ITEM 1. BUSINESS

Sierra Pacific Power Company, hereinafter known as the Company or SPPC, is a Nevada corporation which was organized in 1965, as a successor to a Maine corporation organized in 1912. The Company became a wholly-owned subsidiary of Sierra Pacific Resources (SPR) on May 31, 1984. Its mailing address is Post Office Box 10100 (6100 Neil Road), Reno, Nevada 89520-0400.

The Company has three primary subsidiaries: Pinon Pine Corp. (PPC), Pinon Pine Investment Co. (PPIC) and Sierra Pacific Power Capital I (the Trust). The Company, through PPC and PPIC, owns a 38% interest in the Pinon Pine Co., LLC (The LLC) with a subsidiary of General Electric Capital Corporation owning the remaining 62%.

The Company is a public utility primarily engaged in the generation, purchase, transmission, distribution and sale of electric energy. It provides electricity to approximately 278,000 customers in a 50,000 square mile service area including western, central and northeastern parts of Nevada, including the cities of Reno, Sparks, Carson City and Elko and a portion of eastern California, including the Lake Tahoe area. In 1996 electric revenue was 82% of total revenue.

The Company used diverse resources to meet its 1996 electric energy requirements, including gas and oil generation (34.2%), coal generation (20.2%), hydroelectric generation (.6%), and purchased power (45.0%). The Company has no ownership interest in, nor does it operate, any nuclear generating units.

The Company also provides natural gas in Nevada to approximately 95,000 customers in an area of about 600 square miles in Reno/Sparks and environs. It supplies water service in Nevada to about 63,000 customers in the Reno/Sparks metropolitan area. Natural gas revenues were 11% and water revenues were 7% of total revenues.

In 1996 the Company's electric customers grew 2.8%; its natural gas customers increased by 4.4%; and its water customers were up 2.7%. Many factors account for this growth, not the least of which are favorable business and tax climates.

The Company's workforce numbered 1,491 regular employees as of December 31, 1996, down 2.3% from 1995. Of that number, 21 were considered part-time. In addition, the Company had 44 temporary employees. The Company's current contract with the International Brotherhood of Electrical Workers, which represents 61% of the workforce, is in effect until December 31, 1997. The three-year contract provides for a 2.5% general wage increase for all bargaining unit employees beginning January 1, 1995, with 3% increases in both 1996 and 1997. Negotiations on the renewal of the contract will begin in 1997. Nevada is a "right-to-work" state.

                               1996                1995                1994
                         -----------------    ----------------   -----------------
Operating Revenues
  Electric               $  507,004  (82%)    $ 491,419  (82%)    $ 498,680  (83%)
  Gas                        67,376  (11%)       62,572  (11%)       65,174  (11%)
  Water                      45,344   (7%)       43,793   (7%)       39,339   (6%)
                         ---------------      --------------      --------------
                         $  619,724 (100%)    $ 597,784 (100%)    $ 603,193 (100%)
                         ===============      ==============      ==============
Operating Income
  Electric               $   86,428  (81%)    $  87,825  (86%)    $  81,641  (85%)
  Gas                        11,035  (10%)        5,041   (5%)        5,806   (6%)
  Water                       9,545   (9%)        8,945   (9%)        8,536   (9%)
                         ---------------      --------------      --------------
                         $  107,008 (100%)    $ 101,811 (100%)    $  95,983 (100%)
                         ===============      ==============      ==============
Identifiable Assets
  Electric               $1,324,579   (7%)    $1,222,518  (7%)    $1,144,490 (78%)
  Gas                       117,697   (7%)       109,872  (7%)       106,951  (7%)
  Water                     268,813  (16%)       246,031 (16%)       223,248 (15%)
                         ---------------      --------------      --------------
                         $1,711,089 (100%)    $1,578,421(100%)    $1,474,689(100%)
                         ===============      ==============      ==============

For a discussion of results of operations refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

The economy in the Company's service area is growing and benefits from Nevada's freeport law that promotes the warehouse industry and the processing of goods in transit, primarily to markets in California. Nevada has no corporate, personal, unitary, inventory or income taxes. Permanent residents are attracted to the quality of life found in the area and the absence of personal income tax. Additionally, Reno/Sparks and Lake Tahoe provide leisure-time diversions, including skiing, golf, water sports, camping, casino gaming and big name entertainment that appeal to residents and tourists alike. The combination of tax advantages, supportive government, location and lifestyle make Nevada an attractive site for businesses.

Also contributing to the growth in the service area are Nevada's mineral resources, which support a mining industry that continues to contribute significantly to the area's economy and remains the Company's second largest source of revenue after residential sales. In 1996, mining represented 15% of the Company's electric revenue and 24.5% of total electric megawatt-hour (MWH) sales. The outlook for 1997 forecasts that electric sales to mines may account for 27% of total retail electric MWH sales and 21% of total electric revenue.

The Company's electric, natural gas and water business segments are all, to varying degrees, dependent on weather conditions. Extreme or prolonged variations from historical weather patterns could adversely affect sales in one or more of these business segments.

(1) WHEN USED ANYWHERE IN THIS FORM 10-K AND IN FUTURE FILINGS BY THE COMPANY WITH THE SECURITIES AND EXCHANGE COMMISSION, IN THE COMPANY'S PRESS RELEASES AND IN ORAL STATEMENTS MADE WITH THE APPROVAL OF AN AUTHORIZED EXECUTIVE OFFICER, THE WORDS OR PHRASES "WILL LIKELY RESULT", "ARE EXPECTED TO", "WILL CONTINUE", "IS ANTICIPATED", "ESTIMATED", "PROJECT", OR "OUTLOOK" OR SIMILAR EXPRESSIONS ARE INTENDED TO IDENTIFY "FORWARD- LOOKING STATEMENTS" WITHIN THE MEANING OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995. SUCH STATEMENTS ARE SUBJECT TO CERTAIN RISKS AND UNCERTAINTIES THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM HISTORICAL EARNINGS AND THOSE PRESENTLY ANTICIPATED OR PROJECTED. THE COMPANY WISHES TO CAUTION READERS NOT TO PLACE UNDUE RELIANCE ON ANY SUCH FORWARD-LOOKING STATEMENTS, WHICH SPEAK ONLY AS OF THE DATE MADE. THE COMPANY WISHES TO ADVISE READERS THAT VARIOUS FACTORS DESCRIBED IN THIS FORM 10-K COULD CAUSE THE COMPANY'S ACTUAL RESULTS FOR FUTURE PERIODS TO DIFFER MATERIALLY FROM ANY OPINIONS OR STATEMENTS EXPRESSED WITH RESPECT TO FUTURE PERIODS IN ANY CURRENT STATEMENTS. THE COMPANY SPECIFICALLY DECLINES ANY OBLIGATION TO PUBLICLY RELEASE THE RESULT OF ANY REVISIONS WHICH MAY BE MADE TO ANY FORWARD-LOOKING STATEMENTS TO REFLECT EVENTS OR CIRCUMSTANCES AFTER THE DATE OF SUCH STATEMENTS OR TO REFLECT THE OCCURRENCE OF ANTICIPATED OR UNANTICIPATED EVENTS.

There are many different views concerning the electric utility industry and the changes it is experiencing now and will face in the future. Some changes will be regulatory and others may be legislative.

To meet the challenges such changes bring to the industry, the Company has down-sized and reorganized to cut costs, better serve its customers and prepare for competition. The Company also has negotiated long-term contracts with six of its largest mining customers.

Nevada electric prices were last increased in 1993, and were subsequently reduced in March 1995, following suspension of deferred energy accounting rules. Natural gas prices were last increased in April 1994, and the last increase in water prices occurred in September 1994.

The Company currently has frozen its Nevada electric and natural gas rates until December 31, 1999 and electric rates in California until December 31, 2000. A recent rate plan in Nevada also provides a 50/50 sharing between customers and shareholders of electric and natural gas earnings in excess of a 12 percent return on equity. The plan also provides the opportunity for the Company, subject to certain conditions, to apply such excess to buying down, or buying out of, higher cost long-term fuel and purchased power contracts. This may reduce future costs in what the Company expects will be a more competitive environment.

The Company continues to be the sole provider in its certificated service territories, however, the Company will continue to closely monitor the changes, both locally and nationally, to prepare for competition.

SPR's investment in the transmission pipeline business will continue to provide competitive alternatives and greater reliability to new and expanding markets along its routes in Northern California and Nevada. It also provides competitive alternatives for delivery of natural gas used as fuel for the Company's power generation.

Like most other companies in the world, SPPC is facing the Year 2000 problems. The Company plans to have its problem resolved by December 31, 1998.

In June 1994, the Company, SPR, and The Washington Water Power Company (WWP) entered into a Merger Agreement which provided for the merger of the parties into an entity named Resources West Energy Corporation. (That name was later changed to Altus Corporation). Under the terms of the Merger Agreement, if the merger was not consummated on or before June 27, 1996, either party, by providing written notice to the other, could terminate the Merger Agreement provided that party was not then in breach of any obligation

under the Agreement which caused or resulted in the failure of the Merger Agreement to be consummated by that date.

On June 28, 1996, WWP provided written notice to the Company and SPR that it was terminating the Merger Agreement. Since that time, petitions to withdraw merger applications have been filed by one or more parties in all jurisdictions having approval jurisdiction over the merger.

As a result of the termination of the merger, the Company plans to continue to operate as a separate utility and as a wholly-owned subsidiary of Sierra Pacific Resources.

As a result of the termination of the merger certain filings were made in various regulatory jurisdictions. See Note 2 of the Company's consolidated financial statements.

The Company's electric business contributed $507 million (81.8%) of 1996 operating revenues. Typically the electric business peaks both in summer and winter. The system has an annual load factor of approximately 75%, which is higher than the industry norm.

Winter peak loads are due to shorter daylight hours, colder temperatures (which affect space heating requirements) and ski resort demands (snow-making, lifts, etc.). Summer peak loads result from air-conditioning, cooling equipment and irrigation pumping. The Company's peak load increased an average of four percent annually over the past five years, reaching 1,225 megawatts (MW) on July 22, 1996. The Company's electric MWH sales have increased an average of four percent annually over the past five years.

A significant part of the growth in the Company's electric sales has resulted from growth in the gold mining and gaming industries in northern Nevada. Adverse developments with respect to either industry, or the loss of large individual customers, through closure or use of competing providers, could have a negative impact on the Company's electric sales.

The Company's electric customers by class contributed the following percentages toward 1996 megawatt-hour sales:

                                   MWH SALES
                                   ----------
Residential                          25.4%
Commercial and Industrial:
   Mining                            24.5%
   All Other                         38.5%
Wholesale                            10.0%
Miscellaneous                         1.6%
                                    -----

                    Total           100.0%
                                    =====

Nevada leads the nation in gold production. The majority of Nevada gold mines are located within the Company's service area. Nevada gold production for 1996 is estimated at about 7 million ounces, representing about 67% of U.S. and 9% of the world's production, respectively. The Nevada Bureau of Mines and Geology at the University of Nevada, Reno, has estimated that current Nevada gold reserves are sufficient to sustain substantial levels of production for 20 to 30 years, assuming stable prices.

During the last quarter of 1996, world gold prices fell from about $385 per ounce to approximately $360 per ounce at year-end. Production costs vary widely at Nevada mines. Mining industry reports indicate a high percentage of Nevada gold is produced at a production cost of less than $300 per ounce, with larger mines producing within the range of $175 to $210 per ounce. Should gold prices remain in the mid $300 per ounce range or fall further, reductions in new capital spending and exploration could occur.

The Company has negotiated and signed six long-term power sales contracts with major mining customers. Five have been reviewed and approved by the Nevada Commission with one additional contract pending approval as part of an overall Commission review of a new rate tariff designed for major customers above 3 MW. The Company is currently in negotiations and pursuing a total of four additional contracts. These mining contracts represent over 250 megawatts of present and future mining load, or approximately $86 million in annual revenue. They are based upon customers attaining minimum annual demand and load factors, and require minimum annual bills. Termination charge provisions include recovery of all costs for customer-specific facilities and, for the first five years under the contract, recovery of two years of minimum bills. The loss of any one of these contracts would not have a material adverse effect on the Company.

The resorts and recreation group is comprised of hotels, casinos, and ski resorts. The resorts and recreation market segment comprises 10.7 percent of total electric system sales. Several of these large customers have finished or are in the finishing stages of major expansions in 1996.

Over the past five years, MWH sales to wholesale customers have increased at a compounded rate of 19%. During 1996, firm and non-firm sales to wholesale customers comprised about 8% of total energy sales. The wholesale market is very competitive and sales into this market are typically made at very low margins.

                                               Percent
                                (MWH)          of Total
                               --------        --------
Firm Sales                     333,201           50.0%
Non-firm Sales                 228,416           34.3%
Firm Off-System Sales           88,649           13.3%
Non-firm Off-System Sales       16,325            2.4%
                               -------          -----
Total                          666,591          100.0%
                               =======          =====

The Company's industrial and large commercial customers continue their interest in the electric supply source options potentially available to them under regulatory reforms currently being considered in California and Nevada. The Company continues to prepare for a more competitive environment and has actively participated in regulatory reform deliberations in Nevada and California, and in federal proceedings. See Item 7, Nevada Matters, California

                                                     --------------  ----------
Matters, and FERC Matters.
- -------      ------------


Electric Integrated Resource Planning
- -------------------------------------

In August 1992, the Company executed a cooperative agreement with the U.S. Department of Energy (DOE) for the construction of a coal-gasification power plant. The project, known as the Pinon Pine Power Project (Pinon) was selected by the DOE for funding under the fourth round of the Federal Clean Coal Technology Program. This clean coal integrated gasification combined-cycle power plant will be fully capable of operating on syngas produced from coal, natural gas, and, potentially, other fuels. The project consists of a coal gasification facility (including solids receipt, handling, preparation and storage), and a Company-owned power island and post gasification facilities to partially cool and clean the syngas produced by the gasifier. The current rating is 106 megawatts in the winter and 89 megawatts in the summer. The DOE is providing funding for approximately 50% of the construction cost and half of the operating and fuel expenses for the first 42 months of operation. The DOE has committed $168 million of funding for Pinon. Estimated construction start- up and commissioning costs for Pinon, including the DOE's portion are approximately $272.4 million, which includes permitting, taxes, start-up commissioning, operator training and AFUDC. Expected DOE funding for construction is $125.6 million. The Company and Foster Wheeler USA Corp., the architect, engineer and construction manager on the project are currently investigating the reasons for, exact nature and extent of, and responsibility for cost increases on the entire Pinon project. The Company's cost per kilowatt of capacity net of DOE construction and prior to the sale of the gasifier is $1,390 based on the peak winter rating and $1,640 based on the summer rating.

Construction began on the project in February 1995, following resource plan approval and the receipt of all permits and other approvals. Engineering,

procurement and construction activities are under way, with the gas and steam portion (combined cycle) satisfactorily completed and placed in service December 1, 1996. The balance of the plant will be in service by mid-1997.

Pinon Pine Co. and Pinon Pine Investment Co., subsidiaries of the Company, own 25% and 75%, respectively, of a 38% interest in The LLC with a subsidiary of General Electric Capital Corporation (GECC) holding a 62% interest. The LLC was formed to take advantage of federal income tax credits associated with the alternative fuel (syngas) produced by the coal gasifier and available under
Section 29 of the Internal Revenue Code.

The Company is under contract to build and operate the gasifier portion of the facility for Pinon Pine Co., LLC. The Company has also agreed to purchase from The LLC the syngas produced in the gasifier for use in the Company-owned power island. These contracts are contingent upon the gasifier meeting the necessary requirements to be eligible for the (S) 29 credits. The contracts also contain performance warranties which require the Company to make specified payments to, or to purchase the gasifier from, the LLC under certain conditions. See Note 5 of the Company's consolidated financial statements.

The planned 345 KV line will originate at the Bonneville Power Administration transmission line west of the northeastern California town of Alturas. It will extend south 165 miles to an existing Company substation in Reno. In January 1996, the California Commission certified the final Environmental Impact Report/Statement (EIR/S) prepared for the project and granted the Company a Certificate of Public Convenience and Necessity which recognizes the need for and benefit of the project. To date, the Company has spent $68.6 million on the project.

In February 1996, the lead federal agency, the Bureau of Land Management (BLM) issued a positive Record of Decision for the project approving the issuance of a right-of-way grant for approximately 70 miles of BLM land and confirming that the EIR/S for the project meets the requirements of the National Environmental Protection Act. Final Records of Decision have not yet been heard by the Modoc National Forest or the Humboldt-Toiyabe National Forest. The Company is continuing to work with the Modoc National Forest in California to resolve outstanding environmental issues under their jurisdiction.

The Company and the Humboldt-Toiyabe National Forest (HTNF) were unable to reach agreement with respect to the route for the line on HTNF lands. Additionally, the Truckee Meadows Regional Planning Commission, citing land use conflicts, failed to find the project in conformance with the regional plan.

To address these issues the Company has modified the southern portion of the line in Washoe County and withdrawn its application with the HTNF. This partial reroute has increased project costs by $15 million to approximately $135 million including AFUDC. This additional cost includes right-of-way ($3.5 million), transmission facilities ($3.5 million), additional environmental matters ($3.0 million) and AFUDC ($5.0 million).

The Company is working to conclude the permitting process and begin construction in late summer 1997, assuming all required permits are obtained. When operational, the project is expected to provide greater system reliability and an additional route to bring in hydro-electricity from the Pacific Northwest. If the Company is unable to meet the expected load forecast as a result of the absence, or extended delay in completion of the intertie an alternative would be the construction of generation within our control area.

As of December 31, 1996 the Company's electric transmission facilities consisted of approximately 3,800 overhead pole line miles and 80 substations. Its distribution facilities consisted of approximately 9,200 overhead pole line miles, 4,300 underground cable miles and 176 substations.

The Company continues to maintain a wide variety of resources in its generation system. During 1996 the Company generated 55% of its total electric energy requirements in its own plants, purchasing the remaining 45% as shown below:

                                                 Percent
                               Megawatt-Hours    of Total
                               --------------    --------
Company Generation
- ------------------
   Gas/Oil                          2,899,100       34.2
   Coal                             1,714,697       20.2
   Hydro                               54,801        0.6
                                    ---------      -----
Total Generated                     4,668,598       55.0
                                    ---------      -----

Purchased Power
- ---------------
   Long-Term Firm:
     Utility Purchases              1,820,790       21.5
     Non-Utility Purchases:
       Geothermal                     766,831        9.0
       Other                          134,309        1.6
   Spot Market                      1,090,909       12.9
                                    ---------      -----
          Total Purchased           3,812,839       45.0
                                    ---------      -----

                   Total            8,481,437      100.0
                                    =========      =====

Despite an increase in natural gas prices during 1996 over the lower 1995 level, generation from the Company's gas/oil-fired units made up the largest percentage of total output at 34.2%.

The Company's decision to purchase spot market energy is based on the economics of purchasing "as-available" energy when it is less expensive than the Company's own generation. At the time of the 1996 system peak, the Company had purchased firm capacity under long-term contracts with other utilities and qualifying facilities (QFs) equal to 23.5% of total system peak hour capacity. In 1996, most of the Company's non-utility generation came from QFs, except for 20,252 megawatt hours, which came from two small power producers. The percentage of spot market energy purchases (12.9%) was somewhat lower than the

previous year but still well above pre-1995 levels. Wet weather conditions in the Pacific Northwest created an abundance of low-cost energy during much of 1996, of which the Company took advantage whenever possible.

                                       Capacity at
                                        1996 Peak                     Forecasted Summer MW
                                   -----------------        -----------------------------------------
                                       MW         %          1997     1998     1999     2000     2001
                                   -----------   ---        -----    -----    -----    -----    -----
Company Generation:
   Existing                             964       68%       1,053    1,053    1,053    1,053    1,053
                                      -----      ---        -----    -----    -----    -----    -----
Purchases:
   Long/Short-Term Firm(1)(2)           262       19%         295      294      292      285      285
   Interruptible Customers                5        1%           5        5        5        5        5
   Non-Utility Generators                74        5%          74       74       74       74       74
                                      -----      ---        -----    -----    -----    -----    -----
     Subtotal                           341       25%         374      373      371      364      364
                                      -----      ---        -----    -----    -----    -----    -----
Additional Required                     104        7%          40       93      122      165      215
                                      -----      ---        -----    -----    -----    -----    -----
Total System Capacity                 1,409      100%       1,467    1,519    1,546    1,582    1,632
                                      =====      ===        =====    =====    =====    =====    =====

Net System Peak (3)                   1,225       87%       1,280    1,330    1,352    1,385    1,433
Planning Reserve                        184       13%         187      189      194      197      199
                                      -----      ---        -----    -----    -----    -----    -----
        Total                         1,409      100%       1,467    1,519    1,546    1,582    1,632
                                      =====      ===        =====    =====    =====    =====    =====
Growth over
   previous year                                              4.1%     3.5%     1.8%     2.3%     3.2%
                                                            =====    =====    =====    =====    =====

(1) Value net of losses.
(2) There are currently no contracts for short-term firm purchases. Values shown represent potential purchases within existing transmission system limits.
(3) The system peak shown for 1996 is the actual system peak of 1,225 MW, which occurred on July 22, 1996.

With regard to total system capacity, the Company is expected to maintain a planning reserve margin consistent with the Western System Coordinating Council guidelines. This reserve margin was 184 megawatts in 1996, which the Company expects will increase to 197 megawatts by 2001. To accommodate the system requirement during the 1997-2001 time period, it will be necessary to secure additional capacity beginning in 1997. The Nevada Commission, through the electric resource planning process, approved the Pinon Pine Power Project, which will provide 89 megawatts beginning in 1997. The "Additional Required" will be met by short-term purchases through 1998. The

least-cost option for needs beginning in 1999 will be evaluated in the Company's next Resource Plan filing due in 1998.

                                               Number
                                               ------
                                                 of      MW          Year(s)
                                                 --      --        ------------
 Name                Type/Fuel                 Units   Capacity     Installed
 ----                -----------               -----   --------    ------------
Valmy                Steam/Coal                   2      265        1981 and 1985
Tracy                Steam/Gas, Resid. Oil        3      244     1963, 1965, 1974
Pinon                Combined Cycle/Coal, Gas     1       89          1996 - 1997
Clark Mtn CT's       CT/Gas, Diesel Oil           2      138                 1994
Ft. Churchill        Steam/Gas, Resid. Oil        2      226        1968 and 1971
Other                GT/Gas, Diesel Oil,
                     Propane, Hydro              35       91          1899 - 1970
                                                       -----
                                                       1,053
                                                       =====

(CT)  Combustion Turbine
(GT)  Gas Turbine

     The Company owns 100 percent of all of its electric generation plants with

the exception of Valmy. The Company owns an undivided 50 percent interest in the Valmy plant. Idaho Power Company (Idaho Power) owns the remainder. The capacities shown above for the Valmy plant represent the Company's share only. The table above includes the generation capacity of the 100% SPPC-owned power island portion of the Pinon Pine Power Project. The gasifier portion of Pinon is owned by the Pinon Pine Co., LLC (The LLC). Pinon Pine Corp. and Pinon Pine Investment Co., subsidiaries of the Company, own 25% and 75% of a 38% interest in The LLC with General Electric Capital Corporation (GECC) owning the remaining 62%.

The Company continues to manage a diverse portfolio of contracted and spot market supplies, as well as its own generation, in order to keep the Company's net average system costs as low as possible. With the wet weather conditions and mild temperatures prevailing in the Pacific Northwest over much

of 1996, the Company was also able to purchase surplus economy energy at very low costs.

The Company is a member of the Northwest Power Pool and Western Systems Power Pool. These pools have provided the Company further access to spot market power in the Pacific Northwest and the Southwest. In turn, the Company's generation facilities provide a backup source for other pool members who rely heavily on hydroelectric systems. The Company has an agreement with PacifiCorp's Utah division and Idaho Power in which a portion of the energy purchased by the Company from PacifiCorp is transmitted through the Idaho Power system. The agreement also provides added access to spot market power.

The Company purchases spot market energy, both hydro and thermal-produced, by the hour, based upon economics and system import limits. During drought years, when less spot market hydro energy is available, the Company resorts to energy produced by more expensive fossil fuels. For example, during the early 1990s drought conditions increased regional demand in the Pacific Northwest which coupled with load growth restricted the availability of the region's hydro energy resources. In recent years, however, very wet weather conditions in the Pacific Northwest allowed the Company to purchase large amounts of surplus economy energy at prices which had not been experienced since 1986. Of continuing concern to any purchaser of hydro-generated energy are proposals by regulators, in the interest of saving the salmon, recommending closure of some hydro operations on the Snake and Columbia rivers. The amounts available and the price will depend on weather conditions in the Pacific Northwest and proposals by regulators. The amount of excess generating capacity in other systems and the existence of competition in providing utilities with economic incentives to make secondary sales also will be important factors.

Currently, the Company has contracted for a total of 265 megawatts of long- term firm purchased power from the utility suppliers listed below. Several of the Company's firm purchase power contracts contain minimum purchase obligations. Meeting them has not been a problem for the Company in the past, and is not expected to be a problem in the future.

                                                                        Minimum
                                 Contract    Operation   Termination   Capacity
Contract Party                   Capacity      Date         Date           %
- --------------                   --------    ---------   -----------   --------
Idaho Power                       75 MW      Nov 1989     May 1999         50%
Idaho Power (for Elko)            15 MW      Mar 1994     May 2000         40%
Tri-State                         25 MW      June 1991    Feb 2007         50%
PacifiCorp                        75 MW      June 1989    Feb 2009         70%
PacifiCorp/Utah Power (1)         75 MW      May 1991     Apr 2021         78%

(1) THE COMPANY HAS THE RIGHT TO TERMINATE THE PACIFICORP/UTAH CONTRACT EFFECTIVE APRIL 30, 2000.

According to regulations of the Public Utility Regulatory Policies Act, the Company is obligated, under certain conditions, to purchase the generation produced by small power producers and cogeneration facilities at costs determined by the appropriate state utility commission. Generation facilities that meet the specifications of the regulations are known as qualifying facilities (QFs). As of December 31, 1996, the Company had a total of 105

megawatts of maximum contractual firm capacity under 15 contracts with QFs. The Company also had contracts with four projects at fluctuating short-term avoided cost rates. All contracts currently delivering power to the Company at long- term rates have been approved by either the Nevada Commission or the California Commission, and have QF status. These long-term QF contracts terminate under their own provisions between 2006 and 2039.

The actual QF output of 74 megawatts during the summer 1996 peak was less than the firm contracted amount of 105 megawatts. The table on page 17 reflects actual performance during the 1996 summer peak period. Any capacity shortfall created by under-performance was included in the Company's 1995 Resource Plan.

Energy purchased by the Company from QFs constituted 9% of the net system requirements during 1996. These contracts continue to provide useful diversity for the Company in meeting its load peak. All the QFs from which the Company makes firm purchases are either geothermal (86%), hydroelectric or biomass.

Some QF contracts have been priced higher than alternative utility energy suppliers in the past. The changing nature of some QF contracts has resulted in lower prices to the Company. The long-term contract with California Energy Company for the Desert Peak geothermal plant terminated in January 1996. A new agreement with significantly lower pricing is now in place for future purchases from that plant. Another long-term contract with Far West reverted to the lower short-term avoided cost rates starting in December 1996.

The Company has been making spot market purchases at a reduced cost. The Company has some control over dispatch in its newer purchased power contracts with QFs. In addition, contract expiration dates are staggered to meet changes in demand.

The Company's electric resource planning process has evaluated purchased power as a supply-side alternative and prices have been competitive with alternatives.

In planning its transmission capacity, the Company considers its generation and purchased power needs, as well as the opportunity for providing retail and wholesale wheeling services.

The Company's existing transmission lines extend some 300 miles from the crest of the Sierra Nevada in eastern California, northeast to the Nevada-Idaho border at Jackpot, Nevada, and some 250 miles from the Reno area south to Tonopah, Nevada. A 230 KV transmission line connects the Company to facilities near the Utah-Nevada state line, which in turn interconnects the Company to Pacificorp's Utah division. A 345 KV transmission line connects the Company to Idaho Power facilities at the Idaho-Nevada state line. The Company also has two 120 KV lines and one 60 KV line interconnecting with Pacific Gas and Electric (PG&E) on the West side of the Company's system at Donner Summit, California. Two 60 KV transmission ties allow wheeling of up to 14 megawatts of power from

the Beowawe Geothermal Project, which is located within the Company's service area, to Southern California Edison. These two minor interties are available for use during emergency conditions affecting either party.

The Company's transmission intertie system provides access to competitively-priced energy supplies. The existing system has played a major role in helping stabilize the Company's energy costs by allowing surplus energy purchases throughout the year, but especially during the spring snow melt in the Pacific Northeast.

The Company also relies on transmission capacity to address system emergencies, (such as the loss of generating units), reducing the need for additional reserve generating capacity. The Company provides up to 148 MW of transmission service under long-term firm contracts.

The Company is currently developing the Alturas Intertie to provide the means of serving existing native load and new customers, and to significantly increase the Company's access to lower cost resources. Assuming all required permits can be obtained, the anticipated in-service date of this intertie is the summer of 1998. The projected in-service date is dependent on the outcome of outstanding regulatory approvals yet to be acquired. See Alturas Intertie.

The Company has agreements with Pacificorp's Utah division and Idaho Power which allow for up to 50 megawatts of the energy purchased by the Company from PacifiCorp to be transmitted through the Idaho Power system. The Company also has an interconnection agreement with PG&E that requires PG&E to maintain a firm transmission rating of 108 megawatts, provided the Company pays the Company for any necessary system upgrades. The interconnection's major purpose is to provide an alternative transmission path in the event of an emergency on the Company's system. The Nevada Commission, in a previous electric resource plan opinion and order, approved the payment for upgrades into the late 1990's. These upgrades are considered regulatory assets and are amortized over lives similar to Company-owned facilities. At December 31, 1996 these regulatory assets amounted to $5 million. See Note 1 of the Company's consolidated financial statements.

The Company's 1996 fuel requirements for electric generation were provided by natural gas (61%), coal (37%), and oil (2%). During 1996 natural gas remained the economic generation fuel choice, over oil, for generation plants other than Valmy, which is a coal-fired plant.

The average costs of coal, gas and oil for energy generation per million British thermal units (MMBtu) for the years 1992-1996 were as follows:

                               Cost per MMBtu
                   -------------------------------------
                    1996    1995    1994    1993    1992
                   -----   -----   -----   -----   -----
Gas                $2.10   $1.65   $2.19   $2.19   $1.70
Coal                1.88    2.19    2.07    2.05    2.08
Oil                 3.48    3.80    3.37    3.54    3.36

Since commencing operation of its Valmy coal-fired generating units in the early 1980s, the Company operated these units at a higher load level than its gas/oil-fired units because gas and oil fuels had been generally more expensive. However, the Company has operated its gas/oil-fired units at increased levels since 1989 due to the competitive pricing of natural gas during this time period.

The Company's contract with Black Butte Coal Company (Black Butte), for coal shipments from the Black Butte Mine in Wyoming to Valmy, is in effect until June 30, 2007 or until all commitments required by the contract are delivered and/or canceled. Given the current rate of consumption, the Company anticipates meeting the minimum commitment required by the contract several years prior to its 2007 termination date. At that time the Company will evaluate market conditions and put in place lower cost strategies. This may include purchases on the spot market.

The Company, in concert with the other owner of Valmy, Idaho Power, is actively exploring and implementing options to more rapidly amortize the Black Butte contract prior to its June 30, 2007 final expiration date. In late June 1996, the Company and Idaho Power spent $5 million to cancel all Black Butte contractual requirements for the 1996-97 contract year. This cancellation had three main benefits:

1. To give the Company and Idaho Power the opportunity and flexibility to purchase coal on the lower cost spot market, reducing the overall fuel cost to the Valmy station and increasing the plant's operations;
2. To reduce the coal inventory at the Valmy station; and
3. To save the differential rail transportation costs between coals originating in Wyoming compared to replacement coals originating in Utah.

In the fall of 1996 the Company agreed with Idaho Power to further reduce the Black Butte balancing account through additional actions. Idaho Power agreed to take delivery of quantities of Black Butte coal at the Jim Bridger Power Station (which is located directly across Interstate 80 from the mine) during the months of July, August and September. In return, the Company agreed

to buy out an amount of Black Butte coal rather than coal from the Bridger mine. The Company will pay this additional $1.5 million prior to the end of the 1996- 97 contract year on June 30, 1997.

The Company's coal contract with Canyon Coal Company (Canyon) which provides coal from Canyon's Utah operations extends until the year 2003. The original contract was with Coastal States Coal Company which was sold to Canyon Fuel Company, LLC during 1996. The contract also contains volume commitments which the Company expects to meet.

The total amount of coal burned at the Valmy Power Plant during 1996 was 1.1 million tons. As of December 31, 1996, the coal inventory balance was 307,017 tons, or roughly 54 days of consumption at 100% capacity. The Company targets an average annual coal stock-pile sufficient to provide 30 days supply at full load.

The Company has increasing gas demands and a need for firm capacity, primarily for electric generation, but also for load growth in its LDC.

In 1995 Tuscarora Gas Transmission Company, jointly owned by subsidiaries of SPR and TransCanada Pipelines, USA Limited (TransCanada), completed construction and began service through its new interstate natural gas pipeline, to the Tracy Power Plant. The 229-mile, 20-inch pipeline provides the Company with 95,000 decatherms per day of firm transportation service and direct access to the gas reserves of the Western Canadian Sedimentary Basin, one of the largest known reserves of natural gas in North America. The Tuscarora capacity, matched with upstream capacity on interconnecting pipelines, will substantially reduce the historical gas curtailments experienced by the electric division and provide a competitive alternative for fuel supply.

The Company meets its needs for residual oil for generation through purchases on the spot market. With no other mitigating factors, the Company's residual oil inventory policy is to maintain 50,000-75,000 barrels at each of its Tracy and Fort Churchill facilities. The actual residual oil inventory level at these two sites was 144,882 barrels as of December 31, 1996 which is equal to six days supply at 100% load factor operation. Total residual oil consumption in 1996 was 147,395 barrels.

The Company's natural gas business is a local distribution company (LDC) in the Reno/Sparks area that accounted for $67.4 million in 1996 operating revenues (11% of total company operating revenues). The LDC has experienced rapid customer growth over the past 10 years as a result of population increases in the Company's service territory, active recruitment of businesses into northern Nevada, and special programs promoting the conversion from other energy sources to natural gas. The Company's 1996 peak day send-out for its local distribution system was 84,204 decatherms, occurring on January 22, 1996. A new record peak day sendout of 114,375 decatherms occurred on January 13, 1997.

Natural gas offers economic and environmental advantages over other energy sources for space heating, water heating and other uses in residential, commercial and industrial markets. Growth in the residential and small commercial sectors is expected to continue with a renewed emphasis on the development of those areas where gas service is not yet available. Continued successful economic development activity in 1996 should add additional industrial gas sales in 1997.

The Company is responsible for securing its own gas supply. The Company has personnel and resources in place to deal with the complexities and opportunities presented by the current gas markets and regulatory environment. The Company has purchased spot market and firm gas supplies to meet electric generation fuel requirements since November 1988, and firm gas supplies to meet its LDC requirements since June 1991.

The Company is an active participant in ongoing workshop discussions examining issues relating to gas utility regulation in an increasingly competitive environment. The participants of the workshop, sponsored by the Nevada Commission, represent various customer and utility interests in the State. The issue of further unbundling of natural gas services at the retail level is particularly relevant to the Company's efforts to provide customers choice in their purchases of energy and energy services.

A new firm transportation service was developed by the Company and approved by the Nevada Commission during 1996. The new service provides eligible large commercial and industrial customers with the option of higher priority firm transportation service in addition to the already available interruptible transportation service. The variable rate structure of the transportation service tariffs allows the Company to compete with customer bypass initiatives and alternative energy options. Currently two customers secure their own gas supplies with the Company providing transportation service on its distribution system.

The Company's natural gas LDC business is also subject to competition from other forms of energy available to utility customers. Large customers with fuel switching capabilities compare natural gas prices to alternative energy source prices. To remain competitive, the Company offers an incentive natural gas sales rate (INGR) to these customers.

The Value Based Service Tariff (VBST) was developed in 1995 to compete with the natural gas transportation options available to the Company's largest customers. Currently, nine customers are taking service under VBST Service Agreements. In addition to VBST and the transportation services available to eligible large customers, the Company offers bundled firm sales services for all customers.

With the construction of the Tuscarora Pipeline in 1995, the ability of large customers to obtain firm transportation rights into northern Nevada increases the choices available to natural gas customers in the area. Tuscarora presents opportunities for business growth through expanded services in a regional natural gas market.

Natural gas purchased for the Company's retail gas customers and for use in its electric generating plants is transported on several FERC regulated pipelines.

Northwest Pipeline Corporation (Northwest), in conjunction with Paiute Pipeline Company (Paiute), provides the Company access to natural gas supplies in British Columbia, the Rocky Mountain region, and the San Juan basin. Northwest is a major interstate pipeline stretching from the Canadian border at Sumas, Washington, to the northwestern corner of New Mexico. Paiute interconnects with Northwest at the Idaho/Nevada border and runs southwest to the Reno/Lake Tahoe area of Nevada and California.

With completion of the Tuscarora Pipeline in 1995, SPR has a financial interest in natural gas transmission facilities serving the northern Nevada market. TGTC, a partnership between a subsidiary of SPR and a subsidiary of TransCanada, began service in 1995. Tuscarora interconnects with Pacific Gas Transmission (PGT) near Malin, Oregon and terminates at the Tracy Power Plant east of Reno/Sparks. In addition to providing natural gas service to the Company's Tracy Power Plant and distribution customers in the area, Tuscarora Pipeline also provides service to the Company's main distribution system serving the Company's retail gas customers in Reno/Sparks and the Truckee Meadows. Tuscarora Pipeline also provides service to the community of Malin, Oregon and the Sierra Army Depot near Herlong, California.

PGT is a major interstate pipeline stretching from the Canadian border at Eastport, Idaho to the California/Oregon border near Malin, Oregon. NOVA and Alberta Natural Gas (ANG) pipelines are upstream of PGT in the British Columbia and Alberta provinces of Canada. Firm transportation service on Tuscarora and upstream pipelines improves the reliability of the Company's gas supplies and provides additional access to abundant and competitively priced supplies in Alberta, Canada.

The Company has contracted for firm winter-only and annual gas supplies with 10 Canadian and domestic suppliers to meet the firm requirements of its LDC and electric operations. The contracts total 120,000 decatherms per day through March 1997; 40,000 decatherms per day for April through October 1997; and 50,000 decatherms per day for the remainder of the year. Most of these contracts provide for a fixed price. This ensures that the Company is able to lock in a significant portion of its gas supply cost while retaining the flexibility to purchase spot market supplies.

The Company's firm natural gas supply is supplemented with natural gas storage services and supplies from a Northwest facility located at Jackson Prairie in southern Washington and LNG storage from a facility located in Lovelock, Nevada. The LNG facility is operated by Paiute and is used for meeting peak demand. The Jackson Prairie and LNG facilities can contribute a total of approximately 45,000 decatherms per day of peaking supplies. The Company meets its peak day requirements above Northwest/Paiute capacity with firm transportation capacity on the Tuscarora Pipeline and PGT.

Starting November 1, 1996, the Company entered an agreement to sell winter seasonal peaking supplies to another company over a seven year period. The contract provides for the payment to the Company of a monthly reservation charge, reimbursement of pipeline capacity charges during the winter, and a volumetric commodity charge based on the market price for natural gas. The Company was able to enter into this agreement due to the additional gas supplies being delivered on Tuscarora Pipeline and because of the ability of its power plants to utilize a variety of fuels.

Following is a summary of the transportation and approximate storage capacity of the Company's current gas supply system. Firm transportation capacity on the Northwest/Paiute system exists to serve primarily the LDC. Firm transportation capacity on the PGT/Tuscarora system exists primarily to serve the Company's electric generating plants. Storage capacity is generally used for the peaking requirements of the LDC.

Transportation Capacity
- -----------------------
     Northwest  -        70,696   decatherms per day firm
                         90,000   decatherms per day interruptible
     Paiute     -       105,774   decatherms per day firm from November
                                  through March
                         63,044   decatherms per day firm from April
                                  through October
                         90,000   decatherms per day interruptible
     NOVA       -        30,000   decatherms per day firm
     ANG        -        30,000   decatherms per day firm
     PGT        -        30,000   decatherms per day firm
                         30,000   decatherms per day firm (winter only)
                         90,000   decatherms per day interruptible
     Tuscarora  -        95,000   decatherms per day firm

Storage Capacity
- ----------------

     Northwest  -       277,997   decatherms from Jackson Prairie
                         12,733   decatherms per day from Jackson Prairie
     Paiute     -       463,034   decatherms from Lovelock LNG
                         35,078   decatherms per day from Lovelock LNG
                                  facility

The Company's LDC natural gas requirements have averaged between 10 and 12 million decatherms annually over the past few years. Total LDC therm supply requirements in 1996 and 1995 were 11.8 million decatherms and 10.8 million decatherms, respectively. Electric generating fuel requirements for 1996 and 1995 were 31 million decatherms and 25 million decatherms, respectively.

As of December 31, 1996 the Company owned and operated 1,219 miles of three-inch equivalent natural gas distribution lines.

The local water distribution business contributed $45.3 million (7.3%) to the Company's 1996 operating revenues.

The Company's water business is seasonal to the extent that nearly 70 percent of consumption occurs from May through September as a result of residential and commercial irrigation needs. Permanent conservation measures have resulted in a reduction of usage in drought and non-drought years.

The Company continues to pursue the Negotiated Settlement which has been in the works for several years. The Company is currently operating under a Preliminary Settlement Agreement (PSA) and Interim Storage Contract until the final document is completed. The PSA is a complex set of agreements on Truckee River issues involving the U.S., California, and Nevada governments and the Pyramid Lake Paiute Tribe. Pursuant to the PSA, the Company and the other parties are currently negotiating an operating agreement for the Truckee River and reservoirs on the river, including Lake Tahoe and Boca Reservoirs for drought storage for the Company. The Company will gain use of federal reservoirs for drought reserves in exchange for providing excess non-drought year water for fishery purposes.

The Negotiated Settlement, which is expected to be completed in 1997, will resolve much outstanding litigation on the river. For the operating agreement and PSA to become effective there must be a final resolution of outstanding litigation involving the Company and the parties. Prior to completion, the settlement must satisfy the National Environmental Protection Act (NEPA) through an environmental impact study on the operating plan for the settlement implementation which is expected to be filed in mid-1997. Related agreements and water accounting systems are in development and expected to be finalized by mid-1997. The water conservation and water quality agreements were completed in 1996.

Water obtained from the Truckee River and its tributaries is processed through two major treatment facilities and combined with water pumped from 24 supply wells to serve the needs of the Company's water customers. The Company's upstream reservoirs have a capacity of approximately 7.2 billion gallons of untreated water storage. Additional storage of up to 4.6 billion gallons has been secured in federal reservoirs under a 25-year contract signed in May 1994 or until the Negotiated Settlement goes into effect. This contract will be replaced by a larger storage agreement once the Negotiated Settlement is in place.

As a condition of the Negotiated Settlement, the Company's 45,000 unmetered residential water customers must have meters installed. This retrofit program began in 1995 and was approved by the Nevada Commission in early 1996. Installation funding is provided by new business development. In the early years of the 10 to 12 year program, our meters will be installed only for customers who volunteer for the program. Once 90% of the meters have been installed, the program may become mandatory. Through year-end 1996,

meters have been installed in the homes of 6% of the previously unmetered customers.

After the conversion of both the Hunter Creek and Highland Treatment Facilities to treated water storage facilities, the Company will have water storage capacity of approximately 106 million gallons in its treatment plant reservoirs and distribution storage tanks. Due to this conversion, to treated water storage from open storage, Highland will lose approximately 30 million gallons of its capacity, which accounts for the reduction from 1995 to 1996. Refer to Water Treatment Facilities.

As of December 31, 1996 the Company owned and operated 1,399 miles of six- inch equivalent transmission and distribution mains. The total volume of water distributed during 1996 and 1995 was approximately 22 and 20 billion gallons, respectively. The Company's peak day send-out of water during 1996 was 117 million gallons, which was an increase from the 1995 peak of 111 million gallons.

During 1995 comprehensive legislation was adopted by the Nevada Legislature which provides for regional planning and cooperative management of all aspects of water in the region and the ability of the County to create a remediation district. The Regional Water Planning Commission was created to develop an integrated water plan. The water plan was developed throughout 1996, and has received all necessary approvals from local government entities. By April 1997 the plan will be submitted to the Nevada Legislature for its approval. The Company and Washoe County have negotiated an agreement which provides methodology to determine retail service area boundaries and establishes the Company as the wholesale purveyor for the region. The parties are currently waiting for approval of the agreement from the Nevada Commission. These cooperative efforts between the Company and local agencies will help ensure regional planning and integrated water service.

The Company's water supplies are based on surface water and groundwater sources, with the addition of drought storage and refill provisions sufficient to withstand a repeat of the recent eight-year drought. The Company's water supply during normal years consists of approximately 80 percent from the Truckee River and 20% from local wells. During drought years, approximately 75% of supply comes from the Truckee River and 25% from wells.

The river originates in Lake Tahoe and flows north and east through Reno and Sparks to Pyramid Lake, northeast of Reno. During the drought, little water flowed out of Lake Tahoe for four years, so other system tributaries and reservoirs made up the stream flow. Normal flows and storage levels recovered during 1995 and 1996. The 1997 winter season produced sufficient snowfall, which, combined with the water storage remaining from 1996, should provide ample water supplies through 2000.

The Company plans for future water supplies through the use of an integrated analysis of demand projections, drought reserves and facility capacity. The resulting water resource plan is submitted periodically to the Nevada Commission for review and approval. The most recent Integrated Water Resource Plan (1995 - 2015) was approved in 1994. Although there is no

statutory requirement to file future integrated Water Resource Plans, the Nevada Commission ordered that an update to the current plan be filed in 1998.

As part of the Water Resource Plan, the Company gained approval for three additional sources of supply and upstream drought storage, increasing the approved limit of the Company's water commitments from 82,000 acre feet annually to 97,400 acre feet annually. This allows substantial margin for growth and still have the Company capable of withstanding continued drought. An interim storage contract was reached among the Company, the United States, the Pyramid Lake Paiute Indian Tribe and Washoe County Water Conservation District. It allows the Company to store up to 14,000 acre feet of water for drought use in two federal reservoirs. The Negotiated Settlement discussed above provides the greatest opportunity for drought storage beyond the Resource Plan time frame, with sufficient drought storage to support annual customer demands of up to 119,000 acre feet annually.

The Safe Drinking Water Act (SDWA) amendments passed by Congress in 1986 significantly impacted the cost of the Company's treatment plant facilities. The Company was officially notified in 1991 by the Nevada State Health Division that, under the requirements of the Surface Water Treatment Rule (SWTR) of the SDWA, filtration of water at its non-filtered plants would be required. The Company submitted and received approval of a filtration compliance plan with the Nevada State Health Division. The plan provided for a three-year extension of the original deadline to June 1996.

In order to comply with SWTR filtration requirements and meet projected capacity demands, the Company has completed the construction of a second phase of the Chalk Bluff treatment plant. The first phase, completed in spring 1994, provided a capacity of 27 million gallons per day (MGD) using high- rate filtration approved by the State Health Department. The second phase of the facility, with a capacity of 42 MGD, was completed in April 1996. The Company's Glendale treatment plant also underwent enhancements to its treatment processes which were completed in June 1996. Completion of these projects results in full compliance with the SWTR requirements.

The Company's Idlewild chemical-process treatment plant was removed from operation in 1994 and now serves as a transfer pumping station. Of the two remaining chemical-process plants, Hunter Creek was removed from operation as a treatment facility in October 1995 and was converted to a covered storage facility in May 1996. Highland was removed from operation as a treatment facility in June 1996, and is being converted to a 20 MGD storage facility to be completed by May 1997. Combined, Hunter Creek and Highland will provide 50 million gallons of treated water storage for fire protection, operating storage and emergency requirements.

The Company uses groundwater from 24 supply wells. Manmade contaminants from local business operations, in levels exceeding drinking water standards, have been found in five of these wells. Treatment equipment costing $2.2 million has been installed on two of the wells and the wells have been returned to operations. The three other wells have been removed from operation. The Company has entered into a bilateral compliance agreement with

the Nevada State Health Division which requires these three wells to be in compliance by October 1998. The Company continues its involvement in a cooperative remediation effort with public officials to determine the source and extent of the contaminant and to develop a plan to abate the contamination on an area-wide basis. Washoe County has the ability to create a special remediation district to help cover the cost of this effort. The County Commission passed a resolution initiating proceedings to create the remediation district, and will be proposing legislative amendments to facilitate the establishment of the district. The remediation plan is expected to be developed by June 1998.

As of December 31, 1996, the Company has spent approximately $114 million on water treatment improvements and treated water storage facilities. These investments include Chalk Bluff, Glendale, well treatment, and the Highland and Hunter Creek Reservoirs. An estimated $15 million will be spent in 1997-2001 for additional treatment improvements.

                                                                       Total
                                             1997       1998-2001     5-Year
                                           ---------   -----------   ---------

Electric Facilities                        $111,091    $  398,631    $509,722
Water Facilities                             21,240        45,202      66,442
Gas Facilities                                9,565        35,051      44,616
Common Plant                                  4,579        11,516      16,095
                                           --------    ----------    --------
     Total Construction Expenditures        146,475       490,400     636,875
AFUDC                                        (8,456)       (9,651)    (18,107)
Net Salvage, including cost of removal        1,089         3,648       4,737
Net Customer Advances and
     Contributions in Aid of
      Construction                           (3,634)      (14,491)    (18,125)
                                           --------    ----------    --------
     Total Cash Requirements               $135,474    $  469,906    $605,380
                                           ========    ==========    ========

Total construction expenditures estimated for 1997-2001, for each segment of the Company's business, consist of the following (dollars in thousands):

                                                                 Total
                                         1997     1998-2001     5-Year
                                       --------   ----------   ---------
Electric Facilities:
     System Improvements               $ 35,697   $  219,843    $255,540
     New Business Extensions             31,468      130,647     162,115
     New Transmission                    28,517       37,560      66,077
     New Generation                      14,284            -      14,284
     Other                                1,125       10,581      11,706
                                       --------   ----------    --------
                                       $111,091   $  398,631    $509,722
                                       ========   ==========    ========
Water Facilities:
     Treatment Plant Improvements        11,860        3,149      15,009
     Distribution Improvements            7,487       27,684      35,171
     New Business Extensions              1,305        5,770       7,075
     Other                                  588        8,599       9,187
                                       --------   ----------    --------
                                       $ 21,240   $   45,202    $ 66,442
                                       ========   ==========    ========
Gas Facilities:
     New Business Extensions           $  6,922   $   27,428    $ 34,350
     Other                                2,643        7,623      10,266
                                       --------   ----------    --------
                                       $  9,565   $   35,051    $ 44,616
                                       ========   ==========    ========

The Company's estimated construction program is prepared annually within guidelines imposed by changing economic, regulatory and environmental conditions which may alter the nature and estimated cost of the program. Included in the category of Electric Facilities, System Improvements, is $4.9 million for damage replacements due to the flood of 1997. In the category of Water Facilities Treatment Plant Improvement, is $1.6 million primarily for flood damage to the Glendale Water Treatment Facility.

The Company is subject to the jurisdiction of the Nevada and California Commissions with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to electric operations. The Nevada Commission also has jurisdiction with respect to the Company's gas and water operations. The Company submits integrated resource plans regarding its electric, gas, and water business operations to the Nevada Commission for approval.

Under federal law, the Company is subject to certain jurisdictional regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service, interconnection, accounting, and other matters in connection with the Company's sales of electricity for resale and the transmission of energy for others. The FERC also has jurisdiction over the natural gas pipeline companies that the Company utilizes.

As a result of regulation, many of the fundamental business decisions of the Company, as well as the rate of return it is permitted to earn on its utility assets, are subject to the approval of governmental agencies.

During 1996, 90.6% the Company's revenues were from retail sales of electricity, natural gas and water in Nevada; 6.8% from retail sales of electricity in California and 2.6% from sales of electricity for resale in Nevada and California.

In December 1994, the Nevada Commission approved the Company's request to combine its 1995 Electric and Natural Gas Integrated Resource Plan in a single filing. In September 1995 the Nevada Commission approved this Resource Plan in its entirety. Among many components of the plan, are these three-year Action Items:

1. Approval of a natural gas purchasing strategy;

2. Approval to permit the Fort Churchill site to accommodate two 90 megawatt combustion turbines; and

3. Approval to develop a new generation site.

On November 7, 1996, the Company received an operating permit from the Nevada Division of Environmental Protection for two 83 MW combustion turbines for the Fort Churchill site. In 1996, the Company selected an architectural/engineering consultant to perform a generation siting study anticipated to be completed in April 1997. At that time a new site will be selected.

In the 1995 resource plan, the Company prepared a strategy for Demand Side Management that responds to the pressure of growing competition and the price of its basic product. The Company continues to design and pursue cost effective demand side management through the Custom Energy Solutions Program and the Interruptible Program where it continues to make economic sense for its customers. The next electric resource plan is due to be filed mid-1998.

The 1995-2014 Electric and Gas Integrated Resource Plan contains forecasts of future natural gas demand and the Company's plans to meet those requirements economically while maintaining service reliability and flexibility. Also included in the plan are distribution facility additions including the Company's LDC interconnection with the Tuscarora Pipeline. The resource plan identifies the criteria used in evaluating gas supply contracts, the proposed mix of firm and interruptible natural gas supplies, and the supply sources required to meet peak day demands over the planning period. The next gas resource plan is due mid 1997.

The Company intends to file a water rate case in 1997 to recover cost increases related to investments in water plant to comply with the Safe Drinking Water Act.

As with other utilities, the Company is subject to federal, state and local regulations governing air and water quality, hazardous and solid waste, land use and other environmental considerations. These considerations affect the construction and operation of electric, gas and water utility facilities.

The Nevada Utility Environmental Protection Act requires Nevada Commission approval prior to the construction of major utility generation and transmission facilities. The Nevada Division of Environmental Protection and the Federal Environmental Protection Agency administer regulations involving air quality, water pollution, solid, hazardous and toxic waste.

The Company's Board of Directors has a comprehensive environmental policy and separate board committee on environmental compliance which oversees corporate performance and achievements related to the environment. Through its employees, the Company's business activities are guided by the corporate environmental policy, which places environmental considerations at the forefront of the decision-making process.

Start-up of the combined cycle power island of the Pinon Pine Power Project in December 1996 was a significant event. A DOE Clean Coal Technology Project, Pinon will be capable of burning natural gas or gas synthesized from coal. Besides providing the flexibility to burn the most economic fuel available, pollutant and greenhouse gas emission rates are significantly lower than those from conventional or scrubbed coal generation units. As an added benefit, water use per unit of electricity produced is much lower than for other similar power plants.

The Company conducted compliance audits on 59 sites, including eight vendor sites. During 1996, remediation was performed on eight sites at a cost of more than $320,000. In addition, 28 spills were successfully remediated. In 1995 the Company identified one site that was formerly used for manufacturing gas from oil. Currently, the Company has negotiated a sale of this parcel. The Company's total liability for this site is estimated to be $500,000, of which approximately $250,000 has been spent through December 31, 1996. The remaining balance has been accrued as a liability on the December 31, 1996 consolidated balance sheets.

In 1996, the Company continued and initiated several actions in accordance with its policy to be an environmental leader in principle and practice. These actions have resulted in reduced pollutant and greenhouse gas emission rates at power plants, demonstrated stewardship of wildlife and waterfowl habitat on and adjacent to Company property, improved water quality conditions, and lowered cost of compliance with environmental regulations.

Once again the Company was awarded bonus sulfur dioxide emission allowances by the US Environmental Protection Agency (EPA) for use of

geothermal energy, a renewable resource. Sierra received 666 bonus allowances in 1996. Under the Acid Rain Rule of the Clean Air Act, bonus emission allowances are granted to utilities that have avoided sulfur dioxide emissions by using renewable energy to generate electricity or by reducing electricity demand with energy conservation and efficiency measures. Only four US utilities have been awarded more bonus allowances than the Company.

As a voluntary Climate Challenge participant, the Company filed with the DOE its second annual report on greenhouse gas emissions and actions taken to reduce them. Carbon dioxide, the principal greenhouse gas, is produced when oil, natural gas or coal is combusted. Some scientists are concerned that rising levels of carbon dioxide and other greenhouse gases may lead to rapid changes in climate conditions, potentially resulting in serious economic and environmental impacts. About 3.7 million tons of carbon dioxide were produced from the Company's generating units; however, emissions could have been about 665,000 tons more if certain actions had not been taken, representing a 15% reduction. Use of renewable resources (geothermal and hydroelectric energy), energy conservation and efficiency measures, generating unit efficiency improvements, increased use of natural gas over oil (a benefit of the Tuscarora Pipeline Project completed in 1995), reuse of coal fly ash in cement production, and natural gas use in fleet vehicles contributed to offset carbon dioxide emissions.

Stewardship of Nevada's water and wildlife resources is being demonstrated at the Fort Churchill and Tracy power plants. At Fort Churchill the Company expanded its 1995 wetland restoration efforts with a joint effort at the wetlands on the Mason Valley Wildlife Refuge. The Refuge, adjacent to the Walker River, is administered by the Nevada Department of Wildlife (NDOW). This cost and resource-sharing partnership between the Company, NDOW, and Ducks Unlimited involves use of cooling water from the Company's facilities. Water will be piped to wetland ponds on the Refuge, expanding open water recreation opportunities and wildlife habitat by about 500 acres. Besides enhancing water resources in the region, this project is an inexpensive way to improve cooling systems at the generating units.

Implementation of a riparian habitat improvement project and planning for an 80 acre wetland restoration project at Tracy Power Plant occurred in 1996. The riparian project consists of removing an invasive weed along the Truckee River and planting willows and cottonwood trees. Besides providing bank stability along the cooling pond levee, habitat for birds and mammals will be enhanced and river water quality conditions improved. The 80 acre wetland restoration project will have similar environmental benefits, in addition to reducing the potential for flood damage in the vicinity of the power plant.

While the Company has been involved with waste minimization projects for years, during 1996 a formal pollution prevention program was initiated. The Company's Pollution Prevention Program will increase awareness of wasteful practices and products, and introduce decision-making tools and processes which have been shown to prevent, reduce, reuse, or recycle hazardous, solid and liquid waste streams.

In September 1994, the United States Environmental Protection Agency Region VII (EPA) notified the Company that it was being named as a potentially

responsible party (PRP) regarding the past improper handling of PCBs by PCB Treatment, Inc. located in Kansas City, Kansas and Kansas City, Missouri (the Sites). EPA is requesting that the Company voluntarily pay an undefined (pro rata) share of the ultimate clean-up costs at the Sites. A number of the largest PRP's have formed a Steering Committee which is chaired by the Company. The responsibility of the Committee is to direct clean-up activities, determine appropriate cost allocation and pursue actions against recalcitrant parties, if necessary. EPA has issued an Administrative Order on Consent requiring signatories to perform certain investigative work at the Sites. The Steering Committee has retained a consultant to prepare both a removal site evaluation to determine the nature and extent of the contamination at the sites and an engineering evaluation/cost analysis to determine and evaluate alternatives for removal action to prevent, mitigate, or otherwise respond to or remedy the release or threatened potential subsequent release of hazardous substances. The consultant will also perform a streamlined risk assessment that includes contaminant identification, exposure assessment, toxicology assessment and human health and environmental risk characterization. The Company has recorded a preliminary liability for this site of $500,000 of which approximately $26,000 has been spent through December 31, 1996. The remaining balance is shown as a liability on the December 31, 1996 consolidated balance sheets. Once the removal site evaluation and the engineering evaluation/cost analysis are completed, the Company will be in a better position to estimate and record the ultimate liabilities for this site.

The Company's general office building is located at 6100 Neil Road, Reno, Nevada. The facility is leased by the Company for an initial term of 25 years, which will end on June 30, 2010. The lease includes six renewal options for five years each and two renewal options for 10 years each. See Note 14 of the Company's consolidated financial statements.

Other major facilities include the operations center, transportation building and warehouse located at Ohm Place in Reno and 13 business offices/service centers located throughout the Company's service territory.

The Company operates portions of its electric system as lessee under lease agreements with Truckee-Carson Irrigation District (TCID) and Mineral County Power System.

Under terms of the TCID lease, the Company is obligated to pay an annual lease payment of $108,000 plus 2% of gross revenues derived from operations within the leasehold area, which covers portions of Washoe (excluding Reno/Sparks), Lyon, Storey and Churchill counties. In 1996, the Company paid approximately $351,000 as 2% of gross revenues. The lease expires in July 1998, at which time TCID is obligated to purchase any Company capital improvements unless the lease is renewed. To date, capital improvements, net of depreciation, total $21.3 million.

Under terms of the Mineral County Power System lease, the Company is obligated to pay, on a sliding scale, a percentage of gross revenues derived from operations within the leasehold area. The leasehold area includes the towns of Hawthorne, Mina, and Luning, along with other unincorporated towns roughly 100 miles southeast of Reno. During 1996 the Company paid $145,000 on gross revenues of $6.2 million. The lease expires in 2000. As with TCID, Mineral County Power System is obligated to purchase any Company capital improvements unless the lease is renewed. To date, capital improvements, net of depreciation, total $7.2 million.

The Company has nonexclusive franchises or revocable permits, in fact by grant (in most cases for specified terms of years) or in effect by acquies cence, to carry on its business in the localities in which its respective operations are conducted in Nevada and California. The franchise requirements of the various cities and counties in which the Company operates provide for varying payments based either on gross revenues, in which case the Company collects the fees directly through customer billings and remits to grantors of the franchise, or net profits from operations, which the Company records as expense. Franchise payments expense aggregated $1.0 million during 1996. Following are the Company's major franchises.

Franchise                                 Type of Service        Expiration Date
- ---------                             -----------------------   -----------------
Reno                                  Electric, Gas and Water   January      2006
Sparks                                Electric                  May          2006
Sparks                                Gas                       May          2007
Sparks                                Water                     April        2004
Carson City                           Electric                  February     2012
City of Elko                          Electric                  April        2017
City of South Lake
  Tahoe                               Electric                  April        2018
Washoe County                         Gas and Water             May          2015
Washoe County                         Electric                  September    2015
Eureka  County                        Electric                  July         2018

The Company applies for renewal of franchises in a timely manner prior to their respective expiration dates.

The Research, Development and Demonstration (RD&D) mission is to establish, encourage and execute RD&D related activities in pursuit of corporate excellence. In particular, the focus is on the activities to improve customer competitiveness and satisfaction, while strengthening the Company's corporate financial position.

The RD&D program includes elements managed and executed locally, those in participation with other utilities through the Electric Power Research Institute (EPRI), the Gas Research Institute, the American Gas Association, the American Waterworks Association, and other utility groups. These activities focus on performance improvements of existing utility facilities, effective resource utilization, efficiency improvements for customers' equipment, technologies, and generation technology for alternative energy resources.

The Company donated its electric vehicle to the University of Nevada, Reno for development of a special metropolitan area transportation project utilizing the electric vehicle as a pilot instant rent-a-car.

The Company's strategy includes effective use of technology to improve its business processes, existing and future. The key to this strategy is timely implementation of proven technologies, such as those resulting from its collaborative research and testing efforts with EPRI. The Company also supports future technology applications with investments in energy-related technology. For example, through SPR's partnership investments in Nth Power Fund, an R&D Venture Capital Fund, the Company has the opportunity to adopt and profit from new energy-related technologies.