exchange. This agreement resulted in a $2.5 million one-time addition to pretax income. Earnings per share of common stock were $1.80 in 1994, down from $2.14 in 1993, a year of improved precipitation and streamflows. However, the 1994 earnings per share are an increase over 1992's drought-affected $1.55. The 1994 earnings equate to a 10.0 percent earned return on year-end common equity, as compared to the 11.8 percent earned in 1993 and the 8.7 percent earned in 1992. At December 31, 1994, the book value per share of common stock was $17.91.
RESULTS OF OPERATIONS
Energy Demand and Customer Growth
A prolonged period of high temperatures sparked sharp increases in energy demand during the summer of 1994. Southwestern Idaho and southeastern Oregon--the most densely populated area of the Company's service territory--experienced a record 44 consecutive days with temperatures of at least 90 degrees. On June 23, 1994, the Company set a new record for system peak load at 2,392 megawatts (MW).
The Company's growth in new customers this year broke a record of its own. By December 31, 1994, Idaho Power had connected 12,536 new general business customers to its system, far outpacing the previous record of 11,563 set in 1978. By customer class, the Company added 10,505 residential customers, 1,548 commercial and industrial customers, and 483 irrigation customers.
Economy
The Company's service territory posted another outstanding year of economic growth in 1994. Idaho's nonagricultural employment grew by an estimated 4.6 percent, following gains of 5.0 percent in 1993 and 4.6 percent in 1992. Across the entire service territory, nonagricultural employment showed an estimated gain of nearly 4.6 percent for 1994, building on gains of 4.9 percent in 1993 and 3.5 percent in 1992.
Population growth remains strong in the Company's service area. The number of residential customers grew by 3.4 percent in both 1992 and 1993, and by 4.0 percent in 1994. Over the next five years, the Company projects that the number of new households in its service area will grow by an average rate of 3.0 percent per year, while population growth over the same period will exceed 2.2 percent.
Revenues
For the three-year period 1992-1994, the Company received an average 86 percent of its operating revenues from electric sales in Idaho, 5 percent in Oregon, less than 1 percent in Nevada, and 9 percent from the wholesale market. For the same three-year period, the average percentages of total operating revenues by category were as follows: - - 34 percent from residential customers; - - 30 percent from a combination of irrigation customers, street lighting customers, and commercial and industrial customers with less than 750 kW demand; - - 19 percent from commercial and industrial customers with demand of 750 kW or greater; - - 12 percent from sales to other utilities and interchange arrangements; - - 5 percent miscellaneous revenue.
The Company's energy sales to general business customers rose 3.0 percent in 1992, fell 1.7 percent in 1993, then increased 6.9 percent in 1994. The sales increases in 1992 and 1994 reflect the strong economic growth in Idaho Power's service territory, increases in new customers served, and varied temperature, streamflow, and energy usage patterns. The decline in 1993 can be traced to two factors: (1) wet spring weather that reduced irrigation kilowatt-hour sales by 28.8 percent; and (2) temporary operational changes made by two of the Company's large industrial customers that lowered energy consumption. FMC Corporation periodically curtailed 1993 operations at its elemental phosphorous production plant in response to market conditions for its product. Also, the Idaho National Engineering Laboratory (INEL) reduced its 1993 electrical usage. Both FMC and INEL returned to a higher level of operation during 1994.
Record growth in new customers contributed to the 1994 increase in energy sales. In addition, a long, hot, dry summer boosted the Company's irrigation load by 34.5 percent.
General business revenues constitute approximately 83 percent of the Company's total operating revenues. For 1992, general business revenues were $431.8 million, for 1993 $428.7 million, and for 1994 $457.4 million. The decrease in 1993 is a result of that year's wet spring, which reduced irrigation revenues by 27.9 percent. The decrease was partially offset by increases in residential revenues (9.3 percent) and small commercial revenues (4.0 percent). The 1994 increase reflects above-normal summer temperatures that increased irrigation revenues by 33.2 percent, or $16.2 million. The number of general business customers served increased by 32,500, or 10.9 percent during the three-year period. Energy usage per average residential customer was 13,856 kilowatt hours (kWh) in 1992, 14,587 kWh in 1993, and 14,159 kWh in 1994.
Total operating revenues increased by $14.9 million (3.1 percent) in 1992, $42.3 million (8.5 percent) in 1993, and $3.3 million (0.6 percent) in 1994. Increased opportunity sales to other utilities created the 1993 increase in total operating revenue. Customer growth, coupled with above-normal summer temperatures, accounted for the 1994 increase. However, the increase was offset by a decline in opportunity sales caused by reduced streamflows.
Off-System Sales
Revenues from sales to other utilities fell $10.6 million in 1992, rose $44.5 million in 1993, and decreased by $26.6 million in 1994. These are composed of firm sales (long-term contractual agreements) and opportunity sales made on a when-available basis. The volume and price of these sales depend on the Company's firm energy demand, hydroelectric generation conditions in its service territory, and market conditions throughout the West. Revenues from firm sales to other utilities were $37.5 million in 1992, $45.4 million in 1993, and $53.6 million in 1994. Revenues from opportunity sales to other utilities were $4.5 million in 1992, $41.1 million in 1993, and $6.3 million in 1994. Drought conditions reduced opportunity sales in 1992 and 1994, while the return to more normal hydro conditions in 1993 increased the volume of sales and revenue dramatically.
Expenses
Total operating expenses grew $16.4 million in 1992, $5.3 million in 1993, and $15.5 million in 1994. The added expense for 1992 and 1994 are a result of drought conditions that elevated the Company's reliance on thermal generation and purchased power. The 1993 rise in operating expenses reflects the deferral of certain 1992 drought-related net power supply costs to 1993 authorized by the Idaho Public Utilities Commission (IPUC). Maintenance expense also increased in 1993 with that year's return to improved hydroelectric operating conditions.
Purchased power expenses have been high and fluctuating during the last three years. This situation reflects both necessity purchases from neighboring utilities during drought periods and increased 1993 purchases from cogeneration and small power production (CSPP) projects as a result of improved hydro conditions. The current estimated annualized cost for the 62 CSPP projects on-line at December 31, 1994 is $40.7 million. The Company relies on its thermal generation facilities to operate at high-capacity factors during periods of drought. Increased thermal generation raised fuel expenses by $21.5 million in 1992 and $7.0 million in 1994. In 1993, fuel expenses declined by $8.9 million as a direct result of the increased availability of hydro generation to meet customer demand.
All other operation and maintenance expenses fluctuated during the three-year period, with a cumulative increase of $3.1 million. These variations are due, in part, to increases in payroll and benefits, and changes in operation and maintenance due to drought conditions.
Depreciation expense was up for the three-year period by $2.6 million, or 4.5 percent, due to a greater plant investment base. Taxes other than income taxes grew $2.8 million, or 13.1 percent, as a result of additional property taxes and taxes on the increased generation and sale of hydroelectric power.
Interest Charges
Interest charges on long-term debt fluctuated during the three- year period. Ultimately, they were down by $3.2 million, reflecting the maturity, early redemption, and issuance of several series of first mortgage bonds. The Company took advantage of declining interest rates to refinance several higher- cost bond issues. These refinancings reduced the overall cost of debt and annual interest expense by an amount that largely offset the cost of additional financing (see Note 5 of Notes to Consolidated Financial Statements).
Interest on short-term debt rose due to varying interest rates during the period, as well as to a larger level of short-term borrowings. At December 31, 1994, the Company's short-term borrowings were $55.0 million (see Note 7 of Notes to Consolidated Financial Statements).
Income Taxes
In August 1993, Congress enacted the Omnibus Budget Reconciliation Act. Among other things, the Act raised the statutory corporate federal income tax rate from 34 percent to 35 percent, retroactive to January 1, 1993. Accordingly, taxes on current income were computed at the higher rate. Also in 1993, the Company settled with the Internal Revenue Service (IRS) federal income tax liabilities for the 1987-1990 tax years and in 1994 the Company settled federal income tax liabilities for the 1991-1992 tax years, except for immaterial amounts relating to a partnership.
Precipitation and Streamflows
After experiencing an above-average water year in 1993, Idaho Power's service territory experienced below-normal precipitation and above-normal temperatures throughout much of 1994. Between April and July, the Company recorded 2.75 million acre feet (MAF) of water flowing into Brownlee Reservoir (water source for the three-dam Hells Canyon hydroelectric complex). This figure is 46 percent of 1993's 6.0 MAF, 153 percent of 1992's 1.8 MAF, and 57 percent of the 66-year median of 4.8 MAF.
The early indications for l995 are somewhat better. As of February 1, l995, reservoir storage above Brownlee Reservoir was at 37 percent of capacity. However, the average snow water equivalent for the Snake River above Brownlee Reservoir was at 114 percent of the 30-year average, compared to 56 percent of the average at this time last year. Based on current hydrologic conditions and projected meteorological conditions, the Company estimates that approximately 4.5 MAF of water will flow into Brownlee Reservoir between April and July 1995. If the estimate holds true, it would be a 64 percent increase over 1994's streamflow, but still 6 percent below the 66-year median inflow.
Energy Requirements
With drought conditions returning in 1994, hydroelectric generation accounted for only 40 percent of the Company's total energy requirements. This figure is a substantial decrease from 52 percent in 1993, but higher than 1992's 35 percent. Thermal generation accounted for 46 percent of total energy requirements in 1994, while purchased power and other exchanges supplied 14 percent. Under normal conditions, the Company's hydro system supplies approximately 58 percent of its total energy requirements, with thermal generation accounting for 33 percent and purchased power and other interchanges contributing the remaining 9 percent.
The Company expects to meet l995's projected energy loads by using its hydro and coal-fired facilities and strategic geographic location-which presents excellent opportunities to purchase, sell, exchange, and transmit Northwest energy-even if stream flow conditions are below normal.
Regulatory Issues
Power Cost Adjustment (PCA)
Since 1993, the Company's PCA mechanism has allowed it to collect, or to refund, the differences between actual net power supply costs and those allowed in the Company's Idaho base rates. Deviations from forecasted costs are deferred with interest and trued up the following year. The Company filed its 1994 PCA application with the IPUC on April 15, 1994, requesting an increase in base rates for the Idaho jurisdiction. The increase (in effect from May 16, 1994 through May 15, 1995) was approximately $9.8 million, or 2.5 percent including last year's true-up. At December 31, 1994, the Company had recorded $8.6 million of power supply costs above those projected in the 1994 forecast. This cumulative amount will be requested to be included in the 1995 true-up adjustment. With the IPUC's revenue requirement order on February 1, 1995, the PCA mechanism increased to a 90 percent recovery level from its original 60 percent.
General Revenue Requirement Case
On June 30, 1994, the Company filed its application based upon calendar year 1993, using a thirteen month average rate base (annualized for its new Swan Falls production project) and a year end capitalization structure. The IPUC conducted ten days of hearings commencing on October 10 and December 12, 1994. Public hearings were also held in Pocatello, Idaho on December 5 and in Caldwell, Idaho on December 7, 1994. Throughout the proceeding, including the interim rate hearing, documentary and oral evidence was presented by a number of parties.
On January 31, 1995, the Company received IPUC Order No. 25880 authorizing $17.2 million in general rate relief from the IPUC representing a 4.2 percent overall increase in Idaho retail rates. The relief is based on an 11.0 percent allowed return on equity with an overall rate of return of 9.199 percent. The Company had requested $37.1 million in general rate relief representing a 9.09 percent increase in rates, a 12.50 percent return on equity, and a 9.88 percent overall rate of return. These increased rates are effective February 1, 1995.
The Company is disappointed with the allowed return on common equity granted in the Order and believes it does not adequately reflect today's financial conditions and the returns investors expect to receive on their investment. An allowed return on common equity of 11.0 percent only marginally exceeds the Company's dividend payout ratio of 10.4 percent on year-end book value. This makes it difficult for the Company to meet dividend requirements because of the implied constraint the return allowed places on the Company's earnings potential. The Company has petitioned the IPUC for reconsideration of its decision with regard to the allowed return on common equity seeking an authorized return on common equity which, if earned, would be sufficient to safely cover the current dividend. However, the Company cannot predict the final outcome of this request for reconsideration.
The Company will file a general revenue requirement case in Oregon in early l995. This filing will utilize the same information used in the 1994 filing in Idaho.
Cogeneration and Small Power Production Contracts
In September 1993, the Company submitted a detailed position paper to its state regulators and other interested parties. This report outlined proposed changes in the Company' s resource acquisition policy. With the potential deregulation of the electric utility industry, and a more competitive power supply marketplace, the Company believes that current resource acquisition policies must be changed to avoid burdening it and its customers with unnecessary future power supply costs. Idaho Power believes that the appropriate criteria for adding future supplies should be power needs at the time of development and that the addition be the least-cost market alternative. Therefore, in December 1993 the Company filed with the IPUC for permission to approve lower published prices for new CSPP contracts. In response to the Company's filing, on January 31, 1995 the IPUC issued an order approving lower published CSPP rates. In the order, the IPUC also determined that negotiated rates for future CSPP projects larger than 1 megawatt should be more closely tied to values determined in the Company's integrated resource planning (IRP) process. In its January 31, l995 order, the IPUC stated, "There is a widely held expectation that there will be increasing competition within the electric utility industry. In light of that, we believe it is especially important that the QF [Qualified Facilities] industry be able to demonstrate that the energy resources offers are as cost effective as those that a utility would construct."
Rosebud Enterprises, Inc. (Rosebud) filed a Complaint against the Company with the IPUC, alleging that the Company refused to sign a contract to purchase the output of a 40 MW petroleum waste- fired generating plant that Rosebud proposes to build near Mountain Home, Idaho. Because this facility, known as the Mountain Home Project, was larger than l0 MW, the IPUC's established rates for small CSPP projects were not available to Rosebud. On September 16, 1994, the IPUC issued an order directing the Company to recalculate and offer avoided cost rates as described in the order. In October 1994, the Company transmitted a purchase offer to Rosebud conforming to the IPUC's final order. Rosebud rejected that purchase offer and has appealed the IPUC's final order to the Idaho Supreme Court.
Oregon Drought Rate Relief
The Company's PCA mechanism applies only to its Idaho jurisdiction. As a result of 1994's high power supply costs, the Company also filed for temporary drought rate relief with the Oregon Public Utility Commission (OPUC). The OPUC issued an accounting order that granted the Company permission to defer with interest 60 percent of Oregon's share of the Company's increased power supply costs incurred between May 13, 1994 and December 31, 1994. The amount deferred at December 31, 1994 was $1.3 million. The Company is required to file a request with the OPUC in early 1995 to recover these deferred costs.
Subsidiaries
Ida-West Energy Company
This wholly-owned subsidiary of the Company owns, through various partnerships, 50 percent of five Idaho hydroelectric projects with a total generating capacity of approximately 34 megawatts (MW). Third parties unaffiliated with Ida-West own the remaining 50 percent of these projects, thus satisfying the "qualifying facility" status under PURPA guidelines. The partnerships have obtained project financing (non-recourse to the Company) for each of these facilities.
As a part of its Resource Contingency Program, the Bonneville Power Administration (BPA) requested proposals to provide up to 800 average megawatts of energy options. Ida-West, along with two partners, submitted a proposal for a 227 MW gas-fired cogeneration project to be located near Hermiston, Oregon. On June 4, 1993, BPA selected three projects--including that of the partnership--for participation in the program. The partnership and BPA signed an option development agreement granting BPA an option to acquire energy and capacity from the project any time during a five-year option hold period after all option development period tasks, including permitting, have been completed. The option also entitles the partnership to BPA reimbursement for certain development costs, based on the achievement of certain milestones. This option includes an exclusive right to acquire energy and capacity from a second 233 MW unit at the site during the same five-year option hold period. In March 1994, BPA and the partnership reached an additional agreement on the power purchase contract, setting forth the terms and conditions on which BPA will purchase energy and capacity from the project upon exercise of the option. The partnership expects to complete development period tasks by the end of l995. Project financing for construction costs would be non-recourse to the Company.
The Company has invested $20 million in Ida-West. Ida-West continues an active search for new projects.
Stellar Dynamics
In 1994, Idaho Power announced the formation of a fifth subsidiary company. Stellar Dynamics will commercialize the Company's extensive expertise in control technology for electric substations and power plants. The Company approved the new venture after receiving a positive recommendation from Newton- Evans Research Company. The recommendation, based on a market survey conducted by Newton-Evans, was backed by strong interest from potential customers. One-third of the companies surveyed, including several large investor-owned utilities, requested product information. The primary opportunity for Stellar Dynamics' design, consulting, installation, and troubleshooting services lies in the U.S. substation controls market. The Company expects to capitalize Stellar Dynamics in early 1995.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow
Net cash generation from operations totaled $377.3 million for the three-year period 1992-1994. After deducting common and preferred dividends of $221.7 million, net cash generation from operations provided approximately $155.6 million for the Company's construction program and other capital requirements.
Internal cash generation after dividends provided 30 percent of total capital requirements in 1992, 54 percent in 1993, and 41 percent in 1994. Idaho Power expects to continue financing its construction program with both internally generated funds and, to the extent necessary, externally financed capital. Drought conditions hurt the Company's internal cash generation two of the last three years. The Company has first mortgage bond refundings of $20.0 million in 1996 and $30.0 million in 1998. At January 1, 1995, the Company's lines of credit maintained with various banks totaled $70.0 million. The total lines of credit maintained with various banks will increase to $90.0 million at March 1, l995 (see Note 7 of Notes to Consolidated Financial Statements).
Construction Program
The Company's consolidated cash construction expenditures were $118.0 million in 1992, $122.9 million in 1993, and $110.5 million in 1994. Approximately 42 percent of these expenditures were for generation facilities, 8 percent for transmission facilities, 38 percent for distribution facilities, and 12 percent for general plant and equipment. After completion of the Swan Falls and Twin Falls projects, the Company does not anticipate any new major generation construction projects.
Swan Falls Project
In early spring of 1994, the Company completed testing of the Swan Falls Project and both units were declared available for commercial operation. At December 31, 1994, the Company had spent approximately $55.0 million for construction of the Swan Falls Project, including allowance for funds used during construction. Additional work to preserve the old power plant as an historical site began during the year, while work to establish a museum on the site is scheduled for completion in 1995. In May, crews completed the federally-mandated stabilization of the dam and began the environmental reclamation of approximately 18 acres of land affected by construction activities.
Twin Falls Project
Expansion of the Twin Falls Project recently passed the halfway point, with completion estimated for mid-1995. The commitment estimate, including allowance for funds used during construction, is $50.8 million which represents the maximum amount the Company recommends be included in Idaho ratebase. Revised total cash expenditures for the Twin Falls expansion are currently estimated at $38.1 million, with total construction costs at $41.9 million, including an allowance for funds used during construction. At December 31, 1994, the Company had spent approximately $29.4 million on the Twin Falls Project. When completed, it will add 43 MW of new capacity to the Company's generation system.
Southwest Intertie Project (SWIP)
Idaho Power is continuing to study the economic feasibility of constructing the SWIP to capitalize on its strategic location between the Intermountain West and the Pacific Northwest. The SWIP would serve as a major north-south transmission artery for regional transfers of electric power. The Company's SWIP proposal calls for a 500-mile, 500 kV transmission line that would interconnect the Company's system with those of utilities in California and the Southwest. In December 1994, the U.S. Bureau of Land Management issued a favorable record of decision on the Company's environmental impact statement and granted the project a right-of-way across public lands in Idaho, Nevada, and Utah. At present, the Company is conducting financial and contractual discussions with potential partners in the project. Idaho Power intends to retain up to 20 percent of ownership and capacity in the 1,200 MW project. The SWIP may be built in segments as warranted by demand for its transmission services.
Solar and Solar Photovoltaic Projects
Solar Two
Idaho Power is a member of a consortium supporting the upgrade of an existing solar thermal power plant near Barstow, California. The Company has committed $630,500 in direct support to improve the plant's ability to store the sun's heat and use it later to generate electricity. The Electric Power Research Institute (EPRI), of which the Company is also a member, will contribute an additional $630,500, bringing the Company's credited contribution to approximately $1.3 million. Workers have completed over one- third of the retrofitting to date. When finished, Solar Two will use 1,900 mirrors to track the sun and focus its energy on a central receiving tower. The project will use a molten-salt fluid to store and transfer the collected heat. The main benefit the Company will receive by participating in this 10 MW project, is valuable experience and knowledge in solar power plant design, construction, and operation.
Mountain Home Air Force Base
The U.S. Air Force retained Idaho Power to design, build, and maintain one of the nation's largest hybrid solar-powered photovoltaic (PV) systems. The $1.2 million project, completed in February 1995, provides electricity to a remote Mountain Home AFB radar training installation near Grasmere, Idaho. Under optimal solar conditions, the PV system produces a peak capacity of 80,000 watts, reducing both the need for combustion generators and the emissions they produce. Under the terms of the contract, the federal government owns the system and pays the Company a monthly maintenance fee.
International Photovoltaics Conference
The Company has been selected to host an international conference on the emerging global business opportunities associated with photovoltaic power applications. The Executive Conference on Strategic Photovoltaic Business opportunities for Utilities is scheduled for September 17-20, 1995 in Sun Valley, Idaho. Representatives of the utility and PV industries and government agencies will discuss how they and their organizations can plan for and shape the influence of photovoltaics in developing and changing utility markets.
Photovoltaic Service Tariff (PST)
The PST offers basic electric service for small loads at remote sites as an alternative to either line extensions for grid service or the use of on-site, fossil-fuel generators. In many cases, PV technology offers a cost-effective solution for both the customer and the Company. Idaho Power benefits by reducing the number of costly line extensions to serve small loads that produce little revenue. Under the PST, the customer pays a monthly fee to receive electric service from a PV system designed, installed, owned, and maintained by Idaho Power. The program, which the Company launched in January 1993, is a pilot offering with a $5,000,000 program limit and a $50,000 limit for individual systems.
In 1994, the Company made significant operational and technical improvements to its PST systems based on feedback from early PV customers. Customer comments helped to identify obstacles to customer acceptance of PV systems. To date, seven systems have been installed and are operating as designed.
Financing Program
Capital Structure
The Company's capital structure (as illustrated in Selected Financial Data) fluctuated during the three-year period, with common equity growing to 45 percent, preferred rising to 9 percent, and debt falling to 46 percent. The Company's objective is to maintain capitalization ratios of approximately 45 percent common equity, 8-10 percent preferred stock, and the balance in long-term debt. The Company's strategy for achieving this target is through the use of accumulated retained earnings and the issuance of new equity. The Company's pre-tax interest coverage ratios were 2.50 times in 1992, 3.14 times in 1993, and 3.01 times in 1994. The Company has on file a shelf registration statement for the issuance of first mortgage bonds and/or preferred stock, with an aggregate principal amount not to exceed $200.0 million. The Company's primary financial commitments at year-end 1994 were related to contracts for the Company's facility construction and maintenance program.
Common Stock
During the period of January 1992 through May 1994, the Company issued original issue shares of common stock for its Dividend Reinvestment and Stock Purchase Plan and the Employee Savings Plan. During 1992, 1993, and 1994, common shares totaling 959,527; 898,528 and 527,296, respectively, were issued to these plans. The net proceeds from these issues were used for the Company's ongoing construction program.
Preferred Stock
On July 1, 1993, Idaho Power issued $25 million of serial preferred stock. The Company used the net proceeds of this issuance for its ongoing construction program.
Long-Term Debt
On April 28, 1993, the Company issued $160,000,000 principal amount of secured medium-term notes: $80,000,000 due in 2003 and $80,000,000 due in 2023. In May of that year, the Company used the net proceeds to retire early four series of first mortgage bonds totaling $155,000,000, plus premiums and accrued interest. On September 1, 1993, the Company issued $30,000,000 principal amount of secured medium-term notes due in 1998. In October 1993, the Company used the net proceeds to retire early first mortgage bonds totaling $30,000,000, plus premiums and accrued interest.
Environmental Issues
Salmon Recovery Plan
Work continues on the development of a comprehensive and scientifically credible plan to ensure the long-term survival of anadromous fish runs on the Columbia and Lower Snake Rivers.
In mid-August 1994, the federal government changed its designation of the Snake River Fall Chinook Salmon from Threatened to Endangered. The Company does not anticipate that the new designation will have any additional effects on its operations. In September 1991, the Company modified operations at its three-dam Hells Canyon Hydroelectric Complex to protect the Fall Chinook downstream during spawning and juvenile emergence. From its start, the Company's Fall Chinook program has exceeded the protection requirements for threatened species, affording the fish the same high level of protection due an endangered species.
Pending completion of a final recovery plan by the National Marine Fisheries Service (NMFS), the U.S. Army Corps of Engineers and other governmental agencies operating federally-owned dams and reservoirs on the Snake and Columbia Rivers have consulted the NMFS each year regarding federal system operations. On March 28, 1994, Judge Malcolm Marsh of the U.S. District Court for the District of Oregon ordered the federal agencies to reinitiate the consultation completed for 1993 operations of the federal system. Judge Marsh concluded that the consultations and subsequent operations were "...too heavily geared towards a status quo that has allowed all forms of river activity to proceed..." at the expense of fish. On September 9, 1994, the Ninth Circuit Court of Appeals echoed Judge Marsh's decision when it found that the 1993 Strategy for Salmon proposed by the Northwest Power Planning Council (NWPPC) was in violation of the 1980 Northwest Power Planning Act. The appeals court ordered the NWPPC to focus on saving young salmon and to defer to the expertise of state, federal and tribal fisheries management agencies in developing its salmon recovery program. Pursuant to the Ninth Circuit's opinion, the NWPPC adopted amendments to its Strategy for Salmon on December 15, 1994. The amended Strategy calls for a substantial increase in water from the Snake River to aid juvenile fish in their downstream migration to the sea. The Plan requires the Bureau of Reclamation to acquire 500,000 acre-feet of additional water by 1996 and another 500,000 acre-feet by 1998 for a total of 1,000,000 acre-feet in addition to the present contribution of 427,000 acre-feet. This water is to be acquired from willing sellers and could have a material impact on the Company's power supply costs. The Plan also calls for an additional 237,000 acre-foot contribution from the Company's Brownlee Reservoir for which the Company is to be reimbursed for by the BPA.
The Company expects a draft of the final Salmon Recovery Plan from the NMFS by March 1, 1995. It is possible this recovery plan could also have a material impact on the Company. The Company hopes that anadromous fish runs can be restored without placing undue hardship on either the Company or those who benefit from its service.
Nez Perce Tribe
On December 6, 1991, the Nez Perce Tribe filed a civil action against the Company in the U.S. District Court for the District of Idaho. The Tribe alleged that the Company's construction, operation, and maintenance of the three-dam Hells Canyon Project prevented anadromous fish from reaching their traditional spawning areas, destroyed certain fish runs, and prevented access to certain of the Tribe's usual and accustomed fishing places. These actions allegedly deprived the Nez Perce Tribe of its treaty rights to take fish from the Columbia and Snake Rivers. The Tribe is seeking compensatory and punitive damages, each in an amount to be proven at trial.
Idaho Power maintains that the suit is without merit and asked the federal court to issue a summary judgment dismissing the action. The Company believes that the responsibility for concerns expressed by the Nez Perce Tribe lies with the United States. The Hells Canyon Project was licensed by the federal government, was built in accordance with federally approved plans, and is operated subject to federal regulation. The Company has complied with all governmental requirements to mitigate any effects the Project may have had on the fisheries.
On January 19, 1993, the Court took the Company's motion for summary judgment under advisement. On July 30, 1993, U.S. Magistrate Judge Larry Boyle issued a Report and Recommendation to the District Judge. Judge Boyle recommended that the District Judge grant that portion of the Company's motion for summary judgment regarding the loss of fish and deny the portion of its motion dealing with the Tribe's claim to compensation for exclusion from its usual and accustomed fishing sites. On March 21, 1994, U.S. District Judge Harold L. Ryan upheld Judge Boyle's recommendation regarding fish losses and took the question of compensation for exclusion from fishing sites under advisement. On September 28, 1994, after reviewing responses and objections on that issue, Judge Ryan rejected the Tribe's claim and granted the final portion of the Company's motion for summary judgment. The Tribe has appealed Judge Ryan's decision to the Ninth Circuit Court of Appeals. No date has been set for oral argument on the appeal.
Snake River Mollusk
In mid-December, 1992, the U.S. Fish and Wildlife Service (USFWS) listed the Snake River Mollusk as a Threatened and Endangered Species. Since that time, the Company has included this possibility in all of its discussions regarding relicensing and new hydro development.
The listing specifically mentions the impact that fluctuating water levels related to hydroelectric operations may have on the snails' habitat. While most of the hydro facilities on that reach of the Snake River are baseload facilities, some of them do provide limited load-following capability. At present, there is no certainty as to the impacts, if any, that water fluctuations caused by these facilities may have on the snails. Idaho Power intends to testify to the USFWS that there is little scientific data in this area and that the Company proposes to study these operations. While it is possible that the listing could affect how Idaho Power operates its existing hydroelectric facilities on the middle reach of the Snake River, the Company believes that such changes will be minor and will not present any undue hardship.
Mountaineer
In May 1993, the Company was notified that Bridger Coal Company (BCC) was a potential contributor to a Superfund site involving waste motor oil delivered to Mountaineer Refinery in Wyoming. Idaho Energy Resources Company (IERCo), a wholly-owned subsidiary of the Company, owns one-third of BCC. In November 1993, BCC agreed to be included on the list of parties potentially responsible for this site. The current estimated cleanup costs are between $2.6 million and $5.0 million. During the past year, more contributors were added to the list of potentially responsible parties for cleanup of this site. Therefore, BCC's portion of these costs, based on the amount of oil delivered to the site, is estimated now to be approximately 5.0 percent, or between $130,000 and $250,000. IERCo would be liable for one- third of the BCC portion, or between $42,900 and $82,500. In 1994 BCC recorded expenses of $129,450 of which one-third flowed through to the Company's consolidated financials. Of this amount, $42,750 remains on BCC's books as an unfunded liability at December 31, 1994.
Clean Air
Idaho Power has analyzed the Clean Air Act legislation's effects on the Company and its ratepayers. The Company's coal-fired plants in Oregon and Nevada already meet the federal sulfur dioxide (SO2) emission rate standards. The Company's coal-fired plant in Wyoming meets that state's even more stringent SO2 regulations. Therefore, the Company anticipates no adverse effects on its operations with regard to SO2 emissions.
The Company, together with PacifiCorp and Black Hills Corporation, entered into Phase I substitution agreements with Illinois Power Company. The agreements designate Units 1, 2, 3, and 4 of the Company's Jim Bridger thermal facility and facilities owned by PacifiCorp and Black Hills Corporation as substitution units for Baldwin #2, owned by Illinois Power. The substitution agreements will allow the Company to grandfather in less restrictive Phase I nitrous oxide emission requirements at the Jim Bridger units. As part of the agreements, the Company negotiated the sale of a number of its Phase I SO2 emission allowances to Illinois Power.
Electric and Magnetic Fields (EMF)
While scientific research has yet to establish any conclusive link between EMF and human health, the possibility has caused public concern in the United States and abroad. Electric and magnetic fields are found wherever there is electric current, whether the source is a high-voltage transmission line or the simplest of electrical household appliances. Concerns over possible health effects have prompted regulatory efforts in several states to limit human exposure to EMF. Depending on what researchers ultimately discover and what regulations may be deemed necessary, it is possible that this issue could affect a number of industries, including electric utilities. However, at this time it is difficult to estimate what impacts, if any, the EMF issue could have on the Company and its operations.
Competition and Strategic Planning
Competition is increasing in the electric utility industry, due to a variety of developments. In response, the Company continues to proceed with a strategic planning process. The goal of this process is to anticipate and fully integrate into Company operations any legislative, regulatory, environmental, competitive, or technological changes. With its low energy production costs, Idaho Power is well-positioned to enter a more competitive environment and is taking action to preserve its low- cost competitive advantage (see Regulatory Issues - Cogeneration and Small Power Production Contracts for a discussion of the Company's revised resource acquisition policy).
On June 3, 1994 the IPUC approved the buyout and cancellation of a January 22, 1993 Firm Energy Sales Agreement (FESA) with Meridian Generating Company, L. P. (MGC). The FESA was a 25-year agreement with MGC for a 54 MW natural gas-fired combined cycle cogeneration facility located in Meridian, Idaho. The Company estimates that the revenue requirement savings, including cancellation charges paid to MGC, are between $130 and $170 million.
On June 28, 1994, Washington Water Power and Sierra Pacific Resources announced that their respective boards of directors had approved a merger agreement between the two companies. Idaho Power is intervening in the approval process to ensure that the proposed merger has no adverse effects on its operations. In addition, the Company is actively identifying and responding to business opportunities presented by the proposed merger.
Internally, the Company continues its commitment to refining its business processes to ensure its ability to offer the greatest possible value to its customers and its shareowners. Among these strategic initiatives are:
- - the examination and refinement of the Company's distribution function, work order, and line extension processes; - - the initiation of a four-year, $3 million project to automate and consolidate the operation of the Company's 17 hydroelectric power plants; - - the formation of a Technical Advisory Panel, composed of representatives from public and private interest groups, to advise the Company on such matters as competition, alternative resources, and conservation. The Company will use the panel's advice as it reviews its IRP, due for publication in mid 1995. - - the implementation of a Restricted Stock Plan and Employee Incentive Plan to focus employees' attention on achieving annual financial and operational goals, to promote and reinforce teamwork, and to encourage employee accountability for business results and the Company's responsiveness to a competitive environment.
Relicensing of Hydroelectric Projects
Idaho Power is vigorously pursuing the relicensing of its hydroelectric projects, a process that will continue for the next 10 to 15 years. The Company will submit its first applications for license renewal to the Federal Energy Regulatory Commission in December 1995. These first applications will seek renewal of the Company's licenses for its Bliss, Upper Salmon Falls, and Lower Salmon Falls Hydroelectric Projects. Although various federal requirements and issues must be resolved through the relicensing process, the Company anticipates that its efforts will be successful. At this point, however, the Company cannot predict what type of environmental or operational requirements it may face, nor can it estimate the eventual cost of relicensing.
BOARD OF DIRECTORS
On January 12, 1995, the Company welcomed two new members to its Board of Directors. Jack K. Lemley, 59, was Chief Executive officer of Transmanche-Ling, the Anglo-French construction firm that built the motor and rail transportation tunnel beneath the English Channel. A former senior vice president of Morrison- Knudsen Corporation, Mr. Lemley is currently President of Lemley & Associates, Inc. Peter S. O'Neill, 56, is President of Boise- based O'Neill Enterprises, Inc., a real estate development firm. Mr. O'Neill served as a senior vice president of Boise Cascade Corporation and as President of the Columbia-Willamette Development Co.
Three directors retired from the board in accordance with the Company's Restated Articles of Incorporation and By-Laws. The articles and by-laws require directors to retire by age 70. Former U.S. Senator James A. McClure and retired plumbing and heating wholesaler Richard T. Norman left the board in December, the same month as their 70th birthdays. Rancher George Coiner retired at the January 12 board meeting. Mr. Coiner turns 70 in February 1995.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
AND FINANCIAL STATEMENT SCHEDULES
PAGE
Management's Responsibility for Financial Statements 58
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1994, 1993 and 1992 59-60
Consolidated Statements of Income for the Years Ended December 31, 1994, 1993 and 1992 61
Consolidated Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992 62
Consolidated Statements of Capitalization as of December 31, 1994, 1993 and 1992 63
Consolidated Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992 64
Notes to Consolidated Financial Statements 65-79
Independent Auditors' Report 80
Supplemental Financial Information (Unaudited) 81
Supplemental Schedule for the Years Ended December 31, 1994, 1993 and 1992:
Schedule II- Consolidated Valuation and Qualifying Accounts 90
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of Idaho Power Company is responsible for the preparation and presentation of the information and representations contained in the accompanying financial statements. The financial statements have been prepared in conformance with generally accepted accounting principles for a rate regulated enterprise. Where estimates are required to be made in preparing the financial statements, management has applied its best judgment as to the adequacy of the estimates based upon all available information.
The Company maintains systems of internal accounting controls and related policies and procedures. The systems are designed to provide reasonable assurance that all assets are protected against loss or unauthorized use. Also, the systems provide that transactions are executed in accordance with management's authorization and properly recorded to permit preparation of reliable financial statements. The systems are supported by a staff of corporate accountants and internal auditors who, among other duties, evaluate and monitor the systems of internal accounting control in coordination with the independent auditors. The staff of internal auditors conduct special and operational audits in support of these accounting controls throughout the year.
The Board of Directors, through its Audit Committee comprised entirely of outside directors, meets periodically with management, internal auditors and the Company's independent auditors to discuss auditing, internal control and financial reporting matters. To ensure their independence, both the internal auditors and independent auditors have full and free access to the Audit Committee.
The financial statements have been audited by Deloitte & Touche LLP, the Company's independent auditors, who were responsible for conducting their audit in accordance with generally accepted auditing standards.
By: /s/ Joseph W. Marshall By: /s/ J. LaMont Keen Joseph W. Marshall J. LaMont Keen Chairman and Vice President and Chief Chief Executive Officer Financial Officer
By: /s/ Harold J. Hochhalter Harold J. Hochhalter Controller and Chief Accounting Officer
IDAHO POWER COMPANY CONSOLIDATED BALANCE SHEETS ASSETS
December 31, 1994 1993 (Thousands of Dollars)
ELECTRIC PLANT (Notes 1, 5 and 10): In service (at original cost) $2,383,898 $2,249,723 $2,198,747 Less accumulated provision for depreciation 775,033 728,979 683,332
In service - Net 1,608,865 1,520,744 1,515,415 Construction work in progress 46,628 92,682 66,997 Held for future use 1,150 2,958 3,083
Electric plant - Net 1,656,643 1,616,384 1,585,495
INVESTMENTS AND OTHER PROPERTY 18,034 20,772 11,411
CURRENT ASSETS: Cash and cash equivalents 7,748 8,228 4,966 Receivables: Customer 31,889 29,741 28,687 Allowance for uncollectible accounts (1,377) (1,377) (1,421) Notes 4,962 5,616 1,669 Employee notes receivable 5,444 5,909 5,970 Other 4,316 1,858 1,695 Accrued unbilled revenues (Note 1) 29,115 25,583 27,210 Materials and supplies (at average cost) 24,141 23,372 25,762 Fuel stock (at average cost) 11,310 11,553 14,282 Prepayments (Note 9) 21,398 20,975 22,171 Regulatory assets associated with income taxes (Note 1) 5,674 4,914 -
Total current assets 144,620 136,372 130,991
DEFERRED DEBITS: American Falls and Milner water rights 32,605 32,755 32,890 Company-owned life insurance (Note 9) 49,510 45,294 40,228 Regulatory assets associated with income taxes (Note 1) 179,311 171,569 - Regulatory assets - other (Note 1) 67,713 35,036 - Other 43,380 39,235 61,292
Total deferred debits 372,519 323,889 134,410
TOTAL $2,191,816 $2,097,417 $1,862,307
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILITIES
December 31, 1994 1993 1992 (Thousands of Dollars) CAPITALIZATION (see Page 63): Common stock equity (Note 3): Common stock - $2.50 par value (shares authorized 50,000,000; shares outstanding 1994 - 37,612,351; 1993 - 37,085,055; 1992 - 36,186,527) $94,031 $92,713 $90,466 Premium on capital stock 363,063 350,882 326,338 Capital stock expense (4,132) (4,128) (3,806) Retained earnings 220,838 222,900 212,404
Total common stock equity 673,800 662,367 625,402 Preferred stock (Note 4) 132,456 132,751 107,874 Long-term debt (Note 5) 693,206 693,780 701,948
Total capitalization 1,499,462 1,488,898 1,435,224
CURRENT LIABILITIES: Long-term debt due within one year 517 466 464 Notes payable (Note 7) 55,000 4,000 6,000 Accounts payable 32,063 31,912 34,821 Taxes accrued 16,394 15,452 16,182 Interest accrued 14,755 14,920 18,287 Other 12,574 13,731 12,125
Total current liabilities 131,303 80,481 87,879
DEFERRED CREDITS: Accumulated deferred investment tax credits (Notes 1 and 2) 71,593 72,013 73,651 Accumulated deferred income taxes (Notes 1 and 2) 380,926 358,280 210,435 Regulatory liabilities associated with income taxes (Note 1) 35,090 34,968 - Regulatory liabilities - other (Note 1) 626 4,235 - Other (Note 9) 72,816 58,542 55,118
Total deferred credits 561,051 528,038 339,204
COMMITMENTS AND CONTINGENT LIABILITIES (Note 8)
TOTAL $2,191,816 $2,097,417 $1,862,307
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31, 1994 1993 1992 (Thousands of Dollars)
REVENUES (Note 1) $543,658 $540,402 $498,092 EXPENSES: Operation: Purchased power (Notes 8 and 10) 60,216 45,361 58,496 Fuel expense (Note 10) 94,888 87,855 96,710 Other 111,252 121,252 101,659 Maintenance 43,490 43,136 35,888 Depreciation (Note 1) 60,202 58,724 59,823 Taxes other than income taxes 23,945 22,129 20,562 Total expenses 393,993 378,457 373,138
INCOME FROM OPERATIONS 149,665 161,945 124,954
OTHER INCOME: Allowance for equity funds used during construction (Note 1) 1,680 3,060 2,400 Other - Net (Note 9) 10,480 9,924 8,733 Total other income 12,160 12,984 11,133
INTEREST CHARGES: Interest on long-term debt 51,172 53,706 53,408 Other interest (Notes 1 and 7) 3,261 2,750 2,050 Total interest charges 54,433 56,456 55,458 Allowance for borrowed funds used during construction (Note 1) (1,781) (2,465) (2,523) Net interest charges 52,652 53,991 52,935
INCOME BEFORE INCOME TAXES 109,173 120,938 83,152
INCOME TAXES (Notes 1 and 2) 34,243 36,474 23,162
NET INCOME 74,930 84,464 59,990 Dividends on preferred stock (Note 4) 7,398 6,009 5,516
EARNINGS ON COMMON STOCK $ 67,532 $ 78,455 $ 54,474
AVERAGE COMMON SHARES OUTSTANDING (000) 37,499 36,675 35,116
EARNINGS PER SHARE OF COMMON STOCK (Note 3) $ 1.80 $ 2.14 $ 1.55
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year Ended December 31,
1994 1993 1992 (Thousands of Dollars) RETAINED EARNINGS Beginning of year $222,900 $212,404 $222,973
NET INCOME 74,930 84,464 59,990
Total 297,830 296,868 282,963
DIVIDENDS: Preferred stock (Note 4) 7,398 6,009 5,516 Common stock (per share: 1994 - 1992 - $1.86) (Note 3) 69,594 67,959 65,043
Total dividends 76,992 73,968 70,559
RETAINED EARNINGS End of year $220,838 $222,900 $212,404
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
PRINCIPLES OF CONSOLIDATION _ The consolidated financial statements include the accounts of the Company and its wholly- owned subsidiaries, Idaho Energy Resources Co (IERCO), Idaho Utility Products Company (IUPCO), IDACORP, INC., Ida-West Energy Company (Ida-West) and Stellar Dynamics. All significant intercompany transactions and balances have been eliminated in consolidation.
SYSTEM OF ACCOUNTS _ The Company is an electric utility and its accounting records conform to the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by the public utility commissions of Idaho, Oregon, Nevada and Wyoming.
ELECTRIC PLANT _ The cost of additions to electric plant in service represents the original cost of contracted services, direct labor and material, allowance for funds used during construction and indirect charges for engineering, supervision and similar overhead items. Maintenance and repairs of property and replacements and renewals of items determined to be less than units of property are charged to operations. For property replaced or renewed the original cost plus removal cost less salvage is charged to accumulated provision for depreciation while the cost of related replacements and renewals is added to electric plant.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFDC) _ The allowance, a non-cash item, represents the composite interest costs of debt, shown as a reduction to interest charges, and a return on equity funds, shown as an addition to other income, used to finance construction. While cash is not realized currently from such allowance, it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from higher rate base and higher depreciation expense. Based on the uniform formula adopted by FERC, the Company's weighted average monthly AFDC rates for 1994, 1993 and 1992 were 8.2 percent, 9.6 percent and 8.7 percent, respectively.
REVENUES _ In order to match revenues with associated expenses, the Company accrues unbilled revenues for electric services delivered to customers but not yet billed at month- end.
RATE RELIEF _ On March 29, 1993, the Idaho Public Utilities Commission (IPUC) approved a power cost adjustment (PCA) mechanism for the Company, pursuant to the Company's application requesting authority to implement a PCA. Under the PCA, customer's rates will be adjusted annually to reflect the Company's forecasted net power supply costs. Deviations from predicted costs are deferred with interest and then adjusted (trued-up) in the subsequent year.
On January 31, 1994, the Company received an IPUC order authorizing $17.2 million in general rate relief from the IPUC representing a 4.2 percent overall increase in Idaho retail rates. The relief is based on an 11.0 percent allowed return on equity with an overall rate of return of 9.199 percent. The Company had requested $37.1 million in general rate relief representing a 9.09 percent increase in rates, a 12.50 percent return on equity, and a 9.88 percent overall rate of return. These increased rates are effective February 1, 1995.
In addition in May 1994, the Company filed for temporary drought rate relief with the Oregon Public Utility Commission (OPUC). The OPUC issued an accounting order that granted the Company permission to defer with interest 60 percent of Oregon's share in the Company's increased power supply costs incurred between May 13, 1994 and December 31, 1994. After the close of 1994, the Company is required to file with the OPUC for an amortization proposal for the $1.3 million deferral.
DEPRECIATION _ Effective April 1, 1993, the Company revised its depreciation methodology on certain generation plants from the five percent present worth method to the straight- line method. This change and the extension of the service lives of certain plants resulted in a minimal change in depreciation expense. All electric plant is now depreciated using the straight-line method. Annual depreciation provisions as a percent of average depreciable electric plant in service approximated 2.93 percent in 1994, 2.92 percent in 1993 and 2.91 percent in 1992 and are considered adequate to amortize the original cost over the estimated service lives of the properties.
INCOME TAXES _ Consistent with orders and directives of the IPUC, the regulatory authority having principal jurisdiction, deferred income taxes (commonly referred to as normalized accounting) are provided for the difference between income tax depreciation and straight-line depreciation on coal-fired generation facilities and properties acquired after 1980. On other facilities, deferred income taxes are provided for the difference between accelerated income tax depreciation and straight-line depreciation using tax guideline lives on assets acquired prior to 1981. Deferred income taxes are not provided for those income tax timing differences where the prescribed regulatory accounting methods do not provide for current recovery in rates. The Company adopted Statement of Financial Accounting Standards (SFAS) No. 109 "Accounting for Income Taxes" on January 1, 1993 which had no material effect on the earnings of the Company (see Note 2).
The state of Idaho allows a three percent investment tax credit upon certain plant additions. Investment tax credits earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties and credits earned on non-regulated assets or investments are recognized in the year earned.
CASH AND CASH EQUIVALENTS _ For purposes of reporting cash flows, cash and cash equivalents include cash on hand and highly liquid temporary investments with original maturity dates of three months or less.
REGULATION OF UTILITY OPERATIONS - The Company follows SFAS No 71, "Accounting for the Effects of Certain Types of Regulation", and its financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating the Company. Pursuant to SFAS 71 the Company capitalizes, as deferred regulatory assets, incurred costs which are expected to be recovered in future utility rates. The Company also records as deferred regulatory liabilities the current recovery in utility rates of costs which are expected to be paid in the future.
The following is a breakdown of regulatory assets and liabilities for the years 1994 and 1993 (in millions of dollars):
1994 1993 Millions of Dollars Assets Liabilities Assets Liabilities Income Taxes $185.0 $35.1 $176.5 $35.0 Conservation 29.7 21.2 Postretirement Benefits 5.5 3.5 Postemployment Benefits 4.0 3.9 Other 28.5 0.6 6.4 4.2 Total $252.7 $35.7 $211.5 $39.2
The regulatory environment is becoming more complex resulting from the expanding effects of competition. In the event that recovery of cost through rates becomes unlikely or uncertain, this would force the Company away from the cost of service ratemaking and SFAS 71 would no longer apply. If the Company were to discontinue application of SFAS 71 for some or all of its operations then these items would represent stranded investments. Certain regulators are currently reviewing ways to allow the electric utilities to recover these investments in the event the customers are allowed to choose their energy supplier. However, if the Company was not allowed recovery of its stranded investments it would be required to write off the applicable portion of regulatory assets and the financial effects could be significant.
OTHER ACCOUNTING POLICIES _ Debt discount, expense and premium are being amortized over the terms of the respective debt issues.
2. INCOME TAXES:
A reconciliation between the statutory federal income tax rate and the effective rate for the years 1994, 1993 and 1992 is as follows:
1994 1993 1992 Amount Rates Amount Rates Amount Rates (Thousands of Dollars) Computed income taxes based on statutory federal income tax rate $38,210 35.0% $42,328 35.0% $28,272 34.0% Change in taxes resulting from: AFUDC (1,211) (1.1) (1,798) (1.5) (1,508) (1.8) Investment tax credits (3,351) (3.1) (2,898) (2.4) (3,446) (4.1) Repair allowance (1,575) (1.4) (2,975) (2.5) (2,278) (2.7) Elimination of amounts provided in prior years (2,607) (2.4) (4,686) (3.9) (1,601) (1.9) Current state income taxes 1,496 1.4 2,693 2.2 973 1.2 Depreciation 2,812 2.6 4,116 3.4 1,738 2.1 Other 469 0.4 (306) (0.1) 1,012 1.1
Total provision for federal and state income taxes $34,243 31.4% $36,474 30.2% $23,162 27.9%
The provision for income taxes consists of the following:
Income taxes currently payable: Federal $20,016 $27,199 $16,366 State 1,425 4,168 56 Total 21,441 31,367 16,422 Income taxes deferred - Net of amortization: Federal 12,196 6,621 7,688 State 1,670 69 491 Total 13,866 6,690 8,179 Investment and other tax credits: Deferred 1,643 1,315 2,007 Restored (2,707) (2,898) (3,446) Total (1,064) (1,583) (1,439) Total provision for income taxes $34,243 $36,474 $23,162
The provision for deferred income taxes consists of the following:
Deferred: Excess of tax over book depreciation normalized $12,813 $14,044 $12,474 Other 11,310 6,384 6,743 Total 24,123 20,428 19,217 Restored (10,257) (13,738) (11,038) Total $13,866 $6,690 $8,179
During 1993, the Company settled federal tax liabilities on all open years through the 1990 tax year; in 1994, it settled federal tax liabilities on the 1991 and 1992 tax years and settled Idaho tax liabilities on the 1987-1992 tax years except for immaterial amounts that relate to a partnership.
The Company adopted SFAS No. 109 "Accounting for Income Taxes" on January 1, 1993 which had no material effect on the earnings of the Company. SFAS 109, among other things, (i) requires the liability method be used in computing deferred taxes on all temporary differences between book and tax basis of assets and liabilities; (ii) requires that deferred tax liabilities and assets be adjusted for an enacted change in tax laws or rates; and (iii) prohibits net-of-tax accounting and reporting. Regulated enterprises are required to recognize such adjustments as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates. As of December 31, 1994, the Company has recorded regulatory assets of $185.0 million and regulatory liabilities in the amount of $35.1 million which were offset by an equal amount of accumulated deferred income tax. The regulatory asset is primarily based upon differences between the book and tax basis of the electric plant in service and the accumulated reserve for depreciation.
3. COMMON STOCK:
Changes in shares of the common stock of the Company for 1994, 1993 and 1992 were as follows:
Common Stock Premium on $2.50 Capital Shares Par Stock Value (Thousands of Dollars)
Balance at December 31, 1991 33,977,000 $84,942 $275,505 Gain on reacquired 4% preferred stock (Note 4) - - 152 Stock purchase plans 959,527 2,399 23,101 Public offering (July 1992) 1,250,000 3,125 27,580
Balance at December 31, 1992 36,186,527 90,466 326,338 Gain on reacquired 4% preferred stock (Note 4) - - 50 Stock purchase plans 898,528 2,247 24,494
Balance at December 31, 1993 37,085,055 92,713 350,882 Gain on reacquired 4% preferred stock (Note 4) - - 126 Stock purchase plans 527,296 1,318 12,055
Balance at December 31, 1994 37,612,351 $94,031 $363,063
During the period of January 1992 through May 1994, the Company issued original issue shares of common stock for its Dividend Reinvestment and Stock Purchase Plan and the Employee Savings Plan. During 1992, 1993, and 1994 common shares totaling 959,527; 898,528; and 527,296 respectively, have been issued to these plans.
On July 8, 1992, the Company issued 1,250,000 shares of its common stock. The net proceeds of $30,706,250 were received and used for the payment of $4.0 million of short-term debt with the remainder used for the Company's ongoing construction program.
As of December 31, 1994, the Company had 2,791,321 of its authorized but unissued shares of common stock reserved for future issuance under its Dividend Reinvestment and Stock Purchase Plan and Employee Savings Plan.
On January 11, 1990, the Board of Directors adopted a Shareowner Rights Plan (Plan). Under the Plan, the Company declared a distribution of one Preferred Stock Right (Right) for each of the Company's outstanding Common shares held on January 29, 1990 or issued thereafter. The Rights are currently not exercisable and will be exercisable only if a person or group (Acquiring Person) either acquires ownership of 20 percent or more of the Company's Voting Stock or commences a tender offer that would result in ownership of 20 percent or more. The Company may redeem the Rights at a price of $0.01 per Right anytime prior to acquisition by an Acquiring Person of a 20 percent position.
Following the acquisition of a 20 percent position, each Right will entitle its holder, subject to regulatory approval, to purchase for $85 that number of shares of Common Stock or Preferred Stock having a market value of $170.
If after the Rights become exercisable, the Company is acquired in a merger or other business combination, 50 percent or more of its consolidated assets or earnings power are sold or the Acquiring Person engages in certain acts of self-dealing, each Right entitles the holder to purchase for $85, shares of the acquiring company's Common Stock having a market value of $170. Any Rights that are or were held by an Acquiring Person become void if either of these events occurs. The Rights expire on January 11, 2000.
A restricted stock plan approved by shareholders at the May 1994 Annual Meeting was implemented January 1, 1995 as an equity-based long-term incentive plan.
4. PREFERRED STOCK:
The number of shares of preferred stock outstanding at December 31, 1994, 1993 and 1992 were as follows:
Shares Outstanding at December 31 Call Price 1994 1993 1992 Per Share Preferred stock: Cumulative, $100 par value:
4% preferred stock (authorized 215,000 shares) 174,556 177,506 178,735 $104.00
Serial preferred stock, 7.68% Series (authorized 150,000 shares) 150,000 150,000 150,000 $102.97
Serial preferred stock, cumulative, without par value; total of 3,000,000 shares authorized:
8.375% Series, $100 stated value, (authorized 250,000 shares)(a) 250,000 250,000 250,000 $105.58 to $100.37
7.07% Series, $100 stated value, (authorized 250,000 shares)(b) 250,000 250,000 - $103.535 to $100.354
Auction rate preferred stock, $100,000 stated value, (authorized 500 shares)(c) 500 500 500 $100,000.0
Total 825,056 828,006 579,235
(a) The preferred stock is not redeemable prior to October 1, 1996. (b) The preferred stock is not redeemable prior to July 1, 2003. (c) Dividend rate at December 31, 1994 was 5.16% and ranged between 2.55% and 5.16% during the year.
During 1994, 1993 and 1992 the Company reacquired and retired 2,950; 1,229 and 3,178 shares of 4% preferred stock resulting in a net addition to premium on capital stock of $126,066; $50,151 and $151,891, respectively. As of December 31, 1994 the overall effective cost of all outstanding preferred stock was 6.55 percent.
On July 1, 1993 the Company utilized the remaining preferred stock shelf registration and issued $25,000,000 of 7.07% Series, Serial Preferred Stock ($100 stated value). The net proceeds of the issuance were used for the Company's ongoing construction program.
5. LONG-TERM DEBT:
The amount of first mortgage bonds issuable by the Company is limited to a maximum of $900,000,000 and by property, earnings and other provisions of the mortgage and supplemental indentures thereto. Substantially all of the electric utility plant is subject to the lien of the indenture. Pollution Control Revenue Bonds, Series 1984, due December 1, 2014, are secured by First Mortgage Bonds, Pollution Control Series A, which were issued by the Company and are held by a Trustee for the benefit of the bondholders.
On April 28, 1993 the Company issued $80,000,000 principal amount of Secured Medium Term Notes, Series A, 6.40% Series due 2003 and $80,000,000 principal amount of Secured Medium Term Notes, Series A, 7.50% Series due 2023. In May, the net proceeds were used to retire early four series (7 3/4% Series due 2002, 8 3/8% Series due 2004, 8 1/2% Series due 2006 and 9% Series due 2008) of first mortgage bonds totaling $155,000,000 plus premiums and accrued interest. On September 1, 1993 the Company issued $30,000,000 principal amount of Secured Medium Term Notes, Series A, 5.33% Series due 1998. On October 1, 1993, the net proceeds were used to retire early the 6 1/8% Series, First Mortgage Bonds of $30,000,000 plus premiums and accrued interest.
The only first mortgage bonds maturing during the five-year period ending 1999 are $20,000,000 in 1996 and $30,000,000 in 1998. Sinking fund requirements for the first mortgage bonds outstanding at December 31, 1994 are $5,398,000 per year. These requirements may be met by the deposit of cash, deposit of bonds, or by certification of property additions at the rate of 167% of requirements. The Company's practice is to certify additional property to meet the sinking fund requirements. In September 1992, 1993 and 1994, $350,000, $400,000, and $400,000 respectively, of the 5.90% Series, Pollution Control Revenue Bonds, were retired pursuant to sinking fund requirements for those years. Sinking fund requirements during the five-year period ending 1999 for pollution control bonds outstanding at December 31, 1994 are $450,000 in 1995 and 1996, and $500,000 in 1997, 1998 and in 1999. As of December 31, 1993 and 1994, the overall effective cost of all outstanding first mortgage bonds and pollution control revenue bonds was 8.02 percent and 8.33 percent in 1992.
6. FAIR VALUE OF FINANCIAL INSTRUMENTS:
The estimated fair value of the Company's financial instruments have been determined by the Company using available market information and appropriate valuation methodologies. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
Cash and cash equivalents, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued are reported at their carrying value as these are a reasonable estimate of their fair value. The total estimated fair value of long-term debt was approximately $733,251,000 for 1992, $762,575,000 for 1993, and $682,647,000 for 1994. The estimated fair values for long-term debt are based upon quoted market prices of the same or similar issues.
7. NOTES PAYABLE:
At January 1, 1995, the Company had regulatory authority to incur up to $150,000,000 of short-term indebtedness. Under this authority, total lines of credit maintained with various banks amounted to $70,000,000. The total lines of credit maintained with various banks will increase to $90,000,000 at March 1, 1995. Under annual borrowing arrangements with these banks, the Company is required to pay a fee of 1/10 of 1 percent on the available and committed lines of credit. Commercial paper may be issued in an amount not to exceed 25 percent of revenues for the latest twelve-month period and are supported by bank lines of credit of an equal amount.
Balances and interest rates of short-term borrowings were as follows:
Year Ended December 31,
1994 1993 1992 (Thousands of Dollars) Balance at end of year $55,000 $4,000 $6,000 Effective annual interest rate at end of year 6.1% 6.9%(a) 5.9%
(a)Effective rates have been inflated by the commitment fees being larger than the interest paid for the year. If the commitment fees were excluded the effective annual interest rate at end of period would have been 3.6%.
8. COMMITMENTS AND CONTINGENT LIABILITIES:
Commitments under contracts and purchase orders relating to the Company's program for construction and operation of facilities amounted to approximately $9,500,000 at December 31, 1994. The commitments are generally revocable by the Company subject to reimbursement of manufacturers' expenditures incurred and/or other termination charges.
The Company is currently purchasing energy from 62 on-line cogeneration and small power production facilities with contracts ranging from 1 to 33 years. Under these contracts the Company could be required to purchase up to 692,000 (MWH) annually. During the fiscal year ended December 31, 1994, the Company purchased 543,000 (MWH) at a cost of $30.9 million.
The Company is party to various legal claims, actions, and complaints, certain of which involve material amounts. Although the Company is unable to predict with certainty whether or not it will ultimately be successful in these legal proceedings or, if not, what the impact might be, based upon the advice of legal counsel, management presently believes that disposition of these matters will not have a material adverse effect on the Company's results of operations.
9. BENEFIT PLANS:
Incentive Plan - The Company implemented two annual incentive plans and a long-term incentive plan effective January 1, 1995. The Executive Annual Incentive Plan and the Employee Incentive Plan tie a portion of each employee's compensation to achieving annual operational and financial goals. The plans share common goals designed to promote safety, control capital expenditures, control operation and maintenance expenses and increase annual earnings per share.
Restricted Stock Plan - The 1994 Restricted Stock Plan ("Plan") approved by shareholders at the May 1994 Annual Meeting was implemented January 1, 1995 as an equity-based long-term incentive plan. The performance-based grant approach and administrative guidelines for the Plan were developed by the Compensation Committee of the Board of Directors ("Committee") during 1994. The first grant under the Plan was made to all officers during January 1995. For the first grant, the Committee has selected a three-year restricted period beginning January 1, 1995, through December 31, 1997, with a single financial performance goal of Cumulative Earnings Per Share ("CEPS"). To receive a final share award, each officer must be employed by the Company, as an officer, during the entire restricted period, and the Company must achieve the CEPS performance goal established by the Committee.
Pension Plan - The Company maintains a trusteed noncontributory defined benefit pension plan for all employees who work 1,000 hours or more during a calendar year. The benefits under the plan are based on years of service and the employee's final average earnings. The Company's policy is to fund with an independent corporate trustee at least the minimum required under the Employee Retirement Income Security Act of 1974 but not more than the maximum amount deductible for income tax purposes. The Company funded $5.5 million in 1994, $5.0 million in 1993, and $5.1 million in 1992. The plan's assets held by the trustee consist primarily of listed stocks (both U.S. and foreign), fixed income securities and investment grade real estate.
Deferred Compensation Plan - The Company has a nonqualified, deferred compensation plan for certain senior management employees and directors that provides for supplemental retirement and death benefit payments to the participant and his or her family. The plan is being financed by life insurance policies, of which the Company is the beneficiary, with premiums being paid by the Company. These policies have accumulated cash values of $47.1 million and $42.4 million at December 31, 1994 and 1993, respectively, which do not qualify as plan assets in the actuarial computation of the funded status. Based upon SFAS No. 87, the Company has recorded a liability of $4.6 million as of December 31, 1994.
The following tables set forth the amounts recognized in the Company's financial statements and the funded status of both plans in accordance with accounting standard SFAS No. 87, "Employers' Accounting for Pensions."
Plan Costs for the Year 1994 1993 1992 (Thousands of Dollars)
Pension plan: Service cost $ 6,049 $ 4,496 $ 3,762 Interest cost 12,263 11,688 10,926 Actual return on plan assets 312 (23,322) (10,877) Deferred gain (loss) on plan assets (15,584) 9,848 (1,861)
Net cost $ 3,040 $ 2,710 $ 1,950 Approximate percentage included in operating expenses 67% 66% 64%
Net deferred compensation plan costs charged to other income (including life insurance and SFAS No. 87 liability accrual)(a) $ 508 $ 1,372 $ 1,276
(a) These charges to the Income Statement have been reduced by gains from the Company-Owned Life Insurance (COLI) of $2,724,000; $1,638,000; and $1,607,000 for 1994, 1993 and 1992, respectively.
Funded status and significant assumptions as of December 31:
Deferred Pension Plan Compensation Plan 1994 1993 1994 1993 (Thousands of Dollars)
Actuarial present value of benefit obligations: Vested benefit obligation $128,162 $134,292 $19,148 $24,024 Accumulated benefit obligation $132,766 $139,270 $19,148 $24,027
Projected benefit obligation $167,103 $179,895 $19,681 $30,114 Plan assets at fair value 165,839 169,920 - - Plan assets in excess of (or less than) projected benefit obligation (1,264) (9,975) (19,681) (30,114)
Unrecognized net (gain) loss from past experience different from that assumed 6,040 17,295 2,173 7,295
Unrecognized prior service cost 6,365 1,460 (3,516) 2,546
Unrecognized net (asset) obligation existing at date of initial adoption (19.5 year straight-line amortization) (2,756) (3,019) 6,440 7,053 Minimum liability adjustment - - (4,564) (10,807) Net asset (liability) included in the balance sheet $8,385 $5,761 $(19,148) $(24,027) Discount rate to compute projected benefit obligation 8.0% 7.0% 8.0% 7.0% Rate for future compensation increases 4.5 4.5 4.5 4.5 Expected long-term rate of return on plan assets 9.0 9.0 - -
Supplemental Employee Retirement Plan (SERP) - The Company has a nonqualified SERP that provides benefits in excess of Internal Revenue Service limits (Section 401 (a)(17) of the Internal Revenue Code) for highly paid individuals. The projected benefits obligation of this plan was $857,000 and $525,000 at December 31, 1994 and 1993, respectively, with accrued pension costs of $396,000 and $226,000. The Company's net periodic pension cost of this plan was $125,000 and $36,000 for the same periods.
Savings Plan _ The Company has an Employee Savings Plan whereby, for each $1 of employee contribution up to 6 percent of their salary the Company will match 100 percent of the first 2 percent employee contribution and 50 percent of the next 4 percent employee contribution, all such amounts to be invested by a trustee to any or all of seven investment options. The Company's contribution amounted to $2,410,200 in 1994, $2,283,200 in 1993 and $2,046,100 in 1992. As of December 31, 1994, a total of 4,214,735 Idaho Power Company common shares were held in this Plan.
Postretirement Benefits _ The Company maintains a defined benefit postretirement plan (consisting of health care and life insurance) that covers all employees who were enrolled in the active group plan at the time of retirement, their spouses and qualifying dependents. The plan provides for payment of hospital services, physician services, prescription drugs, dental services and various other health services, some of which have annual or lifetime limits, after subtracting payments by Medicare or other providers and after a stated deductible and co-payments have been met. Participants become eligible for the benefits if they retire from the Company after reaching age 55 with 15 years of service or after 30 years of service. The plan is contributory with retiree contributions adjusted annually. For those retirees that were age 65 or older at December 31, 1992 the plan is noncontributory. The Company also provides life insurance of one times salary for pre-65 retirees and $20,000 for post-65 retirees with the retirees paying a portion of the cost.
The Company adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" as of January 1, 1993. This new standard requires that the expected costs of postretirement benefits be charged to expense during the years that the employees render service. The Company has elected to amortize the transition obligation of $41.4 million that was measured as of January 1, 1993 over a period of 20 years and was approved by IPUC Order No. 25880.
The following tables set forth the amounts to be recognized in the Company's financial statements for year-end 1994 and 1993 and the funded status of the plan in accordance with accounting standard SFAS No. 106 as of December 31, 1993 and 1994.
December 31, 1994 December 31, 1993 (Thousands of Dollars) Postretirement Benefit Cost: Service cost $ 855 $ 750 Interest cost 3,334 3,610 Actual return on plan assets (1,114) (860) Amortization of transition obligation 2,040 2,040 Net amortization and deferral - - Regulatory asset (1,907) (3,548) Net cost (a) $ 3,208 $ 1,992
(a) Postretirement benefit costs charged to expense in 1992 was $2,622,300
December 31, 1994 December 31, 1993 (Thousands of Dollars) Funded Status: Accumulated postretirement benefit obligation (APBO) $(45,001) $(48,290) Plan assets at fair value 12,116 11,840 APBO in excess of plan assets (32,885) (36,450) Unrecognized gain/losses 773 4,670 Unrecognized transition obligation 36,720 38,760 Prepaid postretirement benefit cost $ 4,608 $ 6,980
Discount rate 8.25% 7.25% Medical and dental inflation rate 7.25 6.75 Long-term plan assets expected 9.0 9.0 return
A one percent change in the medical inflation rate would change the APBO by 7.3 percent and the postretirement expense for 1994 by 9.0 percent.
The Company has a retiree medical benefits funding program which consists of life insurance policies on active employees of which the Company is the beneficiary, and a qualified Voluntary Employees Beneficiary Association (VEBA) Trust. The net charge to other income for the life insurance policies was $776,400 in 1994, $632,500 in 1993, $1,733,000 in 1992. The funding to the VEBA was $743,600 in 1994, $2,692,000 in 1993, and $2,977,400 in 1992, and recorded as a prepayment. The VEBA trust represents plan assets which are invested in variable life insurance policies, Trust Owned Life Insurance (TOLI), on active employees. Inside buildup in the TOLI policies is tax deferred and tax free if the policy proceeds are paid to the Trust as death benefits. The investment return assumption reflects an expectation that investment income in the VEBA will be substantially tax free.
The IPUC issued an order approving the appropriateness of applying accrual accounting to postretirement benefit expense for ratemaking and revenue requirement purposes. The IPUC also approved the deferral of the difference between the accrual amount and the pay-as-you-go amount until the Company's next general rate case subject to an earnings test, but not to exceed two years or $6,000,000. The OPUC and the FERC have also approved accrual accounting to postretirement benefit expense for ratemaking, and FERC has approved the deferral of the difference between accrual and pay-as-you-go not to exceed three years. The FERC deferral of $545,400 was expensed in 1994. The remaining amount deferred, as a regulatory asset, at December 31, 1994 is $5.5 million. The Company received IPUC Order No. 25880 authorizing the amortization of the $5.5 million over a 10-year period.
Postemployment Benefits _ The Company provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement. The Company has recognized its portion of the cost of providing these benefits as an expense during the period in which the costs were incurred.
The Company adopted SFAS No. 112, "Employers' Accounting for Postemployment Benefits" as of January 1, 1993. The statement requires accrual of postemployment benefits. These benefits include salary continuation and related heath care and life insurance for both long and short-term disability plans, workmen's compensation and healthcare for surviving spouse and dependent plan. The adoption of SFAS 112 is a change of accounting principal; but since the Company is a regulated utility, a deferred asset was established which represents future revenue expected to be realized at the time the postemployment benefits are included in the Company's rates. The Company has recorded a liability and a regulatory asset of $4.0 million which represents the costs associated with postemployment benefits at December 31, 1994. The Company received IPUC Order No. 25880 authorizing the amortization of the regulatory asset over a 10- year period.
10. ELECTRIC PLANT IN SERVICE AND JOINTLY-OWNED PROJECTS:
The following table sets out the major classifications of the Company's electric plant in service and accumulated provision for depreciation for the years 1994, 1993, and 1992.
Electric Plant in Service 1994 1993 1992 (Thousands of Dollars)
Production $1,301,525 $1,199,188 $1,194,148 Transmission 310,102 328,249 324,222 Distribution 625,149 582,604 545,490 General and Other 147,122 139,682 134,887 Total In Service 2,383,898 2,249,723 2,198,747 Less accumulated provision for depreciation 775,033 728,979 683,332
In Service - Net $1,608,865 $1,520,744 $1,515,415
The Company is involved in the ownership and operation of three jointly-owned generating facilities. The Consolidated Statements of Income include the Company's proportionate share of direct operations and maintenance expenses applicable to the projects.
Each facility and extent of Company participation as of December 31, 1994 are as follows:
Company Ownership Electric Accumulated Plant In Provision For Name of Plant Location Service Depreciation % MW (Thousands of Dollars)
Jim Bridger Units 1-4 Rock Springs, WY $376,928 $150,599 33 693 Boardman Boardman, OR 59,488 24,112 10 53 Valmy Units 1 & 2 Winnemucca, NV 299,865 98,030 50 261
The Company's wholly-owned subsidiary, IERCO, is a joint venturer in Bridger Coal Company, which operates the mine supplying coal for the Jim Bridger steam generation plant. Coal purchased by the Company from the joint venture amounted to $46,097,000 in 1994, $45,424,000 in 1993 and $42,291,000 in 1992.
The Company has contracts to purchase the energy from five PURPA Qualified Facilities which are 50 percent owned by Ida-West. Power purchased from these facilities amounted to $7,139,000 in 1994, $5,975,093 in 1993 and $1,848,904 in 1992.
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareowners Idaho Power Company Boise, Idaho
We have audited the accompanying consolidated financial statements of Idaho Power Company and its subsidiaries listed in the accompanying index to financial statements and financial statement schedules at Item 8. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the consolidated financial position of Idaho Power Company and subsidiaries at December 31, 1994, 1993 and 1992, and the results of their operations and their cash flows for the years then ended, in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Notes 2 and 9 to the consolidated financial statements, the Company changed its method of accounting for income taxes and postretirement benefits in the year ended December 31, 1993.
DELOITTE & TOUCHE LLP
Portland, Oregon January 31, 1995
IDAHO POWER COMPANY SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED
QUARTERLY FINANCIAL DATA:
The following unaudited information is presented for each quarter of 1994, 1993 and 1992 (in thousands of dollars, except for per share amounts). In the opinion of the Company, all adjustments necessary for a fair statement of such amounts for such periods have been included. The results of operation for the interim periods are not necessarily indicative of the results to be expected for the full year. Accordingly, earnings information for any three month period should not be considered as a basis for estimating operating results for a full fiscal year. Amounts are based upon quarterly statements and the sum of the quarters may not equal the annual amount reported.
Quarter Ended March 31 June 30 September 30 December 31 Revenues $128,810 $128,541 $151,031 $135,277 Income from operations 37,408 33,984 33,609 44,663 Income taxes 9,406 6,554 8,150 10,133 Net income 18,260 17,030 16,289 23,351 Dividends on preferred stock 1,789 1,819 1,862 1,928 Earnings on common stock 16,471 15,211 14,427 21,423 Earnings per share of common 0.44 0.41 0.38 0.57 stock
Revenues 140,809 129,471 134,577 135,545 Income from operations 41,479 38,980 34,286 47,201 Income taxes 10,610 9,270 9,108 7,486 Net income 21,347 18,524 16,427 28,166 Dividends on preferred stock 1,345 1,318 1,565 1,781 Earnings on common stock 20,002 17,206 14,862 26,385 Earnings per share of common stock 0.55 0.47 0.40 0.71
Revenues 114,453 124,656 129,050 129,934 Income from operations 31,024 30,376 29,593 33,962 Income taxes 7,396 6,670 4,353 4,743 Net income 13,378 12,394 15,067 19,152 Dividends on preferred stock 1,424 1,400 1,346 1,347 Earnings on common stock 11,954 10,994 13,721 17,805 Earnings per share of common stock 0.35 0.32 0.38 0.49
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
Part III has been omitted because the registrant will file a definitive proxy statement pursuant to Regulation 14A, which involves the election of Directors, with the Commission within 120 days after the close of the fiscal year portions of which are hereby incorporated by reference (except for information with respect to executive officers which is set forth in Part I hereof).
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K
(a) Please refer to Item 8, "Financial Statements and Supplementary Data" for a complete listing of all consolidated financial statements and financial statement schedule.
(b) Reports on SEC Form 8-K. No reports on Form 8-K were filed during the three months ended December 31, 1994.
(c) Exhibits.
* Previously Filed and Incorporated Herein by Reference
File As Exhibit Number Exhibit
*3(a) 33-00440 4(a)(xiii) Restated Articles of Incorporation of the Company as filed with the Secretary of State of Idaho on June 30, 1989.
*3(a)(i) 33-65720 4(a)(i) Statement of Resolution Establishing Terms of 8.375% Serial Preferred Stock, Without Par Value (cumulative stated value of $100 per share), as filed with the Secretary of State of Idaho on September 23, 1991.
*3(a)(ii) 33-65720 4(a)(ii) Statement of Resolution Establishing Terms of Flexible Auction Series A, Serial Preferred Stock, Without Par Value (cumulative stated value of $100,000 per share), as filed with the Secretary of State of Idaho on November 5, 1991. *3(a)(iii) 33-65720 4(a)(iii) Statement of Resolution Establishing Terms of 7.07% Serial Preferred Stock, Without Par Value (cumulative stated value of $100 per share), as filed with the Secretary of State of Idaho on June 30, 1993.
*3(b) 33-41166 4(b) Waiver resolution to Restated Articles of Incorporation adopted by Shareholders on May 1, 1991.
*3(c) 33-00440 4(a)(xiv) By-laws of the Company amended on June 30, 1989, and presently in effect.
*4(a)(i) 2-3413 B-2 Mortgage and Deed of Trust, dated as of October 1, 1937, between the Company and Bankers Trust Company and R. G. Page, as Trustees.
*4(a)(ii) Supplemental Indentures to Mortgage and Deed of Trust:
Number Dated
1-MD B-2-a First July 1, 1939 2-5395 7-a-3 Second November 15, 1943 2-7237 7-a-4 Third February 1, 1947 2-7502 7-a-5 Fourth May 1, 1948 2-8398 7-a-6 Fifth November 1, 1949 2-8973 7-a-7 Sixth October 1, 1951 2-12941 2-C-8 Seventh January 1, 1957 2-13688 4-J Eighth July 15, 1957 2-13689 4-K Ninth November 15, 1957 2-14245 4-L Tenth April 1, 1958 2-14366 2-L Eleventh October 15, 1958 2-14935 4-N Twelfth May 15, 1959 2-18976 4-O Thirteenth November 15, 1960 2-18977 4-Q Fourteenth November 1, 1961 2-22988 4-B-16 Fifteenth September 15, 1964 2-24578 4-B-17 Sixteenth April 1, 1966 2-25479 4-B-18 Seventeenth October 1, 1966 2-45260 2(c) Eighteenth September 1, 1972 2-49854 2(c) Nineteenth January 15, 1974 2-51722 2(c)(i) Twentieth August 1, 1974 Number Dated 2-51722 2(c)(ii) Twenty-first October 15, 1974 2-57374 2(c) Twenty-second November 15, 1976 2-62035 2(c) Twenty-third August 15, 1978 33-34222 4(d)(iii) Twenty-fourth September 1, 1979 33-34222 4(d)(iv) Twenty-fifth November 1, 1981 33-34222 4(d)(v) Twenty-sixth May 1, 1982 33-34222 4(d)(vi) Twenty-seventh May 1, 1986 33-00440 4(c)(iv) Twenty-eighth June 30, 1989 33-34222 4(d)(vii) Twenty-ninth January 1, 1990 33-65720 4(d)(iii) Thirtieth January 1, 1991 33-65720 4(d)(iv) Thirty-first August 15, 1991 33-65720 4(d)(v) Thirty-second March 15, 1992 33-65720 4(d)(vi) Thirty-third April 16, 1993 1-3198 4 Thirty-fourth December 1, 1993 Form 8-K Dated 12/17/93
*4(b) Instruments relating to American Falls bond guarantee. (see Exhibits 10(f) and 10(f)(i)).
*4(c) 33-65720 4(f) Agreement to furnish certain debt instruments.
*4(d) 33-00440 2(a)(iii) Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine Corporation, and Idaho Power Migrating Corporation.
*4(e) 33-65720 4(e) Rights Agreement dated January 11, 1990, between the Company and First Chicago Trust Company of New York, as Rights Agent (The Bank of New York, successor Rights Agent).
*10(a) 2-51762 5(a) Agreement, dated April 20, 1973, between the Company and FMC Corporation.
*10(a)(i) 2-57374 5(b) Letter Agreement, dated October 22, 1975, relating to agreement filed as Exhibit 10(a).
*10(a)(ii) 2-62034 5(b)(i) Letter Agreement, dated December 22, 1976, relating to agreement filed as Exhibit 10(a).
*10(a)(iii) 33-65720 10(a) Letter Agreement, dated December 11, 1981, relating to agreement filed as Exhibit 10(a).
*10(b) 2-49584 5(b) Agreements, dated September 22, 1969, between the Company and Pacific Power & Light Company relating to the operation, construction and ownership of the Jim Bridger Project.
*10(b)(i) 2-51762 5(c) Amendment, dated February 1, 1974, relating to operation agreement filed as Exhibit 10(b).
*10(c) 2-49584 5(c) Agreement, dated as of October 11, 1973, between the Company and Pacific Power & Light Company.
*10(d) 2-49584 5(d) Agreement, dated as of October 24, 1973, between the Company and Utah Power & Light Company.
*10(d)(i) 2-62034 5(f)(i) Amendment, dated January 25, 1978, relating to agreement filed as Exhibit 10(d).
*10(e) 33-65720 10(b) Coal Purchase Contract, dated as of June 19, 1986, among the Company, Sierra Pacific Power Company and Black Butte Coal Company.
*10(f) 2-57374 5(k) Contract, dated March 31, 1976, between the United States of America and American Falls Reservoir District, and related Exhibits.
*10(f)(i) 33-65720 10(c) Guaranty Agreement, dated March 1, 1990, between the Company and West One Bank, as Trustee, relating to $21,425,000 American Falls Replacement Dam Bonds of the American Falls Reservoir District, Idaho.
*10(g) 2-57374 5(m) Agreement, effective April 15, 1975, between the Company and The Washington Water Power Company.
*10(h) 2-62034 5(p) Bridger Coal Company Agreement, dated February 1, 1974, between Pacific Minerals, Inc., and Idaho Energy Resources Co.
*10(i) 2-62034 5(q) Coal Sales Agreement, dated February 1, 1974, between Bridger Coal Company and Pacific Power & Light Company and the Company.
*10(i)(i) 33-65720 10(d) Second Restated and Amended Coal Sales Agreement, dated March 7, 1988, among Bridger Coal Company and PacifiCorp (dba Pacific Power & Light Company) and the Company.
*10(j) 2-62034 5(r) Guaranty Agreement, dated as of August 30, 1974, with Pacific Power & Light Company.
*10(k) 2-56513 5(i) Letter Agreement, dated January 23, 1976, between the Company and Portland General Electric Company.
*10(k)(i) 2-62034 5(s) Agreement for Construction, Ownership and Operation of the Number One Boardman Station on Carty Reservoir, dated as of October 15, 1976, between Portland General Electric Company and the Company.
*10(k)(ii) 2-62034 5(t) Amendment, dated September 30, 1977, relating to agreement filed as Exhibit 10(k).
*10(k)(iii) 2-62034 5(u) Amendment, dated October 31, 1977, relating to agreement filed as Exhibit 10(k).
*10(k)(iv) 2-62034 5(v) Amendment, dated January 23, 1978, relating to agreement filed as Exhibit 10(k).
*10(k)(v) 2-62034 5(w) Amendment, dated February 15, 1978, relating to agreement filed as Exhibit 10(k).
*10(k)(vi) 2-68574 5(x) Amendment, dated September 1, 1979, relating to agreement filed as Exhibit 10(k).
*10(l) 2-68574 5(z) Participation Agreement, dated September 1, 1979, relating to the sale and leaseback of coal handling facilities at the Number One Boardman Station on Carty Reservoir.
*10(m) 2-64910 5(y) Agreements for the Operation, Construction and Ownership of the North Valmy Power Plant Project, dated December 12, 1978, between Sierra Pacific Power Company and the Company.
10(n)(i)1 The Revised Security Plans for Senior Management Employees and for Directors-a non-qualified, deferred compensation plan effective November 30, 1994.
10(n)(ii)1 The Executive Annual Incentive Plan for senior management employees effective January 1, 1995.
10(n)(iii)1 The 1994 Restricted Stock Plan for officers and key executives effective July 1, 1994.
*10(o) 33-65720 10(f) Residential Purchase and Sale Agreement, dated August 22, 1981, among the United Stated of America Department of Energy acting by and through the Bonneville Power Administration, and the Company.
*10(p) 33-65720 10(g) Power Sales Contact, dated August 25, 1981, including amendments, among the United States of America Department of Energy acting by and through the Bonneville Power Administration, and the Company.
*10(q) 33-65720 10(h) Framework Agreement, dated October 1, 1984, between the State of Idaho and the Company relating to the Company's Swan Falls and Snake River water rights.
*10(q)(i) 33-65720 10(h)(i) Agreement, dated October 25, 1984, between the State of Idaho and the Company relating to the agreement filed as Exhibit 10(q).
*10(q)(ii) 33-65720 10(h)(ii) Contract to Implement, dated October 25, 1984, between the State of Idaho and the Company relating to the agreement filed as Exhibit 10(q). ___________________ 1 Compensatory Plan
*10(r) 33-65720 10(i) Agreement for Supply of Power and Energy, dated February 10, 1988, between the Utah Associated Municipal Power Systems and the Company.
*10(s) 33-65720 10(j) Agreement Respecting Transmission Facilities and Services, dated March 21, 1988 among PC/UP&L Merging Corp. and the Company including a Settlement Agreement between PacifiCorp and the Company.
*10(s)(i) 33-65720 10(j)(i) Restated Transmission Services Agreement, dated February 6, 1992, between Idaho Power Company and PacifiCorp. *10(t) 33-65720 10(k) Agreement for Supply of Power and Energy, dated February 23, 1989, between Sierra Pacific Power Company and the Company.
*10(u) 33-65720 10(l) Transmission Services Agreement, dated May 18, 1989, between the Company and the Bonneville Power Administration.
*10(v) 33-65720 10(m) Agreement Regarding the Ownership, Construction, Operation and Maintenance of the Milner Hydroelectric Project (FERC No. 2899), dated January 22, 1990, between the Company and the Twin Falls Canal Company and the Northside Canal Company Limited.
*10(v)(i) 33-65720 10(m)(i) Guaranty Agreement, dated February 10, 1992, between the Company and New York Life Insurance Company, as Note Purchaser, relating to $11,700,000 Guaranteed Notes due 2017 of Milner Dam Inc.
*10(w) 33-65720 10(n) Agreement for the Purchase and Sale of Power and Energy, dated October 16, 1990, between the Company and The Montana Power Company.
12 Statement Re: Computation of Ratio of Earnings to Fixed Charges.
12(a) Statement Re: Computation of Supplemental Ratio of Earnings to Fixed Charges.
12(b) Statement Re: Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements.
12(c) Statement Re: Computation of Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements.
21 Subsidiaries of Registrant.
23 Independent Auditors' Consent.
27 Financial Data Schedule
IDAHO POWER COMPANY SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1994, 1993 and 1992
Column C Column A Column B Additions Column D Column E
Balance Charged Charged Balance At to (Credited) At Classification Beginning Income to Other Deductions End Of Of Period Accounts (1) Period (Thousands of Dollars)
1994: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $1,377 $1,360 $1,018(2) $2,378 $1,377 Other Reserves: Injuries and damages reserve $1,500 $1,804 $ - $1,804 $1,500 Miscellaneous operating reserves $ 748 $ 429 $ (156) $ 81 $ 940
1993: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $1,421 $1,174 $1,001(2) $2,219 $1,377 Other Reserves: Injuries and damages reserve $1,500 $2,820 $ - $2,820 $1,500 Miscellaneous operating reserves $ - $ 870 $ 332 $ 454 $ 748
1992: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $1,300 $1,224 $ 963(2) $2,066 $1,421 Other Reserves: Injuries and damages reserve $1,366 $2,468 $ - $2,334 $1,500
NOTES: (1) Represents deductions from the reserves for purposes for which the reserves were created. (2) Represents collections of accounts previously written off.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
IDAHO POWER COMPANY (Registrant)
March 9, 1995 By:__/s/___ Joseph W. Marshall_______ Joseph W. Marshall Chairman of the Board and Chief Executive Officer and Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this report is signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
By:__/s/_Joseph W. Marshall____Chairman of the Board and March 9, 1995 Joseph W. Marshall Chief Executive Officer and Director
By:__/s/ Larry R. Gunnoe ______President and Chief Operating " Larry R. Gunnoe Officer and Director
By:__/s/_ J. LaMont Keen ______Vice President and Chief Financial " J. LaMont Keen Officer (Principal Financial Officer)
By:__/s/_ Harold J. Hochhalter__Controller and Chief Accounting Officer " Harold J. Hochhalter (Principal Accounting Officer)
By:__/s/_ Robert D. Bolinder __ By:__/s/_ Evelyn Loveless ______ " Robert D. Bolinder Evelyn Loveless Director Director
By:__/s/_ __ By:__/s/__Jon H. Miller ________ " Roger L. Breezley Jon H. Miller Director Director
By:__/s/_ John B. Carley_______ By:__/s/__Peter S. O'Neill ______ " John B. Carley Peter S. O'Neill Director Director
By:__/s/__Peter T. Johnson_____ By:__/s/__Gene C. Rose _______ " Peter T. Johnson Gene C. Rose Director Director
By:__/s/__Jack K. Lemley_____ By:__/s/__Phil Soulen _______ " Jack K. Lemley Phil Soulen Director Director
EXHIBIT INDEX
Exhibit Page Number Number
10(n)(i) The Revised Security Plans for Senior 93 Management Employees and for Directors- a non-qualified, deferred compensation plan effective November 30, 1994.
10(n)(ii) The Executive Annual Incentive Plan for 126 senior management employees effective January 1, 1995.
10(n)(iii) The 1994 Restricted Stock Plan for 128 officers and key executives effective July 1, 1994.
12 Statement Re: Computation of Ratio of 133 Earnings to Fixed Charges.
12(a) Statement Re: Computation of 134 Supplemental Ratio of Earnings to Fixed Charges.
12(b) Statement Re: Computation of Ratio of 135 Earnings to Combined Fixed Charges and Preferred Dividend Requirements.
12(c) Statement Re: Computation of 136 Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements.
21 Subsidiaries of Registrant. 137
23 Independent Auditors' Consent. 138
27 Financial Data Schedule 139